
[Federal Register Volume 80, Number 205 (Friday, October 23, 2015)]
[Rules and Regulations]
[Pages 64661-64964]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2015-22842]



[[Page 64661]]

Vol. 80

Friday,

No. 205

October 23, 2015

Part III





Environmental Protection Agency





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40 CFR Part 60





Carbon Pollution Emission Guidelines for Existing Stationary Sources: 
Electric Utility Generating Units; Final Rule

  Federal Register / Vol. 80 , No. 205 / Friday, October 23, 2015 / 
Rules and Regulations  

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60

[EPA-HQ-OAR-2013-0602; FRL-9930-65-OAR]
RIN 2060-AR33


Carbon Pollution Emission Guidelines for Existing Stationary 
Sources: Electric Utility Generating Units

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

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SUMMARY: In this action, the Environmental Protection Agency (EPA) is 
establishing final emission guidelines for states to follow in 
developing plans to reduce greenhouse gas (GHG) emissions from existing 
fossil fuel-fired electric generating units (EGUs). Specifically, the 
EPA is establishing: Carbon dioxide (CO2) emission 
performance rates representing the best system of emission reduction 
(BSER) for two subcategories of existing fossil fuel-fired EGUs--fossil 
fuel-fired electric utility steam generating units and stationary 
combustion turbines; state-specific CO2 goals reflecting the 
CO2 emission performance rates; and guidelines for the 
development, submittal and implementation of state plans that establish 
emission standards or other measures to implement the CO2 
emission performance rates, which may be accomplished by meeting the 
state goals. This final rule will continue progress already underway in 
the U.S. to reduce CO2 emissions from the utility power 
sector.

DATES: This final rule is effective on December 22, 2015.

ADDRESSES: Docket. The EPA has established a docket for this action 
under Docket No. EPA-HQ-OAR-2013-0602. All documents in the docket are 
listed in the http://www.regulations.gov index. Although listed in the 
index, some information is not publicly available (e.g., confidential 
business information (CBI) or other information for which disclosure is 
restricted by statute). Certain other material, such as copyrighted 
material, will be publicly available only in hard copy. Publicly 
available docket materials are available either electronically in 
http://www.regulations.gov or in hard copy at the EPA Docket Center, 
EPA WJC West Building, Room 3334, 1301 Constitution Ave. NW., 
Washington, DC. The Public Reading Room is open from 8:30 a.m. to 4:30 
p.m., Monday through Friday, excluding federal holidays. The telephone 
number for the Public Reading Room is (202) 566-1744, and the telephone 
number for the Air Docket is (202) 566-1742. For additional information 
about the EPA's public docket, visit the EPA Docket Center homepage at 
http://www2.epa.gov/dockets.
    World Wide Web. In addition to being available in the docket, an 
electronic copy of this final rule will be available on the World Wide 
Web (WWW). Following signature, a copy of this final rule will be 
posted at the following address: http://www.epa.gov/cleanpowerplan/. A 
number of documents relevant to this rulemaking, including technical 
support documents (TSDs), a legal memorandum, and the regulatory impact 
analysis (RIA), are also available at http://www.epa.gov/cleanpowerplan/. These and other related documents are also available 
for inspection and copying in the EPA docket for this rulemaking.

FOR FURTHER INFORMATION CONTACT: Ms. Amy Vasu, Sector Policies and 
Programs Division (D205-01), U.S. EPA, Research Triangle Park, NC 
27711; telephone number (919) 541-0107, facsimile number (919) 541-
4991; email address: vasu.amy@epa.gov or Mr. Colin Boswell, 
Measurements Policy Group (D243-05), Sector Policies and Programs 
Division, U.S. EPA, Research Triangle Park, NC 27711; telephone number 
(919) 541-2034, facsimile number (919) 541-4991; email address: 
boswell.colin@epa.gov.

SUPPLEMENTARY INFORMATION:
    Acronyms. A number of acronyms and chemical symbols are used in 
this preamble. While this may not be an exhaustive list, to ease the 
reading of this preamble and for reference purposes, the following 
terms and acronyms are defined as follows:

ACEEE American Council for an Energy-Efficient Economy
AEO Annual Energy Outlook
AFL-CIO American Federation of Labor and Congress of Industrial 
Organizations
ASTM American Society for Testing and Materials
BSER Best System of Emission Reduction
Btu/kWh British Thermal Units per Kilowatt-hour
CAA Clean Air Act
CBI Confidential Business Information
CCS Carbon Capture and Storage (or Sequestration)
CEIP Clean Energy Incentive Program
CEMS Continuous Emissions Monitoring System
CHP Combined Heat and Power
CO2 Carbon Dioxide
DOE U.S. Department of Energy
ECMPS Emission Collection and Monitoring Plan System
EE Energy Efficiency
EERS Energy Efficiency Resource Standard
EGU Electric Generating Unit
EIA Energy Information Administration
EM&V Evaluation, Measurement and Verification
EO Executive Order
EPA Environmental Protection Agency
FERC Federal Energy Regulatory Commission
ERC Emission Rate Credit
FR Federal Register
GHG Greenhouse Gas
GW Gigawatt
HAP Hazardous Air Pollutant
HRSG Heat Recovery Steam Generator
IGCC Integrated Gasification Combined Cycle
IPCC Intergovernmental Panel on Climate Change
IPM Integrated Planning Model
IRP Integrated Resource Plan
ISO Independent System Operator
kW Kilowatt
kWh Kilowatt-hour
lb CO2/MWh Pounds of CO2 per Megawatt-hour
LBNL Lawrence Berkeley National Laboratory
MMBtu Million British Thermal Units
MW Megawatt
MWh Megawatt-hour
NAAQS National Ambient Air Quality Standards
NAICS North American Industry Classification System
NAS National Academy of Sciences
NGCC Natural Gas Combined Cycle
NOX Nitrogen Oxides
NRC National Research Council
NSPS New Source Performance Standard
NSR New Source Review
NTTAA National Technology Transfer and Advancement Act
OMB Office of Management and Budget
PM Particulate Matter
PM2.5 Fine Particulate Matter
PRA Paperwork Reduction Act
PUC Public Utilities Commission
RE Renewable Energy
REC Renewable Energy Credit
RES Renewable Energy Standard
RFA Regulatory Flexibility Act
RGGI Regional Greenhouse Gas Initiative
RIA Regulatory Impact Analysis
RPS Renewable Portfolio Standard
RTO Regional Transmission Organization
SBA Small Business Administration
SCC Social Cost of Carbon
SIP State Implementation Plan
SO2 Sulfur Dioxide
Tg Teragram (one trillion (10\12\) grams)
TSD Technical Support Document
TTN Technology Transfer Network
UMRA Unfunded Mandates Reform Act of 1995
UNFCCC United Nations Framework Convention on Climate Change
USGCRP U.S. Global Change Research Program
VCS Voluntary Consensus Standard

    Organization of This Document. The information presented in this 
preamble is organized as follows:

I. General Information
    A. Executive Summary
    B. Organization and Approach for This Final Rule

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II. Background
    A. Climate Change Impacts From GHG Emissions
    B. GHG Emissions From Fossil Fuel-Fired EGUs
    C. The Utility Power Sector
    D. Challenges in Controlling Carbon Dioxide Emissions
    E. Clean Air Act Regulations for Power Plants
    F. Congressional Awareness of Climate Change
    G. International Agreements and Actions
    H. Legislative and Regulatory Background for CAA Section 111
    I. Statutory and Regulatory Requirements
    J. Clean Power Plan Proposal and Supplemental Proposal
    K. Stakeholder Outreach and Consultations
    L. Comments on the Proposal
III. Rule Requirements and Legal Basis
    A. Summary of Rule Requirements
    B. Summary of Legal Basis
IV. Authority for This Rulemaking, Definition of Affected Sources, 
and Treatment of Categories
    A. EPA's Authority Under CAA Section 111(d)
    B. CAA Section 112 Exclusion to CAA Section 111(d) Authority
    C. Authority To Regulate EGUs
    D. Definition of Affected Sources
    E. Combined Categories and Codification in the Code of Federal 
Regulations
V. The Best System of Emission Reduction and Associated Building 
Blocks
    A. The Best System of Emission Reduction (BSER)
    B. Legal Discussion of Certain Aspects of the BSER
    C. Building Block 1--Efficiency Improvements at Affected Coal-
Fired Steam EGUs
    D. Building Block 2--Generation Shifts Among Affected EGUs
    E. Building Block 3--Renewable Generating Capacity
VI. Subcategory-Specific CO2 Emission Performance Rates
    A. Overview
    B. Emission Performance Rate Requirements
    C. Form of the Emission Performance Rates
    D. Emission Performance Rate-Setting Equation and Computation 
Procedure
VII. Statewide CO2 Goals
    A. Overview
    B. Reconstituting Statewide Rate-Based CO2 Emission 
Performance Goals From the Subcategory-Specific Emission Performance 
Rates
    C. Quantifying Mass-Based CO2 Emission Performance 
Goals From the Statewide Rate-Based CO2 Emission 
Performance Goals
    D. Addressing Potential Leakage in Determining the Equivalence 
of Statewide CO2 Emission Performance Goals
    E. State Plan Adjustments of State Goals
    F. Geographically Isolated States and Territories With Affected 
EGUs
VIII. State Plans
    A. Overview
    B. Timeline for State Plan Performance and Provisions To 
Encourage Early Action
    C. State Plan Approaches
    D. State Plan Components and Approvability Criteria
    E. State Plan Submittal and Approval Process and Timing
    F. State Plan Performance Demonstrations
    G. Additional Considerations for State Plans
    H. Resources for States to Consider in Developing Plans
    I. Considerations for CO2 Emission Reduction Measures 
That Occur at Affected EGUs
    J. Additional Considerations and Requirements for Mass-Based 
State Plans
    K. Additional Considerations and Requirements for Rate-Based 
State Plans
    L. Treatment of Interstate Effects
IX. Community and Environmental Justice Considerations
    A. Proximity Analysis
    B. Community Engagement in State Plan Development
    C. Providing Communities With Access to Additional Resources
    D. Federal Programs and Resources Available to Communities
    E. Multi-Pollutant Planning and Co-Pollutants
    F. Assessing Impacts of State Plan Implementation
    G. EPA Continued Engagement
X. Interactions With Other EPA Programs and Rules
    A. Implications for the NSR Program
    B. Implications for the Title V Program
    C. Interactions With Other EPA Rules
XI. Impacts of This Action
    A. What are the air impacts?
    B. Endangered Species Act
    C. What are the energy impacts?
    D. What are the compliance costs?
    E. What are the economic and employment impacts?
    F. What are the benefits of the proposed action?
XII. Statutory and Executive Order Reviews
    A. Executive Order 12866, Regulatory Planning and Review, and 
Executive Order 13563, Improving Regulation and Regulatory Review
    B. Paperwork Reduction Act (PRA)
    C. Regulatory Flexibility Act (RFA)
    D. Unfunded Mandates Reform Act (UMRA)
    E. Executive Order 13132, Federalism
    F. Executive Order 13175, Consultation and Coordination With 
Indian Tribal Governments
    G. Executive Order 13045, Protection of Children From 
Environmental Health Risks and Safety Risks
    H. Executive Order 13211, Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use
    I. National Technology Transfer and Advancement Act (NTTAA)
    J. Executive Order 12898, Federal Actions To Address 
Environmental Justice in Minority Populations and Low-Income 
Populations
    K. Congressional Review Act (CRA)
XIII. Statutory Authority

I. General Information

A. Executive Summary

1. Introduction
    This final rule is a significant step forward in reducing 
greenhouse gas (GHG) emissions in the U.S. In this action, the EPA is 
establishing for the first time GHG emission guidelines for existing 
power plants. These final emission guidelines, which rely in large part 
on already clearly emerging growth in clean energy innovation, 
development and deployment, will lead to significant carbon dioxide 
(CO2) emission reductions from the utility power sector that 
will help protect human health and the environment from the impacts of 
climate change. This rule establishes, at the same time, the foundation 
for longer term GHG emission reduction strategies necessary to address 
climate change and, in so doing, confirms the international leadership 
of the U.S. in the global effort to address climate change. In this 
final rule, we have taken care to ensure that achievement of the 
required emission reductions will not compromise the reliability of our 
electric system, or the affordability of electricity for consumers. 
This final rule is the result of unprecedented outreach and engagement 
with states, tribes, utilities, and other stakeholders, with 
stakeholders providing more than 4.3 million comments on the proposed 
rule. In this final rule, we have addressed the comments and concerns 
of states and other stakeholders while staying consistent with the law. 
As a result, we have followed through on our commitment to issue a plan 
that is fair, flexible and relies on the accelerating transition to 
cleaner power generation that is already well underway in the utility 
power sector.
    Under the authority of Clean Air Act (CAA) section 111(d), the EPA 
is establishing CO2 emission guidelines for existing fossil 
fuel-fired electric generating units (EGUs)--the Clean Power Plan. 
These final guidelines, when fully implemented, will achieve 
significant reductions in CO2 emissions by 2030, while 
offering states and utilities substantial flexibility and latitude in 
achieving these reductions. In this final rule, the EPA is establishing 
a CO2 emission performance rate for each of two 
subcategories of fossil fuel-fired EGUs--fossil fuel-fired electric 
steam generating units and stationary combustion turbines--that 
expresses the ``best system of emissions reduction . . . adequately 
demonstrated'' (BSER)

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for CO2 from the power sector.\1\ The EPA is also 
establishing state-specific rate-based and mass-based goals that 
reflect the subcategory-specific CO2 emission performance 
rates and each state's mix of affected EGUs. The guidelines also 
provide for the development, submittal and implementation of state 
plans that implement the BSER--again, expressed as CO2 
emission performance rates--either directly by means of source-specific 
emission standards or other requirements, or through measures that 
achieve equivalent CO2 reductions from the same group of 
EGUs.
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    \1\ Under CAA section 111(d), pursuant to 40 CFR 60.22(b)(5), 
states must establish, in their state plans, emission standards that 
reflect the degree of emission limitation achievable through the 
application of the ``best system of emission reduction'' that, 
taking into account the cost of achieving such reduction and any 
non-air quality health and environmental impacts and energy 
requirements, the Administrator determines has been adequately 
demonstrated (i.e., the BSER). Under CAA section 111(a)(1) and (d), 
the EPA is authorized to determine the BSER and to calculate the 
amount of emission reduction achievable through applying the BSER. 
The state is authorized to identify the emission standard or 
standards that reflect that amount of emission reduction.
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    States with one or more affected EGUs will be required to develop 
and implement plans that set emission standards for affected EGUs. The 
CAA section 111(d) emission guidelines that the EPA is promulgating in 
this action apply to only the 48 contiguous states and any Indian tribe 
that has been approved by the EPA pursuant to 40 CFR 49.9 as eligible 
to develop and implement a CAA section 111(d) plan.\2\ Because Vermont 
and the District of Columbia do not have affected EGUs, they will not 
be required to submit a state plan. Because the EPA does not possess 
all of the information or analytical tools needed to quantify the BSER 
for the two non-contiguous states with otherwise affected EGUs (Alaska 
and Hawaii) and the two U.S. territories with otherwise affected EGUs 
(Guam and Puerto Rico), these emission guidelines do not apply to those 
areas, and those areas will not be required to submit state plans on 
the schedule required by this final action.
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    \2\ In the case of a tribe that has one or more affected EGUs in 
its area of Indian country, the tribe has the opportunity, but not 
the obligation, to establish a CO2 emission standard for 
each affected EGU located in its area of Indian country and a CAA 
section 111(d) plan for its area of Indian country. If the tribe 
chooses to establish its own plan, it must seek and obtain authority 
from the EPA to do so pursuant to 40 CFR 49.9. If it chooses not to 
seek this authority, the EPA has the responsibility to determine 
whether it is necessary or appropriate, in order to protect air 
quality, to establish a CAA section 111(d) plan for an area of 
Indian country where affected EGUs are located.
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    The emission standards in a state's plan may incorporate the 
subcategory-specific CO2 emission performance rates set by 
the EPA or, in the alternative, may be set at levels that ensure that 
the state's affected EGUs, individually, in aggregate, or in 
combination with other measures undertaken by the state achieve the 
equivalent of the interim and final CO2 emission performance 
rates between 2022 and 2029 and by 2030, respectively. State plans must 
also: (1) Ensure that the period for emission reductions from the 
affected EGUs begin no later than 2022, (2) show how goals for the 
interim and final periods will be met, (3) ensure that, during the 
period from 2022 to 2029, affected EGUs in the state collectively meet 
the equivalent of the interim subcategory-specific CO2 
emission performance rates, and (4) provide for periodic state-level 
demonstrations prior to and during the 2022-2029 period that will 
ensure required CO2 emission reductions are being 
accomplished and no increases in emissions relative to each state's 
planned emission reduction trajectory are occurring. A Clean Energy 
Incentive Program (CEIP) will provide opportunities for investments in 
renewable energy (RE) and demand-side energy efficiency (EE) that 
deliver results in 2020 and/or 2021. The plans must be submitted to the 
EPA in 2016, though an extension to 2018 is available to allow for the 
completion of stakeholder and administrative processes.
    The EPA is promulgating: (1) Subcategory-specific CO2 
emission performance rates, (2) state rate-based goals, and (3) state 
mass-based CO2 goals that represent the equivalent of each 
state's rate-based goal. This will facilitate states' choices in 
developing their plans, particularly for those seeking to adopt mass-
based allowance trading programs or other statewide policy measures as 
well as, or instead of, source-specific requirements. The EPA received 
significant comment to the effect that mass-based allowance trading was 
not only highly familiar to states and EGUs, but that it could be more 
readily applied than rate-based trading for achieving emission 
reductions in ways that optimize affordability and electric system 
reliability.
    In this summary, we discuss the purpose of this rule, the major 
provisions of the final rule, the context for the rulemaking, key 
changes from the proposal, the estimated CO2 emission 
reductions, and the costs and benefits expected to result from full 
implementation of this final action. Greater detail is provided in the 
body of this preamble, the RIA, the response to comments (RTC) 
documents, and various TSDs and memoranda addressing specific topics.
2. Purpose of This Rule
    The purpose of this rule is to protect human health and the 
environment by reducing CO2 emissions from fossil fuel-fired 
power plants in the U.S. These plants are by far the largest domestic 
stationary source of emissions of CO2, the most prevalent of 
the group of air pollutant GHGs that the EPA has determined endangers 
public health and welfare through its contribution to climate change. 
This rule establishes for the first time emission guidelines for 
existing power plants. These guidelines will lead to significant 
reductions in CO2 emissions, result in cleaner generation 
from the existing power plant fleet, and support continued investments 
by the industry in cleaner power generation to ensure reliable, 
affordable electricity now and into the future.
    Concurrent with this action, the EPA is also issuing a final rule 
that establishes CO2 emission standards of performance for 
new, modified, and reconstructed power plants. Together, these rules 
will reduce CO2 emissions by a substantial amount while 
ensuring that the utility power sector in the U.S. can continue to 
supply reliable and affordable electricity to all Americans using a 
diverse fuel supply. As with past EPA rules addressing air pollution 
from the utility power sector, these guidelines have been designed with 
a clear recognition of the unique features of this sector. 
Specifically, the agency recognizes that utilities provide an essential 
public service and are regulated and managed in ways unlike any other 
industrial activity. In providing assurances that the emission 
reductions required by this rule can be achieved without compromising 
continued reliable, affordable electricity, this final rule fully 
accounts for the critical service utilities provide.
    As with past rules under CAA section 111, this rule relies on 
proven technologies and measures to set achievable emission performance 
rates that will lead to cost-effective pollutant emission reductions, 
in this case CO2 emission reductions at power plants, across 
the country. In fact, the emission guidelines reflect strategies, 
technologies and approaches already in widespread use by power 
companies and states. The vast preponderance of the input we received 
from stakeholders is supportive of this conclusion.
    States will play a key role in ensuring that emission reductions 
are achieved at a reasonable cost. The experience of

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states in this regard is especially important because CAA section 
111(d) relies on the well-established state-EPA partnership to 
accomplish the required CO2 emission reductions. States will 
have the flexibility to choose from a range of plan approaches and 
measures, including numerous measures beyond those considered in 
setting the CO2 emission performance rates, and this final 
rule allows and encourages states to adopt the most effective set of 
solutions for their circumstances, taking account of cost and other 
considerations. This rulemaking, which will be implemented through the 
state-EPA partnership, is a significant step that will reduce air 
pollution, in this case GHG emissions, in the U.S. At the same time, 
the final rule greatly facilitates flexibility for EGUs by establishing 
a basis for states to set trading-based emission standards and 
compliance strategies. The rule establishes this basis by including 
both uniform emission performance rates for the two subcategories of 
sources and also state-specific rate- and mass-based goals.
    This final rule is a significant step forward in implementing the 
President's Climate Action Plan.\3\ To address the far-reaching harmful 
consequences and real economic costs of climate change, the President's 
Climate Action Plan details a broad array of actions to reduce GHG 
emissions that contribute to climate change and its harmful impacts on 
public health and the environment. Climate change is already occurring 
in this country, affecting the health, economic well-being and quality 
of life of Americans across the country, and especially those in the 
most vulnerable communities. This CAA section 111(d) rulemaking to 
reduce GHG emissions from existing power plants, and the concurrent CAA 
section 111(b) rulemaking to reduce GHG emissions from new, modified, 
and reconstructed power plants, implement one of the strategies of the 
Climate Action Plan.
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    \3\ The President's Climate Action Plan, June 2013. http://www.whitehouse.gov/sites/default/files/image/president27sclimateactionplan.pdf.
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    Nationwide, by 2030, this final CAA section 111(d) existing source 
rule will achieve CO2 emission reductions from the utility 
power sector of approximately 32 percent from CO2 emission 
levels in 2005.
    The EPA projects that these reductions, along with reductions in 
other air pollutants resulting directly from this rule, will result in 
net climate and health benefits of $25 billion to $45 billion in 2030. 
At the same time, coal and natural gas will remain the two leading 
sources of electricity generation in the U.S., with coal providing 
about 27 percent of the projected generation and natural gas providing 
about 33 percent of the projected generation.
3. Summary of Major Provisions
    a. Overview. The fundamental goal of this rule is to reduce harmful 
emissions of CO2 from fossil fuel-fired EGUs in accordance 
with the requirements of the CAA. The June 2014 proposal for this rule 
was designed to meet this overarching goal while accommodating two 
important objectives. The first was to establish guidelines that 
reflect both the unique interconnected and interdependent manner in 
which the power system operates and the actions, strategies, and 
policies states and utilities have already been undertaking that are 
resulting in CO2 emission reductions. The second objective 
was to provide states and utilities with broad flexibility and choice 
in meeting those requirements in order to minimize costs to ratepayers 
and to ensure the reliability of electricity supply. In this final 
rule, the EPA has focused on changes that, in addition to being 
responsive to the critical concerns and priorities of stakeholders, 
more fully accomplish these objectives.
    While our consideration of public input and additional information 
has led to notable revisions from the emission guidelines we proposed 
in June 2014, the proposed guidelines remain the foundation of this 
final rule. These final guidelines build on the progress already 
underway to reduce the carbon intensity of power generation in the 
U.S., especially through the lowest carbon-intensive technologies, 
while reflecting the unique interconnected and interdependent system 
within which EGUs operate. Thus, the BSER, as determined in these 
guidelines, incorporates a range of CO2-reducing actions, 
while at the same time adhering to the fundamental approach the EPA has 
relied on for decades in implementing section 111 of the CAA. 
Specifically, in making its BSER determination, the EPA examined not 
only actions, technologies and measures already in use by EGUs and 
states, but also deliberately incorporated in its identification of the 
BSER the unique way in which affected EGUs actually operate in 
providing electricity services. This latter feature of the BSER mirrors 
Congress' approach to regulating air pollution in this sector, as 
exemplified by Title IV of the CAA. There, Congress established a 
pollution reduction program specifically for fossil fuel-fired EGUs and 
designed the sulfur dioxide (SO2) portion of that program 
with express recognition of the utility power sector's ability to shift 
generation among various EGUs, which enabled pollution reduction by 
increasing reliance on RE and even on demand-side EE. The result of our 
following Congress' recognition of the interdependent operation of EGUs 
within an interconnected grid is the incorporation in the BSER of 
measures, such as shifting generation to lower-emitting NGCC units and 
increased use of RE, that rely on the current interdependent operation 
of EGUs. As we noted in the proposal and note here as well, the EPA 
undertook an unprecedented and sustained process of engagement with the 
public and stakeholders. It is, in many ways, as a direct result of 
public discussion and input that the EPA came to recognize the 
substantial extent to which the BSER needed to account for the unique 
interconnected and interdependent operations of EGUs if it was to meet 
the criteria on which the EPA has long relied in making BSER 
determinations.
    Equally important, these guidelines offer states and owners and 
operators of EGUs broad flexibility and latitude in complying with 
their obligations. Because affordability and electricity system 
reliability are of paramount importance, the rule provides states and 
utilities with time for planning and investment, which is instrumental 
to ensuring both manageable costs and system reliability, as well as to 
facilitating clean energy innovation. The final rule continues to 
express the CO2 emission reduction requirements in terms of 
state goals, as well as in terms of emission performance rates for the 
two subcategories of affected EGUs, reflecting the particular mix of 
power generation in each state, and it continues to provide until 2030, 
fifteen years from the date of this final rule, for states and sources 
to achieve the CO2 reductions. Numerous commenters, 
including most sources, states and energy agencies, indicated that this 
was a reasonable timeframe. The final guidelines also continue to 
provide an option where programs beyond those directly limiting power 
plant emission rates can be used for compliance (i.e., policies, 
programs and other measures). The final rule also continues to allow, 
but not require, multi-state approaches. Finally, EPA took care to 
ensure that states could craft their own emissions reduction 
trajectories in meeting the interim goals included in this final rule.
    b. Opportunities for states. As stated above, the final guidelines 
are designed to build on and reinforce progress by states, cities and 
towns, and companies on a growing variety of sustainable strategies to 
reduce power sector CO2

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emissions. States, in their CAA section 111(d) plans, will be able to 
rely on, and extend, programs they may already have created to address 
emissions of air pollutants, and in particular CO2, from the 
utility power sector or to address the sector from an overall 
perspective. Those states committed to Integrated Resource Planning 
(IRP) will be able to establish their CO2 reduction plans 
within that framework, while states with a more deregulated power 
sector system will be able to develop CO2 reduction plans 
within that specific framework. Each state will have the opportunity to 
take advantage of a wide variety of strategies for reducing 
CO2 emissions from affected EGUs, including demand-side EE 
programs and mass-based trading, which some suggested in their 
comments. The EPA and other federal entities, including the U.S. 
Department of Energy (DOE), the Federal Energy Regulatory Commission 
(FERC) and the U.S. Department of Agriculture (USDA), among others, are 
committed to sharing expertise with interested states as they develop 
and implement their plans.
    States will be able to address the economic interests of their 
utilities and ratepayers by using the flexibilities in this final 
action to reduce costs to consumers, minimize stranded assets, and spur 
private investments in RE and EE technologies and businesses. They may 
also, if they choose, work with other states on multi-state approaches 
that reflect the regional structure of electricity operating systems 
that exists in most parts of the country and is critical to ensuring a 
reliable supply of affordable energy. The final rule gives states the 
flexibility to implement a broad range of approaches that recognize 
that the utility power sector is made up of a diverse range of 
companies of various sizes that own and operate fossil fuel-fired EGUs, 
including vertically integrated companies in regulated markets, 
independent power producers, rural cooperatives and municipally-owned 
utilities, some of which are likely to have more direct access than 
others to certain types of GHG emission reduction opportunities, but 
all of which have a wide range of opportunities to achieve reductions 
or acquire clean generation.
    Again, with features that facilitate mass-based and/or interstate 
trading, the final guidelines also empower affected EGUs to pursue a 
broad range of choices for compliance and for integrating compliance 
action with the full range of their investments and operations.
    c. Main elements. This final rule comprises three main elements: 
(1) Two subcategory-specific CO2 emission performance rates 
resulting from application of the BSER to the two subcategories of 
affected EGUs; (2) state-specific CO2 goals, expressed as 
both emission rates and as mass, that reflect the subcategory-specific 
CO2 emission performance rates and each state's mix of 
affected EGUs the two performance rates; and (3) guidelines for the 
development, submittal and implementation of state plans that implement 
those BSER emission performance rates either through emission standards 
for affected EGUs, or through measures that achieve the equivalent, in 
aggregate, of those rates as defined and expressed in the form of the 
state goals.
    In this final action, the EPA is setting emission performance 
rates, phased in over the period from 2022 through 2030, for two 
subcategories of affected fossil fuel-fired EGUs--fossil fuel-fired 
electric utility steam-generating units and stationary combustion 
turbines. These rates, applied to each state's particular mix of fossil 
fuel-fired EGUs, generate the state's carbon intensity goal for 2030 
(and interim rates for the period 2022-2029). Each state will determine 
whether to apply these to each affected EGU or to take an alternative 
approach and meet either an equivalent statewide rate-based goal or 
statewide mass-based goal. The EPA does not prescribe how a state must 
meet the emission guidelines, but, if a state chooses to take the path 
of meeting a state goal, these final guidelines identify the methods 
that a state can or, in some cases, must use to demonstrate that the 
combination of measures and standards that the state adopts meets its 
state-level CO2 goals. While the EPA accomplishes the phase-
in of the interim goal by way of annual emission performance rates, 
states and EGUs may meet their respective emission reduction 
obligations ``on average'' over that period following whatever emission 
reduction trajectory they determine to pursue over that period.
    CAA section 111(d) creates a partnership between the EPA and the 
states under which the EPA establishes emission guidelines and the 
states take the lead on implementing them by establishing emission 
standards or creating plans that are consistent with the EPA emission 
guidelines. The EPA recognizes that each state has differing policy 
considerations--including varying regional emission reduction 
opportunities and existing state programs and measures--and that the 
characteristics of the electricity system in each state (e.g., utility 
regulatory structure and generation mix) also differ. Therefore, as in 
the proposal, each state will have the latitude to design a program to 
meet source-category specific emission performance rates or the 
equivalent statewide rate- or mass-based goal in a manner that reflects 
its particular circumstances and energy and environmental policy 
objectives. Each state can do so on its own, or a state can collaborate 
with other states and/or tribal governments on multi-state plans, or 
states can include in their plans the trading tools that EGUs can use 
to realize additional opportunities for cost savings while continuing 
to operate across the interstate system through which electricity is 
produced. A state would also have the option of adopting the model 
rules for either a rate- or a mass-based program that the EPA is 
proposing concurrently with this action.\4\
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    \4\ The EPA's proposed CAA section 111(d) federal plan and model 
rules for existing fossil fuel-fired EGUs are being published 
concurrently with this final rule.
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    To facilitate the state planning process, this final rule 
establishes guidelines for the development, submittal, and 
implementation of state plans. The final rule describes the components 
of a state plan, the additional latitude states have in developing 
strategies to meet the emission guidelines, and the options they have 
in the timing of submittal of their plans. This final rule also gives 
states considerable flexibility with respect to the timeframes for plan 
development and implementation, as well as the choice of emission 
reduction measures. The final rule provides up to fifteen years for 
full implementation of all emission reduction measures, with 
incremental steps for planning and then for demonstration of 
CO2 reductions that will ensure that progress is being made 
in achieving CO2 emission reductions. States will be able to 
choose from a wide range of emission reduction measures, including 
measures that are not part of the BSER, as discussed in detail in 
section VIII.G of this preamble.
    d. Determining the BSER. In issuing this final rulemaking, the EPA 
is implementing statutory provisions that have been in place since 
Congress first enacted the CAA in 1970 and that have been implemented 
pursuant to regulations promulgated in 1975 and followed in numerous 
subsequent CAA section 111 rulemakings. These requirements call on the 
EPA to develop emission guidelines that reflect the EPA's determination 
of the ``best system of emission reduction . . . adequately 
demonstrated'' for states to follow in

[[Page 64667]]

formulating plans to establish emission standards to implement the 
BSER.
    As the EPA has done in making BSER determinations in previous CAA 
section 111 rulemakings, for this final BSER determination, the agency 
considered the types of strategies that states and owners and operators 
of EGUs are already employing to reduce the covered pollutant (in this 
case, CO2) from affected sources (in this case, fossil fuel-
fired EGUs).\5\
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    \5\ The final emission guidelines for landfill gas emissions 
from municipal solid waste landfills, published on March 12, 1996, 
and amended on June 16, 1998 (61 FR 9905 and 63 FR 32743, 
respectively), provide an example, as the guidelines allow either of 
two approaches for controlling landfill gas--by recovering the gas 
as a fuel, for sale, and removing from the premises, or by 
destroying the organic content of the gas on the premises using a 
control device. Recovering the gas as a fuel source was a practice 
already being used by some affected sources prior to promulgation of 
the rulemaking.
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    In so doing, as has always been the case, our considerations were 
not limited solely to specific technologies or equipment in 
hypothetical operation; rather, our analysis encompassed the full range 
of operational practices, limitations, constraints and opportunities 
that bear upon EGUs' emission performance, and which reflect the unique 
interconnected and interdependent operations of EGUs and the overall 
electricity grid.
    In this final action, the agency has determined that the BSER 
comprises the first three of the four proposed ``building blocks,'' 
with certain refinements to the three building blocks.
    The three building blocks are:

    1. Improving heat rate at affected coal-fired steam EGUs.
    2. Substituting increased generation from lower-emitting 
existing natural gas combined cycle units for generation from 
higher-emitting affected steam generating units.
    3. Substituting increased generation from new zero-emitting 
renewable energy generating capacity for generation from affected 
fossil fuel-fired generating units.

    These three building blocks are approaches that are available to 
all affected EGUs, either through direct investment or operational 
shifts or through emissions trading where states, which must establish 
emission standards for affected EGUs, do so by incorporating emissions 
trading.\6\ At the same time, and as we noted in the proposal, there 
are numerous other measures available to reduce CO2 
emissions from affected EGUs, and our determination of the BSER does 
not necessitate the use of the three building blocks to their maximum 
extent, or even at all. The building blocks and the BSER determination 
are described in detail in section V of this preamble.
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    \6\ The EPA notes that, in quantifying the emission reductions 
that are achievable through application of the BSER, some building 
blocks will apply to some, but not all, affected EGUs. Specifically, 
building block 1 will apply to affected coal-fired steam EGUs, 
building block 2 will apply to all affected steam EGUs (both coal-
fired and oil/gas-fired), and building block 3 will apply to all 
affected EGUs.
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    e. CO2 state-level goals and subcategory-specific emission 
performance rates.
    (1) Final CO2 goals and emission performance rates.
    In this action, the EPA is establishing CO2 emission 
performance rates for two subcategories of affected EGUs--fossil fuel-
fired electric utility steam generating units and stationary combustion 
turbines. For fossil fuel-fired steam generating units, we are 
finalizing an emission performance rate of 1,305 lb CO2/MWh. 
For stationary combustion turbines, we are finalizing an emission 
performance rate of 771 lb CO2/MWh. As we did at proposal, 
for each state, we are also promulgating rate-based CO2 
goals that are the weighted aggregate of the emission performance rates 
for the state's EGUs. To ensure that states and sources can choose 
additional alternatives in meeting their obligations, the EPA is also 
promulgating each state's goal expressed as a CO2 mass goal. 
The inclusion of mass-based goals, along with information provided in 
the proposed federal plan and model rules that are being issued 
concurrently with this rule, paves the way for states to implement 
mass-based trading, as some states have requested, reflecting their 
view that mass-based trading provides significant advantages over rate-
based trading.
    Affected EGUs, individually, in aggregate, or in combination with 
other measures undertaken by the state, must achieve the equivalent of 
the CO2 emission performance rates, expressed via the state-
specific rate- and mass-based goals, by 2030.
    (2) Interim CO2 emission performance rates and state-specific 
goals.
    The best system of emission reduction includes both the measures 
for reducing CO2 emissions and the timeframe over which they 
can be implemented. In this final action, the EPA is establishing an 8-
year interim period, beginning in 2022 instead of 2020, over which to 
achieve the full required reductions to meet the CO2 
performance rates, a commencement date more than six years from October 
23, 2015, the date of this rulemaking. This 8-year interim period from 
2022 through 2029 is separated into three steps, 2022-2024, 2025-2027, 
and 2028-2029, each associated with its own interim CO2 
emission performance rates. The interim steps are presented both in 
terms of emission performance rates for the two subcategories of 
affected EGUs and in terms of state goals, expressed both as a rate and 
as a mass. A state may adopt emission standards for its sources that 
are identical to these interim emission performance rates or, 
alternatively, adapt these steps to accommodate the timing of expected 
reductions, as long as the state's interim goal is met over the 8-year 
period.
    f. State plans.\7\
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    \7\ The CAA section 111(d) emission guidelines apply to the 50 
states, the District of Columbia, U.S. territories, and any Indian 
tribe that has been approved by the EPA pursuant to 40 CFR 49.9 as 
eligible to develop and implement a CAA section 111(d) plan. In this 
preamble, in instances where these governments are not specifically 
listed, the term ``state'' is used to represent them. Because 
Vermont and the District of Columbia do not have affected EGUs, they 
will not be required to submit a state plan. Because the EPA does 
not possess all of the information or analytical tools needed to 
quantify the BSER for the two non-contiguous states with affected 
EGUs (Alaska and Hawaii) and the two U.S. territories with affected 
EGUs (Guam and Puerto Rico), we are not finalizing emission 
performance rates in those areas at this time, and those areas will 
not be required to submit state plans until we do.
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    In this action, the EPA is establishing final guidelines for states 
to follow in developing, submitting and implementing their plans. In 
developing plans, states will need to choose the type of plan they will 
develop. They will also need to include required plan components in 
their plan submittals, meet plan submittal deadlines, achieve the 
required CO2 emission reductions over time, and provide for 
monitoring and periodic reporting of progress. As with the BSER 
determination, stakeholder comments have provided both data and 
recommendations to which these final guidelines are responsive.
    (1) Plan approaches.
    To comply with these emission guidelines, a state will have to 
ensure, through its plan, that the emission standards it establishes 
for its sources individually, in aggregate, or in combination with 
other measures undertaken by the state, represent the equivalent of the 
subcategory-specific CO2 emission performance rates. This 
final rule includes several options for state plans, as discussed in 
the proposal and in many of the comments we received.
    First, in the final rule, states may establish emission standards 
for their affected EGUs that mirror the uniform emission performance 
rates for the two subcategories of sources included in this final rule. 
They may also pursue alternative approaches that adopt emission 
standards that meet the

[[Page 64668]]

uniform emission performance rates, or emission standards that meet 
either the rate-based goal promulgated for the state or the alternative 
mass-based goal promulgated for the state. It is for the purpose of 
providing states with these choices that the EPA is providing state-
specific rate-based and mass-based goals equivalent to the emission 
performance rates that the EPA is establishing for the two 
subcategories of fossil fuel-fired EGUs. A detailed explanation of 
rate- and mass-based goals is provided in section VII of this preamble 
and in a TSD.\8\ In developing its plan, each state and eligible tribe 
electing to submit a plan will need to choose whether its plan will 
result in the achievement of the CO2 emission performance 
rates, statewide rate-based goals, or statewide mass-based goals by the 
affected EGUs.
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    \8\ The CO2 Emission Performance Rate and Goal 
Computation TSD for the CPP Final Rule, available in the docket for 
this rulemaking.
---------------------------------------------------------------------------

    The second major set of options provided in the final rule includes 
the types of measures states may rely on through the state plans. A 
state will be able to choose to establish emission standards for its 
affected EGUs sufficient to meet the requisite performance rates or 
state goal, thus placing all of the requirements directly on its 
affected EGUs, which we refer to as the ``emission standards 
approach.'' Alternatively, a state can adopt a ``state measures 
approach,'' which would result in the affected EGUs meeting the 
statewide mass-based goal by allowing a state to rely upon state-
enforceable measures on entities other than affected EGUs, in 
conjunction with any federally enforceable emission standards the state 
chooses to impose on affected EGUs. With a state measures approach, the 
plan must also include a contingent backstop of federally enforceable 
emission standards for affected EGUs that fully meet the emission 
guidelines and that would be triggered if the plan failed to achieve 
the required emission reductions on schedule. A state would have the 
option of basing its backstop emission standards on the model rule, 
which focuses on the use of emissions trading as the core mechanism and 
which the EPA is proposing today. A state that adopts a state measures 
approach must use its mass CO2 emission goal as the metric 
for demonstrating plan performance.
    The final rule requires that the state plan submittal include a 
timeline with all of the programmatic plan milestone steps the state 
will take between the time of the state plan submittal and the year 
2022 to ensure that the plan is effective as of 2022. States must 
submit a report to the EPA in 2021 that demonstrates that the state has 
met the programmatic plan milestone steps that the state indicated it 
would take during the period from the submittal of the final plan 
through the end of 2020, and that the state is on track to implement 
the approved state plan as of January 1, 2022.
    The plan must also include a process for reporting on plan 
implementation, progress toward achieving CO2 emission 
reductions, and implementation of corrective actions, in the event that 
the state fails to achieve required emission levels in a timely 
fashion. Beginning January 1, 2025, and then January 1, 2028, January 
1, 2030, and then every two calendar years thereafter, the state will 
be required to compare emission levels achieved by affected EGUs in the 
state with the emission levels projected in the state plan and report 
the results of that comparison to the EPA by July 1 of those calendar 
years.
    Existing state programs can be aligned with the various state plan 
options further described in Section VIII. A state plan that uses one 
of the finalized model rules, which the EPA is proposing concurrently 
with this action, could be presumptively approvable if the state plan 
meets all applicable requirements.\9\ The plan guidelines provide the 
states with the ability to achieve the full reductions over a multi-
year period, through a variety of reduction strategies, using state-
specific or multi-state approaches that can be achieved on either a 
rate or mass basis. They also address several key policy considerations 
that states can be expected to contemplate in developing their plans.
---------------------------------------------------------------------------

    \9\ The EPA would take action on such a state plan through 
independent notice and comment rulemaking.
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    State plan approaches and plan guidelines are explained further in 
section VIII of this preamble.
    (2) State plan components and approvability criteria.
    The EPA's implementing regulations provide certain basic elements 
required for state plans submitted pursuant to CAA section 111(d).\10\ 
In the proposal, the EPA identified certain additional elements that 
should be contained in state plans. In this final action, in response 
to comments, the EPA is making several revisions to the components 
required in a state plan submittal and is also incorporating the 
approvability criteria into the final list of components required in a 
state plan submittal. In addition, we have organized the state plan 
components to reflect: (1) Components required for all state plan 
submittals; (2) additional components required for the emission 
standards approach; and (3) additional components required for the 
state measures approach.
---------------------------------------------------------------------------

    \10\ 40 CFR 60.23.
---------------------------------------------------------------------------

    All state plans must include the following components:

     Description of the plan
     Applicability of state plans to affected EGUs
     Demonstration that the plan submittal is projected to 
achieve the state's CO2 emission performance rates or 
state CO2 goal \11\
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    \11\ A state that chooses to set emission standards that are 
identical to the emission performance rates for both the interim 
period and in 2030 and beyond need not identify interim state goals 
nor include a separate demonstration that its plan will achieve the 
state goals.
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     Monitoring, reporting and recordkeeping requirements 
for affected EGUs
     State recordkeeping and reporting requirements
     Public participation and certification of hearing on 
state plan
     Supporting documentation

    Also, in submitting state plans, states must provide documentation 
demonstrating that they have considered electric system reliability in 
developing their plans.
    Further, in this final rule, the EPA is requiring states to 
demonstrate how they are meaningfully engaging all stakeholders, 
including workers and low-income communities, communities of color, and 
indigenous populations living near power plants and otherwise 
potentially affected by the state's plan. In their plan submittals, 
states must describe their engagement with their stakeholders, 
including their most vulnerable communities. The participation of these 
communities, along with that of ratepayers and the public, can be 
expected to help states ensure that state plans maintain the 
affordability of electricity for all and preserve and expand jobs and 
job opportunities as they move forward to develop and implement their 
plans.
    State plan submittals using the emission standards approach must 
also include:

     Identification of each affected EGU; identification of 
federally enforceable emission standards for the affected EGUs; and 
monitoring, recordkeeping and reporting requirements.
     Demonstrations that each emission standard will result 
in reductions that are quantifiable, non-duplicative, permanent, 
verifiable, and enforceable.

    State plan submittals using the state measures approach must also 
include:

     Identification of each affected EGU; identification of 
federally enforceable emission standards for affected EGUs (if 
applicable); identification of backstop of

[[Page 64669]]

federally enforceable emission standards; and monitoring, 
recordkeeping and reporting requirements.
     Identification of each state measure and demonstration 
that each state measure will result in reductions that are 
quantifiable, non-duplicative, permanent, verifiable, and 
enforceable.

    In addition to these requirements, each state plan must follow the 
EPA implementing regulations at 40 CFR 60.23.
    (3) Timing and process for state plan submittal and review.
    Because of the compelling need for actions to begin the steps 
necessary to reduce GHG emissions from EGUs, the EPA proposed that 
states submit their plans within 13 months of the date of this final 
rule and that reductions begin in 2020. In light of the comments 
received and in order to provide maximum flexibility to states while 
still taking timely action to reduce CO2 emissions, in this 
final rule the EPA is allowing for a 2-year extension until September 
6, 2018, for both individual and multi-state plans, to provide a total 
of 3 years for states to submit a final plan if an extension is 
received. Specifically, the final rule requires each state to submit a 
final plan by September 6, 2016. Since some states may need more than 
one year to complete all of the actions needed for their final state 
plans, including technical work, state legislative and rulemaking 
activities, a robust public participation process, coordination with 
third parties, coordination among states involved in multi-state plans, 
and consultation with reliability entities, the EPA is allowing an 
optional two-phased submittal process for state plans. If a state needs 
additional time to submit a final plan, then the state may request an 
extension by submitting an initial submittal by September 6, 2016. For 
the extension to be granted, the initial submittal must address three 
required components sufficiently to demonstrate that a state is able to 
undertake steps and processes necessary to timely submit a final plan 
by the extended date of September 6, 2018. These components are: An 
identification of final plan approach or approaches under 
consideration, including a description of progress made to date; an 
appropriate explanation for why the state needs additional time to 
submit a final plan beyond September 6, 2016; and a demonstration of 
how they have been engaging with the public, including vulnerable 
communities, and a description of how they intend to meaningfully 
engage with community stakeholders during the additional time (if an 
extension is granted) for development of the final plan, as described 
in section VIII.E of this preamble. As further described in section 
VIII.B of this preamble, the EPA is establishing a CEIP in order to 
promote early action. States' participation in the CEIP is optional. In 
order for a state to participate in the program, it must include in its 
initial submittal, if applicable, a non-binding statement of intent to 
participate in the CEIP; if a state is submitting a final plan by 
September 6, 2016, it must include such a statement of intent as part 
of its supporting documentation for the plan.
    If the initial submittal includes those components and if the EPA 
does not notify the state that the initial submittal does not contain 
the required components, then, within 90 days of the submittal, the 
extension of time to submit a final plan will be deemed granted. A 
state will then have until no later than September 6, 2018, to submit a 
final plan. The EPA will also be working with states during the period 
after they make their initial submittals and provide states with any 
necessary information and assistance during the 90-day period. Further, 
states participating in a multi-state plan may submit a single joint 
plan on behalf of all of the participating states.
    States and tribes that do not have any affected EGUs in their 
jurisdictional boundaries may provide emission rate credits (ERCs) to 
adjust CO2 emissions, provided they are connected to the 
contiguous U.S. grid and meet other requirements for eligibility. There 
are certain limitations and restrictions for generating ERCs, and 
these, as well as associated requirements, are explained in section 
VIII of this preamble.
    Following submission of final plans, the EPA will review plan 
submittals for approvability. Given a similar timeline accorded under 
section 110 of the CAA, and the diverse approaches states may take to 
meet the CO2 emission performance rates or equivalent 
statewide goals in the emission guidelines, the EPA is extending the 
period for EPA review and approval or disapproval of plans from the 
four-month period provided in the EPA implementing regulations to a 
twelve-month period. This timeline will provide adequate time for the 
EPA to review plans and follow notice-and-comment rulemaking procedures 
to ensure an opportunity for public comment. The EPA, especially 
through our regional offices, will be available to work with states as 
they develop their plans, in order to make review of submitted plans 
more straightforward and to minimize the chances of unexpected issues 
that could slow down approval of state plans.
    (4) Timing for implementing the CO2 emission guidelines.
    The EPA recognizes that the measures states and utilities have been 
and will be taking to reduce CO2 emissions from existing 
EGUs can take time to implement. We also recognize that investments in 
low-carbon intensity and RE and in EE strategies are currently underway 
and in various stages of planning and implementation widely across the 
country. We carefully reviewed information submitted to us regarding 
the feasible timing of various measures and identifying concerns that 
the required CO2 emission reductions could not be achieved 
as early as 2020 without compromising electric system reliability, 
imposing unnecessary costs on ratepayers, and requiring investments in 
more carbon-intensive generation, while diverting investment in cleaner 
technologies. The record is compelling. To respond to these concerns 
and to reflect the period of time required for state plan development 
and submittal by states, review and approval by the EPA, and 
implementation of approved plans by states and affected EGUs, the EPA 
is determining in this final rule that affected EGUs will be required 
to begin to make reductions by 2022, instead of 2020, as proposed, and 
meet the final CO2 emission performance rates or equivalent 
statewide goals by no later than 2030. The EPA is establishing an 8-
year interim period that begins in 2022 and goes through 2029, and 
which is separated into three steps, 2022-2024, 2025-2027, and 2028-
2029, each associated with its own interim goal. Affected EGUs must 
meet each of the interim period step 1, 2, and 3 CO2 
emission performance rates, or, following the emissions reduction 
trajectory designed by the state itself, must meet the equivalent 
statewide interim period goals, on average, that a state may establish 
over the 8-year period from 2022-2029. The CAA section 111(d) plan must 
include those specific requirements. Affected EGUs must also achieve 
the final CO2 performance rates or the equivalent statewide 
goal by 2030 and maintain that level subsequently. This approach 
reflects adjustments to the timeframe over which reductions must be 
achieved that mirror the determination of the final BSER, which 
incorporates the phasing in of the BSER measures in keeping with the 
achievability of those measures. The agency believes that this approach 
to timing is reasonable and appropriate, is consistent with many of the 
comments we received, and will

[[Page 64670]]

best support the optimization of overall CO2 reductions, 
ratepayer affordability and electricity system reliability.
    The EPA recognizes that successfully achieving reductions by 2022 
will be facilitated by actions and investments that yield 
CO2 emission reductions prior to 2022. The final guidelines 
include provisions to encourage early actions. States will be able to 
take advantage of the impacts of early investments that occur prior to 
the beginning of a plan performance period. Under a mass-based plan, 
those impacts will be reflected in reductions in the reported 
CO2 emissions of affected EGUs during the plan performance 
period. Under a rate-based plan, states may recognize early actions 
implemented after 2012 by crediting MWh of electricity generation and 
savings that are achieved by those measures during the interim and 
final plan performance periods. This provision is discussed in section 
VIII.K of the preamble.
    In addition, to encourage early investments in RE and demand-side 
EE, the EPA is establishing the CEIP. Through this program, detailed in 
section VIII.B of this preamble, states will have the opportunity to 
award allowances and ERCs to qualified providers that make early 
investments in RE, as well as in demand-side EE programs implemented in 
low-income communities. Those states that take advantage of this option 
will be eligible to receive from the EPA matching allowances or ERCs, 
up to a total for all states that represents the equivalent of 300 
million short tons of CO2 emissions.
    The EPA will address design and implementation details of the CEIP 
in a subsequent action. Prior to doing so, the EPA will engage with 
states, utilities and other stakeholders to gather information 
regarding their interests and priorities with regard to implementation 
of the CEIP.
    The CEIP can play an important role in supporting one of the 
critical policy benefits of this rule. The incentives and market signal 
generated by the CEIP can help sustain the momentum toward greater RE 
investment in the period between now and 2022 so as to offset any 
dampening effects that might be created by setting the period for 
mandatory reductions to begin in 2022, two years later than at 
proposal.
    (5) Community and environmental justice considerations.
    Climate change is an environmental justice issue. Low-income 
communities and communities of color already overburdened by pollution 
are disproportionately affected by climate change and are less 
resilient than others to adapt to or recover from climate-change 
impacts. While this rule will provide broad benefits to communities 
across the nation by reducing GHG emissions, it will be particularly 
beneficial to populations that are disproportionately vulnerable to the 
impacts of climate change and air pollution.
    Conventional pollutants emitted by power plants, such as 
particulate matter (PM), SO2, hazardous air pollutants 
(HAP), and nitrogen oxides (NOx), will also be reduced as 
the plants reduce their carbon emissions. These pollutants can have 
significant adverse local and regional health impacts. The EPA analyzed 
the communities in closest proximity to power plants and found that 
they include a higher percentage of communities of color and low-income 
communities than national averages. We thus expect an important co-
benefit of this rule to be a reduction in the adverse health impacts of 
air pollution on these low-income communities and communities of color. 
We refer to these communities generally as ``vulnerable'' or 
``overburdened,'' to denote those communities least resilient to the 
impacts of climate change and central to environmental justice 
considerations.
    While pollution will be cut from power plants overall, there may be 
some relatively small number of coal-fired plants whose operation and 
corresponding emissions increase as energy providers balance energy 
production across their fleets to comply with state plans. In addition, 
a number of the highest-efficiency natural gas-fired units are also 
expected to increase operations, but they have correspondingly low 
carbon emissions and are also characterized by low emissions of the 
conventional pollutants that contribute to adverse health effects in 
nearby communities and regionally. The EPA strongly encourages states 
to evaluate the effects of their plans on vulnerable communities and to 
take the steps necessary to ensure that all communities benefit from 
the implementation of this rule. In order to identify whether state 
plans are causing any adverse impacts on overburdened communities, 
mindful that substantial overall reductions, nevertheless, may be 
accompanied by potential localized increases, the EPA intends to 
perform an assessment of the implementation of this rule to determine 
whether it and other air quality rules are leading to improved air 
quality in all areas or whether there are localized impacts that need 
to be addressed.
    Effective engagement between states and affected communities is 
critical to the development of state plans. The EPA encourages states 
to identify communities that may be currently experiencing adverse, 
disproportionate impacts of climate change and air pollution, how state 
plan designs may affect them, and how to most effectively reach out to 
them. This final rule requires that states include in their initial 
submittals a description of how they engaged with vulnerable 
communities as they developed their initial submittals, as well as the 
means by which they intend to involve communities and other 
stakeholders as they develop their final plans. The EPA will provide 
training and other resources for states and communities to facilitate 
meaningful engagement.
    In addition to the benefits for vulnerable communities from 
reducing climate change impacts and effects of conventional pollutant 
emissions, this rule will also help communities by moving the utility 
industry toward cleaner generation and greater EE. The federal 
government is committed to ensuring that all communities share in these 
benefits.
    The EPA also encourages states to consider how they may incorporate 
approaches already used by other states to help low-income communities 
share in the investments in infrastructure, job creation, and other 
benefits that RE and demand-side EE programs provide, have access to 
financial assistance programs, and minimize any adverse impacts that 
their plans could have on communities. To help support states in taking 
concrete actions that provide economic development, job and electricity 
bill-cutting benefits to low-income communities directly, the EPA has 
designed the CEIP specifically to target the incentives it creates on 
investments that benefit low-income communities.
    Community and environmental justice considerations are discussed 
further in section IX of this preamble.
    (6) Addressing employment concerns.
    In addition, the EPA encourages states in designing their state 
plans to consider the effects of their plans on employment and overall 
economic development to assure that the opportunities for economic 
growth and jobs that the plans offer are realized. To the extent 
possible, states should try to assure that communities that can be 
expected to experience job losses can also take advantage of the 
opportunities for job growth or otherwise transition to healthy, 
sustainable economic growth. The President has proposed the POWER+ Plan 
to help communities impacted by power sector transition. The POWER+ 
plan invests in workers and jobs, addresses important legacy costs in 
coal country, and drives

[[Page 64671]]

development of coal technology.\12\ Implementation of one key part of 
the POWER+ Plan, the Partnerships for Opportunity and Workforce and 
Economic Revitalization (POWER) initiative, has already begun. The 
POWER initiative specifically targets economic and workforce 
development assistance to communities affected by ongoing changes in 
the coal industry and the utility power sector.\13\
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    \12\ https://www.whitehouse.gov/the-press-office/2015/03/27/fact-sheet-partnerships-opportunity-and-workforce-and-economic-revitaliz.
    \13\ http://www.eda.gov/power/.
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    (7) Electric system reliability.
    In no small part thanks to the comments we received and our 
extensive consultation with key agencies responsible for reliability, 
including FERC and DOE, among others, along with EPA's longstanding 
principles in setting emission standards for the utility power sector, 
these guidelines reflect the paramount importance of ensuring electric 
system reliability. The input we received on this issue focused heavily 
on the extent of the reductions required at the beginning of the 
interim period, proposed as 2020. We are addressing these concerns in 
large part by moving the beginning of the period for mandatory 
reductions under the program from 2020 to 2022 and significantly 
adjusting the interim goals so that they provide a less abrupt initial 
reduction expectation. This, in turn, will provide states and utilities 
with a great deal more latitude in determining their emission reduction 
trajectories over the interim period. As a result, there will be more 
time for planning, consultation and decision making in the formulation 
of state plans and in EGUs' choice of compliance strategies, all within 
the existing extensive structure of energy planning at the state and 
regional levels. These adjustments in the interim goals are supported 
by the information in the record concerning the time needed to develop 
and implement reductions under the BSER. In addition, the various forms 
of flexibility retained and enhanced in this final rule, including 
opportunities for trading within and between states, and other multi-
state compliance approaches, will further support electric system 
reliability.
    The final guidelines address electric system reliability in several 
additional important ways. Numerous commenters urged us to include, as 
part of the plan development or approval process, input from review by 
energy regulatory agencies and reliability entities. In the final rule, 
we are requiring that each state demonstrate in its final state plan 
submittal that it has considered reliability issues in developing its 
plan. Second, we recognize that issues may arise during the 
implementation of the guidelines that may warrant adjustments to a 
state's plan in order to maintain electric system reliability. The 
final guidelines make clear that states have the ability to propose 
amendments to approved plans in the event that unanticipated and 
significant electric system reliability challenges arise and compel 
affected EGUs to generate at levels that conflict with their compliance 
obligations under those plans.
    As a final element of reliability assurance, the rule also provides 
for a reliability safety valve for individual sources where there is a 
conflict between the requirements the state plan imposes on a specific 
affected EGU and the maintenance of electric system reliability in the 
face of an extraordinary and unanticipated event that presents 
substantial reliability concerns.
    We anticipate that these situations will be extremely rare because 
the states have the flexibility to craft requirements for their EGUs 
that will provide long averaging periods and/or compliance mechanisms, 
such as trading, whose inherent flexibility will make it unlikely that 
an individual unit will find itself in this kind of situation. As one 
example, under compliance regimes that allow individual EGUs to 
establish compliance through the acquisition and holding of allowances 
or ERCs equal to their emissions, an EGU's need to continue to 
operate--and emit--for the purposes of ensuring system reliability will 
not put the EGU into non-compliance, provided, of course, it obtains 
the needed allowances or credits in a timely fashion. We, nevertheless, 
agree with many commenters that it is prudent to provide an electric 
system reliability safety valve as a precaution.
    Finally, the EPA, DOE and FERC have agreed to coordinate their 
efforts, at the federal level, to help ensure continued reliable 
electricity generation and transmission during the implementation of 
the final rule. The three agencies have set out a memorandum that 
reflects their joint understanding of how they will work together to 
monitor implementation, share information, and to resolve any 
difficulties that may be encountered.
    As a result of the many features of this final rule that provide 
states and affected EGUs with meaningful time and decision making 
latitude, we believe that the comprehensive safeguards already in place 
in the U.S. to ensure electric system reliability will continue to 
operate effectively as affected EGUs reduce their CO2 
emissions under this program.
    (8) Outreach and resources for stakeholders.
    To provide states, U.S. territories, tribes, utilities, 
communities, and other interested stakeholders with understanding about 
the rule requirements, and to provide efficiencies where possible and 
reduce the cost and administrative burden, the EPA will continue to 
work with states, tribes, territories, and stakeholders to provide 
information and address questions about the final rule. Outreach will 
include opportunities for states and tribes to participate in 
briefings, teleconferences, and meetings about the final rule. The 
EPA's ten regional offices will continue to be the entry point for 
states, tribes and territories to ask technical and policy questions. 
The agency will host (or partner with appropriate groups to co-host) a 
number of webinars about various components of the final rule; these 
webinars are planned for the first two months after the final rule is 
issued. The EPA will also offer consultations with tribal governments. 
The EPA will continue outreach throughout the plan development and 
submittal process. The EPA will use information from this outreach 
process to inform the training and other tools that will be of most use 
to the state, tribes, and territories that are implementing the final 
rule.
    The EPA has worked with communities, states, tribes and relevant 
associations to develop an extensive training plan that will continue 
in the months after the Clean Power Plan is finalized. The EPA has 
assembled resources from a variety of sources to create a comprehensive 
training curriculum for those implementing this rule. Recorded 
presentations from the EPA, DOE and other federal entities will be 
available for communities, states, and others involved in composing and 
participating in the development of state plans. This curriculum is 
available online at EPA's Air Pollution Training Institute.
    The EPA also expects to issue guidance on specific topics. As 
guidance documents, tools, templates and other resources become 
available, the EPA, in consultation with DOE and other federal 
agencies, will continue to make these resources available via a 
dedicated Web site.\14\
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    \14\ www.epa.gov/cleanpowerplantoolbox.
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    We intend to continue to work actively with states and tribes, as 
appropriate, to provide information and technical support that will be 
helpful to

[[Page 64672]]

them in developing and implementing their plans. The EPA will engage in 
formal consultations with tribal governments and provide training 
tailored to the needs of tribes and tribal governments.
    Additional detail on aspects of the final rule is included in 
several technical support documents (TSDs) and memoranda that are 
available in the rulemaking docket.
4. Key Changes From Proposal
    a. Overview and highlights. As noted earlier in this overview, the 
June 2014 proposal for the rule was designed to meet the fundamental 
goal of reducing harmful emissions of CO2 from fossil fuel-
fired EGUs in a manner consistent with the CAA requirements, while 
accommodating two important objectives. The first objective was to 
establish guidelines that reflect both the manner in which the power 
system operates and the actions and measures already underway across 
states and the utility power sector that are resulting in 
CO2 emission reductions. The second objective was to provide 
states and utilities maximum flexibility, control and choice in meeting 
their compliance obligations. In this final rule, the EPA has focused 
on changes that, in addition to being responsive to the critical 
concerns and priorities of stakeholders, more fully accomplish these 
two crucial objectives.
    To achieve these objectives, the June 2014 proposal featured 
several important elements: The building block approach for the BSER; 
state-specific, rather than source-specific, goals; a 10-year interim 
goal that could be met ``on average'' over the 10-year period between 
2020 and 2029; and a ``portfolio'' option for state plans. These 
features were intended either to capture, in the emission guidelines, 
emission reduction measures already in widespread use or to maximize 
the range of choices that states and utilities could select in order to 
achieve their emission limitations at low cost while ensuring electric 
system reliability. In this final rule, we are retaining the key design 
elements of the proposal and making certain adjustments to respond to a 
variety of very constructive comments on ways that will implement the 
CAA section 111(d) requirements efficiently and effectively.
    The building block approach is a key feature of the proposal that 
we are retaining in the final rule, but have refined to include only 
the first three building blocks and to reflect implementation of the 
measures encompassed in the building blocks on a broad regional grid-
level. In the proposal, we expressed the emission limitation 
requirements reflecting the BSER in terms of the state goals in order 
to provide states with maximum flexibility and latitude. We viewed this 
as an important feature because each state has its own energy profile 
and state-specific policies and needs relative to the production and 
use of electricity. In the final rule, we extend that flexibility 
significantly in direct response to comments from states and utilities. 
The final rule establishes source-level emission performance rates for 
the source subcategories, while retaining state-level rate- and mass-
based goals. One of the key messages conveyed by state and utility 
commenters was that the final rule should make it easier for states to 
adopt mass-based programs and for utilities accustomed to operating 
across broad multi-state grids to be able to avail themselves of more 
``ready-made'' emissions trading regimes. The inclusion of both of 
these new features--mass-based state goals in addition to rate-based 
goals, and source-level emission performance rates for the two 
subcategories of sources--is intended to make it easier for states and 
utilities to achieve these outcomes. In fact, these additions, together 
with the model rules and federal plan being proposed concurrently with 
this rule, should demonstrate the relative ease with which states can 
adopt mass-based trading programs, including interstate mass-based 
programs that lend themselves to the kind of interstate compliance 
strategies so well suited for integration with the current interstate 
operations of the overall utility grid.
    Many stakeholders conveyed to the EPA that the proposal's interim 
goals for the 2020-2029 period were designed in a way that defeated the 
EPA's objective of allowing states and utilities to shape their 
emission reduction trajectories. They pointed out that, in many cases, 
the timing and stringency of the states' interim goals could require 
actions that could result in high costs, threaten electric system 
reliability or hinder the deployment of renewable technology. In 
response, the EPA has revised the interim goals in two critical ways. 
First, the period for mandatory reductions begin in 2022 rather than 
2020; second, in keeping with the BSER, emission reduction requirements 
are phased in more gradually over the interim period. These changes 
will allow states and utilities to delineate their own emission 
reduction trajectories so as to minimize costs and foster broader 
deployment of RE technologies. The value of these changes is 
demonstrated by our analysis of the final rule, which shows lower 
program costs, especially in the early years of the interim period, and 
greater RE deployment, relative to the analysis of the proposed rule. 
At the same time, this re-design of the interim goals, together with 
refinements we have made to state plan requirements and the inclusion 
of a reliability safety valve, provide states, utilities and other 
entities with the ability to continue to guarantee system reliability.
    b. Outreach, engagement and comment record. This final rule is the 
product of one of the most extensive and long-running public engagement 
processes the EPA has ever conducted, starting in the summer of 2013, 
prior to proposal, and continuing through December 2014, when the 
public comment period ended, and continuing beyond that with 
consultations and meetings with stakeholders. The result of this 
extensive consultation was millions of comments from stakeholders, 
which we have carefully considered over the past several months. The 
EPA gained crucial insights from the more than 4 million comments that 
the agency received on the proposal and associated documents leading to 
this final rulemaking. Comments were provided by stakeholders that 
include state environmental and energy officials, tribal officials, 
public utility commissioners, system operators, owners and operators of 
every type of power generating facility, other industry 
representatives, labor leaders, public health leaders, public interest 
advocates, community and faith leaders, and members of the public.
    The insights gained from public comments contributed to the 
development of final emission guidelines that build on the proposal and 
the alternatives on which we sought comment. The modifications 
incorporated in the final guidelines are directly responsive to the 
comments we received from the many and diverse stakeholders. The 
improved guidelines reflect information and ideas that states and 
utilities provided to us about both the best approach to establishing 
CO2 emission reduction requirements for EGUs and the most 
effective ways to create true flexibility for states and utilities in 
meeting these requirements. These final rules also reflect the results 
of EPA's robust consultation with federal, state and regional energy 
agencies and authorities, to ensure that the actions sources will take 
to reduce GHG emissions will not compromise electric system reliability 
or affordability of the U.S. electricity supply. Input and assistance 
from FERC

[[Page 64673]]

and DOE have been particularly important in shaping some provisions in 
these final guidelines. At the same time, input from faith-based, 
community-based and environmental justice organizations, who provided 
thoughtful comments about the potential impacts of this rule on 
pollution levels in overburdened communities and economic impacts, 
including utility rates in low-income communities, is also reflected in 
this rule. The final rule also reflects our response to concerns raised 
by labor leaders regarding the potential effects on workers and 
communities of the transition away from higher-emitting power 
generation to lower- and zero-emitting power generation.
    c. Key changes. The most significant changes in these final 
guidelines are: (1) The period for mandatory emission reductions 
beginning in 2022 instead of 2020 and a gradual application of the BSER 
over the 2022-2029 interim period, such that a state has substantial 
latitude in selecting its own emission reduction trajectory or ``glide 
path'' over that period, (2) a revised BSER determination that focuses 
on narrower generation options that do not include demand-side EE 
measures and that includes refinements to the building blocks, more 
complete incorporation in the BSER of the realities of electricity 
operations over the three regional interconnections, and up-to-date 
information about the cost and availability of clean generation 
options, (3) establishment of source-specific CO2 emission 
performance rates that are uniform across the two fossil fuel-fired 
subcategories covered in these guidelines, as well as rate- and mass-
based state goals, to facilitate emission trading, including interstate 
trading and, in particular, mass-based trading, (4) a variation on the 
proposal's ``portfolio'' option for state plans--called here the 
``state measures'' approach--that continues to provide states 
flexibility while ensuring that all state plans have federally 
enforceable measures as a backstop, (5) additional, more flexible 
options for states and utilities to adopt multi-state compliance 
strategies, (6) an extension of up to two years available to all states 
for submittal of their final compliance plans following making initial 
submittals in 2016, (7) provisions to encourage actions that achieve 
early reductions, including a Clean Energy Incentive Program (CEIP), 
(8) a combination of provisions expressly designed to ensure electric 
system reliability, (9) the addition of employment considerations for 
states in plan development, and (10) the expansion of considerations 
and programs for low-income and vulnerable communities.
    We provide summary explanations in the following paragraphs and 
more detailed explanations of all of these changes in later sections of 
this preamble and associated documents.
    (1) Mandatory reduction period beginning in 2022 and a gradual 
glide path.
    The proposal's mandatory emission reduction period beginning in 
2020 and the trajectory of emission reduction requirements in the 
interim period were both the subjects of significant comment. Earlier 
this year, FERC conducted a series of technical conferences comprising 
one national session and three regional sessions. The information 
provided by workshop participants echoed much of the material that had 
been submitted to the comment record for this rulemaking. On May 15, 
2015, the FERC Commissioners, drawing upon information highlighted at 
the technical conferences, transmitted to the EPA some suggestions for 
the final rule. In addition, via comments, states, utilities, and 
reliability entities asked us to ensure adequate time for them to 
implement strategies to achieve CO2 reductions. They 
expressed concern that, in the proposal, at least some states would be 
required to reduce emissions in 2020 to levels that would require 
abrupt shifts in generation in ways that raised concerns about impacts 
to electric system reliability and ratepayer bills, as well as about 
stranded assets. To many commenters, the proposal's requirement for 
CO2 emission reductions beginning in 2020, together with the 
stringency of the interim CO2 goal, posed significant 
reliability implications, in particular. In this final rule, the agency 
is addressing these concerns, in part, by adjusting the compliance 
timeframe from a 10-year interim period that begins in 2020 to an 8-
year interim period that begins in 2022, and by refining the approach 
for meeting interim CO2 emission performance rates to be a 
gradual glide path separated into three steps, 2022-2024, 2025-2027, 
and 2028-2029, that is also achievable ``on average'' over the 8-year 
interim period. In response to the concerns of commenters that the 
proposal's 10-year interim target failed to afford sufficient 
flexibility, the final guidelines' approach will provide states with 
realistic options for customizing their emission reduction 
trajectories. Of equal importance, the approach provides more time for 
planning, consultation and decision making in the formulation of state 
plans and in EGUs' choices of compliance strategies. Both FERC's May 
15, 2015 letter and the comment record, as well as other information 
sources, made it clear that providing sufficient time for planning and 
implementation was essential to ensuring electric system reliability.
    The final guidelines' approach to the interim emission performance 
rates is the result of the application of the measures constituting the 
BSER in a more gradual way, reflecting stakeholder comments and 
information about the appropriate period of time over which those 
measures can be deployed consistent with the BSER factors of cost and 
feasibility. In addition to facilitating reliable system operations, 
these changes provide states and utilities with the latitude to 
consider a broader range of options to achieve the required reductions 
while addressing concerns about ratepayer impacts and stranded assets.
    (2) Revised BSER determination.
    Commenters urged the EPA to confine its BSER determination to 
actions that involve what they characterized as more ``traditional'' 
generation. While some stakeholders recognized demand-side EE as being 
an integral part of the electricity system, with many of the 
characteristics of more traditional generating resources, other 
stakeholders did not. As explained in section V.B.3.c.(8) below, our 
traditional interpretation and implementation of CAA section 111 has 
allowed regulated entities to produce as much of a particular good as 
they desire, provided that they do so through an appropriately clean 
(or low-emitting) process. While building blocks 1, 2, and 3 fall 
squarely within this paradigm, the proposed building block 4 does not. 
In view of this, since the BSER must serve as the foundation of the 
emission guidelines, the EPA has not included demand-side EE as part of 
the final BSER determination. Thus, neither the final guidelines' BSER 
determination nor the emission performance rates for the two 
subcategories of affected EGUs take into account demand-side EE. 
However, many commenters also urged the EPA to allow states and sources 
to rely on demand-side EE as an element of their compliance strategies, 
as demand-side EE is treated as functionally interchangeable with other 
forms of generation for planning and operational purposes, as EE 
measures are in widespread use across the country and provide energy 
savings that reduce emissions, lower electric bills, and lead to 
positive investments and job creation. We agree, and the final 
guidelines provide ample latitude for states and utilities to rely on 
demand-side EE in

[[Page 64674]]

meeting emission reduction requirements.
    In response to stakeholder comments on the first three building 
blocks and considerable data in the record, the EPA has made 
refinements to the building blocks, and these are reflected in the 
final BSER. Refinements include adoption of a modified approach to 
quantification of the RE component, exclusion of the proposed nuclear 
generation components, and adoption of a consistent regionalized 
approach to quantification of all three building blocks. The agency 
also recognizes the important functional relationship between the 
period of time over which measures are deployed and the stringency of 
emission limitations those measures can achieve practically and at 
reasonable cost. Therefore, the final BSER also reflects adjustments to 
the stringency of the building blocks, after consideration of more and 
less stringent levels, and refinements to the timeframe over which 
reductions must be achieved. Sections V.C through V.E of this preamble 
provide further information on the refinements made to the building 
blocks and the rationale for doing so.
    Commenters pointed out--and practical experience confirms--what is 
widely known: That the utility power sector operates over regional 
interconnections that are not constrained by state borders. Across a 
variety of issues raised in the proposal, many commenters urged that 
the EPA take that reality into account in developing this final rule. 
Consequently, the BSER determination itself (as well as a number of new 
compliance features included in this final rule) and the resulting 
subcategory-specific emission performance rates take into account the 
grid-level operations of the source category.
    The final guidelines' BSER determination also takes into account 
recent reductions in the cost of clean energy technology, as well as 
projections of continuing cost reductions, and continuing increases in 
RE deployment. We also updated the underlying analysis with the most 
recent Energy Information Administration (EIA) projections that show 
lower growth in electricity demand between 2020 and 2030 than 
previously projected. In keeping with these recent EIA projections, we 
expect the final guidelines will be more conducive to compliance, 
consistent with a strategy that allows for the cleanest power 
generation and greater CO2 reductions in 2030 than the 
proposal. With a date of 2022, instead of 2020, as proposed, for the 
mandatory CO2 emission reduction period to begin, the final 
guidelines reflect that the additional time aligns with the adoption of 
lower-cost clean technology and, thus, its incorporation in the BSER at 
higher levels. At the same time, the 2022-2029 interim period will more 
easily allow for companies to take advantage of improved clean energy 
technologies as potential least cost options.
    (3) Uniform emission performance rates.
    Some stakeholders commented that the proposal's approach of 
expressing the BSER in terms of state-specific goals deviated from the 
requirements of CAA section 111 and from previous new source 
performance standards (NSPS). The effect, they stated, was that the 
proposal created de facto emission standards for all affected EGUs but 
that these de facto standards varied widely depending on the state in 
which a given EGU happened to be located. Instead, these and other 
commenters stated, section 111 requires that EPA establish the BSER 
specifically for affected sources, rather than by means of merely 
setting state-specific goals, and that these standards be uniform. 
Still other commenters observed that the effect of the approach taken 
in the proposal of applying the BSER to each state's fleet was to put a 
greater burden of reductions on lower-emitting or less carbon-intensive 
states and a lesser emission reduction burden on sources and states 
that were higher-emitting or more carbon-intensive. This, they argued, 
was both inequitable and at odds with the way in which NSPS have been 
applied in the past, where the higher-emitting sources have made the 
greater and more cost-effective reductions, while lower-emitting 
sources, whose reduction opportunities tend to be less cost-effective, 
have been required to make fewer reductions to meet the applicable 
standard.
    At the same time, state and utility commenters expressed concern 
that relying on state-specific goals and state-by-state planning could 
introduce complexity into the otherwise seamless integrated operation 
of affected EGUs across the multi-state grids on which system 
operators, states and utilities currently rely and intend to continue 
to rely. Accordingly, they recommended that the final guidelines 
facilitate emissions trading, in particular interstate trading, which 
would enable EGU operators to integrate compliance with CO2 
emissions limitations with facility and grid-level operations. These 
sets of comments intersected at the point at which they focused on the 
fact that it is at the source level at which the standard is set for 
NSPS and at the source level at which compliance must be achieved.
    The EPA carefully considered these comments and while we believe 
that the approach we took at proposal was well-founded and reflected a 
number of important considerations, we have concluded that there is a 
way to address these concerns while expanding upon the advantages 
offered by the proposal. Accordingly, the final guidelines establish 
uniform rates for the two subcategories of sources--an approach that is 
valuable for creating greater equity between and among utilities and 
states with widely varying emission levels and for expanding the 
flexibility of the program, especially in ways that have been 
identified as important to utilities and states. Specifically, the 
final guidelines express the BSER by means of performance-based 
CO2 emission rates that are uniform across each of two 
subcategories--fossil fuel-fired electric steam generating units and 
stationary combustion turbines--for the affected EGUs covered by the 
guidelines. The rates are determined, in part, by applying the 
methodology identified in the Notice of Data Availability (NODA) 
published on October 30, 2014, which was based on the proposal's 
building block approach. The final guidelines also maintain the 
approach adopted in the proposal of establishing state-level goals; in 
the final rule, those goals are equal to the weighted aggregate of the 
two emission performance rates as applied to the EGUs in each state.
    This approach rectifies what would have been an inefficient, 
unintended outcome of putting the greater reduction burden on lower-
emitting sources and states while exempting higher-emitting sources and 
states. Expressing the BSER by means of these rates also augments the 
range of options for both states and EGUs for securing needed 
flexibility. Inclusion of state goals creates latitude for states as to 
how they will meet the guidelines. States also may meet the guideline 
requirements by adopting the CO2 emission performance rates 
as emission standards that apply to the affected EGUs in their 
jurisdiction. Such an approach would lend itself to the ready 
establishment of intra-state and interstate trading, with the uniform 
rate-based standards of performance established for each EGU as the 
basis for such trading. At the same time, as at proposal, each state 
also has the option of complying with these guidelines by adopting a 
plan that takes a different approach to setting standards of 
performance for its EGUs and/or by applying complementary or 
alternative

[[Page 64675]]

measures to meet the state goal set by these guidelines--as either a 
rate or a mass total.
    During the outreach process and through comments, a number of state 
officials and other stakeholders expressed concern that the EPA's 
approach at proposal necessitated or represented a significant 
intrusion into state-level energy policy-making, drawing the EPA well 
beyond the bounds of its CAA authority and expertise. In fact, these 
final guidelines are entirely respectful of the EPA's responsibility 
and authority to regulate sources of air pollution. Instead, by 
establishing and operating through uniform performance rates for the 
two subcategories of sources that can be applied by states at the 
individual source level and that can readily be implemented through 
emission standards that incorporate emissions trading, these final 
guidelines align with the approach Congress and the EPA have 
consistently taken to regulating emissions from this and other 
industrial sectors, namely setting source-level, source category-wide 
standards that individual sources can meet through a variety of 
technologies and measures.
    We emphasize, at the same time, that while the final guidelines 
express the BSER by means of source-level CO2 emission 
performance rates, as well as state-level goals, as at proposal, each 
state will have a goal reflecting its particular mix of sources, and 
the final guidelines retain the flexibility inherent in the proposal's 
state-specific goals approach (and, as discussed in section VIII of 
this preamble, enhanced in various ways). Thus, in keeping with the 
proposal's flexibility, states may choose to adopt either the emission 
performance rates as emission standards for their sources, set 
different but, in the aggregate, equivalent rates, or fulfill their 
obligations by meeting their respective individual state goals.
    (4) State plan approaches.
    Commenters expressed support for the objectives served by the 
``portfolio'' option in the state plan approaches included at proposal, 
but many raised concerns about its legality, with respect, in 
particular, to the CAA's enforceability requirements. Some of these 
commenters identified a ``state commitment approach'' with backstop 
measures as a variation of the ``portfolio'' approach that would retain 
the benefits of the ``portfolio'' approach while resolving legal and 
enforceability concerns. In this final rule, in response to stakeholder 
comments on the portfolio approach and alternative approaches, the EPA 
is finalizing two approaches: A source-based ``emission standards'' 
approach, and a ``state measures'' approach. Through the latter, states 
may adopt a set of policies and programs, which would not be federally 
enforceable, except that any standards imposed on affected EGUs would 
be federally enforceable. In addition, states would be required to 
include federally enforceable backstop measures applicable to each 
affected EGU in the event that the measures included in the state plan 
failed to achieve the state plan's emissions reduction trajectory. 
Under these guidelines, states can implement the BSER through standards 
of performance incorporating the uniform performance rates or 
alternative but in the aggregate equivalent rates, or they can adopt 
plans that achieve in aggregate the equivalent of the subcategory-
specific CO2 emission performance rates by relying on other 
measures undertaken by the state that complement source-specific 
requirements or, save for the contingent backstop requirement, supplant 
them entirely. This revision provides consistency in the treatment of 
sources while still providing maximum flexibility for states to design 
their plans around reduction approaches that best suit their policy 
objectives.
    (5) Emission trading programs.
    Many state and utility commenters supported the use of mass-based 
and rate-based emission trading programs in state plans, including 
interstate emission trading programs, and either pointed out obstacles 
to establishing such programs or suggested approaches that would 
enhance states' and utilities' ability to create and participate in 
such programs.
    Through a combination of features retained from the proposal and 
changes made to the proposal, these final guidelines provide states and 
utilities with a panoply of tools that greatly facilitate their putting 
in place and participating in emissions trading programs. These 
include: (1) Expressing BSER in uniform emission performance rates that 
states may rely on in setting emission standards for affected EGUs such 
that EGUs operating under such standards readily qualify to trade with 
affected EGUs in states that adopt the same approach, (2) promulgating 
state mass goals so that states can move quickly to establish mass-
based programs such that their affected EGUs readily qualify to trade 
with affected EGUs in states that adopt the same approach, and (3) 
providing EPA resources and capacity to create a tracking system to 
support state emissions trading programs.
    (6) Extension of plan submittal date.
    Stakeholders, particularly states, provided compelling information 
establishing that it could take longer than the agency initially 
anticipated for the states to develop and submit their required plans. 
While the approach at proposal reflected the EPA's conclusion that it 
was essential to the environmental and economic purposes of this 
rulemaking that utilities and states establish the path towards 
emissions reductions as early as possible, we recognize commenters' 
concerns. To strike the proper balance, the EPA has developed a revised 
state plan submittal schedule. For states that cannot submit a final 
plan by September 6, 2016, the EPA is requiring those states to make an 
initial submittal by that date to assure that states begin to address 
the urgent needs for reductions quickly, and is providing until 
September 6, 2018, for states to submit a final plan, if an extension 
until that date is justified, to address the concern that a submitting 
state needs more time to develop comprehensive plans that reflect the 
full range of the state's and its stakeholders' interests.
    (7) Provisions to encourage early action.
    Many commenters supported providing incentives for states and 
utilities to deploy CO2-reducing investments, such as RE and 
demand-side EE measures, as early as possible. We also received 
comments from stakeholders regarding the disproportionate burdens that 
some communities already bear, and stating that all communities should 
have equal access to the benefits of clean and affordable energy. The 
EPA recognizes the validity and importance of these perspectives, and 
as a result has determined to provide a program--called the CEIP--in 
which states may choose to participate.
    The CEIP is designed to incentivize investment in certain RE and 
demand-side EE projects that commence construction, in the case of RE, 
or commence construction, in the case of demand-side EE, following the 
submission of a final state plan to the EPA, or after September 6, 
2018, for states that choose not to submit a final state plan by that 
date, and that generate MWh (RE) or reduce end-use energy demand (EE) 
during 2020 and/or 2021. State participation in the program is 
optional.
    Under the CEIP, a state may set aside allowances from the 
CO2 emission budget it establishes for the interim plan 
performance period or may generate early action ERCs (ERCs are 
discussed in more detail in section VIII.K.2), and allocate these 
allowances or ERCs to

[[Page 64676]]

eligible projects for the MWh those projects generate or the end-use 
energy savings they achieve in 2020 and/or 2021. For each early action 
allowance or ERC a state allocates to such projects, the EPA will 
provide the state with an appropriate number of matching allowances or 
ERCs for the state to allocate to the project. The EPA will match 
state-issued early action ERCs and allowances up to an amount that 
represents the equivalent of 300 million short tons of CO2 
emissions.
    For a state to be eligible for a matching award of allowances or 
ERCs from the EPA, it must demonstrate that it will award allowances or 
ERCs only to ``eligible'' projects. These are projects that:
     Are located in or benefit a state that has submitted a 
final state plan that includes requirements establishing its 
participation in the CEIP;
     Are implemented following the submission of a final state 
plan to the EPA, or after September 6, 2018, for a state that chooses 
not to submit a complete state plan by that date;
     For RE: Generate metered MWh from any type of wind or 
solar resources;
     For EE: Result in quantified and verified electricity 
savings (MWh) through demand-side EE implemented in low-income 
communities; and
     Generate or save MWh in 2020 and/or 2021.
    The following provisions outline how a state may award early action 
ERCs and allowances to eligible projects, and how the EPA will provide 
matching ERCs or allowances to states.
     For RE projects that generate metered MWh from any type of 
wind or solar resources: For every two MWh generated, the project will 
receive one early action ERC (or the equivalent number of allowances) 
from the state, and the EPA will provide one matching ERC (or the 
equivalent number of allowances) to the state to award to the project.
     For EE projects implemented in low-income communities: For 
every two MWh in end-use demand savings achieved, the project will 
receive two early action ERCs (or the equivalent number of allowances) 
from the state, and the EPA will provide two matching ERCs (or the 
equivalent number of allowances) to the state to award to the project.
    Early action allowances or ERCs awarded by the state, and matching 
allowances or ERCs awarded by the EPA pursuant to the CEIP, may be used 
for compliance by an affected EGU with its emission standards and are 
fully transferrable prior to such use.
    The EPA discusses the CEIP in the proposed federal plan rule and 
will address design and implementation details of the CEIP in a 
subsequent action. Prior to doing so, the EPA will engage with states, 
utilities and other stakeholders to gather information regarding their 
interests and priorities with regard to implementation of the CEIP.
    (8) Provisions for electric system reliability.
    A number of commenters stressed the importance of final guidelines 
that addressed the need to ensure that EGUs could meet their emission 
reduction requirements without being compelled to take actions that 
would undermine electric system reliability. As noted above, the EPA 
has consulted extensively with federal, regional and state energy 
agencies, utilities and many others about reliability concerns and ways 
to address them. The final guidelines support electric system 
reliability in a number of ways, some inherent in the improvements made 
in the program's design and some through specific provisions we have 
included in the final rule. Most important are the two key changes we 
made to the interim goal: Establishing 2022, instead of 2020, as the 
period for mandatory emission reductions begin and phasing in, over the 
8-year period, emission performance rates such that the level of 
stringency of the emission performance rates in 2022-2024 is 
significantly less than that for the years 2028 and 2029. Since states 
and utilities need only to meet their interim goal ``on average'' over 
the 8-year period, these changes provide them with a great deal of 
latitude in determining for themselves their emission reduction 
trajectory--and they have additional time to do so. As a result, the 
final guidelines provide the ingredients that commenters, reliability 
entities and expert agencies told the EPA were essential to ensuring 
electric system reliability: Time and flexibility sufficient to allow 
for planning, implementation and the integration of actions needed to 
address reliability while achieving the required emissions reductions.
    In addition, the final guidelines add a requirement, based on 
substantial input from experts in the energy field, for states to 
demonstrate that they have considered electric system reliability in 
developing their state plans. The final rule also offers additional 
opportunities that support electric system reliability, including 
opportunities for trading within and between states. The final 
guidelines also make clear that states can adjust their plans in the 
event that reliability challenges arise that need to be remedied by 
amending the state plan. In addition, the final rule includes a 
reliability safety valve to address situations where, because of an 
unanticipated catastrophic event, there is a conflict between the 
requirements imposed on an affected unit and the maintenance of 
reliability.
    (9) Approaches for addressing employment concerns.
    Some commenters brought to our attention the concerns of workers, 
their families and communities, particularly in coal-producing regions 
and states, that the ongoing shift toward lower-carbon electricity 
generation that the final rule reflects will cause harm to communities 
that are dependent on coal. Others had concerns about whether new jobs 
created as a result of actions taken pursuant to the final rule will 
allow for overall economic development. In the final rule, the EPA 
encourages states, in designing their state plans, to consider the 
effects of their plans on employment and overall economic development 
to assure that the opportunities for economic growth and jobs that the 
plans offer are manifest. We also identify federal programs, including 
the multi-agency Partnerships for Opportunity and Workforce and 
Economic Revitalization (POWER) Initiative.\15\ The POWER Initiative is 
competitively awarding planning assistance and implementation grants 
with funding from the Department of Commerce, Department of Labor 
(DOL), Small Business Administration, and the Appalachian Regional 
Commission,\16\ whose mission is to assist communities affected by 
changes in the coal industry and the utility power sector.
---------------------------------------------------------------------------

    \15\ http://www.eda.gov/power/.
    \16\ https://www.whitehouse.gov/the-press-office/2015/03/27/fact-sheet-partnerships-opportunity-and-workforce-and-economic-revitaliz.
---------------------------------------------------------------------------

    (10) Community and environmental justice considerations.
    Many community leaders, environmental justice advocates, faith-
based organizations and others commented that the benefits of this rule 
must be shared broadly across society and that undue burdens should not 
be imposed on low-income ratepayers. We agree. The federal government 
is taking significant steps to help low-income families and individuals 
gain access to RE and demand-side EE through new initiatives involving, 
for example, increasing solar energy systems in federally subsidized 
homes and supporting solar systems for others with low incomes. The 
final rule ensures that bill-lowering measures such as demand-side EE 
continue to be a major

[[Page 64677]]

compliance option. The CEIP will encourage early investment in these 
types of projects as well. In addition to carbon reduction benefits, we 
expect significant near- and long-term public health benefits in 
communities as conventional air pollutants are reduced along with GHGs. 
However, some stakeholders expressed concerns about the possibility of 
localized increases in emissions from some power plants as the utility 
industry complies with state plans, in particular in communities 
already disproportionately affected by air pollution. This rule sets 
expectations for states to engage with vulnerable communities as they 
develop their plans, so that impacts on these communities are 
considered as plans are designed. The EPA also encourages states to 
engage with workers in the utility power and related sectors, as well 
as their worker representatives, so that impacts on their communities 
may be considered. The EPA commits, once implementation is under way, 
to assess the impacts of this rule. Likewise, we encourage states to 
evaluate the effects of their plans to ensure that there are no 
disproportionate adverse impacts on their communities.
5. Additional Context for This Final Rule
    a. Climate change impacts. This final rule is an important step in 
an essential series of long-term actions that are achieving and must 
continue to achieve the GHG emission reductions needed to address the 
serious threat of climate change, and constitutes a major commitment--
and international leadership-by-doing--on the part of the U.S., one of 
the world's largest GHG emitters. GHG pollution threatens the American 
public by leading to damaging and long-lasting changes in our climate 
that can have a range of severe negative effects on human health and 
the environment. CO2 is the primary GHG pollutant, 
accounting for nearly three-quarters of global GHG emissions\17\ and 82 
percent of U.S. GHG emissions.\18\ The May 2014 report of the National 
Climate Assessment \19\ concluded that climate change impacts are 
already manifesting themselves and imposing losses and costs. The 
report documents increases in extreme weather and climate events in 
recent decades, with resulting damage and disruption to human well-
being, infrastructure, ecosystems, and agriculture, and projects 
continued increases in impacts across a wide range of communities, 
sectors, and ecosystems. New scientific assessments since 2009, when 
the EPA determined that GHGs pose a threat to human health and the 
environment (the ``Endangerment Finding''), highlight the urgency of 
addressing the rising concentration of CO2 in the 
atmosphere. Certain groups, including children, the elderly, and the 
poor, are most vulnerable to climate-related effects. Recent studies 
also find that certain communities, including low-income communities 
and some communities of color (more specifically, populations defined 
jointly by ethnic/racial characteristics and geographic location), are 
disproportionately affected by certain climate change related impacts--
including heat waves, degraded air quality, and extreme weather 
events--which are associated with increased deaths, illnesses, and 
economic challenges. Studies also find that climate change poses 
particular threats to the health, well-being, and ways of life of 
indigenous peoples in the U.S.
---------------------------------------------------------------------------

    \17\ Intergovernmental Panel on Climate Change (IPCC) report, 
``Contribution of Working Group I to the Fourth Assessment Report of 
the Intergovernmental Panel on Climate Change,'' 2007. Available at 
http://epa.gov/climatechange/ghgemissions/global.html.
    \18\ From Table ES-2 ``Inventory of U.S. Greenhouse Gas 
Emissions and Sinks: 1990-2013'', Report EPA 430-R-15-004, United 
States Environmental Protection Agency, April 15, 2015. Available at 
http://epa.gov/climatechange/ghgemissions/usinventoryreport.html.
    \19\ U.S. Global Change Research Program, Climate Change Impacts 
in the United States: The Third National Climate Assessment, May 
2014. Available at http://nca2014.globalchange.gov/.
---------------------------------------------------------------------------

    b. The utility power sector. One of the strategies of the 
President's Climate Action Plan is to reduce CO2 emissions 
from power plants.\20\ This is because fossil fuel-fired EGUs are by 
far the largest emitters of GHGs, primarily in the form of 
CO2. Among stationary sources in the U.S. and among fossil 
fuel-fired EGUs, coal-fired units are by far the largest emitters of 
GHGs. To accomplish the goal of reducing CO2 emissions from 
power plants, President Obama issued a Presidential Memorandum \21\ 
that recognized the importance of significant and prompt action. The 
Memorandum directed the EPA to complete carbon pollution standards, 
regulations or guidelines, as appropriate, for new, modified, 
reconstructed and existing power plants, and in doing so to build on 
state leadership in moving toward a cleaner power sector. In this 
action and the concurrent CAA section 111(b) rule, the EPA is 
finalizing regulations to reduce GHG emissions from fossil fuel-fired 
EGUs. This CAA section 111(d) action builds on actions states and 
utilities are already taking to move toward cleaner generation of 
electric power.
---------------------------------------------------------------------------

    \20\ The President's Climate Action Plan, June 2013. http://www.whitehouse.gov/sites/default/files/image/president27sclimateactionplan.pdf.
    \21\ Presidential Memorandum--Power Sector Carbon Pollution 
Standards, June 25, 2013. http://www.whitehouse.gov/the-press-office/2013/06/25/presidential-memorandum-power-sector-carbon-pollution-standards.
---------------------------------------------------------------------------

    The utility power sector is unlike other industrial sectors. In 
other sectors, sources effectively operate independently and on a 
local-site scale, with control of their physical operations resting in 
the hands of their respective owners and operators. Pollution control 
standards, which focus on each source in a non-utility industrial 
source category, have reflected the standalone character of individual 
source investment decision-making and operations.
    In stark contrast, the utility power sector comprises a unique 
system of electricity resources, including the EGUs affected under 
these guidelines, that operate in a complex and interconnected grid 
where electricity generally flows freely (e.g., portions of the system 
cannot be easily isolated through the use of switches or valves as can 
be done in other networked systems like trains and pipeline systems). 
That grid is physically interconnected and operated on an integrated 
basis across large regions. In this interconnected system, system 
operators, whose decisions, protocols, and actions, to a significant 
extent, dictate the operations of individual EGUs and large ensembles 
of EGUs, must reliably balance supply and demand using available 
generation and demand-side resources, including EE, demand response and 
a wide range of low- and zero-emitting sources. These resources are 
managed to meet the system needs in a reliable and efficient manner. 
Each aspect of this interconnected system is highly regulated and 
coordinated, with supply and demand constantly being balanced to meet 
system needs. Each step of the process from the electric generator to 
the end user is highly regulated by multiple entities working in 
coordination and considering overall system reliability. For example, 
in an independent system operator (ISO) or regional transmission 
organization (RTO) with a centralized, organized capacity market, 
electric generators are paid to be available to run when needed, must 
bid into energy markets, must respond to dispatch instructions, and 
must have permission to schedule maintenance. The ISO/RTO dispatches 
resources in a way that maintains electric system reliability.
    The approach we take in the final guidelines--both in the way we 
defined the BSER and established the resulting emission performance 
rates, and in the ranges of options we created for states

[[Page 64678]]

and affected EGUs--is consistent with, and in some ways mirrors, the 
interconnected, interdependent and highly regulated nature of the 
utility power sector, the daily operation of affected EGUs within this 
framework, and the critical role of utilities in providing reliable, 
affordable electricity at all times and in all places within this 
complex, regulated system. Thus, not only do these guidelines put a 
premium on providing as much flexibility and latitude as possible for 
states and utilities, they also recognize that a given EGU's operations 
are determined by the availability and use of other generation 
resources to which it is physically connected and by the collective 
operating regime that integrates that individual EGU's activity with 
other resources across the grid.
    In this integrated system, numerous entities have both the 
capability and the responsibility to maintain a reliable electric 
system. FERC, DOE, state public utility commissions, ISOs, RTOs, other 
planning authorities, and the North American Electric Reliability 
Corporation (NERC), all contribute to ensuring the reliability of the 
electric system in the U.S. Critical to this function are dispatch 
tools, applied primarily by RTOs, ISOs, and balancing authorities, that 
operate such that actions taken or costs incurred at one source 
directly affect or cause actions to occur at other sources. Generation, 
outages, and transmission changes in one part of the synchronous grid 
can affect the entire interconnected grid.\22\ The interconnection is 
such that ``[i]f a generator is lost in New York City, its effect is 
felt in Georgia, Florida, Minneapolis, St. Louis, and New Orleans.'' 
\23\ The U.S. Supreme Court has explicitly recognized the 
interconnected nature of the electricity grid.\24\
---------------------------------------------------------------------------

    \22\ Casazza, J. and Delea, F., Understanding Electric Power 
Systems, IEEE Press, at 159 (2d ed. 2010).
    \23\ Casazza, J. and Delea, F., Understanding Electric Power 
Systems, IEEE Press, at 160 (2d ed. 2010).
    \24\ Federal Power Comm'n v. Florida Power & Light Co., 404 U.S. 
453, at 460 (1972) (quoting a Federal Power Commission hearing 
examiner, `` `If a housewife in Atlanta on the Georgia system turns 
on a light, every generator on Florida's system almost instantly is 
caused to produce some quantity of additional electric energy which 
serves to maintain the balance in the interconnected system between 
generation and load.' '') (citation omitted). See also New York v. 
FERC, 535 U.S. 1, at 7-8 (2002) (stating that ``any electricity that 
enters the grid immediately becomes a part of a vast pool of energy 
that is constantly moving in interstate commerce.'') (citation 
omitted). In Federal Power Comm'n v. Southern California Edison Co., 
376 U.S. 205 (1964), the Supreme Court found that a sale for resale 
of electricity from Southern California Edison to the City of 
Colton, which took place solely in California, was under Federal 
Power Commission jurisdiction because some of the electricity that 
Southern California Edison marketed came from out of state. The 
Supreme Court stated that, `` `federal jurisdiction was to follow 
the flow of electric energy, an engineering and scientific, rather 
than a legalistic or governmental, test.' '' Id. at 210, quoting 
Connecticut Light & Power Co. v. Federal Power Commission, 324 U.S. 
515, 529 (1945) (emphasis omitted).
---------------------------------------------------------------------------

    The uniqueness of the utility power sector inevitably affects the 
way in which environmental regulations are designed. When the EPA 
promulgates environmental regulations that affect the utility power 
sector, as we have done numerous times over the past four decades, we 
do so with the awareness of the importance of the efficient and 
continuous, uninterrupted operation of the interconnected electricity 
system in which EGUs participate. We also keep in mind the unique 
product that this interconnected system provides--electricity 
services--and the critical role of this sector to the U.S. economy and 
to the fundamental well-being of all Americans.
    In the context of environmental regulation, Congress, the EPA and 
the states all have recognized--as we do in these final guidelines--
that electricity production takes place, at least to some extent, 
interchangeably between and among multiple generation facilities and 
different types of generation. This is evidenced in the enactment or 
promulgation of pollution reduction programs, such as Title IV of the 
CAA, the NOX state implementation plan (SIP) Call, the 
Cross-State Air Pollution Rule (CSAPR), and the Regional Greenhouse Gas 
Initiative (RGGI). As these actions show, both Congress and the EPA 
have consistently tailored legislation and regulations affecting the 
utility power sector to its unique characteristics. For example, in 
Title IV of the Clean Air Act Amendments of 1990, Congress established 
a pollution reduction program specifically for fossil fuel-fired EGUs 
and designed the SO2 portion of that program with express 
recognition of the sector's ability to shift generation among various 
EGUs, which enabled pollution reduction by increasing reliance on 
natural gas-fired units and RE. Similarly, in the NOX SIP 
Call, the Clean Air Interstate Rule (CAIR), and CSAPR, the EPA 
established pollution reduction programs focused on fossil fuel-fired 
EGUs and designed those programs with express recognition of the 
sector's ability to shift generation among various EGUs. In this 
action, we continue that approach. Both the subcategory-specific 
emission performance rates, and the pathways offered to achieve them, 
reflect and are tailored to the unique characteristics of the utility 
power sector.
    The way that power is produced, distributed and used in the U.S. is 
already changing as a result of advancements in innovative power sector 
technologies and in the availability and cost of low-carbon fuel, RE 
and demand-side EE technologies, as well as economic conditions. These 
changes are taking place at a time when the average age of the coal-
fired generating fleet is approaching that at which utilities and 
states undertake significant new investments to address aging assets. 
In 2025, the average age of the coal-fired generating fleet is 
projected to be 49 years old, and 20 percent of those units would be 
more than 60 years old if they remain in operation at that time. 
Therefore, even in the absence of additional environmental regulation, 
states and utilities can be expected to be, and already are, making 
plans for and investing in the next generation of power production, 
simply because of the need to take account of the age of current assets 
and infrastructure. Historically, the industry has invested about $100 
billion a year in capital improvements. These guidelines will help 
ensure that, as those necessary investments are being made, they are 
integrated with the need to address GHG pollution from the sector.
    At the same time, owners/operators of affected EGUs are already 
pursuing the types of measures contemplated in this rule. Out of 404 
entities identified as owners or operators of affected EGUs, 
representing ownership of 82 percent of the total capacity of the 
affected EGUs, 178 already own RE generating capacity in addition to 
fossil fuel-fired generating capacity. In fact, these entities already 
own aggregate amounts of RE generating capacity equal to 25 percent of 
the aggregate amounts of their affected EGU capacity.\25\ In addition, 
funding for utility EE programs has been growing rapidly, increasing 
from $1.6 billion in 2006 to $6.3 billion in 2013.
---------------------------------------------------------------------------

    \25\ SNL Energy. Data used with permission. Accessed on June 9, 
2015.
---------------------------------------------------------------------------

    The final guidelines are based on, and reinforce, the actions 
already being taken by states and utilities to upgrade aging 
electricity infrastructure with 21st century technologies. The 
guidelines will ensure that these trends continue in ways that are 
consistent with the long-term planning and investment processes already 
used in the utility power sector. This final rule provides flexibility 
for states to build upon their progress, and the progress of cities and 
towns, in addressing GHGs, and minimizes

[[Page 64679]]

additional requirements for existing programs where possible. It also 
allows states to pursue policies to reduce carbon pollution that: (1) 
Continue to rely on a diverse set of energy resources; (2) ensure 
electric system reliability; (3) provide affordable electricity; (4) 
recognize investments that states and power companies are already 
making; and (5) tailor plans to meet their respective energy, 
environmental and economic needs and goals, and those of their local 
communities. Thus, the final guidelines will achieve meaningful 
CO2 emission reductions while maintaining the reliability 
and affordability of electricity in the U.S.
6. Projected National-Level Emission Reductions
    Under the final guidelines, the EPA projects annual CO2 
reductions of 22 to 23 percent below 2005 levels in 2020, 28 to 29 
percent below 2005 levels in 2025, and 32 percent below 2005 levels in 
2030. These guidelines will also result in important reductions in 
emissions of criteria air pollutants, including SO2, 
NOX, and directly-emitted fine particulate matter 
(PM2.5). A thorough discussion of the EPA's analysis is 
presented in Section XI.A of this preamble and in Chapter 3 of the 
Regulatory Impact Analysis (RIA) included in the docket for this 
rulemaking.
7. Costs and Benefits
    Actions taken to comply with the final guidelines will reduce 
emissions of CO2 and other air pollutants, including 
SO2, NOX, and directly emitted PM2.5 
from the utility power sector. States will make the ultimate 
determination as to how the emission guidelines are implemented. Thus, 
all costs and benefits reported for this action are illustrative 
estimates. The illustrative costs and benefits are based upon 
compliance approaches that reflect a range of measures consisting of 
improved operations at EGUs, dispatching lower-emitting EGUs and zero-
emitting energy sources, and increasing levels of end-use EE.
    Because of the range of choices available to states and the lack of 
a priori knowledge about the specific choices states will make in 
response to the final goals, the RIA for this final action presents two 
scenarios designed to achieve these goals, which we term the ``rate-
based'' illustrative plan approach and the ``mass-based'' illustrative 
plan approach.
    In summary, we estimate the total combined climate benefits and 
health co-benefits for the rate-based approach to be $3.5 to $4.6 
billion in 2020, $18 to $28 billion in 2025, and $34 to $54 billion in 
2030 (3 percent discount rate, 2011$). Total combined climate benefits 
and health co-benefits for the mass-based approach are estimated to be 
$5.3 to $8.1 billion in 2020, $19 to $29 billion in 2025, and $32 to 
$48 billion in 2030 (3 percent discount rate, 2011$). A summary of the 
emission reductions and monetized benefits estimated for this rule at 
all discount rates is provided in Tables 15 through 22 of this 
preamble.
    The annual compliance costs are estimated using the Integrated 
Planning Model (IPM) and include demand-side EE program and participant 
costs as well as monitoring, reporting and recordkeeping costs. In 
2020, total compliance costs of the final guidelines are approximately 
$2.5 billion (2011$) under the rate-based approach and $1.4 billion 
(2011$) under the mass-based approach. In 2025, total compliance costs 
of the final guidelines are approximately $1.0 billion (2011$) under 
the rate-based approach and $3.0 billion (2011$) under the mass-based 
approach. In 2030, total compliance costs of the final guidelines are 
approximately $8.4 billion (2011$) under the rate-based approach and 
$5.1 billion (2011$) under the mass-based approach.
    The quantified net benefits (the difference between monetized 
benefits and compliance costs) in 2020 are estimated to range from $1.0 
billion to $2.1 billion (2011$) using a 3 percent discount rate (model 
average) under the rate-based approach and from $3.9 billion to $6.7 
billion (2011$) using a 3 percent discount rate (model average) under 
the mass-based approach. In 2025, the quantified net benefits (the 
difference between monetized benefits and compliance costs) in 2025 are 
estimated to range from $17 billion to $27 billion (2011$) using a 3 
percent discount rate (model average) under the rate-based approach and 
from $16 billion to $26 billion (2011$) using a 3 percent discount rate 
(model average) under the mass-based approach. In 2030, the quantified 
net benefits (the difference between monetized benefits and compliance 
costs) in 2030 are estimated to range from $26 billion to $45 billion 
(2011$) using a 3 percent discount rate (model average) under the rate-
based approach and from $26 billion to $43 billion (2011$) using a 3 
percent discount rate (model average) under the mass-based approach.

[[Page 64680]]



  Table 1--Summary of the Monetized Benefits, Compliance Costs, and Net
 Benefits for the Final Guidelines in 2020, 2025, and 2030 \a\ Under the
                  Rate-Based Illustrative Plan Approach
                           [Billions of 2011$]
------------------------------------------------------------------------
                        Rate-based approach, 2020
-------------------------------------------------------------------------
                                 3% Discount rate     7% Discount rate
------------------------------------------------------------------------
Climate benefits b............                    $2.8
------------------------------------------------------------------------
Air pollution health co-        $0.70 to $1.8....  $0.64 to $1.7.
 benefits c.
Total Compliance Costs d......  $2.5.............  $2.5.
Net Monetized Benefits e......  $1.0 to $2.1.....  $1.0 to $2.0.
                               -----------------------------------------
Non-monetized Benefits........  Non-monetized climate benefits.
                                Reductions in exposure to ambient NO2
                                 and SO2.
                                Reductions in mercury deposition.
                                Ecosystem benefits associated with
                                 reductions in emissions of NOX, SO2,
                                 PM, and mercury.
                                Visibility impairment.
------------------------------------------------------------------------
                        Rate-based approach, 2025
------------------------------------------------------------------------
Climate benefits b............                     $10
------------------------------------------------------------------------
Air pollution health co-        $7.4 to $18......  $6.7 to $16.
 benefits c.
Total Compliance Costs d......  $1.0.............  $1.0.
Net Monetized Benefits e......  $17 to $27.......  $16 to $25.
------------------------------------------------------------------------
Non-monetized Benefits........  Non-monetized climate benefits.
                                Reductions in exposure to ambient NO2
                                 and SO2.
                                Reductions in mercury deposition.
                                Ecosystem benefits associated with
                                 reductions in emissions of NOX, SO2,
                                 PM, and mercury.
                                Visibility impairment.
------------------------------------------------------------------------
                        Rate-based approach, 2030
------------------------------------------------------------------------
Climate benefits b............  $20
------------------------------------------------------------------------
Air pollution health co-        $14 to $34.......  $13 to $31.
 benefits c.
Total Compliance Costs d......  $8.4.............  $8.4.
Net Monetized Benefits e......  $26 to $45.......  $25 to $43.
------------------------------------------------------------------------
Non-monetized Benefits........  Non-monetized climate benefits.
                                Reductions in exposure to ambient NO2
                                 and SO2.
                                Reductions in mercury deposition.
                                Ecosystem benefits associated with
                                 reductions in emissions of NOX, SO2,
                                 PM, and mercury.
                                Visibility impairment.
------------------------------------------------------------------------
\a\ All are rounded to two significant figures, so figures may not sum.
\b\ The climate benefit estimate in this summary table reflects global
  impacts from CO2 emission changes and does not account for changes in
  non-CO2 GHG emissions. Also, different discount rates are applied to
  SC-CO2 than to the other estimates because CO2 emissions are long-
  lived and subsequent damages occur over many years. The benefit
  estimates in this table are based on the average SCC estimated for a 3
  percent discount rate, however we emphasize the importance and value
  of considering the full range of SC-CO2 values. As shown in the RIA,
  climate benefits are also estimated using the other three SC-CO2
  estimates (model average at 2.5 percent discount rate, 3 percent, and
  5 percent; 95th percentile at 3 percent). The SC-CO2 estimates are
  year-specific and increase over time.
\c\ The air pollution health co-benefits reflect reduced exposure to
  PM2.5 and ozone associated with emission reductions of directly
  emitted PM2.5, SO2 and NOX. The range reflects the use of
  concentration-response functions from different epidemiology studies.
  The reduction in premature fatalities each year accounts for over 98
  percent of total monetized co-benefits from PM2.5 and ozone. These
  models assume that all fine particles, regardless of their chemical
  composition, are equally potent in causing premature mortality because
  the scientific evidence is not yet sufficient to allow differentiation
  of effect estimates by particle type.
\d\ Total costs are approximated by the illustrative compliance costs
  estimated using the Integrated Planning Model for the final guidelines
  and a discount rate of approximately 5%. This estimate includes
  monitoring, recordkeeping, and reporting costs and demand-side EE
  program and participant costs.
\e\ The estimates of net benefits in this summary table are calculated
  using the global SC-CO2 at a 3 percent discount rate (model average).
  The RIA includes combined climate and health estimates based on
  additional discount rates.


[[Page 64681]]


  Table 2--Summary of the Monetized Benefits, Compliance Costs, and Net
  Benefits for the Final Guidelines in 2020, 2025 and 2030 a Under the
                  Mass-Based Illustrative Plan Approach
                           [Billions of 2011$]
------------------------------------------------------------------------
                        Mass-based approach, 2020
-------------------------------------------------------------------------
                                 3% Discount rate     7% Discount rate
------------------------------------------------------------------------
Climate benefits b............                    $3.3
------------------------------------------------------------------------
Air pollution health co-        $2.0 to $4.8.....  $1.8 to $4.4.
 benefits c.
Total Compliance Costs d......  $1.4.............  $1.4.
Net Monetized Benefits e......  $3.9 to $6.7.....  $3.7 to $6.3.
------------------------------------------------------------------------
Non-monetized Benefits........  Non-monetized climate benefits.
                                Reductions in exposure to ambient NO2
                                 and SO2.
                                Reductions in mercury deposition.
                                Ecosystem benefits associated with
                                 reductions in emissions of NOX, SO2,
                                 PM, and mercury.
                                Visibility impairment.
------------------------------------------------------------------------
                        Mass-based approach, 2025
------------------------------------------------------------------------
      Climate benefits b                           $12
------------------------------------------------------------------------
Air pollution health co-        $7.1 to $17......  $6.5 to $16.
 benefits c.
Total Compliance Costs d......  $3.0.............  $3.0.
Net Monetized Benefits e......  $16 to $26.......  $15 to $24.
------------------------------------------------------------------------
Non-monetized Benefits........  Non-monetized climate benefits.
                                Reductions in exposure to ambient NO2
                                 and SO2.
                                Reductions in mercury deposition.
                                Ecosystem benefits associated with
                                 reductions in emissions of NOX, SO2,
                                 PM, and mercury.
                                Visibility impairment.
------------------------------------------------------------------------
                        Mass-based approach, 2030
------------------------------------------------------------------------
Climate benefits b............                     $20
------------------------------------------------------------------------
Air pollution health co-        $12 to $28.......  $11 to $26.
 benefits c.
Total Compliance Costs d......  $5.1.............  $5.1.
Net Monetized Benefits e......  $26 to $43.......  $25 to $40.
------------------------------------------------------------------------
Non-monetized Benefits........  Non-monetized climate benefits.
                                Reductions in exposure to ambient NO2
                                 and SO2.
                                Reductions in mercury deposition.
                                Ecosystem benefits associated with
                                 reductions in emissions of NOX, SO2,
                                 PM, and mercury.
                                Visibility impairment.
------------------------------------------------------------------------
a All are rounded to two significant figures, so figures may not sum.
b The climate benefit estimate in this summary table reflects global
  impacts from CO2 emission changes and does not account for changes in
  non-CO2 GHG emissions. Also, different discount rates are applied to
  SC-CO2 than to the other estimates because CO2 emissions are long-
  lived and subsequent damages occur over many years. The benefit
  estimates in this table are based on the average SC-CO2 estimated for
  a 3 percent discount rate, however we emphasize the importance and
  value of considering the full range of SC-CO2 values. As shown in the
  RIA, climate benefits are also estimated using the other three SC-CO2
  estimates (model average at 2.5 percent discount rate, 3 percent, and
  5 percent; 95th percentile at 3 percent). The SC-CO2 estimates are
  year-specific and increase over time.
c The air pollution health co-benefits reflect reduced exposure to PM2.5
  and ozone associated with emission reductions of directly emitted
  PM2.5, SO2 and NOX. The range reflects the use of concentration-
  response functions from different epidemiology studies. The reduction
  in premature fatalities each year accounts for over 98 percent of
  total monetized co-benefits from PM2.5 and ozone. These models assume
  that all fine particles, regardless of their chemical composition, are
  equally potent in causing premature mortality because the scientific
  evidence is not yet sufficient to allow differentiation of effect
  estimates by particle type.
d Total costs are approximated by the illustrative compliance costs
  estimated using the Integrated Planning Model for the final guidelines
  and a discount rate of approximately 5 percent. This estimate includes
  monitoring, recordkeeping, and reporting costs and demand-side EE
  program and participant costs.
e The estimates of net benefits in this summary table are calculated
  using the global SC-CO2 at a 3 percent discount rate (model average).
  The RIA includes combined climate and health estimates based on
  additional discount rates.


[[Page 64682]]

    There are additional important benefits that the EPA could not 
monetize. Due to current data and modeling limitations, our estimates 
of the benefits from reducing CO2 emissions do not include 
important impacts like ocean acidification or potential tipping points 
in natural or managed ecosystems. The unquantified benefits also 
include climate benefits from reducing emissions of non-CO2 
GHGs (e.g., nitrous oxide and methane) \26\ and co-benefits from 
reducing direct exposure to SO2, NOX, and HAP 
(e.g., mercury and hydrogen chloride), as well as from reducing 
ecosystem effects and visibility impairment.
---------------------------------------------------------------------------

    \26\ Although CO2 is the predominant greenhouse gas 
released by the power sector, electricity generating units also emit 
small amounts of nitrous oxide and methane. For more detail about 
power sector emissions, see RIA Chapter 2 and the U.S. Greenhouse 
Gas Reporting Program's power sector summary, http://www.epa.gov/ghgreporting/ghgdata/reported/powerplants.html.
---------------------------------------------------------------------------

    We project employment gains and losses relative to base case for 
different types of labor, including construction, plant operation and 
maintenance, coal and natural gas production, and demand-side EE. In 
2030, we project a net decrease in job-years of about 31,000 under the 
rate-based approach and 34,000 under the mass-based approach \27\ for 
construction, plant operation and maintenance, and coal and natural gas 
and a gain of 52,000 to 83,000 jobs in the demand-side EE sector under 
either approach. Actual employment impacts will depend upon measures 
taken by states in their state plans and the specific actions sources 
take to comply.
---------------------------------------------------------------------------

    \27\ A job-year is not an individual job; rather, a job-year is 
the amount of work performed by the equivalent of one full-time 
individual for one year. For example, 20 job-years in 2025 may 
represent 20 full-time jobs or 40 half-time jobs.
---------------------------------------------------------------------------

    Based upon the foregoing, it is clear that the monetized benefits 
of this rule are substantial and far outweigh the costs.

B. Organization and Approach for This Rule

    This final rule establishes the EPA's emission guidelines for 
states to follow in developing plans to reduce CO2 emissions 
from the utility power sector. Section II of this preamble provides 
background information on climate change impacts from GHG emissions, 
GHG emissions from fossil fuel-fired EGUs, the utility power sector, 
the CAA section 111(d) requirements, EPA actions prior to this final 
action, outreach and consultations, and the number and extent of 
comments received. In section III of the preamble, we present a summary 
of the rule requirements and the legal basis for these. Section IV 
explains the EPA authority to regulate CO2 and EGUs, 
identifies affected EGUs, and describes the proposed treatment of 
source categories. Section V describes the agency's determination of 
the BSER using three building blocks and our key considerations in 
making the determination. Section VI provides the subcategory-specific 
emission performance rates, and section VII provides equivalent 
statewide rate-based and mass-based goals. Section VIII then describes 
state plan approaches and the requirements, and flexibilities, for 
state plans, followed by section IX, in which considerations for 
communities are described. Interactions between this final rule and 
other EPA programs and rules are discussed in section X. Impacts of the 
proposed action are then described in section XI, followed by a 
discussion of statutory and executive order reviews in section XII and 
the statutory authority for this action in section XIII.
    We note that this rulemaking is being promulgated concurrently with 
two related actions in this issue of the Federal Register: The final 
NSPS for CO2 emissions from newly constructed, modified, and 
reconstructed EGUs, which is being promulgated under CAA section 
111(b), and the proposed federal plan and model rules. These 
rulemakings have their own rulemaking dockets.

II. Background

    In this section, we discuss climate change impacts from GHG 
emissions, both on public health and public welfare. We also present 
information about GHG emissions from fossil fuel-fired EGUs, the 
challenges associated with controlling carbon dioxide emissions, the 
uniqueness of the utility power sector, and recent and continuing 
trends and transitions in the utility power sector. In addition, we 
briefly describe CAA regulations for power plants, provide highlights 
of Congressional awareness of climate change and international 
agreements and actions, and summarize statutory and regulatory 
requirements relevant to this rulemaking. In addition, we provide 
background information on the EPA's June 18, 2014 Clean Power Plan 
proposal, the November 4, 2014 supplemental proposal, and other actions 
associated with this rulemaking,\28\ followed by information on 
stakeholder outreach and consultations and the comments that the EPA 
received prior to issuing this final rulemaking.
---------------------------------------------------------------------------

    \28\ The EPA also published in the Federal Register a notice of 
data availability (79 FR 64543; November 8, 2014) and a notice on 
the translation of emission rate-based CO2 goals to mass-
based equivalents (79 FR 67406; November 13, 2014).
---------------------------------------------------------------------------

A. Climate Change Impacts From GHG Emissions

    According to the National Research Council, ``Emissions of 
CO2 from the burning of fossil fuels have ushered in a new 
epoch where human activities will largely determine the evolution of 
Earth's climate. Because CO2 in the atmosphere is long 
lived, it can effectively lock Earth and future generations into a 
range of impacts, some of which could become very severe. Therefore, 
emission reduction choices made today matter in determining impacts 
experienced not just over the next few decades, but in the coming 
centuries and millennia.'' \29\
---------------------------------------------------------------------------

    \29\ National Research Council, Climate Stabilization Targets, 
p.3.
---------------------------------------------------------------------------

    In 2009, based on a large body of robust and compelling scientific 
evidence, the EPA Administrator issued the Endangerment Finding under 
CAA section 202(a)(1).\30\ In the Endangerment Finding, the 
Administrator found that the current, elevated concentrations of GHGs 
in the atmosphere--already at levels unprecedented in human history--
may reasonably be anticipated to endanger public health and welfare of 
current and future generations in the U.S. We summarize these adverse 
effects on public health and welfare briefly here.
---------------------------------------------------------------------------

    \30\ ``Endangerment and Cause or Contribute Findings for 
Greenhouse Gases Under Section 202(a) of the Clean Air Act,'' 74 FR 
66496 (Dec. 15, 2009) (``Endangerment Finding'').
---------------------------------------------------------------------------

1. Public Health Impacts Detailed in the 2009 Endangerment Finding
    Climate change caused by human emissions of GHGs threatens the 
health of Americans in multiple ways. By raising average temperatures, 
climate change increases the likelihood of heat waves, which are 
associated with increased deaths and illnesses. While climate change 
also increases the likelihood of reductions in cold-related mortality, 
evidence indicates that the increases in heat mortality will be larger 
than the decreases in cold mortality in the U.S. Compared to a future 
without climate change, climate change is expected to increase ozone 
pollution over broad areas of the U.S., especially on the highest ozone 
days and in the largest metropolitan areas with the worst ozone 
problems, and thereby increase the risk of morbidity and mortality. 
Climate change is also

[[Page 64683]]

expected to cause more intense hurricanes and more frequent and intense 
storms and heavy precipitation, with impacts on other areas of public 
health, such as the potential for increased deaths, injuries, 
infectious and waterborne diseases, and stress-related disorders. 
Children, the elderly, and the poor are among the most vulnerable to 
these climate-related health effects.
2. Public Welfare Impacts Detailed in the 2009 Endangerment Finding
    Climate change impacts touch nearly every aspect of public welfare. 
Among the multiple threats caused by human emissions of GHGs, climate 
changes are expected to place large areas of the country at serious 
risk of reduced water supplies, increased water pollution, and 
increased occurrence of extreme events such as floods and droughts. 
Coastal areas are expected to face a multitude of increased risks, 
particularly from rising sea level and increases in the severity of 
storms. These communities face storm and flooding damage to property, 
or even loss of land due to inundation, erosion, wetland submergence 
and habitat loss.
    Impacts of climate change on public welfare also include threats to 
social and ecosystem services. Climate change is expected to result in 
an increase in peak electricity demand. Extreme weather from climate 
change threatens energy, transportation, and water resource 
infrastructure. Climate change may also exacerbate ongoing 
environmental pressures in certain settlements, particularly in Alaskan 
indigenous communities, and is very likely to fundamentally rearrange 
U.S. ecosystems over the 21st century. Though some benefits may balance 
adverse effects on agriculture and forestry in the next few decades, 
the body of evidence points towards increasing risks of net adverse 
impacts on U.S. food production, agriculture and forest productivity as 
temperature continues to rise. These impacts are global and may 
exacerbate problems outside the U.S. that raise humanitarian, trade, 
and national security issues for the U.S.
3. New Scientific Assessments and Observations
    Since the administrative record concerning the Endangerment Finding 
closed following the EPA's 2010 Reconsideration Denial, the climate has 
continued to change, with new records being set for a number of climate 
indicators such as global average surface temperatures, Arctic sea ice 
retreat, CO2 concentrations, and sea level rise. 
Additionally, a number of major scientific assessments have been 
released that improve understanding of the climate system and 
strengthen the case that GHGs endanger public health and welfare both 
for current and future generations. These assessments, from the 
Intergovernmental Panel on Climate Change (IPCC), the U.S. Global 
Change Research Program (USGCRP), and the National Research Council 
(NRC), include: IPCC's 2012 Special Report on Managing the Risks of 
Extreme Events and Disasters to Advance Climate Change Adaptation 
(SREX) and the 2013-2014 Fifth Assessment Report (AR5), the USGCRP's 
2014 National Climate Assessment, Climate Change Impacts in the United 
States (NCA3), and the NRC's 2010 Ocean Acidification: A National 
Strategy to Meet the Challenges of a Changing Ocean (Ocean 
Acidification), 2011 Report on Climate Stabilization Targets: 
Emissions, Concentrations, and Impacts over Decades to Millennia 
(Climate Stabilization Targets), 2011 National Security Implications 
for U.S. Naval Forces (National Security Implications), 2011 
Understanding Earth's Deep Past: Lessons for Our Climate Future 
(Understanding Earth's Deep Past), 2012 Sea Level Rise for the Coasts 
of California, Oregon, and Washington: Past, Present, and Future, 2012 
Climate and Social Stress: Implications for Security Analysis (Climate 
and Social Stress), and 2013 Abrupt Impacts of Climate Change (Abrupt 
Impacts) assessments.
    The EPA has carefully reviewed these recent assessments in keeping 
with the same approach outlined in Section VIII.A of the 2009 
Endangerment Finding, which was to rely primarily upon the major 
assessments by the USGCRP, the IPCC, and the NRC of the National 
Academies to provide the technical and scientific information to inform 
the Administrator's judgment regarding the question of whether GHGs 
endanger public health and welfare. These assessments addressed the 
scientific issues that the EPA was required to examine, were 
comprehensive in their coverage of the GHG and climate change issues, 
and underwent rigorous and exacting peer review by the expert 
community, as well as rigorous levels of U.S. government review.
    The findings of the recent scientific assessments confirm and 
strengthen the conclusion that GHGs endanger public health, now and in 
the future. The NCA3 indicates that human health in the U.S. will be 
impacted by ``increased extreme weather events, wildfire, decreased air 
quality, threats to mental health, and illnesses transmitted by food, 
water, and disease-carriers such as mosquitoes and ticks.'' The most 
recent assessments now have greater confidence that climate change will 
influence production of pollen that exacerbates asthma and other 
allergic respiratory diseases such as allergic rhinitis, as well as 
effects on conjunctivitis and dermatitis. Both the NCA3 and the IPCC 
AR5 found that increasing temperature has lengthened the allergenic 
pollen season for ragweed, and that increased CO2 by itself 
can elevate production of plant-based allergens.
    The NCA3 also finds that climate change, in addition to chronic 
stresses such as extreme poverty, is negatively affecting indigenous 
peoples' health in the U.S. through impacts such as reduced access to 
traditional foods, decreased water quality, and increasing exposure to 
health and safety hazards. The IPCC AR5 finds that climate change-
induced warming in the Arctic and resultant changes in environment 
(e.g., permafrost thaw, effects on traditional food sources) have 
significant impacts, observed now and projected, on the health and 
well-being of Arctic residents, especially indigenous peoples. Small, 
remote, predominantly-indigenous communities are especially vulnerable 
given their ``strong dependence on the environment for food, culture, 
and way of life; their political and economic marginalization; existing 
social, health, and poverty disparities; as well as their frequent 
close proximity to exposed locations along ocean, lake, or river 
shorelines.'' \31\ In addition, increasing temperatures and loss of 
Arctic sea ice increases the risk of drowning for those engaged in 
traditional hunting and fishing.
---------------------------------------------------------------------------

    \31\ IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and 
Vulnerability. Part B: Regional Aspects. Contribution of Working 
Group II to the Fifth Assessment Report of the Intergovernmental 
Panel on Climate Change [Barros, V.R., C.B. Field, D.J. Dokken, M.D. 
Mastrandrea, K.J. Mach, T.E. Bilir, M. Chatterjee, K.L. Ebi, Y.O. 
Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. Levy, S. 
MacCracken, P.R. Mastrandrea, and L.L. White (eds.)]. Cambridge 
University Press, Cambridge, p. 1581. https://www.ipcc.ch/report/ar5/wg2/.
---------------------------------------------------------------------------

    The NCA3 concludes that children's unique physiology and developing 
bodies contribute to making them particularly vulnerable to climate 
change. Impacts on children are expected from heat waves, air 
pollution, infectious and waterborne illnesses, and mental health 
effects resulting from extreme weather events. The IPCC AR5 indicates 
that children are among those especially susceptible to most allergic 
diseases, as well as health effects

[[Page 64684]]

associated with heat waves, storms, and floods. The IPCC finds that 
additional health concerns may arise in low income households, 
especially those with children, if climate change reduces food 
availability and increases prices, leading to food insecurity within 
households.
    Both the NCA3 and IPCC AR5 conclude that climate change will 
increase health risks facing the elderly. Older people are at much 
higher risk of mortality during extreme heat events. Pre-existing 
health conditions also make older adults susceptible to cardiac and 
respiratory impacts of air pollution and to more severe consequences 
from infectious and waterborne diseases. Limited mobility among older 
adults can also increase health risks associated with extreme weather 
and floods.
    The new assessments also confirm and strengthen the conclusion that 
GHGs endanger public welfare, and emphasize the urgency of reducing GHG 
emissions due to their projections that show GHG concentrations 
climbing to ever-increasing levels in the absence of mitigation. The 
NRC assessment Understanding Earth's Deep Past projected that, without 
a reduction in emissions, CO2 concentrations by the end of 
the century would increase to levels that the Earth has not experienced 
for more than 30 million years.\32\ In fact, that assessment stated 
that ``the magnitude and rate of the present GHG increase place the 
climate system in what could be one of the most severe increases in 
radiative forcing of the global climate system in Earth history.'' \33\ 
Because of these unprecedented changes, several assessments state that 
we may be approaching critical, poorly understood thresholds. As stated 
in the assessment, ``As Earth continues to warm, it may be approaching 
a critical climate threshold beyond which rapid and potentially 
permanent--at least on a human timescale--changes not anticipated by 
climate models tuned to modern conditions may occur.'' The NRC Abrupt 
Impacts report analyzed abrupt climate change in the physical climate 
system and abrupt impacts of ongoing changes that, when thresholds are 
crossed, can cause abrupt impacts for society and ecosystems. The 
report considered destabilization of the West Antarctic Ice Sheet 
(which could cause 3-4 m of potential sea level rise) as an abrupt 
climate impact with unknown but probably low probability of occurring 
this century. The report categorized a decrease in ocean oxygen content 
(with attendant threats to aerobic marine life); increase in intensity, 
frequency, and duration of heat waves; and increase in frequency and 
intensity of extreme precipitation events (droughts, floods, 
hurricanes, and major storms) as climate impacts with moderate risk of 
an abrupt change within this century. The NRC Abrupt Impacts report 
also analyzed the threat of rapid state changes in ecosystems and 
species extinctions as examples of an irreversible impact that is 
expected to be exacerbated by climate change. Species at most risk 
include those whose migration potential is limited, whether because 
they live on mountaintops or fragmented habitats with barriers to 
movement, or because climatic conditions are changing more rapidly than 
the species can move or adapt. While the NRC determined that it is not 
presently possible to place exact probabilities on the added 
contribution of climate change to extinction, they did find that there 
was substantial risk that impacts from climate change could, within a 
few decades, drop the populations in many species below sustainable 
levels thereby committing the species to extinction. Species within 
tropical and subtropical rainforests such as the Amazon and species 
living in coral reef ecosystems were identified by the NRC as being 
particularly vulnerable to extinction over the next 30 to 80 years, as 
were species in high latitude and high elevation regions. Moreover, due 
to the time lags inherent in the Earth's climate, the NRC Climate 
Stabilization Targets assessment notes that the full warming from any 
given concentration of CO2 reached will not be fully 
realized for several centuries, underscoring that emission activities 
today carry with them climate commitments far into the future.
---------------------------------------------------------------------------

    \32\ National Research Council, Understanding Earth's Deep Past, 
p. 1.
    \33\ Id., p.138.
---------------------------------------------------------------------------

    Future temperature changes will depend on what emission path the 
world follows. In its high emission scenario, the IPCC AR5 projects 
that global temperatures by the end of the century will likely be 2.6 
[deg]C to 4.8 [deg]C (4.7 to 8.6[emsp14][deg]F) warmer than today. 
Temperatures on land and in northern latitudes will likely warm even 
faster than the global average. However, according to the NCA3, 
significant reductions in emissions would lead to noticeably less 
future warming beyond mid-century, and therefore less impact to public 
health and welfare.
    While rainfall may only see small globally and annually averaged 
changes, there are expected to be substantial shifts in where and when 
that precipitation falls. According to the NCA3, regions closer to the 
poles will see more precipitation, while the dry subtropics are 
expected to expand (colloquially, this has been summarized as wet areas 
getting wetter and dry regions getting drier). In particular, the NCA3 
notes that the western U.S., and especially the Southwest, is expected 
to become drier. This projection is consistent with the recent observed 
drought trend in the West. At the time of publication of the NCA, even 
before the last 2 years of extreme drought in California, tree ring 
data was already indicating that the region might be experiencing its 
driest period in 800 years. Similarly, the NCA3 projects that heavy 
downpours are expected to increase in many regions, with precipitation 
events in general becoming less frequent but more intense. This trend 
has already been observed in regions such as the Midwest, Northeast, 
and upper Great Plains. Meanwhile, the NRC Climate Stabilization 
Targets assessment found that the area burned by wildfire is expected 
to grow by 2 to 4 times for 1 [deg]C (1.8[emsp14][deg]F) of warming. 
For 3 [deg]C of warming, the assessment found that 9 out of 10 summers 
would be warmer than all but the 5 percent of warmest summers today, 
leading to increased frequency, duration, and intensity of heat waves. 
Extrapolations by the NCA also indicate that Arctic sea ice in summer 
may essentially disappear by mid-century. Retreating snow and ice, and 
emissions of carbon dioxide and methane released from thawing 
permafrost, will also amplify future warming.
    Since the 2009 Endangerment Finding, the USGCRP NCA3, and multiple 
NRC assessments have projected future rates of sea level rise that are 
40 percent larger to more than twice as large as the previous estimates 
from the 2007 IPCC 4th Assessment Report due in part to improved 
understanding of the future rate of melt of the Antarctic and Greenland 
Ice sheets. The NRC Sea Level Rise assessment projects a global sea 
level rise of 0.5 to 1.4 meters (1.6 to 4.6 feet) by 2100, the NRC 
National Security Implications assessment suggests that ``the 
Department of the Navy should expect roughly 0.4 to 2 meters [1.3 to 
6.6 feet] global average sea-level rise by 2100,'' \34\ and the NRC 
Climate Stabilization Targets assessment states that an increase of 3 
[deg]C will lead to a sea level rise of 0.5 to 1 meter (1.6 to 3.3 
feet) by 2100. These assessments continue to recognize that there is

[[Page 64685]]

uncertainty inherent in accounting for ice sheet processes. 
Additionally, local sea level rise can differ from the global total 
depending on various factors: The east coast of the U.S. in particular 
is expected to see higher rates of sea level rise than the global 
average. For comparison, the NCA3 states that ``five million Americans 
and hundreds of billions of dollars of property are located in areas 
that are less than four feet above the local high-tide level,'' and the 
NCA3 finds that ``[c]oastal infrastructure, including roads, rail 
lines, energy infrastructure, airports, port facilities, and military 
bases, are increasingly at risk from sea level rise and damaging storm 
surges.'' \35\ Also, because of the inertia of the oceans, sea level 
rise will continue for centuries after GHG concentrations have 
stabilized (though more slowly than it would have otherwise). 
Additionally, there is a threshold temperature above which the 
Greenland ice sheet will be committed to inevitable melting: According 
to the NCA, some recent research has suggested that even present day 
CO2 levels could be sufficient to exceed that threshold.
---------------------------------------------------------------------------

    \34\ NRC, 2011: National Security Implications of Climate Change 
for U.S. Naval Forces. The National Academies Press, p. 28.
    \35\ Melillo, Jerry M., Terese (T.C.) Richmond, and Gary W. 
Yohe, Eds., 2014: Climate Change Impacts in the United States: The 
Third National Climate Assessment. U.S. Global Change Research 
Program, p. 9.
---------------------------------------------------------------------------

    In general, climate change impacts are expected to be unevenly 
distributed across different regions of the U.S. and have a greater 
impact on certain populations, such as indigenous peoples and the poor. 
The NCA3 finds climate change impacts such as the rapid pace of 
temperature rise, coastal erosion and inundation related to sea level 
rise and storms, ice and snow melt, and permafrost thaw are affecting 
indigenous people in the U.S. Particularly in Alaska, critical 
infrastructure and traditional livelihoods are threatened by climate 
change and, ``[i]n parts of Alaska, Louisiana, the Pacific Islands, and 
other coastal locations, climate change impacts (through erosion and 
inundation) are so severe that some communities are already relocating 
from historical homelands to which their traditions and cultural 
identities are tied.'' \36\ The IPCC AR5 notes, ``Climate-related 
hazards exacerbate other stressors, often with negative outcomes for 
livelihoods, especially for people living in poverty (high confidence). 
Climate-related hazards affect poor people's lives directly through 
impacts on livelihoods, reductions in crop yields, or destruction of 
homes and indirectly through, for example, increased food prices and 
food insecurity.'' \37\
---------------------------------------------------------------------------

    \36\ Melillo, Jerry M., Terese (T.C.) Richmond, and Gary W. 
Yohe, Eds., 2014: Climate Change Impacts in the United States: The 
Third National Climate Assessment. U.S. Global Change Research 
Program, p. 17.
    \37\ IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and 
Vulnerability. Part A: Global and Sectoral Aspects. Contribution of 
Working Group II to the Fifth Assessment Report of the 
Intergovernmental Panel on Climate Change [Field, C.B., V.R. Barros, 
D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E. Bilir, M. Chatterjee, 
K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. 
Levy, S. MacCracken, P.R. Mastrandrea, and L.L. White (eds.)]. 
Cambridge University Press, p. 796. https://www.ipcc.ch/report/ar5/wg2/.
---------------------------------------------------------------------------

    Carbon dioxide in particular has unique impacts on ocean 
ecosystems. The NRC Climate Stabilization Targets assessment found that 
coral bleaching will increase due both to warming and ocean 
acidification. Ocean surface waters have already become 30 percent more 
acidic over the past 250 years due to absorption of CO2 from 
the atmosphere. According to the NCA3, this acidification will reduce 
the ability of organisms such as corals, krill, oysters, clams, and 
crabs to survive, grow, and reproduce. The NRC Understanding Earth's 
Deep Past assessment notes four of the five major coral reef crises of 
the past 500 million years were caused by acidification and warming 
that followed GHG increases of similar magnitude to the emissions 
increases expected over the next hundred years. The NRC Abrupt Impacts 
assessment specifically highlighted similarities between the 
projections for future acidification and warming and the extinction at 
the end of the Permian which resulted in the loss of an estimated 90 
percent of known species. Similarly, the NRC Ocean Acidification 
assessment finds that ``[t]he chemistry of the ocean is changing at an 
unprecedented rate and magnitude due to anthropogenic carbon dioxide 
emissions; the rate of change exceeds any known to have occurred for at 
least the past hundreds of thousands of years.'' \38\ The assessment 
notes that the full range of consequences is still unknown, but the 
risks ``threaten coral reefs, fisheries, protected species, and other 
natural resources of value to society.'' \39\
---------------------------------------------------------------------------

    \38\ NRC, 2010: Ocean Acidification: A National Strategy to Meet 
the Challenges of a Changing Ocean. The National Academies Press, p. 
5.
    \39\ Ibid.
---------------------------------------------------------------------------

    Events outside the U.S., as also pointed out in the 2009 
Endangerment Finding, will also have relevant consequences. The NRC 
Climate and Social Stress assessment concluded that it is prudent to 
expect that some climate events ``will produce consequences that exceed 
the capacity of the affected societies or global systems to manage and 
that have global security implications serious enough to compel 
international response.'' The NRC National Security Implications 
assessment recommends preparing for increased needs for humanitarian 
aid; responding to the effects of climate change in geopolitical 
hotspots, including possible mass migrations; and addressing changing 
security needs in the Arctic as sea ice retreats.
    In addition to future impacts, the NCA3 emphasizes that climate 
change driven by human emissions of GHGs is already happening now and 
it is happening in the U.S. According to the IPCC AR5 and the NCA3, 
there are a number of climate-related changes that have been observed 
recently, and these changes are projected to accelerate in the future. 
The planet warmed about 0.85 [deg]C (1.5 [deg]F) from 1880 to 2012. It 
is extremely likely (>95 percent probability) that human influence was 
the dominant cause of the observed warming since the mid-20th century, 
and likely (>66 percent probability) that human influence has more than 
doubled the probability of occurrence of heat waves in some locations. 
In the Northern Hemisphere, the last 30 years were likely the warmest 
30 year period of the last 1400 years. U.S. average temperatures have 
similarly increased by 1.3 to 1.9 degrees F since 1895, with most of 
that increase occurring since 1970. Global sea levels rose 0.19 m (7.5 
inches) from 1901 to 2010. Contributing to this rise was the warming of 
the oceans and melting of land ice. It is likely that 275 gigatons per 
year of ice melted from land glaciers (not including ice sheets) since 
1993, and that the rate of loss of ice from the Greenland and Antarctic 
ice sheets increased substantially in recent years, to 215 gigatons per 
year and 147 gigatons per year respectively since 2002. For context, 
360 gigatons of ice melt is sufficient to cause global sea levels to 
rise 1 mm. Annual mean Arctic sea ice has been declining at 3.5 to 4.1 
percent per decade, and Northern Hemisphere snow cover extent has 
decreased at about 1.6 percent per decade for March and 11.7 percent 
per decade for June. Permafrost temperatures have increased in most 
regions since the 1980s, by up to 3 [deg]C (5.4 [deg]F) in parts of 
Northern Alaska. Winter storm frequency and intensity have both 
increased in the Northern Hemisphere. The NCA3 states that the 
increases in the severity or frequency of some types of extreme weather 
and climate events in recent decades can affect energy production

[[Page 64686]]

and delivery, causing supply disruptions, and compromise other 
essential infrastructure such as water and transportation systems.
    In addition to the changes documented in the assessment literature, 
there have been other climate milestones of note. In 2009, the year of 
the Endangerment Finding, the average concentration of CO2 
as measured on top of Mauna Loa was 387 parts per million, far above 
preindustrial concentrations of about 280 parts per million.\40\ The 
average concentration in 2013, the last full year before this rule was 
proposed, was 396 parts per million. The average concentration in 2014 
was 399 parts per million. And the monthly concentration in April of 
2014 was 401 parts per million, the first time a monthly average has 
exceeded 400 parts per million since record keeping began at Mauna Loa 
in 1958, and for at least the past 800,000 years.\41\ Arctic sea ice 
has continued to decline, with September of 2012 marking a new record 
low in terms of Arctic sea ice extent, 40 percent below the 1979-2000 
median. Sea level has continued to rise at a rate of 3.2 mm per year 
(1.3 inches/decade) since satellite observations started in 1993, more 
than twice the average rate of rise in the 20th century prior to 
1993.\42\ And 2014 was the warmest year globally in the modern global 
surface temperature record, going back to 1880; this now means 19 of 
the 20 warmest years have occurred in the past 20 years, and except for 
1998, the ten warmest years on record have occurred since 2002.\43\ The 
first months of 2015 have also been some of the warmest on record.
---------------------------------------------------------------------------

    \40\ ftp://aftp.cmdl.noaa.gov/products/trends/co2/co2_annmean_mlo.txt.
    \41\ http://www.esrl.noaa.gov/gmd/ccgg/trends/.
    \42\ Blunden, J., and D. S. Arndt, Eds., 2014: State of the 
Climate in 2013. Bull. Amer. Meteor. Soc., 95 (7), S1-S238.
    \43\ http://www.ncdc.noaa.gov/sotc/global/2014/13.
---------------------------------------------------------------------------

    These assessments and observed changes make it clear that reducing 
emissions of GHGs across the globe is necessary in order to avoid the 
worst impacts of climate change, and underscore the urgency of reducing 
emissions now. The NRC Committee on America's Climate Choices listed a 
number of reasons ``why it is imprudent to delay actions that at least 
begin the process of substantially reducing emissions.'' \44\ For 
example:
---------------------------------------------------------------------------

    \44\ NRC, 2011: America's Climate Choices, The National 
Academies Press.
---------------------------------------------------------------------------

     The faster emissions are reduced, the lower the risks 
posed by climate change. Delays in reducing emissions could commit the 
planet to a wide range of adverse impacts, especially if the 
sensitivity of the climate to GHGs is on the higher end of the 
estimated range.
     Waiting for unacceptable impacts to occur before taking 
action is imprudent because the effects of GHG emissions do not fully 
manifest themselves for decades and, once manifest, many of these 
changes will persist for hundreds or even thousands of years.
     In the committee's judgment, the risks associated with 
doing business as usual are a much greater concern than the risks 
associated with engaging in strong response efforts.
4. Observed and Projected U.S. Regional Changes
    The NCA3 assessed the climate impacts in 8 regions of the U.S., 
noting that changes in physical climate parameters such as 
temperatures, precipitation, and sea ice retreat were already having 
impacts on forests, water supplies, ecosystems, flooding, heat waves, 
and air quality. Moreover, the NCA3 found that future warming is 
projected to be much larger than recent observed variations in 
temperature, with precipitation likely to increase in the northern 
states, decrease in the southern states, and with the heaviest 
precipitation events projected to increase everywhere.
    In the Northeast, temperatures increased almost 2[emsp14][deg]F 
from 1895 to 2011, precipitation increased by about 5 inches (10 
percent), and sea level rise of about a foot has led to an increase in 
coastal flooding. The 70 percent increase in the amount of rainfall 
falling in the 1 percent of the most intense events is a larger 
increase in extreme precipitation than experienced in any other U.S. 
region.
    In the future, if emissions continue increasing, the Northeast is 
expected to experience 4.5 to 10[emsp14][deg]F of warming by the 2080s. 
This will lead to more heat waves, coastal and river flooding, and 
intense precipitation events. The southern portion of the region is 
projected to see 60 additional days per year above 90[emsp14][deg]F by 
mid-century. Sea levels in the Northeast are expected to increase 
faster than the global average because of subsidence, and changing 
ocean currents may further increase the rate of sea level rise. 
Specific vulnerabilities highlighted by the NCA include large urban 
populations particularly vulnerable to climate-related heat waves and 
poor air quality episodes, prevalence of climate sensitive vector-borne 
diseases like Lyme and West Nile Virus, usage of combined sewer systems 
that may lead to untreated water being released into local water bodies 
after climate-related heavy precipitation events, and 1.6 million 
people living within the 100-year coastal flood zone who are expected 
to experience more frequent floods due to sea level rise and tropical-
storm induced storm-surge. The NCA also highlighted infrastructure 
vulnerable to inundation in coastal metropolitan areas, potential 
agricultural impacts from increased rain in the spring delaying 
planting or damaging crops or increased heat in the summer leading to 
decreased yields and increased water demand, and shifts in ecosystems 
leading to declines in iconic species in some regions, such as cod and 
lobster south of Cape Cod.
    In the Southeast, average annual temperature during the last 
century cycled between warm and cool periods. A warm peak occurred 
during the 1930s and 1940s followed by a cool period and temperatures 
then increased again from 1970 to the present by an average of 
2[emsp14][deg]F. There have been increasing numbers of days above 
95[emsp14][deg]F and nights above 75[emsp14][deg]F, and decreasing 
numbers of extremely cold days since 1970. Daily and five-day rainfall 
intensities have also increased, and summers have been either 
increasingly dry or extremely wet. Louisiana has already lost 1,880 
square miles of land in the last 80 years due to sea level rise and 
other contributing factors.
    The Southeast is exceptionally vulnerable to sea level rise, 
extreme heat events, hurricanes, and decreased water availability. 
Major consequences of further warming include significant increases in 
the number of hot days (95[emsp14][deg]F or above) and decreases in 
freezing events, as well as exacerbated ground-level ozone in urban 
areas. Although projected warming for some parts of the region by the 
year 2100 are generally smaller than for other regions of the U.S., 
projected warming for interior states of the region are larger than 
coastal regions by 1[emsp14][deg]F to 2[emsp14][deg]F. Projections 
further suggest that globally there will be fewer tropical storms, but 
that they will be more intense, with more Category 4 and 5 storms. The 
NCA identified New Orleans, Miami, Tampa, Charleston, and Virginia 
Beach as being specific cities that are at risk due to sea level rise, 
with homes and infrastructure increasingly prone to flooding. 
Additional impacts of sea level rise are expected for coastal highways, 
wetlands, fresh water supplies, and energy infrastructure.
    In the Northwest, temperatures increased by about 1.3 [deg]F 
between 1895 and 2011. A small average increase in precipitation was 
observed over this time period. However, warming temperatures have 
caused increased rainfall relative to snowfall, which has

[[Page 64687]]

altered water availability from snowpack across parts of the region. 
Snowpack in the Northwest is an important freshwater source for the 
region. More precipitation falling as rain instead of snow has reduced 
the snowpack, and warmer springs have corresponded to earlier snowpack 
melting and reduced streamflows during summer months. Drier conditions 
have increased the extent of wildfires in the region.
    Average annual temperatures are projected to increase by 3.3 [deg]F 
to 9.7 [deg]F by the end of the century (depending on future global GHG 
emissions), with the greatest warming expected during the summer. 
Continued increases in global GHG emissions are projected to result in 
up to a 30 percent decrease in summer precipitation. Earlier snowpack 
melt and lower summer stream flows are expected by the end of the 
century and will affect drinking water supplies, agriculture, 
ecosystems, and hydropower production. Warmer waters are expected to 
increase disease and mortality in important fish species, including 
Chinook and sockeye salmon. Ocean acidification also threatens species 
such as oysters, with the Northwest coastal waters already being some 
of the most acidified worldwide due to coastal upwelling and other 
local factors. Forest pests are expected to spread and wildfires burn 
larger areas. Other high-elevation ecosystems are projected to be lost 
because they can no longer survive the climatic conditions. Low lying 
coastal areas, including the cities of Seattle and Olympia, will 
experience heightened risks of sea level rise, erosion, seawater 
inundation and damage to infrastructure and coastal ecosystems.
    In Alaska, temperatures have changed faster than anywhere else in 
the U.S. Annual temperatures increased by about 3[emsp14][deg]F in the 
past 60 years. Warming in the winter has been even greater, rising by 
an average of 6[emsp14][deg]F. Arctic sea ice is thinning and shrinking 
in area, with the summer minimum ice extent now covering only half the 
area it did when satellite records began in 1979. Glaciers in Alaska 
are melting at some of the fastest rates on Earth. Permafrost soils are 
also warming and beginning to thaw. Drier conditions have contributed 
to more large wildfires in the last 10 years than in any previous 
decade since the 1940s, when recordkeeping began. Climate change 
impacts are harming the health, safety and livelihoods of Native 
Alaskan communities.
    By the end of this century, continued increases in GHG emissions 
are expected to increase temperatures by 10 to 12 [deg]F in the 
northernmost parts of Alaska, by 8 to 10 [deg]F in the interior, and by 
6 to 8 [deg]F across the rest of the state. These increases will 
exacerbate ongoing arctic sea ice loss, glacial melt, permafrost thaw 
and increased wildfire, and threaten humans, ecosystems, and 
infrastructure. Precipitation is expected to increase to varying 
degrees across the state, however warmer air temperatures and a longer 
growing season are expected to result in drier conditions. Native 
Alaskans are expected to experience declines in economically, 
nutritionally, and culturally important wildlife and plant species. 
Health threats will also increase, including loss of clean water, 
saltwater intrusion, sewage contamination from thawing permafrost, and 
northward extension of diseases. Wildfires will increasingly pose 
threats to human health as a result of smoke and direct contact. Areas 
underlain by ice-rich permafrost across the state are likely to 
experience ground subsidence and extensive damage to infrastructure as 
the permafrost thaws. Important ecosystems will continue to be 
affected. Surface waters and wetlands that are drying provide breeding 
habitat for millions of waterfowl and shorebirds that winter in the 
lower 48 states. Warmer ocean temperatures, acidification, and 
declining sea ice will contribute to changes in the location and 
availability of commercially and culturally important marine fish.
    In the Southwest, temperatures are now about 2[emsp14][deg]F higher 
than the past century, and are already the warmest that region has 
experienced in at least 600 years. The NCA notes that there is evidence 
that climate-change induced warming on top of recent drought has 
influenced tree mortality, wildfire frequency and area, and forest 
insect outbreaks. Sea levels have risen about 7 or 8 inches in this 
region, contributing to inundation of Highway 101 and backup of 
seawater into sewage systems in the San Francisco area.
    Projections indicate that the Southwest will warm an additional 5.5 
to 9.5[emsp14][deg]F over the next century if emissions continue to 
increase. Winter snowpack in the Southwest is projected to decline 
(consistent with the record lows from this past winter), reducing the 
reliability of surface water supplies for cities, agriculture, cooling 
for power plants, and ecosystems. Sea level rise along the California 
coast will worsen coastal erosion, increase flooding risk for coastal 
highways, bridges, and low-lying airports, pose a threat to groundwater 
supplies in coastal cities such as Los Angeles, and increase 
vulnerability to floods for hundreds of thousands of residents in 
coastal areas. Climate change will also have impacts on the high-value 
specialty crops grown in the region as a drier climate will increase 
demands for irrigation, more frequent heat waves will reduce yields, 
and decreased winter chills may impair fruit and nut production for 
trees in California. Increased drought, higher temperatures, and bark 
beetle outbreaks are likely to contribute to continued increases in 
wildfires. The highly urbanized population of the Southwest is 
vulnerable to heat waves and water supply disruptions, which can be 
exacerbated in cases where high use of air conditioning triggers energy 
system failures.
    The rate of warming in the Midwest has markedly accelerated over 
the past few decades. Temperatures rose by more than 1.5[emsp14][deg]F 
from 1900 to 2010, but between 1980 and 2010 the rate of warming was 
three times faster than from 1900 through 2010.
    Precipitation generally increased over the last century, with much 
of the increase driven by intensification of the heaviest rainfalls. 
Several types of extreme weather events in the Midwest (e.g., heat 
waves and flooding) have already increased in frequency and/or 
intensity due to climate change.
    In the future, if emissions continue increasing, the Midwest is 
expected to experience 5.6 to 8.5 [deg]F of warming by the 2080s, 
leading to more heat waves. Though projections of changes in total 
precipitation vary across the regions, more precipitation is expected 
to fall in the form of heavy downpours across the entire region, 
leading to an increase in flooding. Specific vulnerabilities 
highlighted by the NCA include long-term decreases in agricultural 
productivity, changes in the composition of the region's forests, 
increased public health threats from heat waves and degraded air and 
water quality, negative impacts on transportation and other 
infrastructure associated with extreme rainfall events and flooding, 
and risks to the Great Lakes including shifts in invasive species, 
increases in harmful algal blooms, and declining beach health.
    High temperatures (more than 100 [deg]F in the Southern Plains and 
more than 95 [deg]F in the Northern Plains) are projected to occur much 
more frequently by mid-century. Increases in extreme heat will increase 
heat stress for residents, energy demand for air conditioning, and 
water losses. North Dakota's increase in annual temperatures over the 
past 130 years is the fastest in the contiguous U.S., mainly driven by 
warming winters. Specific vulnerabilities highlighted by the NCA 
include increased demand for water and energy, changes to crop growth 
cycles and

[[Page 64688]]

agricultural practices, and negative impacts on local plant and animal 
species from habitat fragmentation, wildfires, and changes in the 
timing of flowering or pest patterns. Communities that are already the 
most vulnerable to weather and climate extremes will be stressed even 
further by more frequent extreme events occurring within an already 
highly variable climate system.
    In Hawaii, other Pacific islands, and the Caribbean, rising air and 
ocean temperatures, shifting rainfall patterns, changing frequencies 
and intensities of storms and drought, decreasing baseflow in streams, 
rising sea levels, and changing ocean chemistry will affect ecosystems 
on land and in the oceans, as well as local communities, livelihoods, 
and cultures. Low islands are particularly at risk.
    Rising sea levels, coupled with high water levels caused by 
tropical and extra-tropical storms, will incrementally increase coastal 
flooding and erosion, damaging coastal ecosystems, infrastructure, and 
agriculture, and negatively affecting tourism. Ocean temperatures in 
the Pacific region exhibit strong year-to-year and decadal 
fluctuations, but since the 1950s, they have exhibited a warming trend, 
with temperatures from the surface to a depth of 660 feet rising by as 
much as 3.6 [deg]F. As a result of current sea level rise, the 
coastline of Puerto Rico around Rinc[oacute]n is being eroded at a rate 
of 3.3 feet per year. Freshwater supplies are already constrained and 
will become more limited on many islands. Saltwater intrusion 
associated with sea level rise will reduce the quantity and quality of 
freshwater in coastal aquifers, especially on low islands. In areas 
where precipitation does not increase, freshwater supplies will be 
adversely affected as air temperature rises.
    Warmer oceans are leading to increased coral bleaching events and 
disease outbreaks in coral reefs, as well as changed distribution 
patterns of tuna fisheries. Ocean acidification will reduce coral 
growth and health. Warming and acidification, combined with existing 
stresses, will strongly affect coral reef fish communities. For Hawaii 
and the Pacific islands, future sea surface temperatures are projected 
to increase 2.3 [deg]F by 2055 and 4.7 [deg]F by 2090 under a scenario 
that assumes continued increases in emissions. Ocean acidification is 
also taking place in the region, which adds to ecosystem stress from 
increasing temperatures. Ocean acidity has increased by about 30 
percent since the pre-industrial era and is projected to further 
increase by 37 percent to 50 percent from present levels by 2100.
    The NCA also discussed impacts that occur along the coasts and in 
the oceans adjacent to many regions, and noted that other impacts occur 
across regions and landscapes in ways that do not follow political 
boundaries.

B. GHG Emissions From Fossil Fuel-Fired EGUs \45\
---------------------------------------------------------------------------

    \45\ The emission data presented in this section of the preamble 
(Section II.B) are in metric tons, in keeping with reporting 
requirements for the GHGRP and the U.S. GHG Inventory. Note that the 
mass-based state goals presented in section VII of this preamble, 
and discussed elsewhere in this preamble, are presented in short 
tons.
---------------------------------------------------------------------------

    Fossil fuel-fired electric utility generating units (EGUs) are by 
far the largest emitters of GHGs among stationary sources in the U.S., 
primarily in the form of CO2, and among fossil fuel-fired 
EGUs, coal-fired units are by far the largest emitters. This section 
describes the amounts of these emissions and places these amounts in 
the context of the U.S. Inventory of Greenhouse Gas Emissions and Sinks 
\46\ (the U.S. GHG Inventory).
---------------------------------------------------------------------------

    \46\ ``Inventory of U.S. Greenhouse Gas Emissions and Sinks: 
1990--2013'', Report EPA 430-R-15-004, United States Environmental 
Protection Agency, April 15, 2015. http://epa.gov/climatechange/ghgemissions/usinventoryreport.html.
---------------------------------------------------------------------------

    The EPA implements a separate program under 40 CFR part 98 called 
the Greenhouse Gas Reporting Program \47\ (GHGRP) that requires 
emitting facilities over threshold amounts of GHGs to report their 
emissions to the EPA annually. Using data from the GHGRP, this section 
also places emissions from fossil fuel-fired EGUs in the context of the 
total emissions reported to the GHGRP from facilities in the other 
largest-emitting industries.
---------------------------------------------------------------------------

    \47\ U.S. EPA Greenhouse Gas Reporting Program Dataset, see 
http://www.epa.gov/ghgreporting/ghgdata/reportingdatasets.html.
---------------------------------------------------------------------------

    The EPA prepares the official U.S. GHG Inventory to comply with 
commitments under the United Nations Framework Convention on Climate 
Change (UNFCCC). This inventory, which includes recent trends, is 
organized by industrial sectors. It provides the information in Table 3 
below, which presents total U.S. anthropogenic emissions and sinks \48\ 
of GHGs, including CO2 emissions, for the years 1990, 2005 
and 2013.
---------------------------------------------------------------------------

    \48\ Sinks are a physical unit or process that stores GHGs, such 
as forests or underground or deep sea reservoirs of carbon dioxide.
    \49\ From Table ES-4 of ``Inventory of U.S. Greenhouse Gas 
Emissions and Sinks: 1990-2013'', Report EPA 430-R-15-004, U.S. 
Environmental Protection Agency, April 15, 2015. http://epa.gov/climatechange/ghgemissions/usinventoryreport.html.
    \50\ The energy sector includes all greenhouse gases resulting 
from stationary and mobile energy activities, including fuel 
combustion and fugitive fuel emissions.

                                 Table 3--U.S. GHG Emissions and Sinks by Sector
                       [Million metric tons carbon dioxide equivalent (MMT CO2 Eq.)] \49\
----------------------------------------------------------------------------------------------------------------
                             Sector                                    1990            2005            2013
----------------------------------------------------------------------------------------------------------------
Energy \50\.....................................................         5,290.5         6,273.6         5,636.6
Industrial Processes and Product Use............................           342.1           367.4           359.1
Agriculture.....................................................           448.7           494.5           515.7
Land Use, Land-Use Change and Forestry..........................            13.8            25.5            23.3
Waste...........................................................           206.0           189.2           138.3
                                                                 -----------------------------------------------
    Total Emissions.............................................         6,301.1         7,350.2         6,673.0
Land Use, Land-Use Change and Forestry (Sinks)..................         (775.8)         (911.9)         (881.7)
                                                                 -----------------------------------------------
Net Emissions (Sources and Sinks)...............................         5,525.2         6,438.3         5,791.2
----------------------------------------------------------------------------------------------------------------

    Total fossil energy-related CO2 emissions (including 
both stationary and mobile sources) are the largest contributor to 
total U.S. GHG emissions, representing 77.3 percent of total 2013 GHG 
emissions.\51\ In 2013, fossil fuel

[[Page 64689]]

combustion by the utility power sector--entities that burn fossil fuel 
and whose primary business is the generation of electricity--accounted 
for 38.3 percent of all energy-related CO2 emissions.\52\ 
Table 4 below presents total CO2 emissions from fossil fuel-
fired EGUs, for years 1990, 2005 and 2013.
---------------------------------------------------------------------------

    \51\ From Table ES-2 ``Inventory of U.S. Greenhouse Gas 
Emissions and Sinks: 1990-2013'', Report EPA 430-R-15-004, United 
States Environmental Protection Agency, April 15, 2015. http://epa.gov/climatechange/ghgemissions/usinventoryreport.html.
    \52\ From Table 3-1 ``Inventory of U.S. Greenhouse Gas Emissions 
and Sinks: 1990-2013'', Report EPA 430-R-15-004, United States 
Environmental Protection Agency, April 15, 2015. http://epa.gov/climatechange/ghgemissions/usinventoryreport.html.

           Table 4--U.S. GHG Emissions From Generation of Electricity From Combustion of Fossil Fuels
                                                 [MMT CO2] \53\
----------------------------------------------------------------------------------------------------------------
                          GHG emissions                                1990            2005            2013
----------------------------------------------------------------------------------------------------------------
Total CO2 from fossil fuel-fired EGUs...........................         1,820.8         2,400.9         2,039.8
    --from coal.................................................         1,547.6         1,983.8         1,575.0
    --from natural gas..........................................           175.3           318.8           441.9
    --from petroleum............................................            97.5            97.9            22.4
----------------------------------------------------------------------------------------------------------------

    In addition to preparing the official U.S. GHG Inventory to present 
comprehensive total U.S. GHG emissions and comply with commitments 
under the UNFCCC, the EPA collects detailed GHG emissions data from the 
largest emitting facilities in the U.S. through its Greenhouse Gas 
Reporting Program (GHGRP). Data collected by the GHGRP from large 
stationary sources in the industrial sector show that the utility power 
sector emits far greater CO2 emissions than any other 
industrial sector. Table 5 below presents total GHG emissions in 2013 
for the largest emitting industrial sectors as reported to the GHGRP. 
As shown in Table 4 and Table 5, respectively, CO2 emissions 
from fossil fuel-fired EGUs are nearly three times as large as the 
total reported GHG emissions from the next ten largest emitting 
industrial sectors in the GHGRP database combined.
---------------------------------------------------------------------------

    \53\ From Table 3-5 ``Inventory of U.S. Greenhouse Gas Emissions 
and Sinks: 1990-2013'', Report EPA 430-R-15-004, United States 
Environmental Protection Agency, April 15 2015. http://epa.gov/climatechange/ghgemissions/usinventoryreport.html.

   Table 5--Direct GHG Emissions Reported to GHGRP by Largest Emitting
                           Industrial Sectors
                             [MMT CO2e] \54\
------------------------------------------------------------------------
                      Industrial sector                          2013
------------------------------------------------------------------------
Petroleum Refineries........................................       176.7
Onshore Oil & Gas Production................................        94.8
Municipal Solid Waste Landfills.............................        93.0
Iron & Steel Production.....................................        84.2
Cement Production...........................................        62.8
Natural Gas Processing Plants...............................        59.0
Petrochemical Production....................................        52.7
Hydrogen Production.........................................        41.9
Underground Coal Mines......................................        39.8
Food Processing Facilities..................................        30.8
------------------------------------------------------------------------

C. Challenges in Controlling Carbon Dioxide Emissions

    Carbon dioxide is a unique air pollutant and controlling it 
presents unique challenges. CO2 is emitted in enormous 
quantities, and those quantities, coupled with the fact that 
CO2 is relatively unreactive, make it much more difficult to 
mitigate by measures or technologies that are typically utilized within 
an existing power plant. Measures that may be used to limit 
CO2 emissions would include efficiency improvements, which 
have thermodynamic limitations and carbon capture and sequestration 
(CCS), which is energy resource intensive.
---------------------------------------------------------------------------

    \54\ U.S. EPA Greenhouse Gas Reporting Program Dataset as of 
August 18, 2014. http://ghgdata.epa.gov/ghgp/main.do.
---------------------------------------------------------------------------

    Unlike other air pollutants which are results of trace impurities 
in the fuel, products of incomplete or inefficient combustion, or 
combustion byproducts, CO2 is an inherent product of clean, 
efficient combustion of fossil fuels, and therefore is an unavoidable 
product generated in enormous quantities, far greater than any other 
air pollutant.\55\ In fact, CO2 is emitted in far greater 
quantities than all other air pollutants combined. Total emissions of 
all non-GHG air pollutants in the U.S., from all sources, in 2013, were 
121 million metric tons.56 57
---------------------------------------------------------------------------

    \55\ Lackner et al., ``Comparative Impacts of Fossil Fuels and 
Alternative Energy Sources'', Issues in Environmental Science and 
Technology (2010).
    \56\ This includes NAAQS and HAPs, based on the following table: 
(see table above).
    It should be noted that PM2.5 is included in the 
amounts for PM10. Lead, another NAAQS pollutant, is 
emitted in the amounts of approximately 1,000 tons per year, and, in 
light of that relatively small quantity, was excluded from this 
analysis. Ammonia (NH3) is included because it is a 
precursor to PM2.5 secondary formation. Note that one 
short ton is equivalent to 0.907185 metric ton.
    \57\ In addition, emissions of non-CO2 GHGs totaled 
1.168 billion metric tons of carbon-dioxide equivalents 
(CO2e) in 2013. See Table ES-2, Executive Summary, 1990-
2013 Inventory of U.S. Greenhouse Gas Emissions and Sinks. http://www.epa.gov/climatechange/Downloads/ghgemissions/US-GHG-Inventory-2015-Chapter-Executive-Summary.pdf. This includes emissions of 
methane, nitrous oxide, and fluorinated GHGs (hydrofluorocarbons, 
perfluorocarbons, sulfur hexafluoride, and nitrogen trifluoride). In 
the total, the emissions of each non-CO2 GHG have been 
translated from metric tons of that gas into metric tons of 
CO2e by multiplying the metric tons of the gas by the 
global warming potential (GWP) of the gas. (The GWP of a gas is a 
measure of the ability of one kilogram of that gas to trap heat in 
earth's atmosphere compared to one kilogram of CO2.)

----------------------------------------------------------------------------------------------------------------
                                                    2013 tons (million
                   Pollutant                           short tons)                       Reference
----------------------------------------------------------------------------------------------------------------
CO.............................................                   69.758  Trends file (http://www.epa.gov/ttnchie1/trends/ ttnchie1/trends/).
NOX............................................                   13.072   ''
PM10...........................................                   20.651   ''
SO2............................................                    5.098   ''
VOC............................................                   17.471   ''
NH3............................................                    4.221   ''
HAPS...........................................                    3.641  2011 NEI version 2 (http://www.epa.gov/ttn/chief/net/2011inventory.html).
                                                -------------------------
    Total......................................                  133.912
----------------------------------------------------------------------------------------------------------------


[[Page 64690]]

As noted above, total emissions of CO2 from coal-fired power 
plants alone--the largest stationary source emitter--were 1.575 billion 
metric tons in that year,\58\ and total emissions of CO2 
from all sources were 5.5 billion metric tons.59 60 Carbon 
makes up the majority of the mass of coal and other fossil fuels, and 
for every ton of carbon burned, more than 3 tons of CO2 is 
produced.\61\ In addition, unlike many of the other air pollutants that 
react with sunlight or chemicals in the atmosphere, or are rained out 
or deposited on surfaces, CO2 is relatively unreactive and 
difficult to remove directly from the atmosphere.62 63
---------------------------------------------------------------------------

    \58\ From Table 3-5 ``Inventory of U.S. Greenhouse Gas Emissions 
and Sinks: 1990-2013'', Report EPA 430-R-15-004, United States 
Environmental Protection Agency, April 15, 2015. http://epa.gov/climatechange/ghgemissions/usinventoryreport.html.
    \59\ U.S. EPA, Greenhouse Gas Inventory Data Explorer, http://www.epa.gov/climatechange/ghgemissions/inventoryexplorer/#allsectors/allgas/gas/current.
    \60\ As another point of comparison, except for carbon dioxide, 
SO2 and NOX are the largest air pollutant 
emissions from coal-fired power plants. Over the past decade, U.S. 
power plants have emitted more than 200 times as much CO2 
as they have emitted SO2 and NOX. See de Gouw 
et al., ``Reduced emissions of CO2, NOX, and 
SO2 from U.S. power plants owing to switch from coal to 
natural gas with combined cycle technology,'' Earth's Future (2014).
    \61\ Each atom of carbon in the fuel combines with 2 atoms of 
oxygen in the air.
    \62\ Seinfeld J. and Pandis S., Atmospheric Chemistry and 
Physics: From Air Pollution to Climate Change (1998).
    \63\ The fact that CO2 is unreactive means that it is 
primarily removed from the atmosphere by dissolving in oceans or by 
being converted into biomass by plants. Herzog, H., ``Scaling up 
carbon dioxide capture and storage: From megatons to gigatons'', 
Energy Economics (2011).
---------------------------------------------------------------------------

    CO2's huge quantities and lack of reactivity make it 
challenging to remove from the smokestack. Retrofitted equipment is 
required to capture the CO2 before transporting it to a 
storage site. However, the scale of infrastructure required to directly 
mitigate CO2 emissions from existing EGUs through CCS can be 
quite large and difficult to integrate into the existing fossil fuel 
infrastructure. These CCS techniques are discussed in more depth 
elsewhere in the preamble for this rule and for the section 111(b) rule 
for new sources that accompanies this rule.
    The properties of CO2 can be contrasted with those of a 
number of other pollutants which have more accessible mitigation 
options. For example, the NAAQS pollutants--which generally are emitted 
in the largest quantities of any of the other air pollutants, except 
for CO2--each have more accessible mitigation options. 
Sulfur dioxide (SO2) is the result of a contaminant in the 
fuel, and, as a result, it can be reduced by using low-sulfur coal or 
by using flue-gas desulfurization (FGD) technologies. Emissions of 
NOX can be mitigated relatively easily using combustion 
control techniques (e.g., low-NOX burners) and by using 
downstream controls such as selective catalytic reduction (SCR) and 
selective non-catalytic reduction (SNCR) technologies. PM can be 
effectively mitigated using fabric filters, PM scrubbers, or 
electrostatic precipitators. Lead is part of particulate matter 
emissions and is controlled through the same devices. Carbon monoxide 
and VOCs are the products of incomplete combustion and can therefore be 
abated by more efficient combustion conditions, and can also be 
destroyed in the smokestack by the use of oxidation catalysts which 
complete the combustion process. Many air toxics are VOCs, such as 
polyaromatic hydrocarbons, and therefore can be abated in the same ways 
just described. But in every case, these pollutants can be controlled 
at the source much more readily than CO2 primarily because 
of the comparatively lower quantities that are produced, and also due 
to other attributes such as relatively greater reactivity and 
solubility.

D. The Utility Power Sector

1. A Brief History
    The modern American electricity system is one of the greatest 
engineering achievements of the past 100 years. Since the invention of 
the incandescent light bulb in the 1870s,\64\ electricity has become 
one of the major foundations for modern American life. Beginning with 
the first power station in New York City in 1882, each power station 
initially served a discrete set of consumers, resulting in small and 
localized electricity systems.\65\ During the early 1900s, smaller 
systems consolidated, allowing generation resources to be shared over 
larger areas. Interconnecting systems have reduced generation 
investment costs and improved reliability.\66\ Local and state 
governments initially regulated these growing electricity systems with 
federal regulation coming later in response to public concerns about 
rising electricity costs.\67\
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    \64\ Regulatory Assistance Project (RAP), Electricity Regulation 
in the US: A Guide, at 1 (2011), available at http://www.raponline.org/document/download/id/645.
    \65\ Casazza, J. and Delea, F., Understanding Electric Power 
Systems, IEEE Press, at 2-4 (2d ed. 2010).
    \66\ Casazza, J. and Delea, F., Understanding Electric Power 
Systems, IEEE Press, at 5-6 (2d ed. 2010). Investment in electric 
generation is extremely capital intensive, with generation 
potentially accounting for 65 percent of customer costs. If these 
costs can be spread to more customers, then this can reduce the 
amount that each individual customer pays. Federal Energy Regulatory 
Commission, Energy Primer: A Handbook of Energy Market Basics, at 38 
(2012), available at http://www.ferc.gov/market-oversight/guide/energy-primer.pdf.
    \67\ Burn, An Energy Journal, The Electricity Grid: A History, 
available at http://burnanenergyjournal.com/the-electric-grid-a-history/ (last visited Mar. 9, 2015).
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    Initially, states had broad authority to regulate public utilities, 
but gradually federal regulation increased. In 1920, Congress passed 
the Federal Water Power Act, creating the Federal Power Commission 
(FPC) and providing for the licensing of hydroelectric facilities on 
U.S. government lands and navigable waters of the U.S.\68\ During this 
time period, the U.S. Supreme Court found that state authority to 
regulate public utilities is limited, holding that the Commerce Clause 
does not allow state regulation to directly burden interstate 
commerce.\69\ For example, in Public Utilities Commission of Rhode 
Island v. Attleboro Steam & Electric Company, Rhode Island sought to 
regulate the electricity rates that a Rhode Island generator was 
charging to a company in Massachusetts that resold the electricity to 
Attleboro, Massachusetts.\70\ The Supreme Court found that Rhode 
Island's regulation was impermissible because it imposed a ``direct 
burden upon interstate commerce.'' \71\ The Supreme Court held that 
this kind of interstate transaction was not subject to state 
regulation. However, because Congress had not yet passed legislation to 
make these types of transactions subject to federal regulation, this 
became known as the ``Attleboro gap'' in regulation. In 1935, Congress 
passed the Federal Power Act (FPA), giving the FPC jurisdiction over 
``the transmission of electric energy in interstate commerce'' and 
``the sale of electric energy at wholesale in interstate commerce.'' 
\72\ Under FPA section 205, the FPC was tasked with ensuring that rates 
for jurisdictional services are just, reasonable, and not unduly 
discriminatory or preferential.\73\ FPA section 206 authorized the FPC 
to determine, after a hearing upon its own motion or in response to a 
complaint

[[Page 64691]]

filed at the Commission, whether jurisdictional rates are just, 
reasonable, and not unduly discriminatory or preferential.\74\ In 1938, 
Congress passed the Natural Gas Act (NGA), giving the FPC jurisdiction 
over the transmission or sale of natural gas in interstate 
commerce.\75\ The NGA also gave the FPC the jurisdiction to ``grant 
certificates allowing construction and operation of facilities used in 
interstate gas transmission and authorizing the provision of 
services.'' \76\ In 1977, the FPC became FERC after Congress passed the 
Department of Energy Organization Act.
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    \68\ The FPC became an independent Commission in 1930. United 
States Government Manual 1945: First Edition, at 486, available at 
http://www.ibiblio.org/hyperwar/ATO/USGM/FPC.html.
    \69\ New York v. Federal Energy Regulatory Commission, 535 U.S. 
1, 5 (2002) (citation omitted).
    \70\ Public Utils. Comm'n of Rhode Island v. Attleboro Steam & 
Elec. Co., 273 U.S. 83 (1927).
    \71\ Public Utils. Comm'n of Rhode Island v. Attleboro Steam & 
Elec. Co., 273 U.S. 83, 89 (1927).
    \72\ 16 U.S.C. 824(b)(1).
    \73\ 16 U.S.C. 824d.
    \74\ 16 U.S.C. 824e.
    \75\ Energy Information Administration, Natural Gas Act of 1938, 
available at http://www.eia.gov/oil_gas/natural_gas/analysis_publications/ngmajorleg/ngact1938.html.
    \76\ Energy Information Administration, Natural Gas Act of 1938, 
available at http://www.eia.gov/oil_gas/natural_gas/analysis_publications/ngmajorleg/ngact1938.html.
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    By the 1930s, regulated electric utilities that provided the major 
components of the electrical system--generation, transmission, and 
distribution--were common.\77\ These regulated monopolies are referred 
to as vertically-integrated utilities.
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    \77\ Burn, An Energy Journal, The Electricity Grid: A History, 
available at http://burnanenergyjournal.com/the-electric-grid-a-history/ (last visited Mar. 9, 2015).
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    As utilities built larger and larger electric generation plants, 
the cost per unit to generate electricity decreased.\78\ However, these 
larger plants were extremely capital intensive for any one company to 
fund.\79\ Some neighboring utilities solved this issue by agreeing to 
share electricity reserves when needed.\80\ These utilities began 
building larger transmission lines to deliver power in times when large 
generators experienced outages.\81\ Eventually, some utilities that 
were in reserve sharing agreements formed electric power pools to 
balance electric load over a larger area. Participating utilities gave 
control over scheduling and dispatch of their electric generation units 
to a system operator.\82\ Some power pools evolved into today's RTOs 
and ISOs.
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    \78\ Federal Energy Regulatory Commission, Energy Primer: A 
Handbook of Energy Market Basics, at 38 (2012), available at http://www.ferc.gov/market-oversight/guide/energy-primer.pdf.
    \79\ Federal Energy Regulatory Commission, Energy Primer: A 
Handbook of Energy Market Basics, at 38 (2012), available at http://www.ferc.gov/market-oversight/guide/energy-primer.pdf.
    \80\ Federal Energy Regulatory Commission, Energy Primer: A 
Handbook of Energy Market Basics, at 38 (2012), available at http://www.ferc.gov/market-oversight/guide/energy-primer.pdf.
    \81\ Federal Energy Regulatory Commission, Energy Primer: A 
Handbook of Energy Market Basics, at 38 (2012), available at http://www.ferc.gov/market-oversight/guide/energy-primer.pdf.
    \82\ Shively, B, Ferrare, J, Understanding Today's Electricity 
Business, Enerdynamics, at 94 (2012).
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    In the past, electric utilities generally operated as state 
regulated monopolies, supplying end-use customers with generation, 
distribution, and transmission service.\83\ However, the ability of 
electric utilities to operate as natural monopolies came with consumer 
protection safeguards.\84\ ``In exchange for a franchised, monopoly 
service area, utilities accept an obligation to serve--meaning there 
must be adequate supply to meet customers' needs regardless of the 
cost.'' \85\ Under this obligation to serve, the utility agreed to 
provide service to any customer located within its service 
jurisdiction.
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    \83\ Maryland Department of Natural Resources, Maryland Power 
Plants and the Environment: A Review of the Impacts of Power Plants 
and Transmission Lines on Maryland's Natural Resources, at 2-5 
(2006), available at http://esm.versar.com/pprp/ceir13/toc.htm.
    \84\ Pacific Power, Utility Regulation, at 1, available at 
https://www.pacificpower.net/content/dam/pacific_power/doc/About_Us/Newsroom/Media_Resources/Regulation.PP.08.pdf.
    \85\ Pacific Power, Utility Regulation, at 1, available at 
https://www.pacificpower.net/content/dam/pacific_power/doc/About_Us/Newsroom/Media_Resources/Regulation.PP.08.pdf.
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    On both a federal and state level, competition has entered the 
electricity sector to varying degrees in the last few decades.\86\ In 
the early 1990s, some states began to consider allowing competition to 
enter retail electric service.\87\ Federal and state efforts to allow 
competition in the electric utility industry have resulted in 
independent power producers (IPPs) \88\ producing approximately 37 
percent of net generation in 2013.\89\ Electric utilities in some 
states remain vertically integrated without retail competition from 
IPPs. Today, there are over 3,000 public, private, and cooperative 
utilities in the U.S.\90\ These utilities include both investor-owned 
utilities \91\ and consumer-owned utilities.\92\
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    \86\ For example, in 1978, Congress passed the Public Utilities 
Regulatory Policies Act (PURPA) which allowed non-utility owned 
power plants to sell electricity. Burn, An Energy Journal, The 
Electricity Grid: A History, available at http://burnanenergyjournal.com/the-electric-grid-a-history/ (last visited 
Mar. 9, 2015). PURPA, the Energy Policy Act of 1992 (EPAct 1992), 
and the Energy Policy Act of 2005 (EPAct 2005) ``promoted 
competition by lowering entry barriers and increasing transmission 
access.'' The Electric Energy Market Competition Task Force, Report 
to Congress on Competition in Wholesale and Retail Markets for 
Electric Energy, at 2, available at http://www.ferc.gov/legal/fed-sta/ene-pol-act/epact-final-rpt.pdf (last visited Mar. 20, 2015).
    \87\ The Electric Energy Market Competition Task Force, Report 
to Congress on Competition in Wholesale and Retail Markets for 
Electric Energy, at 2, available at http://www.ferc.gov/legal/fed-sta/ene-pol-act/epact-final-rpt.pdf (last visited Mar. 20, 2015).
    \88\ These entities are also referred to as merchant generators.
    \89\ Energy Information Administration, Electric Power Annual, 
Table 1.1 Total Electric Power Summary Statistics, 2013 and 2012 
(2015), available at http://www.eia.gov/electricity/annual/html/epa_01_01.html.
    \90\ Regulatory Assistance Project (RAP), Electricity Regulation 
in the US: A Guide, at 9 (2011), available at http://www.raponline.org/document/download/id/645.
    \91\ Investor-owned utilities are private companies that are 
financed by a combination of shareholder equity and bondholder debt. 
Regulatory Assistance Project (RAP), Electricity Regulation in the 
US: A Guide, at 9 (2011), available at http://www.raponline.org/document/download/id/645.
    \92\ Consumer-owned utilities include municipal utilities, 
public utility districts, cooperatives, and a variety of other 
entities such as irrigation districts. Regulatory Assistance Project 
(RAP), Electricity Regulation in the US: A Guide, at 9-10 (2011), 
available at http://www.raponline.org/document/download/id/645.
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    Over time, the grid slowly evolved into a complex, interconnected 
transmission system that allows electric generators to produce 
electricity that is then fed onto transmission lines at high 
voltages.\93\ These larger transmission lines are able to access 
generation that is located more remotely, with transmission lines 
crossing many miles, including state borders.\94\ Closer to end users, 
electricity is transformed into a lower voltage that is transported 
across

[[Page 64692]]

localized transmission lines to homes and businesses.\95\ Localized 
transmission lines make up the distribution system. These three 
components of the electricity system--generation, transmission, and 
distribution--are closely related and must work in coordination to 
deliver electricity from the point of generation to the point of 
consumption. This interconnectedness is a fundamental aspect of the 
nation's electricity system, requiring a complicated integration of all 
components of the system to balance supply and demand and a federal, 
state, and local regulatory network to oversee the physically 
interconnected network. Facilities planned and constructed in one 
segment can impact facilities and operations in other segments and vice 
versa.
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    \93\ Peter Fox-Penner, Electric Utility Restructuring: A Guide 
to the Competitive Era, Public Utility Reports, Inc., at 5, 34 
(1997). ``The extent of the power system's short-run physical 
interdependence is remarkable, if not entirely unique. No other 
large, multi-stage industry is required to keep every single 
producer in a region--whether or not owned by the same company--in 
immediate synchronization with all other producers.'' Id. at 34. 
``At an early date, those providing electric power recognized that 
peak use for one system often occurred at a different time from peak 
use in other systems. They also recognized that equipment failures 
occurred at different times in various systems. Analyses showed 
significant economic benefits from interconnecting systems to 
provide mutual assistance; the investment required for generating 
capacity could be reduced and reliability could be improved. This 
lead [sic] to the development of local, then regional, and 
subsequently three transmission grids that covered the U.S. and 
parts of Canada.'' Casazza, J. and Delea, F., Understanding Electric 
Power Systems, IEEE Press, at 5-6 (2d ed. 2010).
    \94\ Burn, An Energy Journal, The Electricity Grid: A History, 
available at http://burnanenergyjournal.com/the-electric-grid-a-history/ (last visited Mar. 9, 2015). Because of the ease and low 
cost of converting voltages in an alternating current (AC) system 
from one level to another, the bulk power system is predominantly an 
AC system rather than a direct current (DC) system. In an AC system, 
electricity cannot be controlled like a gas or liquid by utilizing a 
valve in a pipe. Instead, absent the presence of expensive control 
devices, electricity flows freely along all available paths, 
according to the laws of physics. U.S.-Canada Power System Outage 
Task Force, Final Report on the August 14, 2003 Blackout in the 
United States and Canada: Causes and Recommendations, at 6 (Apr. 
2004), available at http://www.ferc.gov/industries/electric/indus-act/reliability/blackout/ch1-3.pdf.
    \95\ Peter Fox-Penner, Electric Utility Restructuring: A Guide 
to the Competitive Era, Public Utility Reports, Inc., at 5 (1997).
---------------------------------------------------------------------------

    The North American electric grid has developed into a large, 
interconnected system.\96\ Electricity from a diverse set of generation 
resources such as natural gas, nuclear, coal, and renewables is 
distributed over high-voltage transmission lines divided across the 
continental U.S. into three synchronous interconnections--the Eastern 
Interconnection, Western Interconnection, and the Texas 
Interconnection.\97\ These three synchronous systems each act like a 
single machine.\98\ Diverse resources generate electricity that is 
transmitted and distributed through a complex system of interconnected 
components to industrial, business, and residential consumers. Unlike 
other industries where sources make operational decisions 
independently, the utility power sector is unique in that electricity 
system resources operate in a complex, interconnected grid system that 
is physically interconnected and operated on an integrated basis across 
large regions. Additionally, a federal, state, and local regulatory 
network oversees policies and practices that are applied to how the 
system is designed and operates. In this interconnected system, system 
operators must ensure that the amount of electricity available is 
precisely matched with the amount needed in real time. System operators 
have a number of resources potentially available to meet electricity 
demand, including electricity generated by electric generation units 
such as coal, nuclear, renewables, and natural gas, as well as demand-
side resources,\99\ such as EE \100\ and demand response.\101\ 
Generation, outages, and transmission changes in one part of the 
synchronous grid can affect the entire interconnected grid.\102\ The 
interconnection is such that ``[i]f a generator is lost in New York 
City, its affect is felt in Georgia, Florida, Minneapolis, St. Louis, 
and New Orleans.'' \103\ The U.S. Supreme Court has similarly 
recognized the interconnected nature of the electricity grid.\104\
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    \96\ U.S.-Canada Power System Outage Task Force, Final Report on 
the August 14, 2003 Blackout in the United States and Canada: Causes 
and Recommendations, at 5 (Apr. 2004), available at http://www.ferc.gov/industries/electric/indus-act/reliability/blackout/ch1-3.pdf.
    \97\ Regulatory Assistance Project (RAP), Electricity Regulation 
in the US: A Guide, 2011, at 1, available at http://www.raponline.org/document/download/id/645.
    \98\ Casazza, J. and Delea, F., Understanding Electric Power 
Systems, IEEE Press, at 159 (2d ed. 2010). In an amicus brief to the 
Supreme Court, a group of electrical engineers, economists, and 
physicists specializing in electricity explained, ``Energy is 
transmitted, not electrons. Energy transmission is accomplished 
through the propagation of an electromagnetic wave. The electrons 
merely oscillate in place, but the energy--the electromagnetic 
wave--moves at the speed of light. The energized electrons making 
the lightbulb in a house glow are not the same electrons that were 
induced to oscillate in the generator back at the power plant. . . . 
Energy flowing onto a power network or grid energizes the entire 
grid, and consumers then draw undifferentiated energy from that 
grid. A networked grid flexes, and electric current flows, in 
conformity with physical laws, and those laws do not notice, let 
alone conform to, political boundaries. . . . The path taken by 
electric energy is the path of least resistance . . . or, more 
accurately, the paths of least resistance. . . . If a generator on 
the grid increases its output, the current flowing from the 
generator on all paths on the grid increases. These increases affect 
the energy flowing into each point in the network, which in turn 
leads to compensating and corresponding changes in the energy flows 
out of each point.'' Brief Amicus Curiae of Electrical Engineers, 
Energy Economists and Physicists in Support of Respondents at 2, 8-
9, 11, New York v. FERC, 535 U.S. 1 (2001) (No. 00-568).
    \99\ ``Measures using demand-side resources comprise actions 
taken on the customer's side of the meter to change the amount and/
or timing of electricity use in ways that will provide benefits to 
the electricity supply system.'' David Crossley, Regulatory 
Assistance Project (RAP), Effective Mechanisms to Increase the Use 
of Demand-Side Resources, at 9 (2013), available at 
www.raponline.org.
    \100\ Energy efficiency is using less energy to provide the same 
or greater level of service. Demand-side energy efficiency refers to 
an extensive array of technologies, practices and measures that are 
applied throughout all sectors of the economy to reduce energy 
demand while providing the same, and sometimes better, level and 
quality of service.
    \101\ Demand response involves ``[c]hanges in electric usage by 
demand-side resources from their normal consumption patterns in 
response to changes in the price of electricity over time, or to 
incentive payments designed to induce lower electricity use at times 
of high wholesale market prices or when system reliability is 
jeopardized.'' Federal Energy Regulatory Commission, Reports on 
Demand Response & Advanced Metering, (Dec. 23, 2014), available at 
http://www.ferc.gov/industries/electric/indus-act/demand-response/dem-res-adv-metering.asp.
    \102\ Casazza, J. and Delea, F., Understanding Electric Power 
Systems, IEEE Press, at 159 (2d ed. 2010).
    \103\ Casazza, J. and Delea, F., Understanding Electric Power 
Systems, IEEE Press, at 160 (2d ed. 2010).
    \104\ Federal Power Comm'n v. Florida Power & Light Co., 404 
U.S. 453, at 460 (1972) (quoting a Federal Power Commission hearing 
examiner, ```If a housewife in Atlanta on the Georgia system turns 
on a light, every generator on Florida's system almost instantly is 
caused to produce some quantity of additional electric energy which 
serves to maintain the balance in the interconnected system between 
generation and load.''') (citation omitted). See also New York v. 
FERC, 535 U.S. 1, at 7 (2002) (stating that ``any electricity that 
enters the grid immediately becomes a part of a vast pool of energy 
that is constantly moving in interstate commerce.'') (citation 
omitted). In Federal Power Comm'n v. Southern California Edison Co., 
376 U.S. 205 (1964), the Supreme Court found that a sale for resale 
of electricity from Southern California Edison to the City of 
Colton, which took place solely in California, was under Federal 
Power Commission jurisdiction because some of the electricity that 
Southern California Edison marketed came from out of state. The 
Supreme Court stated that, ```federal jurisdiction was to follow the 
flow of electric energy, an engineering and scientific, rather than 
a legalistic or governmental, test.''' Id. at 210 (quoting 
Connecticut Light & Power Co. v. Federal Power Commission, 324 U.S. 
515, 529 (1945) (emphasis omitted)).
---------------------------------------------------------------------------

    Today, federal, state, and local entities regulate electricity 
providers.\105\ Overlaid on the physical electricity network is a 
regulatory network that has developed over the last century or more. 
This regulatory network ``plays a vital role in the functioning of all 
other networks, sometimes providing specific rules for functioning 
while at other times providing restraints within which their operation 
must be conducted.'' \106\ This unique regulatory network results in an 
electricity grid that is both physically interconnected and connected 
through a network of regulation on the local, state, and federal 
levels. This regulation seeks to reconcile the fact that electricity is 
a public good with the fact that facilities providing that electricity 
are privately owned.\107\ While this regulation began on the state and 
local levels, federal regulation of the electricity system increased 
over time. With the passage of the EPAct 1992 and the EPAct 2005, the 
federal government's role in electricity regulation greatly 
increased.\108\ ``The role of the regulator now includes support for 
the development of open

[[Page 64693]]

and fair wholesale electric markets, ensuring equal access to the 
transmission system and more hands-on oversight and control of the 
planning and operating rules for the industry.'' \109\
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    \105\ Casazza, J. and Delea, F., Understanding Electric Power 
Systems, IEEE Press, at 214 (2d ed. 2010).
    \106\ Casazza, J. and Delea, F., Understanding Electric Power 
Systems, IEEE Press, at 213 (2d ed. 2010).
    \107\ Casazza, J. and Delea, F., Understanding Electric Power 
Systems, IEEE Press, at 213 (2d ed. 2010).
    \108\ Casazza, J. and Delea, F., Understanding Electric Power 
Systems, IEEE Press, at 214 (2d ed. 2010).
    \109\ Casazza, J. and Delea, F., Understanding Electric Power 
Systems, IEEE Press, at 214 (2d ed. 2010).
---------------------------------------------------------------------------

2. Electric System Dispatch
    System operators typically dispatch the electric system through a 
process known as Security Constrained Economic Dispatch.\110\ Security 
Constrained Economic Dispatch has two components--economic generation 
of generation facilities and ensuring that the electric system remains 
reliable.\111\ Electricity demand varies across geography and time in 
response to numerous conditions, such that electric generators are 
constantly responding to changes in the most reliable and cost-
effective manner possible. The cost of operating electric generation 
varies based on a number of factors, such as fuel and generator 
efficiency.
---------------------------------------------------------------------------

    \110\ Economic Dispatch: Concepts, Practices and Issues, FERC 
Staff Presentation to the Joint Board for the Study of Economic 
Dispatch, Palm Springs, California (Nov. 13, 2005), available at 
http://www.ferc.gov/CalendarFiles/20051110172953-FERC%20Staff%20Presentation.pdf.
    \111\ Federal Energy Regulatory Commission, Security Constrained 
Economic Dispatch: Definitions, Practices, Issues and 
Recommendations: A Report to Congress (July 31, 2006). The Energy 
Policy Act of 2005 defined economic dispatch as ``the operation of 
generation facilities to produce energy at the lowest cost to 
reliably serve consumers, recognizing any operational limits of 
generation and transmission facilities.'' Energy Policy Act of 2005, 
Pub. L. 109-58, 119 Stat. 594 (2005), section 1234(b), available at 
http://www.ferc.gov/industries/electric/indus-act/joint-boards/final-cong-rpt.pdf.
---------------------------------------------------------------------------

    The decision to dispatch any particular electric generator depends 
upon the relative operating cost, or marginal cost, of generating 
electricity to meet the last increment of electric demand. Fuel is one 
common variable cost--especially for fossil-fueled generators. Coal 
plants will often have considerable variable costs associated with 
running pollution controls.\112\ Renewables, hydroelectric, and nuclear 
have little to no variable costs. If electricity demand decreases or 
additional generation becomes available on the system, this impacts how 
the system operator will dispatch the system. EGUs using technologies 
with relatively low variable costs, such as nuclear units and RE, are 
for economic reasons generally operated at their maximum output 
whenever they are available. When lower cost units are available to 
run, higher variable cost units, such as fossil-fuel generators, are 
generally the first to be displaced.
---------------------------------------------------------------------------

    \112\ Variable costs also include costs associated with 
operation and maintenance and costs of operating a pollution control 
and/or emission allowance charges.
---------------------------------------------------------------------------

    In states with cost-of-service regulation of vertically-integrated 
utilities, the utilities themselves form the balancing authorities who 
determine dispatch based upon the lowest marginal cost. These utilities 
sometimes arrange to buy and sell electricity with other balancing 
authorities. RTOs and ISOs coordinate, control, and monitor electricity 
transmission systems to ensure cost-effective and reliable delivery of 
power, and they are independent from market participants.
3. Reliability Considerations
    The reliability of the electric system has long been a focus of the 
electric industry and regulators. Industry developed a voluntary 
organization in the early 1960s that assisted with bulk power system 
coordination in the U.S. and Canada.\113\ In 1965, the northeastern 
U.S. and southeastern Ontario, Canada experienced the largest power 
blackout to date, impacting 30 million people.\114\ In response to the 
1965 blackout and a Federal Power Commission recommendation,\115\ 
industry developed the National Electric Reliability Council (NERC) and 
nine reliability councils. The organization later became known as the 
North American Electric Reliability Council to recognize Canada's 
participation.\116\ The North American Electric Reliability Council 
became the North American Electric Reliability Corporation in 
2007.\117\
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    \113\ North American Electric Reliability Corporation, History 
of NERC, at 1 (2013), available at http://www.nerc.com/AboutNERC/Documents/History%20AUG13.pdf.
    \114\ Federal Energy Regulatory Commission, Energy Primer: A 
Handbook of Energy Market Basics, at 39 (2012), available at http://www.ferc.gov/market-oversight/guide/energy-primer.pdf.
    \115\ The Federal Power Commission, a precursor to FERC, 
recommended ``the formation of a council on power coordination made 
up of representatives from each of the nation's regional 
coordinating organizations, to exchange and disseminate information 
and to review, discuss and assist in resolving interregional 
coordination matters.'' North American Electric Reliability 
Corporation, History of NERC, at 1 (2013), available at http://www.nerc.com/AboutNERC/Documents/History%20AUG13.pdf.
    \116\ North American Electric Reliability Corporation, History 
of NERC, at 2 (2013), available at http://www.nerc.com/AboutNERC/Documents/History%20AUG13.pdf.
    \117\ North American Electric Reliability Corporation, History 
of NERC, at 4 (2013), available at http://www.nerc.com/AboutNERC/Documents/History%20AUG13.pdf.
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    In August 2003, North America experienced its worst blackout to 
date creating an outage in the Midwest, Northeast, and Ontario, 
Canada.\118\ This blackout was massive in scale impacting an area with 
an estimated 50 million people and 61,800 megawatts of electric 
load.\119\ The U.S. and Canada formed a joint task force to investigate 
the causes of the blackout and made recommendations to avoid similar 
outages in the future. One of the task force's major recommendations 
was that the U.S. Congress should pass legislation making electric 
reliability standards mandatory and enforceable.\120\
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    \118\ North American Electric Reliability Corporation, History 
of NERC, at 3 (2013), available at http://www.nerc.com/AboutNERC/Documents/History%20AUG13.pdf.
    \119\ U.S.-Canada Power System Outage Task Force, Final Report 
on the August 14, 2003 Blackout in the United States and Canada: 
Causes and Recommendations, at 1 (Apr. 2004), available at http://www.ferc.gov/industries/electric/indus-act/reliability/blackout/ch1-3.pdf. The outage impacted areas within Ohio, Michigan, 
Pennsylvania, New York, Vermont, Massachusetts, Connecticut, New 
Jersey, and the Canadian province of Ontario. Id.
    \120\ U.S.-Canada Power System Outage Task Force, Final Report 
on the August 14, 2003 Blackout in the United States and Canada: 
Causes and Recommendations, at 2 (Apr. 2004), available at http://www.ferc.gov/industries/electric/indus-act/reliability/blackout/ch1-3.pdf.
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    Congress responded to this recommendation in EPAct 2005, adding a 
new section 215 to the Federal Power Act making reliability standards 
mandatory and enforceable and authorizing the creation of a new 
Electric Reliability Organization (ERO). Under this new system, FERC 
certifies an entity as the ERO. The ERO develops reliability standards, 
which are subject to FERC review and approval. Once FERC approves 
reliability standards the ERO may enforce those standards or FERC can 
do so independently.\121\ In 2006, the Federal Energy Regulatory 
Commission (FERC) certified NERC as the ERO.\122\ ``NERC develops and 
enforces Reliability Standards; monitors the Bulk-Power System; 
assesses adequacy annually via a 10-year forecast and winter and summer 
forecasts; audits owners, operators and users for preparedness; and 
educates and trains industry personnel.'' \123\
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    \121\ Mandatory Reliability Standards for the Bulk-Power System, 
Order No. 693, 118 FERC ] 61,218, at P 3 (2007) (citing 16 U.S.C. 
824o(e)(3)).
    \122\ Rules Concerning Certification of the Electric Reliability 
Organization; and Procedures for the Establishment, Approval, and 
Enforcement of Electric Reliability Standards, Order No. 672, 114 
FERC ] 61,104 (2006).
    \123\ North American Electric Reliability Corporation, 
Frequently Asked Questions, at 2 (Aug. 2013), available at http://www.nerc.com/AboutNERC/Documents/NERC%20FAQs%20AUG13.pdf.
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    The U.S., Canada, and part of Mexico are divided up into eight 
reliability

[[Page 64694]]

regional entities.\124\ These regional entities include Florida 
Reliability Coordinating Council (FRCC), Midwest Reliability 
Organization (MRO), Northeast Power Coordinating Council (NPCC), 
Reliability First Corporation (RFC), SERC Reliability Corporation 
(SERC), Southwest Power Pool, RE (SPP), Texas Reliability Entity (TRE), 
and Western Electricity Coordinating Council (WECC).\125\ Regional 
entity members come from all segments of the electric industry.\126\ 
NERC delegates authority, with FERC approval, to these regional 
entities to enforce reliability standards, both national and regional 
reliability standards, and engage in other standards-related duties 
delegated to them by NERC.\127\ NERC ensures that there is a 
consistency of application of delegated functions with appropriate 
regional flexibility.\128\ NERC divides the country into assessment 
areas and annually analyzes the reliability, adequacy, and associated 
risks that may affect the upcoming summer, winter, and long-term, 10-
year period. Multiple other entities such as FERC, the Department of 
Energy, state public utility commissions, ISOs/RTOs,\129\ and other 
planning authorities also consider the reliability of the electric 
system. There are numerous remedies that can be utilized to solve a 
potential reliability problem, including long-term planning, 
transmission system upgrades, installation of new generating capacity, 
demand response, and other demand side actions.
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    \124\ Federal Energy Regulatory Commission, Energy Primer: A 
Handbook of Energy Market Basics, at 49-50 (2012), available at 
http://www.ferc.gov/market-oversight/guide/energy-primer.pdf.
    \125\ Federal Energy Regulatory Commission, Energy Primer: A 
Handbook of Energy Market Basics, at 50 (2012), available at http://www.ferc.gov/market-oversight/guide/energy-primer.pdf.
    \126\ North American Electric Reliability Corporation, Key 
Players, available at http://www.nerc.com/AboutNERC/keyplayers/Pages/default.aspx (last visited Mar. 12, 2015). ``The members of 
the regional entities come from all segments of the electric 
industry: investor-owned utilities; federal power agencies; rural 
electric cooperatives; state, municipal and provincial utilities; 
independent power producers; power marketers; and end-use 
customers.'' Id.
    \127\ North American Electric Reliability Corporation, 
Frequently Asked Questions, at 5 (2013), available at http://www.nerc.com/AboutNERC/Documents/NERC%20FAQs%20AUG13.pdf. For 
example, a regional entity may propose reliability standards, 
including regional variances or regional reliability standards 
required to maintain and enhance electric service reliability, 
adequacy, and security in the region. See, e.g., Amended and 
Restated Delegation Agreement Between North American Reliability 
Corporation and Midwest Reliability Organization, Bylaws of the 
Midwest Reliability Organization, Inc., Section 2.2 (2012), 
available at http://www.nerc.com/FilingsOrders/us/Regional%20Delegation%20Agreements%20DL/MRO_RDA_Effective_20130612.pdf.
    \128\ North American Electric Reliability Corporation, 
Frequently Asked Questions, at 5 (2013), available at http://www.nerc.com/AboutNERC/Documents/NERC%20FAQs%20AUG13.pdf.
    \129\ ISOs/RTOs plan for system needs by ``effectively managing 
the load forecasting, transmission planning, and system and resource 
planning functions.'' For example, the New York Independent System 
Operator (NYISO) conducts reliability planning studies, which ``are 
used to assess current reliability needs based on user trends and 
historical energy use.'' NYISO, Planning Studies, available at 
http://www.nyiso.com/public/markets_operations/services/planning/planning_studies/index.jsp. See also PJM, Reliability Assessments, 
available at https://www.pjm.com/planning/rtep-development/reliability-assessments.aspx (stating that the PJM ``Regional 
Transmission Expansion Planning (RTEP) process includes the 
development of periodic reliability assessments to address specific 
system reliability issues in addition to the ongoing expansion 
planning process for the interconnection process of generation and 
merchant transmission.'').
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4. Modern Electric System Trends
    Today, the electricity sector is undergoing a period of intense 
change. Fossil fuels--such as coal, natural gas, and oil--have 
historically provided a large percentage of electricity in the U.S., 
along with nuclear power, with smaller amounts provided by other types 
of generation, including renewables such as wind, solar, and 
hydroelectric power. Coal provided the largest percentage of the fossil 
fuel generation.\130\ In recent years, the nation has seen a sizeable 
increase in renewable generation such as wind and solar, as well as a 
shift from coal to natural gas.\131\ In 2013, fossil fuels supplied 67 
percent of U.S. electricity,\132\ but the amount of renewable 
generation capacity continued to grow.\133\ From 2007 to 2014, use of 
lower- and zero-carbon energy sources such as wind and solar grew, 
while other major energy sources such as coal and petroleum generally 
experienced declines.\134\ Renewable electricity generation, including 
from large hydro-electric projects, grew from 8 percent to 13 percent 
over that time period.\135\ Between 2000 and 2013, approximately 90 
percent of new power generation capacity built in the U.S. came in the 
form of natural gas or RE facilities.\136\ In 2015, the U.S. Energy 
Information Administration (EIA) projected the need for 28.4 GW of 
additional base load or intermediate load generation capacity through 
2020.\137\ The vast majority of this new electric capacity (20.4 GW) is 
already under development (under construction or in advanced planning), 
with approximately 0.7 GW of new coal-fired capacity, 5.5 GW of new 
nuclear capacity, and 14.2 GW of new NGCC capacity already in 
development.
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    \130\ U.S. Energy Information Administration, ``Table 7.2b 
Electricity Net Generation: Electric Power Sector'' data from 
Monthly Energy Review May 2015, available at http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf (last visited May 26, 2015).
    \131\ U.S. Energy Information Administration, ``Table 7.2b 
Electricity Net Generation: Electric Power Sector'' data from 
Monthly Energy Review May 2015, release data April 25, 2014, 
available at http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf (last visited May 26, 2015).
    \132\ U.S. Energy Information Administration, ``Table 7.2b 
Electricity Net Generation: Electric Power Sector'' data from 
Monthly Energy Review May 2015, release data April 25, 2014, 
available at http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf (last visited May 26, 2015).
    \133\ Based on Table 6.3 (New Utility Scale Generating Units by 
Operating Company, Plant, Month, and Year) of the U.S. Energy 
Information Administration (EIA) Electric Power Monthly, data for 
December 2013, for the following RE sources: solar, wind, hydro, 
geothermal, landfill gas, and biomass. Available at http://www.eia.gov/electricity/monthly/epm_table_grapher.cfm?t=epmt_6_03.
    \134\ U.S. Energy Information Administration, ``Table 7.2b 
Electricity Net Generation: Electric Power Sector'' data from 
Monthly Energy Review May 2015, available at http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf (last visited May 26, 2015).
    \135\ Bloomberg New Energy Finance and the Business Council for 
Sustainable Energy, 2015 Factbook: Sustainable Energy in America, at 
16 (2015), available at http://www.bcse.org/images/2015%20Sustainable%20Energy%20in%20America%20Factbook.pdf. Bloomberg 
gave projections for 2014 values, accounting for seasonality, based 
on latest monthly values from EIA (data available through October 
2014).
    \136\ Energy Information Administration, Electricity: Form EIA-
860 detailed data (Feb. 17, 2015), available at http://www.eia.gov/electricity/data/eia860/.
    \137\ EIA, Annual Energy Outlook for 2015 with Projections to 
2040, Final Release, available at http://www.eia.gov/forecasts/AEO/pdf/0383(2015).pdf. The AEO numbers include projects that are under 
development and model-projected nuclear, coal, and NGCC projects.
---------------------------------------------------------------------------

    While the change in the resource mix has accelerated in recent 
years, wind, solar, other renewables, and EEresources have been 
reliably participating in the electric sector for a number of years. 
This rapid development of non-fossil fuel resources is occurring as 
much of the existing power generation fleet in the U.S. is aging and in 
need of modernization and replacement. In 2025, the average age of the 
coal-fired generating fleet is projected to be 49 years old, and 20 
percent of those units would be more than 60 years old if they remain 
in operation at that time. In its 2013 Report Card for America's 
Infrastructure, the American Society for Civil Engineers noted that 
``America relies on an aging electrical grid and pipeline distribution 
systems, some of which originated in the 1880s.'' \138\ While there has 
been an

[[Page 64695]]

increased investment in electric transmission infrastructure since 
2005, the report also found that ``ongoing permitting issues, weather 
events, and limited maintenance have contributed to an increasing 
number of failures and power interruptions.'' \139\ However, innovative 
technologies have increasingly entered the electric energy space, 
helping to provide new answers to how to meet the electricity needs of 
the nation. These new technologies can enable the nation to answer not 
just questions as to how to reliably meet electricity demand, but also 
how to meet electricity demand reliably and cost-effectively with the 
lowest possible emissions and the greatest efficiency.
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    \138\ American Society for Civil Engineers, 2013 Report Card for 
America's Infrastructure (2013), available at http://www.infrastructurereportcard .org/energy/.
    \139\ American Society for Civil Engineers, 2013 Report Card for 
America's Infrastructure (2013), available at http://www.infrastructurereportcard .org/energy/.
---------------------------------------------------------------------------

    Natural gas has a long history of meeting electricity demand in the 
U.S., with a rapidly growing role as domestic supplies of natural gas 
have dramatically increased. Natural gas net generation increased by 
approximately 32 percent between 2005 and 2014.\140\ In 2014, natural 
gas accounted for approximately 27 percent of net generation.\141\ EIA 
projects that this demand growth will continue with its Annual Energy 
Outlook 2015 (AEO 2015) Reference case forecasting that natural gas 
will produce 31 percent of U.S. electric generation in 2040.\142\
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    \140\ U.S. Energy Information Administration (EIA), Electric 
Power Monthly: Table 1.1 Net Generation by Energy Source: Total (All 
Sectors), 2005-February 2015 (2015), available athttp://www.eia.gov/electricity/monthly/epm_table_grapher.cfm?t=epmt_1_1 (last visited 
May 26, 2015).
    \141\ Id.
    \142\ U.S. Energy Information Administration (EIA), Annual 
Energy Outlook 2015 with Projections to 2040, at 24-25 (2015), 
available at http://www.eia.gov/forecasts/aeo/pdf/0383(2015).pdf. 
According to the EIA, the reference case assumes, ``Real gross 
domestic product (GDP) grows at an average annual rate of 2.4% from 
2013 to 2040, under the assumption that current laws and regulations 
remain generally unchanged throughout the projection period. North 
Sea Brent crude oil prices rise to $141/barrel (bbl) (2013 dollars) 
in 2040.'' Id. at 1. The EIA provides complete projection tables for 
the reference case in Appendix A of its report.
---------------------------------------------------------------------------

    Renewable sources of electric generation also have a history of 
meeting electricity demand in the U.S. and are expected to have an 
increasing role going forward. A series of energy crises provided the 
impetus for RE development in the early 1970s. The OPEC oil embargo in 
1973 and oil crisis of 1979 caused oil price spikes, more frequent 
energy shortages, and significantly affected the national and global 
economy. In 1978, partly in response to fuel security concerns, 
Congress passed the Public Utilities Regulatory Policies Act (PURPA) 
which required local electric utilities to buy power from qualifying 
facilities (QFs).\143\ QFs were either cogeneration facilities \144\ or 
small generation resources that use renewables such as wind, solar, 
biomass, geothermal, or hydroelectric power as their primary 
fuels.\145\ Through PURPA, Congress supported the development of more 
RE generation in the U.S. States have also taken a significant lead in 
requiring the development of renewable resources. In particular, a 
number of states have adopted renewable portfolio standards (RPS). As 
of 2013, 29 states and the District of Columbia have enforceable RPS or 
similar laws.\146\
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    \143\ Casazza, J. and Delea, F., Understanding Electric Power 
Systems, IEEE Press, at 220-221 (2d ed. 2010).
    \144\ Cogeneration facilities utilize a single source of fuel to 
produce both electricity and another form of energy such as heat or 
steam. Casazza, J. and Delea, F., Understanding Electric Power 
Systems, IEEE Press, at 220-221 (2d ed. 2010).
    \145\ Casazza, J. and Delea, F., Understanding Electric Power 
Systems, IEEE Press, at 220-221 (2d ed. 2010).
    \146\ U.S. Energy Information Administration (EIA), Annual 
Energy Outlook 2014 with Projections to 2040, at LR-5 (2014), 
available at http://www.eia.gov/forecasts/aeo/pdf/0383(2014).pdf 
(last visited May 26, 2015).
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    Use of RE continues to grow rapidly in the U.S. In 2013, 
electricity generated from renewable technologies, including 
conventional hydropower, represented 13 percent of total U.S. 
electricity, up from 9 percent in 2005.\147\ In 2013, U.S. non-hydro RE 
capacity for the total electric power industry exceeded 80,000 MW, 
reflecting a fivefold increase in just 15 years.\148\ In particular, 
there has been substantial growth in the wind and photovoltaic (PV) 
markets in the past decade. Since 2009, U.S. wind generation has 
tripled and solar generation has grown twenty-fold.\149\
---------------------------------------------------------------------------

    \147\ Energy Information Administration, Annual Energy Outlook 
2015 with Projections to 2040, at ES-6 (2014) and Energy Information 
Administration, Monthly Energy Review, May 2015, Table 7.2b, 
available at http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf.
    \148\ Non-hydro RE capacity for the total electric power 
industry was more than 16,000 megawatts (MW) in 1998. Energy 
Information Administration, 1990-2013 Existing Nameplate and Net 
Summer Capacity by Energy Source Producer Type and State (EIA-860), 
available at http://www.eia.gov/electricity/data/state/.
    \149\ Energy Information Administration, Monthly Energy Review, 
May 2015, Table 7.2b, available at http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf.
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    The global market for RE is projected to grow to $460 billion per 
year by 2030.\150\ RE growth is further encouraged by the significant 
amount of existing natural resources that can support RE production in 
the U.S.\151\ In the Energy Information Administration's Annual Energy 
Outlook 2015, RE generation grows substantially from 2013 to 2040 in 
the reference case and all alternative cases.\152\ In the reference 
case, RE generation increases by more than 70 percent from 2013 to 2040 
and accounts for over one-third of new generation capacity.\153\
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    \150\ ``Global Renewable Energy Market Outlook.'' Bloomberg New 
Energy Finance (Nov. 16, 2011), available at http://bnef.com/WhitePapers/download/53.
    \151\ Lopez et al., NREL, ``U.S. Renewable Energy Technical 
Potentials: A GIS-Based Analysis,'' (July 2012).
    \152\ Energy Information Administration, Annual Energy Outlook 
2015 with Projections to 2040, at 25 (2015), available at http://
www.eia.gov/forecasts/aeo/pdf/0383(2015).pdf.
    \153\ Energy Information Administration, Annual Energy Outlook 
2015 with Projections to 2040, at ES-6 (2015), available at http://
www.eia.gov/forecasts/aeo/pdf/0383(2015).pdf (last visited May 27, 
2015).
---------------------------------------------------------------------------

    Price pressures caused by oil embargoes in the 1970s also brought 
the issues of conservation and EE to the forefront of U.S. energy 
policy.\154\ This trend continued in the early 1990s. EE has been 
utilized to meet energy demand to varying levels since that time. As of 
April 2014, 25 states \155\ have ``enacted long-term (3+ years), 
binding energy savings targets, or energy efficiency resource standards 
(EERS).'' \156\ Funding for EE programs has grown rapidly in recent 
years, with budgets for electric efficiency programs totaling $5.9 
billion in 2012.\157\
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    \154\ Edison Electric Institute, Making a Business of Energy 
Efficiency: Sustainable Business Models for Utilities, at 1 (2007), 
available at http://www.eei.org/whatwedo/PublicPolicyAdvocacy/StateRegulation/Documents/Making_Business_Energy_Efficiency.pdf. 
Congress passed legislation in the 1970s that jumpstarted energy 
efficiency in the U.S. For example, President Ford signed the Energy 
Policy and Conservation Act (EPCA) of 1975--the first law on the 
issue. EPCA authorized the Federal Energy Administration (FEA) to 
``develop energy conservation contingency plans, established vehicle 
fuel economy standards, and authorized the creation of efficiency 
standards for major household appliances.'' Alliance to Save Energy, 
History of Energy Efficiency, at 6 (2013) (citing Anders, ``The 
Federal Energy Administration,'' 5; Energy Policy and Conservation 
Act, S. 622, 94th Cong. (1975-1976)), available at https://www.ase.org/sites/ase.org/files/resources/Media%20browser/ee_commission_history_report_2-1-13.pdf.
    \155\ American Council for an Energy-Efficient Economy, State 
Energy Efficiency Resource Standards (EERS) (2014), available at 
http://aceee.org/files/pdf/policy-brief/eers-04-2014.pdf. ACEEE did 
not include Indiana (EERS eliminated), Delaware (EERS pending), 
Florida (programs funded at levels far below what is necessary to 
meet targets), Utah, or Virginia (voluntary standards) in its 
calculation.
    \156\ American Council for an Energy-Efficient Economy, State 
Energy Efficiency Resource Standards (EERS) (2014), available at 
http://aceee.org/files/pdf/policy-brief/eers-04-2014.pdf.
    \157\ American Council for an Energy-Efficient Economy, The 2013 
State Energy Efficiency Scorecard, at 17 (Nov. 2013), available at 
http://aceee.org/sites/default/files/publications/researchreports/e13k.pdf.

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[[Page 64696]]

    Advancements and innovation in power sector technologies provide 
the opportunity to address CO2 emission levels at affected 
power plants while at the same time improving the overall power system 
in the U.S. by lowering the carbon intensity of power generation, and 
ensuring a reliable supply of power at a reasonable cost.

E. Clean Air Act Regulations for Power Plants

    In this section, we provide a general description of major CAA 
regulations for power plants. We refer to these in later sections of 
this preamble.
1. Title IV Acid Rain Program
    The EPA's Acid Rain Program, established in 1990 under Title IV of 
the CAA, addresses the presence of acidic compounds and their 
precursors (i.e., SO2 and NOX), in the atmosphere 
by targeting ``the principal sources'' of these pollutants through an 
SO2 cap-and-trade program for fossil-fuel fired power plants 
and through a technology based NOX emission limit for 
certain utility boilers. Altogether, Title IV was designed to achieve 
reductions of ten million tons of annual SO2 emissions, and, 
in combination with other provisions of the CAA, two million tons of 
annual NOX emissions.\158\
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    \158\ 42 U.S.C. 7651(b).
---------------------------------------------------------------------------

    The SO2 cap-and-trade program was implemented in two 
phases. The first phase, beginning in 1995, targeted one-hundred and 
ten named power plants, including specific generator units at each 
plant, requiring the plants to reduce their cumulative emissions to a 
specific level.\159\ Under certain conditions, the owner or operator of 
a named power plant could reassign an affected unit's reduction 
requirement to another unit and/or request an extension of two years 
for meeting the requirement.\160\ Congress also established an energy 
conservation and RE reserve from which up to 300,000 allowances could 
be allocated for qualified energy conservation measures or qualified 
RE.\161\
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    \159\ 42 U.S.C. 7651c (Table A).
    \160\ 42 U.S.C. 7651c(b) and (d).
    \161\ 42 U.S.C. 7651c(f) and (g).
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    The second phase, beginning in 2000, expanded coverage to more than 
2,000 generating units and set a national cap at 8.90 million 
tons.\162\ Generally, allowances were allocated at a rate of 1.2 lbs/
mmBtu multiplied by the unit's baseline and divided by 2000.\163\ 
However, bonus allowances could be awarded to certain units.
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    \162\ U.S. Dept. of Energy, Energy Information Administration, 
``The Effects of Title IV of the Clean Air Act Amendments of 1990 on 
Electric Utilities: An Update,'' p. vii. (March 1997).
    \163\ See 42 U.S.C. 7651d.
---------------------------------------------------------------------------

    Title IV also required the EPA to hold or sponsor annual auctions 
and sales of allowances for a small portion of the total allowances 
allocated each year. This ensured that some allowances would be 
directly available for new sources, including independent power 
production facilities.\164\
---------------------------------------------------------------------------

    \164\ 42 U.S.C. 7651o.
---------------------------------------------------------------------------

    The provisions of the EPA's Acid Rain Program are implemented 
through permits issued under the EPA's Title V Operating Permit 
Program.\165\ In accordance with Title IV, moreover, each Title V 
permit application must include a compliance plan for the affected 
source that details how that source expects to meet the requirements of 
Title IV.\166\
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    \165\ 42 U.S.C. 7651g.
    \166\ Such plans may simply state that the owner or operator 
expects to hold sufficient allowances or, in the case of alternative 
compliance methods, must provide a ``comprehensive description of 
the schedule and means by which the unit will rely on one or more 
alternative methods of compliance in the manner and time authorized 
under [Title IV].'' 42 U.S.C. 7651g(b).
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2. Transport Rulemakings
    CAA section 110(a)(2)(D)(i)(I), the ``Good Neighbor Provision,'' 
requires SIPs to prohibit emissions that ``contribute significantly to 
nonattainment . . . or interfere with maintenance'' of the NAAQS in any 
other state.\167\ If the EPA finds that a state has failed to submit an 
approvable SIP, the EPA must issue a federal implementation plan (FIP) 
to prohibit those emissions ``at any time'' within the next two 
years.\168\
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    \167\ 42 U.S.C. 7410(a)(2)(D)(i)(I).
    \168\ EPA v. EME Homer City Generation, L.P., 134 S. Ct. 1584, 
1600-01 (2014) (citing 42 U.S.C. 7410(c)).
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    In three major rulemakings--the NOX SIP Call,\169\ the 
Clean Air Interstate Rule (CAIR),\170\ and the Cross State Air 
Pollution Rule (CSAPR) \171\--the EPA has attempted to delineate the 
scope of the Good Neighbor Provision. These rulemakings have several 
features in common. Although the Good Neighbor Provision does not speak 
specifically about EGUs, in all three rulemakings, the EPA set state 
emission ``budgets'' for upwind states based in part on emissions 
reductions achievable by EGUs through application of cost-effective 
controls. Each rule also adopted a phased approach to reducing 
emissions with both interim and final goals.
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    \169\ 63 FR 57356 (Oct. 27, 1998).
    \170\ 70 FR 25162 (May 12, 2005).
    \171\ 76 FR 48208 (Aug. 8, 2011).
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    a. NOX SIP Call. In 1998, the EPA promulgated the 
NOX SIP Call, which required 23 upwind states to reduce 
emissions of NOX that would impact downwind areas with ozone 
problems. The EPA determined emission reduction requirements based on 
reductions achievable through ``highly cost-effective'' controls--i.e., 
controls that would cost on average no more than $2,000 per ton of 
emissions reduced.\172\ The EPA determined that a uniform emission rate 
on large EGUs coupled with a cap-and-trade program was one such set of 
highly cost-effective controls.\173\ Accordingly, the EPA established 
an interstate cap-and-trade program--the NOX Budget Trading 
Program--as a mechanism for states to reduce emissions from EGUs and 
other sources in a highly cost-effective manner. The D.C. Circuit 
upheld the NOX SIP Call in most significant respects, 
including its use of costs to apportion emission reduction 
responsibilities.\174\
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    \172\ 63 FR at 57377-78.
    \173\ 63 FR at 57377-78. In addition to EGUs, the NOX 
SIP Call also set budgets based on highly cost-effective emission 
reductions from certain other large sources. Id.
    \174\ Michigan v. EPA, 213 F.3d 663 (D.C. Cir. 2000).
---------------------------------------------------------------------------

    b. Clean Air Interstate Rule (CAIR). In 2005, the EPA promulgated 
CAIR, which required 28 upwind states to reduce emissions of 
NOX and SO2 that would impact downwind areas with 
projected nonattainment and maintenance problems for ozone and 
PM2.5. The EPA determined emission reduction requirements 
based on ``controls that are known to be highly cost effective for 
EGUs.'' \175\ The EPA established cap-and-trade programs for sources of 
NOX and SO2 in states that chose to participate 
in the trading programs via their SIPs and for states ultimately 
subject to a FIP.\176\ As relevant here, the D.C. Circuit remanded CAIR 
in North Carolina v. EPA due to in part the structure of its interstate 
trading provisions and the way in which EPA applied the cost-effective 
standard, but kept the rule in place while the EPA developed an 
acceptable substitute.\177\
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    \175\ 70 FR at 25163.
    \176\ 70 FR at 25273-75; 71 FR 25328 (April 28, 2006).
    \177\ 531 F.3d 896, 917-22 (D.C. Cir. 2008), modified on 
rehearing 550 F.3d 1176, 1178 (D.C. Cir. 2008).
---------------------------------------------------------------------------

    c. Cross-state Air Pollution Rule (CSAPR). In 2011, the EPA 
promulgated CSAPR, which required 27 upwind states to reduce emissions 
of NOX and SO2 that would impact downwind areas 
with projected nonattainment and

[[Page 64697]]

maintenance problems for ozone and PM2.5. The EPA determined 
emission reduction requirements based in part on the reductions 
achievable at certain cost thresholds by EGUs in each state, with 
certain provisions developed to account for the need to ensure 
reliability of the electric generating system.\178\ In the same action 
establishing these emission reduction requirements, the EPA promulgated 
FIPs that subjected states to trading programs developed to achieve the 
necessary reductions within each state.\179\ The U.S. Supreme Court 
upheld the EPA's use of cost to set emission reduction requirements, as 
well as its authority to issue the FIPs.\180\
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    \178\ 76 FR at 48270. The EPA adopted this approach in part to 
comport with the D.C. Circuit's opinion in North Carolina v. EPA 
remanding CAIR. Id. at 48270-71.
    \179\ 76 FR at 48209-16.
    \180\ EPA v. EME Homer City Generation, L.P., 134 S. Ct. 1584 
(2014).
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3. Clean Air Mercury Rule
    On March 15, 2005, the EPA issued a rule to control mercury (Hg) 
emissions from new and existing fossil fuel-fired power plants under 
CAA section 111(b) and (d). The rule, known as the Clean Air Mercury 
Rule (CAMR), established, in relevant part, a nationwide cap-and-trade 
program under CAA section 111(d), which was designed to complement the 
cap-and-trade program for SO2 and NOX emissions 
under the Clean Air Interstate Rule (CAIR), discussed above.\181\ 
Though CAMR was later vacated by the D.C. Circuit on account of the 
EPA's flawed CAA section 112 delisting rule, the court declined to 
reach the merits of the EPA's interpretation of CAA section 
111(d).\182\ Accordingly, CAMR continues to be an informative model for 
a cap-and-trade program under CAA section 111(d).
---------------------------------------------------------------------------

    \181\ See 70 FR 28606 (May 18, 2005).
    \182\ New Jersey v. EPA, 517 F.3d 574 (D.C. Cir. 2008).
---------------------------------------------------------------------------

    The cap-and-trade program in CAMR was designed to take effect in 
two phases: in 2010, the cap was set at 38 tons of mercury per year, 
and in 2018, the cap would be lowered to 15 tons per year. The Phase I 
cap was set at a level reflecting the co-benefits of CAIR as determined 
through economic and environmental modeling.\183\ For the more 
stringent Phase II cap, the EPA projected that sources would ``install 
SCR [selective catalytic reduction] to meet their SO2 and 
NOX requirements and take additional steps to address the 
remaining Hg reduction requirements under CAA section 111, including 
adding Hg-specific control technologies (model applies ACI [activated 
carbon injection]), additional scrubbers and SCR, dispatch changes, and 
coal switching.'' \184\ Based on this analysis, EPA determined that the 
BSER ``refers to the combination of the cap-and-trade mechanism and the 
technology needed to achieve the chosen cap level.'' \185\
---------------------------------------------------------------------------

    \183\ 70 FR 28606, at 28617. The EPA's projections under CAIR 
showed a significant number of affected sources would install 
scrubbers for SO2 and selective catalytic reduction for 
NOX on coal-fired power plants, which had the co-benefit 
of capturing mercury emissions. Id. at 28619.
    \184\ 70 FR 28606, at 28619.
    \185\ 70 FR 28606, at 28620.
---------------------------------------------------------------------------

    To accompany the nationwide emissions cap, the EPA also assigned a 
statewide emissions budget for mercury. Pursuant to CAA section 111(d), 
states would be required to submit plans to the EPA ``detailing the 
controls that will be implemented to meet its specified budget for 
reductions from coal-fired Utility Units.'' \186\ Of course, states 
were ``not required to adopt and implement'' the emission trading 
program, ``but they [were] required to be in compliance with their 
statewide Hg emission budget.'' \187\
---------------------------------------------------------------------------

    \186\ 70 FR 28606, at 28621.
    \187\ 70 FR 28606, at 28621. That said, states could ``require 
reductions beyond those required by the [s]tate budget.'' Id. at 
28621.
---------------------------------------------------------------------------

4. Mercury Air Toxics Rule
    On February 16, 2012, the EPA issued the MATS rule (77 FR 9304) to 
reduce emissions of toxic air pollutants from new and existing coal- 
and oil-fired EGUs. The MATS rule will reduce emissions of heavy 
metals, including mercury, arsenic, chromium, and nickel; and acid 
gases, including hydrochloric acid and hydrofluoric acid. These toxic 
air pollutants, also known as hazardous air pollutants or air toxics, 
are known to cause, or suspected of causing, nervous system damage, 
cancer, and other serious health effects. The MATS rule will also 
reduce SO2 and fine particle pollution, which will reduce 
particle concentrations in the air and prevent thousands of premature 
deaths and tens of thousands of heart attacks, bronchitis cases and 
asthma episodes.
    New or reconstructed EGUs (i.e., sources that commence construction 
or reconstruction after May 3, 2011) subject to the MATS rule are 
required to comply by April 16, 2012 or upon startup, whichever is 
later.
    Existing sources subject to the MATS rule were required to begin 
meeting the rule's requirements on April 16, 2015. Controls that will 
achieve the MATS performance standards are being installed on many 
units. Certain units, especially those that operate infrequently, may 
be considered not worth investing in given today's electricity market, 
and are closing. The final MATS rule provided a foundation on which 
states and other permitting authorities could rely in granting an 
additional, fourth year for compliance provided for by the CAA. States 
report that these fourth year extensions are being granted. In 
addition, the EPA issued an enforcement policy that provides a clear 
pathway for reliability-critical units to receive an administrative 
order that includes a compliance schedule of up to an additional year, 
if it is needed to ensure electricity reliability.
    Following promulgation of the MATS rule, industry, states and 
environmental organizations challenged many aspects of the EPA's 
threshold determination that regulation of EGUs is ``appropriate and 
necessary'' and the final standards regulating hazardous air pollutants 
from EGUs. The U.S. Court of Appeals for the D.C. Circuit upheld all 
aspects of the MATS rule. White Stallion Energy Center v. EPA, 748 F.3d 
1222 (D.C. Cir. 2014). In Michigan v. EPA, case no. 14-46, the U.S. 
Supreme Court reversed the portion of the D.C. Circuit decision finding 
the EPA was not required to consider cost when determining whether 
regulation of EGUs was ``appropriate'' pursuant to section 112(n)(1). 
The Supreme Court considered only the narrow question of whether the 
EPA erred in not considering cost when making this threshold 
determination. The Court's decision did not disturb any of the other 
holdings of the D.C. Circuit. The Court remanded the case to the D.C. 
Circuit for further proceedings, and the MATS rule remains in place at 
this time.
5. Regional Haze Rule
    Under CAA section 169A, Congress ``declare[d] as a national goal 
the prevention of any future, and the remedying of any existing, 
impairment of visibility'' in national parks and wilderness areas that 
results from anthropogenic emissions.\188\ To achieve this goal, 
Congress directed the EPA to promulgate regulations directing states to 
submit SIPs that ``contain such emission limits, schedules of 
compliance and other measures as may be necessary to make reasonable 
progress toward meeting the national goal. . . .'' \189\ One such 
measure that Congress deemed necessary to make reasonable progress was 
a requirement that certain older stationary sources that cause or 
contribute to visibility impairment ``procure, install, and operate, as 
expeditiously as practicable

[[Page 64698]]

. . . the best available retrofit technology,'' more commonly referred 
to as BART.\190\ When determining BART for large fossil-fuel fired 
utility power plants, Congress required states to adhere to guidelines 
to be promulgated by the EPA.\191\ As with other SIP-based programs, 
the EPA is required to issue a FIP within two years if a state fails to 
submit a regional haze SIP or if the EPA disapproves such SIP in whole 
or in part.\192\
---------------------------------------------------------------------------

    \188\ 42 U.S.C. 7491(a)(1).
    \189\ 42 U.S.C. 7491(b)(2).
    \190\ 42 U.S.C. 7491(b)(2)(A).
    \191\ 42 U.S.C. 7491(b)(2).
    \192\ 42 U.S.C. 7410(c); 7491(b)(2)(A).
---------------------------------------------------------------------------

    In 1999, the EPA promulgated the Regional Haze Rule to satisfy 
Congress' mandate that EPA promulgate regulations directing states to 
address visibility impairment.\193\ Among other things, the Regional 
Haze Rule allows states to satisfy the Act's BART requirement either by 
adopting source-specific emission limitations or by adopting 
alternatives, such as emissions-trading programs, that achieve greater 
reasonable progress than would source-specific BART.\194\ The Ninth 
Circuit and D.C. Circuit have both upheld the EPA's interpretation that 
CAA section 169A(b)(2) allows for BART alternatives in lieu of source-
specific BART.\195\ In 2005, the EPA promulgated BART Guidelines to 
assist states in determining which sources are subject to BART and what 
emission limitations to impose at those sources.\196\
---------------------------------------------------------------------------

    \193\ 64 FR 35714 (July 1, 1999) (codified at 40 CFR 51.308-
309).
    \194\ 40 CFR 51.308(e)(1) & (2).
    \195\ See Utility Air Regulatory Grp. v. EPA, 471 F.3d 1333 
(D.C. Cir. 2006); Ctr. for Econ. Dev. v. EPA, 398 F.3d 653 (D.C. 
Cir. 2005); Cent. Ariz. Water Dist. v. EPA, 990 F.2d 1531 (9th Cir. 
1993).
    \196\ 70 FR 39104 (July 6, 2005) (codified at 40 CFR pt. 51, 
app. Y).
---------------------------------------------------------------------------

    The Regional Haze Rule set a goal of achieving natural visibility 
conditions by 2064 and requires states to revise their regional haze 
SIPs every ten years.\197\ The first planning period, which ends in 
2018, focused heavily on the BART requirement. States (or the EPA in 
the case of FIPs) made numerous source-specific BART determinations, 
and developed several BART alternatives, for utility power plants. For 
the next planning period, states will need to determine whether 
additional controls are necessary at these plants (and others that were 
not subject to BART) in order to make reasonable progress towards the 
national visibility goal.\198\
---------------------------------------------------------------------------

    \197\ See 40 CFR 51.308(d)(1)(i)(B), (f).
    \198\ See 42 U.S.C. 7491(b)(2); 40 CFR 51.308(d)(3).
---------------------------------------------------------------------------

F. Congressional Awareness of Climate Change in the Context of the 
Clean Air Act Amendments \199\
---------------------------------------------------------------------------

    \199\ The following discussion is not meant to be exhaustive. 
There are many other instances outside the context of the CAA, 
before and after 1970, when Congress discussed or was presented with 
evidence on climate change.
---------------------------------------------------------------------------

    During its deliberations on the 1970 Clean Air Act Amendments, 
Congress learned that ongoing pollution, including from manmade carbon 
dioxide, could ``threaten irreversible atmospheric and climatic 
changes.'' \200\ At that time, Congress heard the views of scientists 
that carbon dioxide emissions tended to increase global temperatures, 
but that there was uncertainty as to the extent to which those 
increases would be offset by the decreases in temperatures brought 
about by emissions of particulates. President Nixon's Council on 
Environmental Quality (CEQ) reported that ``the addition of 
particulates and carbon dioxide in the atmosphere could have dramatic 
and long-term effects on world climate.'' \201\ The CEQ's First Annual 
Report, which was transmitted to Congress, devoted a chapter to ``Man's 
Inadvertent Modification of Weather and Climate.'' \202\ Moreover, 
Charles Johnson, Jr., Administrator of the Consumer Protection and 
Environmental Health Service, testified before the House Subcommittee 
on Public Health that ``the carbon dioxide balance might result in the 
heating up of the atmosphere whereas the reduction of the radiant 
energy through particulate matter released to the atmosphere might 
cause reduction in radiation that reaches the earth.'' \203\ 
Administrator Johnson explained that the Nixon Administration was 
``concerned . . . that neither of these things happen'' and that they 
were ``watching carefully the kind of prognosis, the kind of 
calculations that the scientists make to look at the continuous balance 
between heat and cooling of the total earth's atmosphere.'' \204\ He 
concluded that ``[w]hat we are trying to do, however, in terms of our 
air pollution effort should have a very salutary effect on either of 
these.'' \205\
---------------------------------------------------------------------------

    \200\ Sen. Scott, S. Debate on S. 4358 (Sept. 21, 1970), 1970 
CAA Legis. Hist. at 349.
    \201\ Council on Environmental Quality, ``The First Annual 
Report of the Council on Environmental Quality,'' p. 110 (Aug. 1970) 
(recognizing also that ``[man] can increase the carbon dioxide 
content of the atmosphere by burning fossil fuels'' and postulating 
that an increase in the earth's average temperature by about 2[deg] 
to 3[deg] F ``could in a period of decades, lead to the start of 
substantial melting of ice caps and flooding of coastal regions.'').
    \202\ Council on Environmental Quality, ``The First Annual 
Report of the Council on Environmental Quality,'' p. 93-104 (Aug. 
1970)
    \203\ Testimony of Charles Johnson, Jr., Administrator of the 
Consumer Protection and Environmental Health Service (Administration 
Testimony), Hearing of the House Subcommittee on Public Health and 
Welfare (Mar. 16, 1970), 1970 CAA Legis. Hist. at 1381.
    \204\ Testimony of Charles Johnson, Jr., Administrator of the 
Consumer Protection and Environmental Health Service (Administration 
Testimony), Hearing of the House Subcommittee on Public Health and 
Welfare (Mar. 16, 1970), 1970 CAA Legis. Hist. at 1381.
    \205\ Testimony of Charles Johnson, Jr., Administrator of the 
Consumer Protection and Environmental Health Service (Administration 
Testimony), Hearing of the House Subcommittee on Public Health and 
Welfare (Mar. 16, 1970), 1970 CAA Legis. Hist. at 1381.
---------------------------------------------------------------------------

    Scientific reports on climatic change continued to gain traction in 
Congress through the mid-1970s, including while Congress was 
considering the 1977 CAA Amendments. However, uncertainty continued as 
to whether the increased warming brought about by carbon dioxide 
emissions would be offset by cooling brought about by particulate 
emissions.\206\ Congress ordered, as part of the 1977 CAA Amendments, 
the National Oceanic and Atmospheric Administration to research and 
monitor the stratosphere ``for the purpose of early detection of 
changes in the stratosphere and climatic effects of such changes.'' 
\207\
---------------------------------------------------------------------------

    \206\ For instance, while scientists, such as Stephen Schneider 
of the National Center for Atmospheric Research, testified that 
``manmade pollutants will affect the climate,'' they believed that 
we would ``see a general cooling of the Earth's atmosphere.'' Rep. 
Scheuer, H. Debates on H.R. 10498 (Sept. 15, 1976), 1977 CAA Legis. 
Hist. at 6477. Additionally, the Department of Transportation's 
climatic impact assessment program and the Climatic Impact Committee 
of the National Research Council, National Academies of Science and 
Engineering both reported that ``warming or cooling'' could occur. 
Id. at 6476. See also Sen. Bumpers, S. Debates on S. 3219 (August 3, 
1976), 1977 CAA Legis. Hist. at 5368 (inserting ``Summary of 
Statements Received [in the Subcommittee on the Environment and the 
Atmosphere] from Professional Societies for the Hearings on Effects 
of Chronic Pollution'' into the record, which noted that ``there is 
near unamity [sic] that carbon dioxide concentrations in the 
atmosphere are increasing rapidly.'').
    \207\ ``Clean Air Act Amendments of 1977,'' Sec.  125, 91 Stat. 
at 728.
---------------------------------------------------------------------------

    Between the 1977 and 1990 Clean Air Act Amendments, scientific 
uncertainty yielded to the predominant view that global warming ``was 
likely to dominate on time scales that would be significant to human 
societies.'' \208\ In fact, as part of the 1990 Clean Air Act 
Amendments, Congress specifically required the EPA to collect data on 
carbon dioxide emissions--the most significant of the GHGs--from all 
sources subject to the

[[Page 64699]]

newly enacted operating permit program under Title V.\209\ Although 
Congress did not require the EPA to take immediate action to address 
climate change, Congress did identify certain tools that were 
particularly helpful in addressing climate change in the utility power 
sector. The Senate report discussing the acid rain provisions of Title 
IV noted that some of the measures that would reduce coal-fired power 
plant emissions of the precursors to acid rain would also reduce those 
facilities' emissions of CO2. The report stated:
---------------------------------------------------------------------------

    \208\ Peterson, Thomas C., William M. Connolley, and John Fleck, 
``The Myth of the 1970s Global Cooling Scientific Consensus,'' 
Bulletin of the American Meteorological Society, p. 1326 (September 
2008), available at http://journals.ametsoc.org/doi/pdf/10.1175/2008BAMS2370.1.
    \209\ ``Clean Air Act Amendments of 1990,'' Sec.  820, 104 Stat. 
at 2699.

    Energy efficiency is a crucial tool for controlling the 
emissions of carbon dioxide, the gas chiefly responsible for the 
intensification of the atmospheric `greenhouse effect.' In the last 
several years, the Committee has received extensive scientific 
testimony that increases in the human-caused emissions of carbon 
dioxide and other greenhouse gases will lead to catastrophic shocks 
in the global climate system. Accordingly, new title IV shapes an 
acid rain reduction policy that encourages energy efficiency and 
other policies aimed at controlling greenhouse gases.\210\
---------------------------------------------------------------------------

    \210\ Sen. Chafee, S. Debate on S. 1630 (Jan. 24, 1990), 1990 
CAA Legis. Hist. at 8662.

Similarly, Title IV provisions to encourage RE were justified because 
``renewables not only significantly curtail sulfur dioxide emissions, 
but they emit little or no nitrogen oxides and carbon dioxide''.\211\
---------------------------------------------------------------------------

    \211\ Additional Views of Rep. Markey and Rep. Moorhead, H.R. 
Rep. No. 101-490, at 674 (May 17, 1990).
---------------------------------------------------------------------------

G. International Agreements and Actions

    In this final rule, the U.S. is taking action to limit GHGs from 
one of its largest emission sources. Climate change is a global 
problem, and the U.S. is not alone in taking action to address it. The 
UNFCCC \212\ is the international treaty under which countries (called 
``Parties'') cooperatively consider what can be done to limit 
anthropogenic climate change \213\ and adapt to climate change impacts. 
Currently, there are 195 Parties to the UNFCCC, including the U.S. The 
Conference of the Parties (COP) meets annually and is currently 
considering commitments countries can make to limit emissions after 
2020. The 2015 COP will be in Paris and is expected to represent an 
historic step for climate change mitigation. The Parties to the UNFCC 
will meet to establish a climate agreement that applies to all 
countries and focuses on reducing GHG emissions. Such an outcome would 
send a beneficial signal to the markets and civil society about global 
action to address climate change.
---------------------------------------------------------------------------

    \212\ http://unfccc.int/2860.php.
    \213\ Article 2, Objective, The ultimate objective of this 
Convention and any related legal instruments that the Conference of 
the Parties may adopt is to achieve, in accordance with the relevant 
provisions of the Convention, stabilization of greenhouse gas 
concentrations in the atmosphere at a level that would prevent 
dangerous anthropogenic interference with the climate system. Such a 
level should be achieved within a time frame sufficient to allow 
ecosystems to adapt naturally to climate change, to ensure that food 
production is not threatened and to enable economic development to 
proceed in a sustainable manner. http://unfccc.int/files/essential_background/convention/background/application/pdf/convention_text_with_annexes_english_for_posting.pdf
---------------------------------------------------------------------------

    Many countries have announced their intended post-2020 commitments 
already, and other countries are expected to do so before December. In 
April 2015, the U.S. announced its commitment to reduce GHG emissions 
26-28 percent below 2005 levels by 2025.\214\
---------------------------------------------------------------------------

    \214\ United States Cover Note to Intended Nationally Determined 
Contribution (INDC). Available online at: http://www4.unfccc.int/submissions/INDC/Published%20Documents/United%20States%20of%20America/1/U.S.%20Cover%20Note%20INDC%20and%20Accompanying%20Information.pdf.
---------------------------------------------------------------------------

    As Parties to both the UNFCCC and the Kyoto Protocol,\215\ the 
European Union (EU) and member countries have taken aggressive action 
to reduce GHG emissions.\216\ EU initiatives to reduce GHG emissions 
include the EU Emissions Trading System, legislation to increase the 
adoption of RE sources, strengthened EE targets, vehicle emission 
standards, and support for the development of CCS technology for use by 
the power sector and other industrial sources. In 2009, the EU 
announced its ``20-20-20 targets,'' including a 20 percent reduction in 
GHG emissions from 1990 levels by 2020, an increase of 20 percent in 
the share of energy consumption produced by renewable resources, and a 
20 percent improvement in EE. In March 2015, the EU announced its 
commitment to reduce domestic GHG emissions by at least 40% from 1990 
levels by 2030.
---------------------------------------------------------------------------

    \215\ http://unfccc.int/kyoto_protocol/items/2830.php.
    \216\ http://ec.europa.eu/clima/policies/brief/eu/index_en.htm.
---------------------------------------------------------------------------

    Recently, China has also agreed to take action to address climate 
change. In November 2014, in a joint announcement by President Obama 
and China's President Xi, China pledged to curtail GHG emissions, with 
emissions peaking in 2030 and then declining thereafter, and to 
increase the share of energy from non-carbon sources (solar, wind, 
hydropower, nuclear) to 20 percent by 2030.
    Mexico is committed to reduce unconditionally 25 percent of its 
emissions of GHGs and short-lived climate pollutants (below business as 
usual) for the year 2030. This commitment implies a 22 percent 
reduction of GHG emissions and a 51 percent reduction of black carbon 
emissions.
    Brazil has reduced its net CO2 emissions more than any 
other country through a historic effort to slow forest loss. The 
deforestation rate in Brazil in 2014 was roughly 75 percent below the 
average for 1996 to 2005.\217\
---------------------------------------------------------------------------

    \217\ http://www.nature.com/news/stopping-deforestation-battle-for-the-amazon-1.17223.
---------------------------------------------------------------------------

    Together, countries that have already announced their intended 
post-2020 commitments, including the U.S., China, European Union, 
Mexico, Russian Federation and Brazil, make up a large majority of 
global emissions.
    President Obama's Climate Action Plan contains a number of policies 
and programs that are intended to cut carbon pollution that causes 
climate change and affects public health. The Clean Power Plan is a key 
component of the plan, addressing the nation's largest source of 
emissions in a comprehensive manner. Collectively, these policies will 
help spark business innovation, result in cleaner forms of energy, 
create jobs, and cut dependence on foreign oil. They also demonstrate 
to the rest of the world that the U.S. is contributing its share of the 
global effort that is needed to address climate change.\218\ This 
demonstration encourages other major economies to take on similar 
contributions, which is critical given the global impact of GHG 
emissions. The State Department Special Envoy for Climate Change Todd 
Stern, the lead U.S. climate change negotiator, noted the connection 
between domestic and international action to address climate change in 
his speech at Yale University on October 14, 2014:
---------------------------------------------------------------------------

    \218\ President Obama stated, in announcing the Climate Action 
Plan:
    ``The actions I've announced today should send a strong signal 
to the world that America intends to take bold action to reduce 
carbon pollution. We will continue to lead by the power of our 
example, because that's what the United States of America has always 
done.'' President Obama, Climate Action Plan speech, Georgetown 
University, 2013. Available at https://www.whitehouse.gov/the-press-office/2013/06/25/remarks-president-climate-change.

    This mobilization of American effort matters. Enormously. It 
matters because the United States is the biggest economy and largest 
historic emitter of greenhouse gases. Because, here, as in so many 
areas, we feel a responsibility to lead. And because here, as in so 
many areas, we find that American commitment is indispensable to 
effective international action.
    And make no mistake--other countries see what we are doing and 
are taking note. As I travel the world and meet with my

[[Page 64700]]

counterparts, the palpable engagement of President Obama and his 
team has put us in a stronger, more credible position than ever 
before.

    This final rule demonstrates to other countries that the U.S. is 
taking action to limit GHG emissions from its largest emission sources, 
in line with our international commitments. The impact of GHGs is 
global, and U.S. action to reduce GHG emissions complements and 
encourages ongoing programs and efforts in other countries.

H. Legislative and Regulatory Background for CAA Section 111

    In the final days of December 1970, Congress enacted sweeping 
changes to the Air Quality Act of 1967 to confront an ``environmental 
crisis.'' \219\ The Air Quality Act--which expanded federal air 
pollution control efforts after the enactment of the Clean Air Act of 
1963--prioritized the adoption of ambient air standards but failed to 
target stationary sources of air pollution. As a result, ``[c]ities up 
and down the east coast were living under clouds of smoke and daily air 
pollution alerts.'' \220\ In fact, ``[o]ver 200 million tons of 
contaminants . . . spilled into the air'' each year.\221\ The 1970 CAA 
Amendments were designed to face this crisis ``with urgency and in 
candor.'' \222\
---------------------------------------------------------------------------

    \219\ Sen. Muskie, S. Debate on S. 4358 (Sept. 21, 1970), 1970 
CAA Legis. Hist. at 224.
    \220\ Sen. Muskie, S. Consideration of H.R. Conf. Rep. No. 91-
1783 (Dec. 18, 1970), 1970 CAA Legis. Hist.pa at 123.
    \221\ Sen. Muskie, S. Debate on S. 4358 (Sept. 21, 1970), 1970 
CAA Legis. Hist. at 224. These pollutants fell into five main 
classes of pollutants: Carbon monoxide, particulates, sulfur oxides, 
hydrocarbons, and nitrogen oxides. See Sen. Boggs, id. at 244.
    \222\ Sen. Muskie, S. Consideration of H.R. Conf. Rep. No. 91-
1783 (Dec. 18, 1970), 1970 CAA Legis. Hist. at 123.
---------------------------------------------------------------------------

    For the most part, Congress gave EPA and the states flexible tools 
to implement the CAA. This is best exhibited by the newly enacted 
programs regulating stationary sources. For these sources, Congress 
crafted a three-legged regime upon which the regulation of stationary 
sources was intended to sit.
    The first prong--CAA sections 107-110--addressed what are commonly 
referred to as criteria pollutants, ``the presence of which in the 
ambient air results from numerous or diverse mobile or stationary 
sources'' and are determined to have ``an adverse effect on public 
health or welfare''.\223\ Under these provisions, states would have the 
primary responsibility for assuring air quality within their entire 
geographic area but would submit plans to the Administrator for 
``implementation, maintenance, and enforcement'' of national ambient 
air quality standards. These plans would include ``emission 
limitations, schedules, and timetables for compliance . . . and such 
other measures as may be necessary to insure attainment and 
maintenance'' of the national ambient air quality standards.\224\
---------------------------------------------------------------------------

    \223\ ``Clean Air Act Amendments of 1970,'' Pub. L. 91-604, 
Sec.  4, 84 Stat. 1676, 1678 (Dec. 31, 1970). The ``adverse effect'' 
criterion was later amended to refer to pollutants ``which may 
reasonably be anticipated to endanger public health or welfare''. 
See 42 U.S.C. 7408(a)(1)(A). Similar language is also used under the 
current CAA section 111. See 42 U.S.C. 7411(b)(1)(A).
    \224\ ``Clean Air Act Amendments of 1970,'' Sec.  4, 84 Stat. at 
1680.
---------------------------------------------------------------------------

    The second prong--CAA section 111--addressed pollutants on a source 
category-wide basis. Under CAA section 111(b), the EPA lists source 
categories which ``contribute significantly to air pollution which 
causes or contributes to the endangerment of public health or 
welfare,'' And then establishes ``standards of performance'' for the 
new sources in the listed category.\225\ For existing sources in a 
listed source category, CAA section 111(d) set out procedures for the 
establishment of federally enforceable ``emission standards'' of any 
pollutant not otherwise controlled under the CAA's SIP provisions or 
CAA section 112.
---------------------------------------------------------------------------

    \225\ ``Clean Air Act Amendments of 1970,'' Sec.  4, 84 Stat. at 
1684.
---------------------------------------------------------------------------

    Lastly, the third prong--CAA section 112--addressed hazardous air 
pollutants through the establishment of national ``emission standards'' 
at a level which ``provides an ample margin of safety to protect the 
public health''.\226\ All new or modified sources of any hazardous air 
pollutant would be required to meet these emission standards. Existing 
sources were required to meet the same standards or would be shut down 
unless they obtained a temporary EPA waiver or Presidential 
exemption.\227\
---------------------------------------------------------------------------

    \226\ ``Clean Air Act Amendments of 1970,'' Sec.  4, 84 Stat. at 
1685.
    \227\ ``Clean Air Act Amendments of 1970,'' Sec.  4, 84 Stat. at 
1685.
---------------------------------------------------------------------------

    At its inception, CAA section 111 was intended to bear a 
significant weight under this three-legged regime. Indeed, by 1977, the 
EPA had promulgated six times as many performance standards under CAA 
section 111 than emission standards under CAA section 112.\228\ That 
said, states, including Texas and New Jersey, levied ``substantial 
criticisms'' against the EPA for not moving rapidly enough.\229\ 
Accordingly, the 1977 CAA Amendments were designed to ``provide a 
greater role for the [s]tates in standards setting under the [CAA],'' 
``protect [s]tates from `environmental blackmail' as they attempt to 
regulate mobile and competitive industries,'' and lastly ``provide a 
check on the Administrator's inaction or failure to control emissions 
adequately.'' \230\
---------------------------------------------------------------------------

    \228\ H.R. Rep. No. 95-294, at 194 (May 12, 1977).
    \229\ H.R. Rep. No. 95-294, at 194 (May 12, 1977).
    \230\ H.R. Rep. No. 95-294, at 195 (May 12, 1977).
---------------------------------------------------------------------------

    At bottom, CAA section 111 rests on the definition of a standard of 
performance under CAA section 111(a)(1), which reads nearly the same 
now as it did when it was first adopted in the 1970 CAA Amendments. In 
1970, Congress defined standard of performance--a term which had not 
previously appeared in the CAA--as

a standard for emissions of air pollutants which reflects the degree 
of emission limitation achievable through the application of the 
best system of emission reduction which (taking into account the 
cost of achieving such reduction) the Administrator determines has 
been adequately demonstrated.\231\
---------------------------------------------------------------------------

    \231\ ``Clean Air Act Amendments of 1970,'' Sec.  4, 84 Stat. at 
1683.

    Despite significant changes to this definition in 1977, Congress 
reversed course in 1990 and largely reinstated the original 
definition.\232\ As presently defined, the term applies to the 
regulation of new and existing sources under CAA sections 111(b) and 
(d).\233\
---------------------------------------------------------------------------

    \232\ ``Clean Air Act Amendments of 1990,'' Pub. L. 101-549, 
Sec.  403, 104 Stat. 2399, 2631 (Nov. 15, 1990) (retaining only the 
obligation to account for ``any nonair quality health and 
environmental impact and energy requirements'' that was added in 
1977).
    \233\ As CAA section 111(d) was originally adopted, state plans 
would have established ``emission standards'' instead of ``standards 
of performance.'' This distinction was later abandoned in 1977 and 
the same term is used in both CAA sections 111(b) and (d).
---------------------------------------------------------------------------

    The level of control reflected in the definition is generally 
referred to as the ``best system of emission reduction,'' or the BSER. 
The BSER, however, is not further defined, and only appeared after 
conference between the House and Senate in late 1970, and was neither 
discussed in the conference report nor openly debated in either 
chamber. Nevertheless, the originating bills from both houses shed 
light on its construction.
    The BSER grew out of proposed language in two bills, which, for the 
first time, targeted air pollution from stationary sources. The House 
bill sought to establish national emission standards to ``prevent and 
control . . . emissions [of non-hazardous pollutants] to the fullest 
extent compatible with the available technology and economic 
feasibility.'' \234\ The House also

[[Page 64701]]

proposed to prohibit the construction or operation of new sources of 
``extremely hazardous'' pollutants.\235\ The Senate bill, on the other 
hand, authorized ``Federal standards of performance,'' which would 
``reflect the greatest degree of emission control which the Secretary 
[later, the Administrator] determines to be achievable through 
application of the latest available control technology, processes, 
operating methods, or other alternatives.'' \236\ The Senate also would 
have authorized ``national emission standards'' for hazardous air 
pollution and other ``selected air pollution agents.'' \237\
---------------------------------------------------------------------------

    \234\ H.R. 17255, 91st Cong. Sec.  5 (1970).
    \235\ H.R. 17255, 91st Cong. Sec.  5 (1970).
    \236\ S. 4358, 91st Cong. Sec.  6 (1970) (emphasis added). The 
breadth of the Senate bill is further emphasized in the conference 
report, which explains that a standard of performance ``refers to 
the degree of emission control which can be achieved through process 
changes, operation changes, direct emission control, or other 
methods'' and also includes ``other means of preventing or 
controlling air pollution.'' S. Rep. No. 91-1196, at 15-16 (Sept. 
17, 1970).
    \237\ S. 4358, 91st Cong. Sec.  6 (1970).
---------------------------------------------------------------------------

    After conference, CAA section 111 emerged as one of the CAA's three 
programs for regulating stationary sources. In defining the newly 
formed ``standards of performance,'' Congress appeared to merge the 
various ``means of preventing and controlling air pollution'' under the 
Senate bill with the consideration of costs that was central to the 
House bill into the BSER. At the time, however, this definition only 
applied to new sources under CAA section 111(b).
    To regulate existing sources, Congress collapsed section 114 of the 
Senate bill into CAA section 111(d).\238\ Section 114 of the Senate 
bill established emission standards for ``selected air pollution 
agents,'' and was intended to bridge the gap between criteria 
pollutants and hazardous air pollutants. As proposed, the Senate 
identified fourteen substances for regulation under section 114 and 
only four substances for regulation under Senate bill 4358, section 
115, the predecessor of CAA section 112.\239\
---------------------------------------------------------------------------

    \238\ The House bill did not provide for the direct regulation 
of existing sources.
    \239\ See S. Rep. No. 91-1196, at 18 and 20 (Sept. 17, 1970).
---------------------------------------------------------------------------

    As adopted, CAA section 111(d) requires states to submit plans to 
the Administrator establishing ``emission standards'' for certain 
existing sources of air pollutants that were not otherwise regulated as 
criteria pollutants or hazardous air pollutants. This ensured that 
there would be ``no gaps in control activities pertaining to stationary 
source emissions that pose any significant danger to public health or 
welfare.'' \240\
---------------------------------------------------------------------------

    \240\ S. Rep. No. 91-1196, at 20 (Sept. 17, 1970) (discussing 
the relationship between sections 114 (addressing emission standards 
for ``selected air pollution agents'') and 115 (addressing hazardous 
air pollutants) of the Senate bill).
---------------------------------------------------------------------------

    The term ``emission standards,'' however, was not expressly defined 
in the 1970 CAA Amendments (save for purposes of citizen suit 
enforcement) even though the term was also used under the CAA's SIP 
provisions and CAA section 112.\241\ That said, under the newly enacted 
``ambient air quality and emission standards'' sections, Congress 
directed the EPA to provide states with information ``on air pollution 
control techniques,'' including data on ``available technology and 
alternative methods of prevention and control of air pollution'' and on 
``alternative fuels, processes, and operating methods which will result 
in elimination or significant reduction of emissions.'' \242\ 
Similarly, the Administrator would ``issue information on pollution 
control techniques for air pollutants'' in conjunction with 
establishing emission standards under CAA section 112. However, 
analogous text is absent from CAA section 111(d).
---------------------------------------------------------------------------

    \241\ See ``Clean Air Act Amendments of 1970,'' Sec.  12, 84 
Stat. at 1706.
    \242\ ``Clean Air Act Amendments of 1970,'' Sec.  4, 84 Stat. at 
1679.
---------------------------------------------------------------------------

    After the enactment of the 1970 CAA Amendments, the EPA proposed 
standards of performance for an ``initial list of five stationary 
source categories which contribute significantly to air pollution'' in 
August 1971.\243\ The first category listed was for fossil-fuel fired 
steam generators, for which EPA proposed and promulgated standards for 
particulate matter, SO2, and NOX.\244\
---------------------------------------------------------------------------

    \243\ ``Standards of Performance for New Stationary Sources: 
Proposed Standards for Five Categories,'' 36 FR 15704 (Aug. 17, 
1971). See ``Clean Air Act Amendments of 1970,'' Sec.  4, 84 Stat. 
at 1684 (requiring the Administrator to publish a list of categories 
of stationary sources within 90 days of the enactment of the 1970 
CAA Amendments).
    \244\ 36 FR at 15704-706; and ``Standards of Performance for New 
Stationary Sources,'' 36 FR 24876, 24879 (Dec. 23, 1971).
---------------------------------------------------------------------------

    Several years later, the EPA proposed its implementing regulations 
for CAA section 111(d).\245\ These regulations were finalized in 
November 1975, and provided for the publication of emission 
guidelines.\246\ The first emission guidelines were proposed in May 
1976 and finalized in March 1977.\247\
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    \245\ See ``State Plans for the Control of Existing 
Facilities,'' 39 FR 36102 (Oct. 7, 1974).
    \246\ See ``State Plans for the Control of Certain Pollutants 
from Existing Facilities,'' 40 FR 53340 (Nov. 17, 1975).
    \247\ See ``Phosphate Fertilizer Plants; Draft Guideline 
Document; Availability,'' 41 FR 19585 (May 12, 1976); and 
``Phosphate Fertilizer Plants; Final Guideline Document 
Availability,'' 42 FR 12022 (Mar. 1, 1977).
---------------------------------------------------------------------------

    Despite these first steps taken under CAA sections 111(b) and (d), 
Congress revisited the CAA in 1977 to address growing concerns with the 
nation's response to the 1973 oil embargo (noted above), to respond to 
new environmental problems such as stratospheric ozone depletion, and 
to resolve other issues associated with implementing the 1970 CAA 
Amendments.\248\ Most notably, an increase in coal use as a result of 
the oil crisis meant that ``vigorous and effective control'' of air 
emissions was ``even more urgent.'' \249\ Thus, to curb the projected 
surge in air emissions, Congress enacted several new provisions to the 
CAA. These new provisions include the prevention of significant 
deterioration (PSD) program, visibility protections, and requirements 
for nonattainment areas.\250\
---------------------------------------------------------------------------

    \248\ For example, Congress recognized that many air pollutants 
had not been regulated despite ``mounting evidence'' that these 
pollutants ``are associated with serious health hazards''. H.R. Rep. 
No. 94-1175, 22 (May, 15, 1976). Because EPA ``failed to promulgate 
regulations to institute adequate control measures,'' Congress 
ordered EPA to regulate four specific pollutants that had ``been 
found to be cancer-causing or cancer-promoting''. Id. at 23. This 
directive, reflected in CAA section 122, specifically added 
radioactive pollutants, cadmium, arsenic, and polycyclic organic 
matter ``under the various provisions of the Clean Air Act and 
allows their regulation as criteria pollutants under ambient air 
quality standards, as hazardous air pollutants, or under new source 
performance standards, as appropriate.'' H.R. Conf. Rep. No. 95-564, 
142 (Aug. 3, 1977), 1977 CAA Legis. Hist. at 522. At the same time, 
Congress made sure that these commands would have no effect on the 
Administrator's discretion to address ``any substance (whether or 
not enumerated [under CAA section 122(a))'' under CAA sections 108, 
112, or 111. 42 U.S.C. 7422(b).
    \249\ See Statement of EPA Administrator Costle, S. Hearings on 
S. 272, S. 273, S. 977, and S. 1469 (Apr. 5, 7, May 25, June 24 and 
30, 1977), 1977 CAA Legis. Hist. at 3532.
    \250\ See ``Clean Air Act Amendments of 1977,'' Pub. L. 95-95, 
Sec. Sec.  127-129, 91 Stat. 685 (Aug. 7, 1977).
---------------------------------------------------------------------------

    Congress also made significant changes to CAA section 111. For 
example, Congress amended the definition of a standard of performance 
(including by requiring the consideration of ``nonair quality health 
and environmental impact and energy requirements''), authorized 
alternative (e.g., work practice or design) standards in limited 
circumstances, provided states with authority to petition the 
Administrator for new or revised (and more stringent) standards, and 
imposed a strict regulatory schedule for establishing standards of 
performance for categories of major stationary sources that had not yet 
been listed.\251\
---------------------------------------------------------------------------

    \251\ ``Clean Air Act Amendments of 1977,'' Sec.  109, 91 Stat. 
at 697.

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[[Page 64702]]

    The 1977 definition for a standard of performance required ``all 
new sources to meet emission standards based on the reductions 
achievable through the use of the `best technological system of 
continuous emission reduction.' '' \252\ For fossil-fuel fired 
stationary sources, Congress further required a percentage reduction in 
emissions from the use of fuels.\253\ Together, this was designed to 
``force new sources to burn high-sulfur fuel thus freeing low-sulfur 
fuel for use in existing sources where it is harder to control 
emissions and where low-sulfur fuel is needed for compliance.'' \254\
---------------------------------------------------------------------------

    \252\ H.R. Rep. No. 95-294, at 192 (May 12, 1977). Congress 
separately defined ``technological system of continuous emission 
reduction'' as ``(A) a technological process for production or 
operation by any source which is inherently low-polluting or 
nonpolluting, or (B) technological system for continuous reduction 
of the pollution generated by a source before such pollution is 
emitted into the ambient air, including precombustion cleaning or 
treatment of fuels.'' ``Clean Air Act Amendments of 1977,'' Sec.  
109, 91 Stat. at 700; see also 42 U.S.C. 7411(a)(7).
    \253\ ``Clean Air Act Amendments of 1977,'' Sec.  109, 91 Stat. 
at 700.
    \254\ ``New Stationary Sources Performance Standards; Electric 
Utility Steam Generating Units,'' 44 FR 33580, 33581-82 (June 11, 
1979).
---------------------------------------------------------------------------

    Congress also clarified that with respect to CAA section 111(d), 
standards of performance (now applicable in lieu of emission standards) 
``would be based on the best available means (not necessarily 
technological)''.\255\ This was intended to distinguish existing source 
standards from new source standards, for which ``the requirement for 
[the BSER] has been more narrowly redefined as best technological 
system of continuous emission reduction.'' \256\ Additionally, Congress 
clarified that states could consider ``the remaining useful life'' of a 
source when applying a standard of performance to a particular existing 
source.\257\
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    \255\ H.R. Rep. No. 95-294, at 195 (May 12, 1977).
    \256\ Sen. Muskie, S. Consideration of the H.R. Conf. Rep. No. 
95-564 (Aug. 4, 1977), 1977 CAA Legis. Hist. at 353.
    \257\ This concept was already reflected in the EPA's CAA 
section 111(d) implementing regulations under 40 CFR 60.24(f). See 
40 FR 53340, 53347 (Nov. 17, 1975).
---------------------------------------------------------------------------

    In the twenty years since the 1970 CAA Amendments and in spite of 
the refinements of the 1977 CAA Amendments, ``many of the Nation's most 
important air pollution problems [had] failed to improve or [had] grown 
more serious.'' \258\ Indeed, in 1989, President George Bush said that 
`` `progress has not come quickly enough and much remains to be done.' 
'' \259\ This time, with the 1990 CAA Amendments, Congress 
substantially overhauled the CAA. In particular, Congress again added 
to the NAAQS program, completely revised CAA section 112, added a new 
title to target existing fossil fuel-fired stationary sources and 
address growing concerns with acid rain, imported an operating permit 
modeled off the Clean Water Act, and established a phase out of certain 
ozone depleting substances.
---------------------------------------------------------------------------

    \258\ H.R. Rep. No. 101-490, at 144 (May 17, 1990).
    \259\ H.R. Rep. No. 101-490, at 144 (May 17, 1990).
---------------------------------------------------------------------------

    All told, however, there was minimal debate on changes to CAA 
section 111. In fact, the only discussion centered on the repeal of the 
percentage reduction requirement, which became seen as unduly 
restrictive. Accordingly, Congress reverted the definition of 
``standard of performance'' to the definition agreed to in the 1970 CAA 
Amendments, but retained the requirement to consider nonair quality 
environmental impacts and energy requirements added in 1977.\260\ 
However, the repeal would only apply so long as the SO2 cap 
under CAA section 403(e) of the newly established acid rain program 
remained in effect.\261\ Lastly, Congress instructed the EPA to revise 
its new source performance standards for SO2 emissions from 
fossil fuel-fired power plants but required that the revised emission 
rate be no less stringent than before.\262\
---------------------------------------------------------------------------

    \260\ Congress also updated the regulatory schedule that was 
added in the 1977 CAA Amendments to reflect the newly enacted 1990 
CAA Amendments. See ``Clean Air Act Amendments of 1990,'' Sec.  108, 
104 Stat. 2467.
    \261\ ``Clean Air Act Amendments of 1990,'' Sec.  403, 104 Stat. 
at 2631.
    \262\ ``Clean Air Act Amendments of 1990,'' Sec.  301, 104 Stat. 
at 2631.
---------------------------------------------------------------------------

I. Statutory and Regulatory Requirements

    Clean Air Act section 111, which Congress enacted as part of the 
1970 Clean Air Act Amendments, establishes mechanisms for controlling 
emissions of air pollutants from stationary sources. This provision 
requires the EPA to promulgate a list of categories of stationary 
sources that the Administrator, in his or her judgment, finds ``causes, 
or contributes significantly to, air pollution which may reasonably be 
anticipated to endanger public health or welfare.'' \263\ The EPA has 
listed more than 60 stationary source categories under this 
provision.\264\ Once the EPA lists a source category, the EPA must, 
under CAA section 111(b)(1)(B), establish ``standards of performance'' 
for emissions of air pollutants from new sources in the source 
categories.\265\ These standards are known as new source performance 
standards (NSPS), and they are national requirements that apply 
directly to the sources subject to them.
---------------------------------------------------------------------------

    \263\ CAA section 111(b)(1)(A).
    \264\ See 40 CFR 60 subparts Cb--OOOO.
    \265\ CAA section 111(b)(1)(B), 111(a)(1).
---------------------------------------------------------------------------

    When the EPA establishes NSPS for new sources in a particular 
source category, the EPA is also required, under CAA section 111(d)(1), 
to prescribe regulations for states to submit plans regulating existing 
sources in that source category for any air pollutant that, in general, 
is not regulated under the CAA section 109 requirements for the NAAQS 
or regulated under the CAA section 112 requirements for HAP. CAA 
section 111(d)'s mechanism for regulating existing sources differs from 
the one that CAA section 111(b) provides for new sources because CAA 
section 111(d) contemplates states submitting plans that establish 
``standards of performance'' for the affected sources and that contain 
other measures to implement and enforce those standards.
    ``Standards of performance'' are defined under CAA section 
111(a)(1) as standards for emissions that reflect the emission 
limitation achievable from the ``best system of emission reduction,'' 
considering costs and other factors, that ``the Administrator 
determines has been adequately demonstrated.'' CAA section 111(d)(1) 
grants states the authority, in applying a standard of performance to a 
particular source, to take into account the source's remaining useful 
life or other factors.
    Under CAA section 111(d), a state must submit its plan to the EPA 
for approval, and the EPA must approve the state plan if it is 
``satisfactory.'' \266\ If a state does not submit a plan, or if the 
EPA does not approve a state's plan, then the EPA must establish a plan 
for that state.\267\ Once a state receives the EPA's approval of its 
plan, the provisions in the plan become federally enforceable against 
the entity responsible for noncompliance, in the same manner as the 
provisions of an approved SIP under the Act.
---------------------------------------------------------------------------

    \266\ CAA section 111(d)(2)(A).
    \267\ CAA section 111(d)(2)(A).
---------------------------------------------------------------------------

    Section 302(d) of the CAA defines the term ``state'' to include the 
Commonwealth of Puerto Rico, the Virgin Islands, Guam, American Samoa 
and the Commonwealth of the Northern Mariana Islands. While 40 CFR part 
60 contains a separate definition of ``state'' at section 60.2, this 
definition expands on, rather than narrows, the definition in section 
302(d) of the CAA. The introductory language to 40 CFR 60.2 provides: 
``The terms in this part are defined in the Act or in this section as 
follows.'' Section 60.2 defines ``State'' as

[[Page 64703]]

``all non-Federal authorities, including local agencies, interstate 
associations, and State-wide programs that have been delegated 
authority to implement: (1) The provisions of this part and/or (2) the 
permit program established under part 70 of this chapter. The term 
State shall have its conventional meaning where clear from the 
context.'' The EPA believes that the last sentence refers to the 
conventional meaning of ``state'' under the CAA. Thus, the EPA believes 
the term ``state'' as used in the emission guidelines is most 
reasonably interpreted as including the meaning ascribed to that term 
in section 302(d) of the CAA, which expressly includes U.S. 
territories.
    Section 301(d)(A) of the CAA recognizes that the American Indian 
tribes are sovereign Nations and authorizes the EPA to ``treat tribes 
as States under this Act''. The Tribal Authority Rule (63 FR 7254, 
February 12, 1998) identifies that EPA will treat tribes in a manner 
similar to states for all of the CAA provisions with the exception of, 
among other things, specific plan submittal and implementation 
deadlines under the CAA. As a result, though they operate as part of 
the interconnected system of electricity production and distribution, 
affected EGUs located in Indian country would not be encompassed within 
a state's CAA section 111(d) plan. Instead, an Indian tribe with one or 
more affected EGUs located in its area of Indian country \268\ will 
have the opportunity, but not the obligation, to apply for eligibility 
to develop and implement a CAA section 111(d) plan. The Indian tribe 
would need to be approved by the EPA as eligible to develop and 
implement a CAA section 111(d) plan following the procedure set forth 
in 40 CFR part 49. Once a tribe is approved as eligible for that 
purpose, it would be treated in the same manner as a state, and 
references in the emission guidelines to states would refer equally to 
the tribe. The EPA notes that, while tribes have the opportunity to 
apply for eligibility to administer CAA programs, they are not required 
to do so. Further, the EPA has established procedures in 40 CFR part 49 
(see particularly 40 CFR 49.7(c)) that permit eligible tribes to 
request approval of reasonably severable partial program elements. 
Those procedures are applicable here.
---------------------------------------------------------------------------

    \268\ The EPA is aware of at least four affected sources located 
in Indian Country: Two on Navajo lands--the Navajo Generating 
Station and the Four Corners Generating Station; one on Ute lands--
the Bonanza Generating Station; and one on Fort Mojave lands, the 
South Point Energy Center. The affected EGUs at the first three 
plants are coal-fired EGUs. The fourth affected EGU is an NGCC 
facility.
---------------------------------------------------------------------------

    In these final emission guidelines, the term ``state'' encompasses 
the 50 states and the District of Columbia, U.S. territories, and any 
Indian tribe that has been approved by the EPA pursuant to 40 CFR 49.9 
as to develop and implement a CAA section 111(d) plan.
    The EPA issued regulations implementing CAA section 111(d) in 
1975,\269\ and has revised them in the years since.\270\ (We refer to 
the regulations generally as the implementing regulations.) These 
regulations provide that, in promulgating requirements for sources 
under CAA section 111(d), the EPA first develops regulations known as 
``emission guidelines,'' which establish binding requirements that 
states must address when they develop their plans.\271\ The 
implementing regulations also establish timetables for state and EPA 
action: States must submit state plans within 9 months of the EPA's 
issuance of the guidelines,\272\ and the EPA must take final action on 
the state plans within 4 months of the due date for those plans,\273\ 
although the EPA has authority to extend those deadlines.\274\ In this 
rulemaking, the EPA is following the requirements of the implementing 
regulations, and is not re-opening them, except that the EPA is 
extending the timetables, as described below.
---------------------------------------------------------------------------

    \269\ ``State Plans for the Control of Certain Pollutants from 
Existing Facilities,'' 40 FR 53340 (Nov. 17, 1975).
    \270\ The most recent amendment was in 77 FR 9304 (Feb. 16, 
2012).
    \271\ 40 CFR 60.22. In the 1975 rulemaking, the EPA explained 
that it used the term ``emission guidelines''--instead of emissions 
limitations--to make clear that guidelines would not be binding 
requirements applicable to the sources, but instead are ``criteria 
for judging the adequacy of State plans.'' 40 FR at 53343.
    \272\ 40 CFR 60.23(a)(1).
    \273\ 40 CFR 60.27(b).
    \274\ See 40 CFR 60.27(a).
---------------------------------------------------------------------------

    Over the last forty years, under CAA section 111(d), the agency has 
regulated four pollutants from five source categories (i.e., sulfuric 
acid plants (acid mist), phosphate fertilizer plants (fluorides), 
primary aluminum plants (fluorides), Kraft pulp plants (total reduced 
sulfur), and municipal solid waste landfills (landfill gases)).\275\ In 
addition, the agency has regulated additional pollutants under CAA 
section 111(d) in conjunction with CAA section 129.\276\ The agency has 
not previously regulated CO2 or any other GHGs under CAA 
section 111(d).
---------------------------------------------------------------------------

    \275\ See ``Phosphate Fertilizer Plants; Final Guideline 
Document Availability,'' 42 FR 12022 (Mar. 1, 1977); ``Standards of 
Performance for New Stationary Sources; Emission Guideline for 
Sulfuric Acid Mist,'' 42 FR 55796 (Oct. 18, 1977); ``Kraft Pulp 
Mills, Notice of Availability of Final Guideline Document,'' 44 FR 
29828 (May 22, 1979); ``Primary Aluminum Plants; Availability of 
Final Guideline Document,'' 45 FR 26294 (Apr. 17, 1980); ``Standards 
of Performance for New Stationary Sources and Guidelines for Control 
of Existing Sources: Municipal Solid Waste Landfills, Final Rule,'' 
61 FR 9905 (Mar. 12, 1996).
    \276\ See, e.g., ``Standards of Performance for New Stationary 
Sources and Emission Guidelines for Existing Sources: Sewage Sludge 
Incineration Units, Final Rule,'' 76 FR 15372 (Mar. 21, 2011).
---------------------------------------------------------------------------

    The EPA's previous CAA section 111(d) actions were necessarily 
geared toward the pollutants and industries regulated. Similarly, in 
this rulemaking, in defining CAA section 111(d) emission guidelines for 
the states and determining the BSER, the EPA believes that taking into 
account the particular characteristics of carbon pollution, the 
interconnected nature of the power sector and the manner in which EGUs 
are currently operated is warranted. Specifically, the operators 
themselves treat increments of generation as interchangeable between 
and among sources in a way that creates options for relying on varying 
utilization levels, lowering carbon generation, and reducing demand as 
components of the overall method for reducing CO2 emissions. 
Doing so results in a broader, forward-thinking approach to the design 
of programs to yield critical CO2 reductions that improve 
the overall power system by lowering the carbon intensity of power 
generation, while offering continued reliability and cost-
effectiveness. These opportunities exist in the utility power sector in 
ways that were not relevant or available for other industries for which 
the EPA has established CAA section 111(d) emission guidelines.\277\
---------------------------------------------------------------------------

    \277\ See ``Phosphate Fertilizer Plants; Final Guideline 
Document Availability,'' 42 FR 12022 (Mar. 1, 1977); ``Standards of 
Performance for New Stationary Sources; Emission Guideline for 
Sulfuric Acid Mist,'' 42 FR 55796 (Oct. 18, 1977); ``Kraft Pulp 
Mills, Notice of Availability of Final Guideline Document,'' 44 FR 
29828 (May 22, 1979); ``Primary Aluminum Plants; Availability of 
Final Guideline Document,'' 45 FR 26294 (Apr. 17, 1980); ``Standards 
of Performance for New Stationary Sources and Guidelines for Control 
of Existing Sources: Municipal Solid Waste Landfills, Final Rule,'' 
61 FR 9905 (Mar. 12, 1996).
---------------------------------------------------------------------------

    In this action, the EPA is promulgating emission guidelines for 
states to follow in developing their CAA section 111(d) plans to reduce 
emissions of CO2 from the utility power sector.

J. Clean Power Plan Proposal and Supplemental Proposal

    On June 18, 2014, the EPA proposed emission guidelines for states 
to follow in developing plans to address GHG emissions from existing 
fossil fuel-fired electric generating units (EGUs). Specifically, the 
EPA proposed rate-based goals for CO2 emissions for each

[[Page 64704]]

state with existing fossil fuel-fired EGUs, as well as guidelines for 
plans to achieve those goals. On November 4, 2014, the EPA published a 
supplemental proposal that proposed emission rate-based goals for 
CO2 emissions for U.S. territories and areas of Indian 
country with existing fossil fuel-fired EGUs. In the supplemental 
proposal, the EPA also solicited comment on authorizing jurisdictions 
(including any states, territories and areas of Indian country) without 
existing fossil fuel-fired EGUs subject to the proposed emission 
guidelines to partner with jurisdictions (including any states) that do 
have existing fossil fuel-fired EGUs subject to the proposed emission 
guidelines in developing multi-jurisdictional plans. The EPA also 
solicited comment on the treatment of RE, demand-side EE and other new 
low- or zero-emitting electricity generation across international 
boundaries in a state plan.
    The EPA also issued two documents after the June 18, 2014 proposal. 
On October 30, 2014, the EPA published a NODA in which the agency 
provided additional information on several topics raised by 
stakeholders and solicited comment on the information presented. This 
action covered three topic areas: 1) the emission reduction compliance 
trajectories created by the interim goal for 2020 to 2029, 2) certain 
aspects of the building block methodology, and 3) the way state-
specific CO2 goals are calculated.
    In a separate action, the EPA published a document regarding 
potential methods for determining the mass that is equivalent to an 
emission rate-based CO2 goal (79 FR 67406; November 13, 
2014). With the action, the EPA also made available, in the docket for 
this rulemaking, a TSD that provided two examples of how a state, U.S. 
territory or tribe could translate a rate-based CO2 goal to 
total metric tons of CO2 (a mass-based equivalent).

K. Stakeholder Outreach and Consultations

    Following the direction in the Presidential Memorandum to the 
Administrator (June 25, 2013),\278\ the EPA engaged in extensive and 
vigorous outreach to stakeholders and the general public at every stage 
of development of this rule. Our outreach has included direct 
engagement with the energy and environment officials in states, tribes, 
and a full range of stakeholders including leaders in the utility power 
sector, labor leaders, non-governmental organizations, other federal 
agencies, other experts, community groups and members of the public. 
The EPA participated in more than 300 meetings before the rule was 
proposed and more than 300 after the proposal.
---------------------------------------------------------------------------

    \278\ Presidential Memorandum--Power Sector Carbon Pollution 
Standards, June 25, 2013. http://www.whitehouse.gov/the-press-office/2013/06/25/presidential-memorandum-power-sector-carbon-pollution-standards.
---------------------------------------------------------------------------

    Throughout the rulemaking process, the agency has encouraged, 
organized, and participated in hundreds of meetings about CAA section 
111(d) and reducing carbon pollution from existing power plants. The 
agency's outreach prior to proposal, as well as during the public 
comment period, was designed to solicit policy ideas,\279\ concerns, 
and technical information. The agency received 4.3 million comments 
about all aspects of the proposed rule and thousands of people 
participated in the agency's public hearings, webinars, listening 
sessions,\280\ teleconferences and meetings held all across the 
country.
---------------------------------------------------------------------------

    \279\ The EPA received more than 2,000 emails offering input 
into the development of these guidelines through email and a Web-
based form. These emails and other materials provided to the EPA are 
posted on line as part of a non-regulatory docket, EPA Docket ID No. 
EPA-HQ-OAR-2014-0020, at www.regulations.gov.
    \280\ Summaries of the 11 public listening sessions in 2013 are 
available at www.regulations.gov at EPA Docket ID No. EPA-HQ-OAR-
2014-0020.
---------------------------------------------------------------------------

    Our engagement has brought together a variety of states and 
stakeholders to discuss a wide range of issues related to the utility 
power sector and the development of emission guidelines under CAA 
section 111(d). The meetings were attended by the EPA Regional 
Administrators, other senior managers and staff who have been 
instrumental in the development of the rule and will play key roles in 
developing and implementing it.
    This outreach process has produced a wealth of information which 
has informed this rule significantly. The pre-proposal outreach efforts 
far exceeded what is required of the agency in the normal course of a 
rulemaking process, and the EPA expects that the dialogue with states 
and stakeholders will continue after the rule is finalized. The EPA 
recognizes the importance of working with all stakeholders, and in 
particular with the states, to ensure a clear and common understanding 
of the role the states will play in addressing carbon pollution from 
power plants. We firmly believe that our outreach has resulted in a 
more workable rule that will achieve the statutory goals and has 
enhanced the likelihood of timely and successful achievement of the 
carbon reduction goals, given the critical importance and urgency of 
the concrete action.
    The EPA has given stakeholder comments careful consideration and, 
as a result, this final rule includes features that are responsive to 
many stakeholder concerns.
1. Public Hearings
    More than 2,700 people attended the public hearings sessions held 
in Atlanta, Denver, Pittsburgh, and Washington, DC. More than 1,300 
people spoke at the public hearings. Additionally, about 100 people 
attended the public hearing held in Phoenix, Arizona, on the November 
4, 2014 supplemental proposal. Speakers at the public hearings included 
Members of Congress, other public officials, industry representatives, 
faith-based organizations, unions, environmental groups, community 
groups, students, public health groups, energy groups, academia and 
concerned citizens.
    Participants shared a range of perspectives. Many were concerned 
with the impacts of climate change on their health and on future 
generations, others were worried about the impact of regulations on the 
economy. Their support for the agency's efforts varied.
2. State Officials
    Since fall 2013, the agency has provided multiple opportunities for 
the states to inform this rulemaking. Administrator McCarthy has 
engaged with governors from states with a variety of interests in the 
rulemaking. Other senior agency officials have engaged with every 
branch and major agency of state government--including state 
legislators, attorneys general, state energy, environment, and utility 
officials, and governors' staff.
    On several occasions, state environmental commissioners met with 
senior agency officials to provide comments on the Clean Power Plan. 
The EPA organized, encouraged and attended meetings with states to 
discuss multi-state planning efforts. States have come together with 
several collaborative groups to discuss ways to work together to make 
the Clean Power Plan more affordable. The EPA has participated in and 
supported the states in these discussions. Because of the 
interconnectedness of the power sector, and the fact that electricity 
generated at power plants crosses state lines; states, utilities and 
ratepayers may benefit from states working together to implement the 
requirements of this rulemaking. The meetings provided state leaders, 
including governors, environmental commissioners, energy officers, 
public utility commissioners, and air directors, opportunities to 
engage with the EPA officials. In addition, the states

[[Page 64705]]

submitted public comments from several agencies within each state. The 
wealth of comments and input from states was important in developing 
the final rulemaking.
    Agency officials listened to ideas, concerns and details from 
states, including from states with a wide range of experience in 
reducing carbon pollution from power plants. The EPA reached out to all 
50 states to engage with both environmental and energy departments at 
all levels of government. As an example, a three-part webinar series in 
June/July 2014 for the states and tribes offered an interactive format 
for technical staff at the EPA and in the states/tribes to exchange 
ideas and ask clarifying question. The webinars were then posted online 
so other stakeholders could view them. A few weeks after the postings, 
the EPA organized follow-up conference calls with stakeholder groups. 
Also, the EPA hosted scores of technical meetings between states and 
the EPA in the weeks and months after the rule was proposed.
    Additionally, the EPA organized ``hub'' calls; these 
teleconferences brought all of the states in a given EPA region 
together to discuss technical and interstate aspects of the proposal. 
These exchanges helped provide the stakeholders with the information 
they needed to comment on the proposal effectively. The EPA also held a 
series of webinars with state environmental associations and their 
members on a series of technical issues.
    The agency has collected policy papers and comment letters from 
states with overarching energy goals and technical details on the 
states' utility power sector. EPA leadership and staff also 
participated in webinars and meetings with state and tribal officials 
hosted by collaborative groups and trade associations. After the 
comment period closed, and based on our meetings over the last year, as 
well as written comments on the proposal and NODA, the EPA analyzed 
information about data errors that needed to be addressed for the final 
rule. In February and March 2015, we reached out to particular states 
to clarify ambiguous or unclear information that was submitted to the 
EPA related to NEEDS and eGRID data. The EPA contacted particular 
states to clarify the technical comments or concerns to ensure that any 
changes we make are accurate and appropriate.
    To help prepare for implementation of this rule, the agency 
initiated several outreach activities to assist with state planning 
efforts. The agency participated in meetings organized by the National 
Association of State Energy Officials (NASEO), the National Association 
of Regulatory Utility Commissioners (NARUC), and the National 
Association of Clean Air Agencies (NACAA) (the ``3N'' groups). Meeting 
participants discussed issues related to EE and RE.
    To help state officials prepare for the planning process that will 
take place in the states, the EPA presented a webinar on February 24, 
2015. This webinar provided an update on training plans and further 
connection with states in the implementation process. Forty-nine 
states, the District of Columbia, and 14 tribes were represented at 
this webinar. The EPA is developing a state plan electronic collection 
system to receive, track, and store state submittals of plans and 
reports. The EPA plans to use an integrated project team to solicit 
stakeholder input on the system during development. The team 
membership, including state representatives, will bring together the 
business and technology skills required to construct a successful 
product and promote transparency in the EPA's implementation of the 
rule.
    To help identify training needs for the final Clean Power Plan, the 
agency reached out to a number of state and local organizations such as 
the Central State Air Resources Agencies and other such regional air 
agencies. The EPA's outreach on training has included sharing the plans 
with the states and incorporating changes to the training topics based 
on the states' needs. The EPA training plan includes a wide variety of 
topics such as basic training on the electric power sector as well as 
specific pollution control strategies to reduce carbon emissions from 
power plants. In particular, the states requested training on how to 
use programs such as combined heat and power, EE and RE to reduce 
carbon emissions. The EPA will continue to work with states to tailor 
training activities to their needs.
    The agency has engaged, and will continue to engage with states, 
territories, Washington, DC, and tribes after the rulemaking process 
and throughout implementation.
3. Tribal Officials
    The EPA conducted significant outreach to and consultation with 
tribes. Tribes are not required to, but may, develop or adopt Clean Air 
Act programs. The EPA is aware of four facilities with affected EGUs 
located in Indian country: the South Point Energy Center, in Fort 
Mojave Indian country, geographically located within Arizona; the 
Navajo Generating Station, in Navajo Indian country, geographically 
located within Arizona; the Four Corners Power Plant, in Navajo Indian 
country, geographically located within New Mexico; and the Bonanza 
Power Plant, in Ute Indian country, geographically located within Utah. 
The EPA offered consultation to the leaders of the tribes on whose 
lands these facilities are located as well as all of the federally 
recognized tribes to ensure that they had the opportunity to have 
meaningful and timely input into this rule. Section III (``Stakeholder 
Outreach and Conclusions'') of the June 18, 2014 proposal documents the 
EPA's extensive outreach efforts to tribal officials prior to that 
proposal, including an informational webinar, outreach meeting, 
teleconferences with tribal officials and the National Tribal Air 
Association (NTAA), and letters offering consultation. Additional 
outreach to tribal officials conducted by the EPA prior to the November 
4, 2014 supplemental proposal is discussed in Section II.D 
(``Additional Outreach and Consultation'') of the supplemental 
proposal. The additional outreach for the supplemental proposal 
included consultations with all three tribes that have affected EGUs on 
their lands, as well as several other tribes that requested 
consultation, and also additional teleconferences with the NTAA.
    After issuing the supplemental proposal, the EPA offered an 
additional consultation to the leaders of all federally recognized 
tribes. The EPA held an informational meeting open to all tribes and 
also held consultations with the Navajo Nation, Fort McDowell Yavapai 
Nation, Fort Mojave Tribe, Ak-Chin Indian Community, and Hope Tribe on 
November 18, 2014. The EPA held a consultation with the Ute Tribe of 
the Uintah and Ouray Reservation on December 16, 2014, and a 
consultation with the Gila River Indian Community on January 15, 2015. 
The EPA held a public hearing on the supplemental proposal on November 
19, 2014, in Phoenix, Arizona. On April 28, 2015, the EPA held an 
additional consultation with the Navajo Nation.
    Tribes were interested in the impact of this rule on other ongoing 
regulatory actions at the affected EGUs, such as permitting or 
requirements for the best available retrofit technology (BART). Tribes 
also noted that it was important to allow RE projects on tribal lands 
to contribute toward meeting state goals. Some tribes indicated an 
interest in being involved in the development of implementation plans 
for areas of Indian country. Additional detail regarding the EPA's 
outreach to tribes and comments and recommendations from tribes can be 
found in Section X.F of this preamble.

[[Page 64706]]

4. U.S. Territories
    The EPA has met with individual U.S. territories and affected EGUs 
in U.S. territories during the rulemaking process. On July 22, 2014, 
the EPA met with representatives from the Puerto Rico Environmental 
Quality Board, the Puerto Rico Electric Power Authority, the Governor's 
Office, and the Office of Energy, Puerto Rico. On September 8, 2014, 
the EPA held a meeting with representatives from the Guam Environmental 
Protection Agency (GEPA) and the Guam Power Authority and, on February 
18, 2015, the EPA met again with representatives from GEPA.
5. Industry Representatives
    Agency officials have engaged with industry leaders and 
representatives from trade associations in many one-on-one and national 
meetings. Many meetings occurred at the EPA headquarters and in the 
EPA's Regional Offices and some were sponsored by stakeholder groups. 
Because the focus of the rule is on the utility power sector, many of 
the meetings with industry have been with utilities and industry 
representatives directly related to the utility power sector. The 
agency has also met with energy industries such as coal and natural gas 
interests, as well as companies that offer new technology to prevent or 
reduce carbon pollution, including companies that have expertise in RE 
and EE. Other meetings have been held with representatives of energy 
intensive industries, such as the iron and steel and aluminum 
industries, to help understand the issues related to large industrial 
users of electricity.
6. Electric Utility Representatives
    Agency officials participated in many meetings with utilities and 
their associations to discuss all aspects of the proposed guidelines. 
We have met with all types of companies that produce electricity, 
including private utilities or investor owned utilities. Public 
utilities and cooperative utilities were also part of in-depth 
conversations about CAA section 111(d) with EPA officials.
    The conversations included meetings with the EPA headquarters and 
regional offices. State officials were included in many of the 
meetings. Meetings with utility associations and groups of utilities 
were held with key EPA officials. The meetings covered technical, 
policy and legal topics of interest and utilities expressed a wide 
variety of support and concerns about CAA section 111(d).
7. Electricity Grid Operators
    The EPA had a number of conversations with the ISOs and RTOs to 
discuss the rule and issues related to grid operations and reliability. 
EPA staff met with the ISO/RTO Council on several occasions to collect 
their ideas. The EPA regional offices also met with the ISOs and RTOs 
in their regions. System operators have offered suggestions in using 
regional approaches to implement CAA section 111(d) while maintaining 
reliable, affordable electricity.
8. Representatives from Community and Non-governmental Organizations
    Agency officials engaged with community groups representing 
vulnerable communities, and faith-based groups, among others, during 
the outreach effort. In response to a request from communities, the EPA 
held a day-long training on the Clean Power Plan on October 30, 2014, 
in Washington DC At this meeting, the EPA met with a number of 
environmental groups to provide information on how the agency plans on 
reducing carbon pollution from existing power plants using CAA section 
111(d).
    Many environmental organizations discussed the need for reducing 
carbon pollution. Meetings were technical, policy and legal in nature 
and many groups discussed specific state policies that are already in 
place to reduce carbon pollution in the states.
    A number of organizations representing religious groups have 
reached out to the EPA on several occasions to discuss their concerns 
and ideas regarding this rule. Many members of faith communities 
attended the four public hearings.
    Public health groups discussed the need for protection of 
children's health from harmful air pollution. Doctors and health care 
providers discussed the link between reducing carbon pollution and air 
pollution and public health. Consumer groups representing advocates for 
low income electricity customers discussed the need for affordable 
electricity. They talked about reducing electricity prices for 
consumers through EE and low-cost carbon reductions.
    In winter/spring 2015, EPA continued to offer webinars and 
teleconferences for community groups on the rulemaking.
9. Environmental Justice Organizations
    Agency officials engaged with environmental justice groups 
representing communities of color, low-income communities and others 
during the outreach effort. Agency officials also engaged with the 
EPA's National Environmental Justice Advisory Council (NEJAC) members 
in September 2013. The NEJAC is composed of stakeholders, including 
environmental justice leaders and other leaders from state and local 
government and the private sector. Additionally, the agency conducted a 
community call on February 26, 2015, and on February 27, 2015, the EPA 
conducted a follow up webinar for participants in an October 30, 2014 
training session. The EPA also held a webinar for communities on the 
Clean Air Act (CAA) and section 111(d) of the CAA on April 2, 2015. The 
agency, in partnership with FERC and DOE, held two additional webinars 
for communities on the electricity grid and on energy markets on June 
11, 2015, and July 9, 2015.
    During the EPA's extensive outreach conducted before and after 
proposal, the EPA has heard a variety of issues raised by environmental 
justice communities. Communities expressed the desire for the agency to 
conduct an environmental justice (EJ) analysis and to require that 
states in the development of their state plans conduct one as well. 
Additionally, they asked that the agency require that states engage 
with communities in the development of their state plans and that the 
agency conduct meaningful involvement with communities, throughout the 
whole rulemaking process, including the implementation phase. 
Furthermore, communities stressed the importance of low-income and 
communities of color receiving the benefits of this rulemaking and 
being protected from being adversely impacted by this rulemaking.
    The purpose of this rule is to substantially reduce emissions of 
CO2, a key contributor to climate change, which adversely 
and disproportionately affects vulnerable and disadvantaged communities 
in the U.S. and around the world. In addition, the rule will result in 
substantial reductions of conventional air pollutants, providing 
immediate public health benefits to the communities where the 
facilities are located and for many miles around. The EPA is committed 
to ensuring that all Americans benefit from the public health and other 
benefits that this rule will bring. Further discussion of the impacts 
of this rule on vulnerable communities and actions that the EPA is 
taking to address concerns cited by communities is available in 
Sections IX and XII.J of this preamble.
10. Labor
    Senior agency officials met with a number of labor union 
representatives about reducing carbon pollution using CAA section 
111(d). Those unions included: The United Mine Workers of America; the 
Sheet Metal, Air, Rail and Transportation Union (SMART); the

[[Page 64707]]

International Brotherhood of Boilermakers, Iron Ship Builders, 
Blacksmiths, Forgers and Helpers (IBB); United Association of 
Journeymen and Apprentices of the Plumbing and Pipe Fitting Industry of 
the United States and Canada; the International Brotherhood of 
Electrical Workers (IBEW); and the Utility Workers Union of America. In 
addition, agency leaders met with the Presidents of several unions and 
the President of the American Federation of Labor-Congress of 
Industrial Organizations (AFL-CIO) at the AFL-CIO headquarters.
    EPA officials attended meetings sponsored by labor unions to give 
presentations and engage in discussions about reducing carbon pollution 
using CAA section 111(d). These included meetings sponsored by the IBB 
and the IBEW.
11. Other Federal Agencies and Independent Agencies
    Throughout the development of the rulemaking, the EPA consulted 
with other federal agencies with relevant expertise. For example, the 
EPA met with managers from the U.S. Department of Agriculture's 
(USDA's) Rural Utility Service to discuss the rule and potential 
effects on affected EGUs in rural areas and how USDA programs could 
interact with affected EGUs during rule implementation.
    The U.S. Department of Energy (DOE) was a frequent source of 
expertise on the proposed and final rule. EPA management and staff had 
numerous meetings with management and staff at DOE on a range of 
topics, including the effectiveness and costs of energy generation 
technologies, and EE.
    DOE provided technical assistance relating to RE and demand-side 
EE, including RE and demand-side EE cost and performance data and, for 
RE, information on the feasibility of deploying and reliably 
integrating increased RE generation. Further, EPA and DOE staff 
discussed emission measurement and verification (EM&V) strategies.
    The EPA also consulted with DOE on electric reliability issues. EPA 
staff and managers met and spoke with DOE staff and managers throughout 
the development of the proposed and final rules on topic related to 
electric system reliability.
    EPA officials worked closely with DOE and Federal Energy Regulatory 
Commission (FERC) officials to ensure, to the greatest extent possible, 
that actions taken by states and affected EGUs to comply with the final 
rule mitigate potential electric system reliability issues. Senior EPA 
officials met with each of the FERC Commissioners and EPA staff had 
frequent contact with FERC staff throughout the development the rule. 
FERC held four technical conferences to discuss implications of 
compliance approaches to the rule for electric reliability. EPA staff 
attended the four conferences and EPA leadership spoke at all of them. 
The EPA, DOE, and FERC will continue to work together to ensure 
electric grid reliability in the development and implementation of 
state plans.

L. Comments on the Proposal

    The Administrator signed the proposed emission guidelines on June 
2, 2014, and, on the same day, the EPA made this version available to 
the public at http://www.epa.gov/cleanpowerplan/. The 120-day public 
comment period on the proposal began on June 18, 2014, the day of 
publication of the proposal in the Federal Register. On September 18, 
2014, in response to requests from stakeholders, the EPA extended the 
comment period by 45 days, to December 1, 2014, giving stakeholders 
over 165 days to review and comment upon the proposal. Stakeholders 
also had the opportunity to comment on the NODA, as well as the Federal 
Register document and TSD regarding potential methods for determining 
the mass that is equivalent to an emission rate-based CO2 
goal, through December 1, 2014. The EPA offered a separate 45-day 
comment period for the November 4, 2014 supplemental proposal, and that 
comment period closed on December 19, 2014.
    The EPA received more than 4.2 million comments on the proposed 
carbon pollution emission guidelines from a range of stakeholders that 
included, including state environmental and energy officials, local 
government officials, tribal officials, public utility commissioners, 
system operators, utilities, public interest advocates, and members of 
the public. The agency received comments on many aspects of the 
proposal and many suggestions for changes that would address issues of 
concern.

III. Rule Requirements and Legal Basis

A. Summary of Rule Requirements

    The EPA is establishing emission guidelines for states to use in 
developing plans to address GHG emissions from existing fossil fuel-
fired electric generating units. The emission guidelines are based on 
the EPA's determination of the ``best system of emission reduction . . 
. adequately demonstrated'' (BSER) and include source category-specific 
CO2 emission performance rates, state-specific goals, 
requirements for state plan components, and requirements for the 
process and timing for state plan submittal and compliance.
    Under CAA section 111(d), the states must establish standards of 
performance that reflect the degree of emission limitation achievable 
through the application of the ``best system of emission reduction'' 
that, taking into account the cost of achieving such reduction and any 
non-air quality health and environmental impact and energy 
requirements, the Administrator determines has been adequately 
demonstrated.
    The EPA has determined that the BSER is the combination of emission 
rate improvements and limitations on overall emissions at affected EGUs 
that can be accomplished through the following three sets of measures 
or building blocks:

    1. Improving heat rate at affected coal-fired steam EGUs.
    2. Substituting increased generation from lower-emitting 
existing natural gas combined cycle units for generation from 
higher-emitting affected steam generating units.
    3. Substituting increased generation from new zero-emitting RE 
generating capacity for generation from affected fossil fuel-fired 
generating units.

    Consistent with CAA section 111(d) and other rules promulgated 
under this section, the EPA is taking a traditional, performance-based 
approach to establishing emission guidelines for affected sources and 
applying the BSER to two source subcategories of existing fossil fuel-
fired EGUs--fossil fuel-fired electric utility steam generating units 
and stationary combustion turbines. The EPA is finalizing source 
subcategory-specific emission performance rates that reflect the EPA's 
application of the BSER. For fossil fuel-fired steam generating units, 
we are finalizing a performance rate of 1,305 lb CO2/MWh. 
For stationary combustion turbines, we are finalizing a performance 
rate of 771 lb CO2/MWh. The EPA has also translated the 
source subcategory-specific CO2 emission performance rates 
into equivalent statewide rate-based and mass-based CO2 
goals and is providing those as an option for states to use.
    Under CAA section 111(d), each state must develop, adopt, and then 
submit its plan to the EPA. For its CAA section 111(d) plan, a state 
will determine whether to apply these emission performance rates to 
each affected EGU, individually or together, or to take an alternative 
approach and meet either an equivalent statewide rate-based goal or an 
equivalent statewide mass-based

[[Page 64708]]

goal, as provided by the EPA in this rulemaking.
    States with one or more affected EGUs will be required to develop 
and implement plans that set emission standards for affected EGUs. The 
CAA section 111(d) emission guidelines that the EPA is promulgating in 
this action apply to only the 48 contiguous states and any Indian tribe 
that has been approved by the EPA pursuant to 40 CFR 49.9 as eligible 
to develop and implement a CAA section 111(d) plan.\281\ Because 
Vermont and the District of Columbia do not have affected EGUs, they 
will not be required to submit a state plan. Because the EPA does not 
possess all of the information or analytical tools needed to quantify 
the BSER for the two non-contiguous states with otherwise affected EGUs 
(Alaska and Hawaii) and the two U.S. territories with otherwise 
affected EGUs (Guam and Puerto Rico), these emission guidelines do not 
apply to those areas, and those areas will not be required to submit 
state plans on the schedule required by this final action.
---------------------------------------------------------------------------

    \281\ In the case of a tribe that has one or more affected EGUs 
in its area of Indian country, the tribe has the opportunity, but 
not the obligation, to establish a CO2 emission standard 
for each affected EGU located in its area of Indian country and a 
CAA section 111(d) plan for its area of Indian country. If the tribe 
chooses to establish its own plan, it must seek and obtain authority 
from the EPA to do so pursuant to 40 CFR 49.9. If it chooses not to 
seek this authority, the EPA has the responsibility to determine 
whether it is necessary or appropriate, in order to protect air 
quality, to establish a CAA section 111(d) plan for an area of 
Indian country where affected EGUs are located.
---------------------------------------------------------------------------

    In developing its CAA section 111(d) plan, a state will have the 
option of choosing from two different approaches: (1) An ``emission 
standards'' approach, or (2) a ``state measures'' approach. With an 
emission standards approach, a state will apply all requirements for 
achieving the subcategory-specific CO2 emission performance 
rates or the state-specific CO2 emission goal to affected 
EGUs in the form of federally enforceable emission standards. With a 
state measures approach, a state plan would be comprised, at least in 
part, of measures implemented by the state that are not included as 
federally enforceable components of the plan, along with a backstop of 
federally enforceable emission standards for affected EGUs that would 
apply in the event the plan does not achieve its anticipated level of 
CO2 emission performance.
    The EPA is requiring states to make their final plan submittals by 
September 6, 2016, or to make an initial submittal by this date in 
order to obtain an extension for making their final plan submittals no 
later than September 6, 2018, which is 3 years from the signature date 
of the rule. In order to receive an extension, states, in the initial 
submittal, must address three required components sufficiently to 
demonstrate that a state is able to undertake steps and processes 
necessary to timely submit a final plan by the extended date of 
September 6, 2018. The first required component is identification of 
final plan approach or approaches under consideration, including a 
description of progress made to date. The second required component is 
an appropriate explanation for why the state requires additional time 
to submit a final plan beyond September 6, 2016. The third required 
component for states to address in the initial submittal is a 
demonstration of how they have been engaging with the public, including 
vulnerable communities, and a description of how they intend to 
meaningfully engage with community stakeholders during the additional 
time (if an extension is granted) for development of the final plan.
    Affected EGUs must achieve the final emission performance rates or 
equivalent state goals by 2030 and maintain that level thereafter. The 
EPA is establishing an 8-year interim period over which states must 
achieve the full required reductions to meet the CO2 
performance rates, and this begins in 2022. This 8-year interim period 
from 2022 through 2029, is separated into three steps, 2022-2024, 2025-
2027, and 2028-2029, each associated with its own interim 
CO2 emission performance rates that states must meet, as 
explained in Section VI of this preamble.
    For the final emission guidelines, the EPA is revising the list of 
components required in a final state plan submittal to reflect: (1) 
Components required for all state plan submittals; (2) components 
required for the emission standards approach; and (3) components 
required for the state measures approach. The revised list of 
components also reflects the approvability criteria, which are no 
longer separate from the state plan submittal components.
    All state plans must include the following components:

 Description of the plan approach and geographic scope
 Identification of the state's CO2 interim period 
goal (for 2022-2029), interim steps (interim step goal 1 for 2022-
2024; interim step goal 2 for 2025-2027; interim step goal 3 for 
2028-2029) and final CO2 emission goal of 2030 and beyond
 Demonstration that the plan submittal is projected to 
achieve the state's CO2 emission goal \282\
---------------------------------------------------------------------------

    \282\ A state that chooses to set emission standards that are 
identical to the emission performance rates for both the interim 
period and in 2030 and beyond need not identify interim state goals 
nor include a separate demonstration that its plan will achieve the 
state goals.
---------------------------------------------------------------------------

 State recordkeeping and reporting requirements
 Certification of hearing on state plan
 Supporting documentation

    Also, in all state plans, as part of the supporting documentation, 
a state must include a description of how they considered reliability 
in developing its state plan.
    State plan submittals using the emission standards approach must 
also include:

     Identification of each affected EGU; identification of 
federally enforceable emission standards for the affected EGUs; and 
monitoring, recordkeeping and reporting requirements.
     Demonstrations that each emission standard will result 
in reductions that are quantifiable, non-duplicative, permanent, 
verifiable, and enforceable.

    State plan submittals using the state measures approach must also 
include:

     Identification of each affected EGU; identification of 
federally enforceable emission standards for affected EGUs (if 
applicable); identification of backstop of federally enforceable 
emission standards; and monitoring, recordkeeping and reporting 
requirements.
     Identification of each state measure and demonstration 
that each state measure will result in reductions that are 
quantifiable, non-duplicative, permanent, verifiable, and 
enforceable.

    In addition to these requirements, each state plan must follow the 
EPA implementing regulations at 40 CFR 60.23.
    If a state with affected EGUs does not submit a plan or if the EPA 
does not approve a state's plan, then under CAA section 111(d)(2)(A), 
the EPA must establish a plan for that state. A state that has no 
affected EGUs must document this in a formal negative declaration 
submitted to the EPA by September 6, 2016. In the case of a tribe that 
has one or more affected EGUs in its area of Indian country,\283\ the 
tribe has the opportunity, but not the obligation, to establish a CAA 
section 111(d) plan for its area of Indian country. If a tribe with one 
or more affected EGUs located in its area of

[[Page 64709]]

Indian country does not submit a plan or does not receive EPA approval 
of a submitted plan, the EPA has the responsibility to establish a CAA 
section 111(d) plan for that area if it determines that such a plan is 
necessary or appropriate.
---------------------------------------------------------------------------

    \283\ The EPA is aware of at least four affected EGUs located in 
Indian country: Two on Navajo lands, the Navajo Generating Station 
and the Four Corners Power Plant; one on Ute lands, the Bonanza 
Power Plant; and one on Fort Mojave lands, the South Point Energy 
Center. The affected EGUs at the first three plants are coal-fired 
EGUs. The fourth affected EGU is an NGCC facility.
---------------------------------------------------------------------------

    During implementation of its approved state plan, each state must 
demonstrate to the EPA that its affected EGUs are meeting the interim 
and final performance requirements included in this final rule through 
monitoring and reporting requirements. State plan requirements and 
flexibilities are described more fully in Section VIII of this 
preamble.

B. Brief Summary of Legal Basis

    This rule is consistent with the requirements of CAA section 111(d) 
and the implementing regulations.\284\ As an initial matter, the EPA 
reasonably interprets the provisions identifying which air pollutants 
are covered under CAA section 111(d) to authorize the EPA to regulate 
CO2 from fossil fuel-fired EGUs. In addition, the EPA 
recognizes that CAA section 111(d) applies to sources that, if they 
were new sources, would be covered under a CAA section 111(b) rule. 
Concurrently with this rule, the EPA is finalizing a CAA section 111(b) 
rulemaking establishing standards of performance for CO2 
emissions from new fossil fuel-fired EGUs, from modified fossil fuel-
fired EGUs, and from reconstructed fossil fuel-fired EGUs, and any of 
those sets of section 111(b) standards of performance provides the 
requisite predicate for this rulemaking.
---------------------------------------------------------------------------

    \284\ Under CAA section 111(d), there is no requirement that the 
EPA make a finding that the emissions from existing sources that are 
the subject of regulation cause or contribute significantly to air 
pollution which may reasonably be anticipated to endanger public 
health or welfare. As predicates to promulgating regulations under 
CAA section 111(d) for existing sources, the EPA must make 
endangerment and cause-or-contribute-significantly findings for 
emissions from the source category, and the EPA must promulgate 
regulations for new sources in the source category. In the CAA 
section 111(b) rule for CO2 emissions for new affected 
EGUs that the EPA is promulgating concurrently with this rule, the 
EPA discusses the endangerment and cause-or-contribute-significantly 
findings and explains why the EPA has already made them for the 
affected EGU source categories so that the EPA is not required to 
make them for CO2 emissions from affected EGUs, and, in 
the alternative, why, if the EPA were required to make those 
findings, it was making them in that rulemaking.
---------------------------------------------------------------------------

    A key step in promulgating requirements under CAA section 111(d)(1) 
is determining the ``best system of emission reduction which . . . the 
Administrator determines has been adequately demonstrated'' (BSER) 
under CAA section 111(a)(1). It is clear by the terms of section 
111(a)(1) and the implementing regulations for section 111(d) that the 
EPA is authorized to determine the BSER; \285\ accordingly, in this 
rulemaking, the EPA is determining the BSER.
---------------------------------------------------------------------------

    \285\ The EPA is not re-opening that interpretation in this 
rulemaking.
---------------------------------------------------------------------------

    The EPA is finalizing the BSER for fossil fuel-fired EGUs based on 
building blocks 1, 2, and 3. Building block 1 includes operational 
improvements and equipment upgrades that the coal-fired steam-
generating EGUs in the state may undertake to improve their heat rate. 
It qualifies as part of the BSER because it improves the carbon 
intensity of the affected EGUs in generating electricity through 
actions the affected sources may undertake that are adequately 
demonstrated and whose cost is ``reasonable.'' Building blocks 2 and 3 
include increases in low- or zero-emitting generation which substitute 
for generation from the affected EGUs and thereby reduce CO2 
emissions from those sources. All of these measures are components of a 
``system of emission reduction'' for the affected EGUs because they 
entail actions that the affected EGUs may themselves undertake that 
have the effect of reducing their emissions. Further, these measures 
meet the criteria in CAA section 111(a)(1) and the case law for the 
``best'' system of emission reduction that is ``adequately 
demonstrated'' because they achieve the appropriate level of 
reductions, their cost is ``reasonable,'' they do not have adverse non-
air quality health and environmental impacts or impose adverse energy 
requirements, and they are each well-established among affected EGUs. 
It should be emphasized that these measures are consistent with current 
trends in the electricity sector.
    Building blocks 2 and 3 may be implemented through a set of 
measures, including reduced generation from the fossil fuel-fired EGUs. 
These measures do not, however, reduce the amount of electricity that 
can be sold or that is available to end users. In addition, states 
should be expected to allow their affected EGUs to trade rate-based 
emission credits or mass-based emission allowances (trading) because 
trading is well-established for this industry and has the effect of 
focusing costs on the affected EGUs for which reducing emissions is 
most cost-effective. Because trading facilitates implementation of the 
building blocks and may help to optimize cost-effectiveness, trading is 
a method of implementing the BSER as well.
    As a result, an affected EGU has a set of choices for achieving its 
emission standards. For example, an affected coal-fired steam 
generating unit can achieve a rate-based standard through a set of 
actions that implement the building block 1 measures and that implement 
the building block 2 and 3 measures through a set of actions that range 
from purchasing full or partial interest in existing NGCC or new RE 
assets to purchasing ERCs that represent the environmental attributes 
of increased NGCC generation or new renewable generation. In addition, 
the affected EGU may reduce its generation and thereby reduce the 
extent that it needs to implement the building blocks. The affected EGU 
may also purchase rate-based emission credits from other affected EGUs. 
If the state chooses to impose a mass-based emission standard, the 
coal-fired steam generating unit may implement building block 1 
measures, purchase mass-based emission allowances from other affected 
EGUs, or reduce its generation. In light of the available sources of 
lower- and zero-emitting replacement generation, this approach would 
achieve an appropriate level of emission reductions and maintain the 
reliability of the electricity system.
    With the promulgation of the emission guidelines, each state must 
develop and submit a plan to achieve the CO2 emission 
performance rates established by the EPA or the equivalent statewide 
rate-based or mass-based goal provided by the EPA in this rule. The EPA 
interprets CAA section 111(d) to allow states to establish standards of 
performance and provide for their implementation and enforcement 
through either the ``emission standards'' or the ``state measures'' 
plan type. In the case of the ``emission standards'' plan type, the 
emission standards establish standards of performance, and the other 
components of the plan provide for their implementation and 
enforcement. In the case of the ``state measures'' plan type, -the 
state submits a plan that relies upon measures that are only 
enforceable as a matter of state law that will, in conjunction with any 
emission standards on affected EGUs, result in the achievement of the 
applicable performance rates or state goals by the affected EGUs. Under 
the state measures plan type, states must also submit a federally 
enforceable backstop and a mechanism that would trigger implementation 
of the backstop; therefore, in a state measures plan, the standards of 
performance take the form of the backstop, the trigger mechanism 
provides for the implementation of such backstop, and the other 
required components of the plan provide for

[[Page 64710]]

implementation and enforcement of the standards of performance.
    These two types of state plans and their respective approaches, 
which could be implemented on a single-state or multi-state basis, 
allow states to meet the statutory requirements of section 111(d) while 
accommodating the wide range of regulatory requirements and other 
programs that states have deployed or will deploy in the electricity 
sector that reduce CO2 emissions from affected EGUs. It 
should be noted that both state plan types allow the state flexibility 
in assigning the emission performance obligations to its affected EGUs 
in the form of standards of performance as long as the required 
emission performance level is met. Both plan types harness the 
efficiencies of emission reduction opportunities in the interconnected 
electricity system and are fully consistent with the principles of 
cooperative federalism that underlie the Clean Air Act generally and 
CAA section 111(d) particularly. That is, both plan types achieve the 
emission performance requirements through the vehicle of a state plan, 
and provide each state significant flexibility to take local 
circumstances and state policy goals into account in determining how to 
reduce emissions from its affected sources, as long as the plan meets 
minimum federal requirements.
    Both state plan types, and the standards of performance for the 
affected EGUs that the states will establish through the state plan 
process, are consistent with the applicable CAA section 111 provisions. 
A state has discretion in determining the appropriate measures to rely 
upon for its plan. The state may adopt measures that assure the 
achievement of the requisite CO2 emission performance rate 
or state goal by the affected EGUs, and is not limited to the measures 
that the EPA identifies as part of the BSER.
    In this rulemaking, the EPA establishes reasonable deadlines for 
state plan submission. Under CAA section 111(d)(1), state plans must 
``provide for implementation and enforcement'' of the standards of 
performance, and under CAA section 111(d)(2), the state plans must be 
``satisfactory'' for the EPA to approve them. In this rulemaking, the 
EPA is finalizing the criteria that the state plans must meet under 
these requirements.
    The EPA discusses its legal interpretation in more detail in other 
parts of this preamble and provides additional information about 
certain issues in the Legal Memorandum included in the docket for this 
rulemaking.

IV. Authority for This Rulemaking, Definition of Affected Sources, and 
Treatment of Source Categories

A. EPA's Authority Under CAA Section 111(d)

    EPA's authority for this rule is CAA section 111(d). CAA section 
111(d) provides that the EPA will promulgate regulations under which 
each state will establish standards of performance for existing sources 
for any air pollutant that meets two criteria. First, CAA section 
111(d) applies to air pollutants that are not regulated as a criteria 
pollutant under section 108 or as a hazardous air pollutant (HAP) under 
CAA section 112. 42 U.S.C. 7411(d)(1)(A)(i).\286\ Second, section 
111(d) applies only to air pollutants for which the existing source 
would be regulated under section 111 if it were a new source. 42 U.S.C. 
7411(d)(1)(A)(ii). Here, carbon dioxide (CO2) meets both 
criteria: (1) It is not a criteria pollutant regulated under section 
108 nor a HAP regulated under CAA section 112, and (2) CO2 
emissions from new power plants (including newly constructed, modified 
and reconstructed power plants) are regulated under the CAA section 
111(b) rule that is being finalized along with this rule.
---------------------------------------------------------------------------

    \286\ Section 111(d) might be read to apply to HAP under certain 
circumstances. However, because carbon dioxide is not a HAP, this 
issue does not need to be resolved in the context of this rule.
---------------------------------------------------------------------------

B. CAA Section 112 Exclusion to CAA Section 111(d) Authority

    CAA section 111(d) contains an exclusion that limits the regulation 
under CAA section 111(d) of air pollutants that are regulated under CAA 
section 112. 42 U.S.C. 7411(d)(1)(A)(i). This ``Section 112 Exclusion'' 
in CAA section 111(d) was the subject of a significant number of 
comments based on two differing amendments to this exclusion enacted in 
the 1990 CAA Amendments. As discussed in more detail below, the House 
and the Senate each initially passed different amendments to the 
Section 112 Exclusion and both amendments were ultimately passed by 
both houses and signed into law. In 2005, in connection with the Clean 
Air Mercury Rule (CAMR), the EPA discussed the agency's interpretation 
of the Section 112 Exclusion in light of these two differing amendments 
and concluded that the two amendments were in conflict and that the 
provision should be read as follows to give both amendments meaning: 
where a source category has been regulated under CAA section 112, a CAA 
section 111(d) standard of performance cannot be established to address 
any HAP listed under CAA section 112(b) that may be emitted from that 
particular source category. See 70 FR 15994, 16029-32 (March 29, 2005).
    In June 2014, the EPA presented this previous interpretation as 
part of the proposal and requested comment on it. The EPA received 
numerous comments on its previous interpretation, including comments on 
the proper interpretation and effect of each of the two differing 
amendments, and whether the Section 112 Exclusion should be read to 
mean that the EPA's regulation of HAP from power plants under CAA 
section 112 bars the EPA from establishing CAA section 111(d) 
regulations covering CO2 emissions from power plants. In 
particular, many comments focused on two specific issues. First, some 
commenters--including some industry and state commenters that had 
previously endorsed the EPA's interpretation of the Section 112 
Exclusion in other contexts \287\--argued that the EPA's 2005 
interpretation was in error because it allowed the regulation of 
certain pollutants from source categories under CAA section 111(d) when 
those source categories were also regulated for different pollutants 
under CAA section 112. Second, some commenters argued that the EPA's 
previous interpretation of the House amendment (as originally 
represented in 2005 at 70 FR at 16029-30) was in error because it 
improperly read that amendment as focusing on whether a source category 
was regulated under CAA section 112 rather than on whether the air 
pollutant was regulated under CAA section 112, and that improper 
reading lead to an interpretation that was inconsistent with the 
structure and purpose of the CAA.
---------------------------------------------------------------------------

    \287\ For example, in the CAMR litigation (State of New Jersey 
v. EPA, No. 05-1097 (D.C. Cir.), the joint brief filed by a group of 
intervenors and an amicus (including six states and the West 
Virginia Department of Environmental Protection, and Utility Air 
Regulatory Group and nine other industry entities) stated that the 
EPA had interpreted section 111(d) in light of the two different 
amendments and that the EPA's interpretation was ``a reasoned way to 
reconcile the conflicting language and the Court should defer to the 
EPA's interpretation.'' Joint Brief of State Respondent-Intervenors, 
Industry Respondent-Intervernors, and State Amicus, filed May 18, 
2007, at 25.
---------------------------------------------------------------------------

    In light of the comments, the EPA has reconsidered its previous 
interpretation of the Section 112 Exclusion and, in particular, 
considered whether the exclusion precludes the regulation under CAA 
section 111(d) of CO2 from power plants given that power 
plants are regulated for certain HAP under CAA section 112. On this 
issue, the EPA

[[Page 64711]]

has concluded that the two differing amendments are not properly read 
as conflicting. Instead, the House amendment and the Senate Amendment 
should each be read to mean the same in the context presented by this 
rule: that the Section 112 Exclusion does not bar the regulation under 
CAA section 111(d) of non-HAP from a source category, regardless of 
whether that source category is subject to standards for HAP under CAA 
section 112. In reaching this conclusion, the EPA has revised its 
previous interpretation of the House amendment, as discussed below.
1. Structure of the CAA and Pre-1990 Section 112 Exclusion
    The Clean Air Act sets out a comprehensive scheme for air pollution 
control, addressing three general categories of pollutants emitted from 
stationary sources: (1) Criteria pollutants (which are addressed in 
sections 108-110); (2) hazardous pollutants (which are addressed under 
section 112); and (3) ``pollutants that are (or may be) harmful to 
public health or welfare but are not or cannot be controlled under 
sections 108-110 or 112.'' 40 FR 53340 (Nov. 17, 1975).
    Six ``criteria'' pollutants are regulated under sections 108-110. 
These are pollutants that the Administrator has concluded ``cause or 
contribute to air pollution which may reasonably be anticipated to 
endanger public health or welfare;'' ``the presence of which in the 
ambient air results from numerous and diverse mobile or stationary 
sources;'' and for which the Administrator has issued, or plans to 
issue, ``air quality criteria. 42 U.S.C. 7408(a)(1). Once the EPA 
issues air quality criteria for such pollutants, the Administrator must 
propose primary National Ambient Air Quality Standards (NAAQS) for 
them, set at levels ``requisite to protect the public health'' with an 
``adequate margin of safety.'' 42 U.S.C. 7409(a)-(b). States must then 
adopt plans for implementing NAAQS. 42 U.S.C. 7410.
    HAP are regulated under CAA section 112 and include the pollutants 
listed by Congress in section 112(b)(1) and other pollutants that the 
EPA lists under sections 112(b)(2) and (b)(3). CAA section 112 further 
provides that the EPA will publish and revise a list of ``major'' and 
``area'' source categories of HAP, and then establish emissions 
standards for HAP emitted by sources within each listed category. 42 
U.S.C. 7412(c)(1) & (2).
    CAA section 111, 42 U.S.C. 7411, is the third part of the CAA's 
structure for regulating stationary sources. Section 111 has two main 
components. First, section 111(b) requires the EPA to promulgate 
federal ``standards of performance'' addressing new stationary sources 
that cause or contribute significantly to ``air pollution which may 
reasonably be anticipated to endanger public health or welfare.'' 42 
U.S.C. 7411(b)(1)(A). Once the EPA has set new source standards 
addressing emissions of a particular pollutant under CAA section 
111(b), CAA section 111(d) provides that the EPA will promulgate 
regulations requiring states to establish standards of performance for 
existing stationary sources of the same pollutant. 42 U.S.C. 
7411(d)(1).
    Together, the criteria pollutant/NAAQS provisions in sections 108-
110, the hazardous air pollutant provisions in section 112, and 
performance standard provisions in section 111 constitute a 
comprehensive scheme to regulate air pollutants with ``no gaps in 
control activities pertaining to stationary source emissions that pose 
any significant danger to public health or welfare.'' S. Rep. No. 91-
1196, at 20 (1970).\288\
---------------------------------------------------------------------------

    \288\ In subsequent CAA amendments, Congress has maintained this 
three-part scheme, but supplemented it with the Preservation of 
Significant Deterioration (PSD) program, the Acid Rain Program and 
the Regional Haze program.
---------------------------------------------------------------------------

    The specific role of CAA section 111(d) in this structure can be 
seen in CAA subsection 111(d)(1)(A)(i), which provides that regulation 
under CAA section 111(d) is intended to cover pollutants that are not 
regulated under either the criteria pollutant/NAAQS provisions or 
section 112. Prior to 1990, this limitation was laid out in plain 
language, which stated that CAA section 111(d) regulation applied to 
``any air pollutant . . . for which air quality criteria have not been 
issued or which is not included on a list published under section 
[108(a)] or [112(b)(1)(A)].'' This plain language demonstrated that 
section 111(d) is designed to regulate pollutants from existing sources 
that fall in the gap not covered by the criteria pollutant provisions 
or the hazardous air pollutant provisions.
    This gap-filling purpose can be seen in the early legislative 
history of the CAA. As originally enacted in the 1970 CAA, the 
precursor to CAA section 111 (which was originally section 114) was 
described as covering pollutants that would not be controlled by the 
criteria pollutant provisions or the hazardous air pollutant 
provisions. See S. Committee Rep. to accompany S. 4358 (Sept. 17, 
1970), 1970 CAA Legis. Hist. at 420 (``It should be noted that the 
emission standards for pollutants which cannot be considered hazardous 
(as defined in section 115 [which later became section 112]) could be 
established under section 114 [later, section 111]. Thus, there should 
be no gaps in control activities pertaining to stationary source 
emissions that pose any significant danger to public health or 
welfare.''); Statement by S. Muskie, S. Debate on S. 4358 (Sept. 21, 
1970), 1970 CAA Legis. Hist. at 227 (``[T]he bill [in section 114] 
provides the Secretary with the authority to set emission standards for 
selected pollutants which cannot be controlled through the ambient air 
quality standards and which are not hazardous substances.'').
2. The 1990 Amendments to the Section 112 Exclusion
    The Act was amended extensively in 1990. Among other things, 
Congress sought to accelerate the EPA's regulation of hazardous 
pollutants under section 112. To that end, Congress established a 
lengthy list of HAP; set criteria for listing ``source categories'' of 
such pollutants; and required the EPA to establish standards for each 
listed source category's hazardous pollutant emissions. 42 U.S.C. 
7412(b), (c) and (d). In the course of overhauling the regulation of 
HAP under section 112, Congress needed to edit section 111(d)'s 
reference to section 112(b)(1)(A), which was to be eliminated as part 
of the revisions to section 112.
    To address the obsolete cross-reference to section 7412(b)(1)(A), 
Congress passed two differing amendments--one from the Senate and one 
from the House--that were never reconciled in conference. The Senate 
amendment replaced the cross reference to old section 112(b)(1)(A) with 
a cross-reference to new section 112. Pub. L. 101-549, Sec.  302(a), 
104 Stat. 2399, 2574 (1990). The House amendment replaced the cross-
reference with the phrase ``emitted from a source category which is 
regulated under section [112].'' Pub. L. 101-549, Sec.  108(g), 104 
Stat. 2399, 2467 (1990).\289\ Both amendments were

[[Page 64712]]

enacted into law, and thus both are part of the current CAA. To 
determine how this provision is properly applied in light of the two 
differing amendments, we first look at the Senate amendment, then at 
the House amendment, then discuss how the two amendments are properly 
read together.

---------------------------------------------------------------------------

    \289\ Originally, when the House bill to amend the CAA was 
introduced in January 1989, it focused on amendments to control HAP. 
Of particular note, the amendments to section 112 included a 
provision that excluded regulation under section 112 of ``[a]ny air 
pollutant which is included on the list under section 108(a), or 
which is regulated for a source category under section 111(d).'' 
H.R. 4, Sec.  2 (Jan. 3, 1989), 1990 CAA Legist. Hist. at 4046. In 
other words, the Section 112 Exclusion in section 111(d) that was 
ultimately contained in the House amendment was originally crafted 
as what might be called a ``Section 111(d) Exclusion'' in section 
112. This is significant because the ``source category'' phrasing in 
the original January 1989 text with respect to section 111(d) makes 
sense, whereas the ``source category'' phrasing in the 1990 House 
amendment does not. When referring to the scope of what is regulated 
under section 111(d), it makes sense to frame that scope with 
respect to source categories, because section 111 regulation begins 
with the identification of source categories under section 
111(b)(1)(A). By contrast, regulation under section 112 begins with 
the identification of HAP under section 112(b); the listing of 
source categories under section 112(c) is secondary to the listing 
of HAP. From this history, and in light of this difference between 
the scope of what is regulated in sections 111 and 112, it is 
reasonable to conclude that the ``source category'' phrasing is a 
legacy from the original 1989 bill--that is, when converting the 
1989 text into the Section 112 Exclusion that we see in the 1990 
House amendment, the legislative drafters continued to use phrasing 
based on ``source category'' notwithstanding that this phrasing 
created a mismatch with the way that the scope of section 112 
regulation is determined.
---------------------------------------------------------------------------

3. The Senate Amendment is Clear and Unambiguous
    Unlike the ambiguous amendment to CAA section 111(d) in the House 
amendment (discussed below), the Senate amendment is straightforward 
and unambiguous. It maintained the pre-1990 meaning of the Section 112 
Exclusion by simply substituting ``section 112(b)'' for the prior 
cross-reference to ``section 112(b)(1)(A).'' Pub. L. 101-549, Sec.  
302(a), 104 Stat. 2399, 2574 (1990). So amended, CAA section 111(d) 
mandates that the EPA require states to submit plans establishing 
standards for ``any air pollutant . . . which is not included on a list 
published under section [108(a)] or section [112(b)].'' Thus, the 
Section 112 Exclusion resulting from the Senate amendment would 
preclude CAA section 111(d) regulation of HAP emission but would not 
preclude CAA section 111(d) regulation of CO2 emissions from 
power plants notwithstanding that power plants are also regulated for 
HAP under CAA section 112.
    Some commenters have argued that the Senate amendment should be 
given no effect, because only the House amendment is shown in the U.S. 
Code, and because the Senate amendment appeared under the heading 
``conforming amendments,'' and for various other reasons. The EPA 
disagrees. The Senate amendment, like the House amendment, was enacted 
into law as part of the 1990 CAA amendments, and must be given effect.
    First, that the U.S. Code only reflects the House amendment does 
not change the fact that both amendments were signed into law as part 
of the 1990 Amendments, as shown in the Statutes at Large. Pub. L. 101-
549, Sec. Sec.  108(g) and 302(a), 104 Stat. 2399, 2467, 2574 (1990). 
Where there is a conflict between the U.S. Code and the Statutes at 
Large, the latter controls. See 1 U.S.C. 112 & 204(a); Stephan v. 
United States, 319 U.S. 423, 426 (1943) (``the Code cannot prevail over 
the Statutes at Large when the two are inconsistent''); Five Flags Pipe 
Line Co. v. Dep't of Transp., 854 F.2d 1438, 1440 (D.C. Cir. 1988) 
(``[W]here the language of the Statutes at Large conflicts with the 
language in the United States Code that has not been enacted into 
positive law, the language of the Statutes at Large controls.'').
    Second, the ``conforming'' label is irrelevant. A ``conforming'' 
amendment may be either substantive or non-substantive. Burgess v. 
United States, 553 U.S. 124, 135 (2008). And while the House Amendment 
contains more words, it also qualifies as a ``conforming amendment'' 
under the definition in the Senate Legislative Drafting Manual, Section 
126(b)(2) (defining ``conforming amendments'' as those ``necessitated 
by the substantive amendments of provisions of the bill''). Here, both 
the House and Senate amendments were ``necessitated by'' Congress' 
revisions to section 112 in the 1990 CAA Amendment, which included the 
deletion of old section 112(b)(1)(A). Thus, the House's amendment is no 
less ``conforming'' than the Senate's, and the heading under which it 
was enacted (``Miscellaneous Guidance'') does not suggest any more 
importance than ``Conforming Amendments.'' In any event, courts gives 
full effect to conforming amendments, see Washington Hosp. Ctr. v. 
Bowen, 795 F.2d 139, 149 (D.C. Cir. 1986), and so neither the Senate 
Amendment nor the House amendment can be ignored.
    Third, the legislative history of the Senate amendment supports the 
conclusion that the substitution of the updated cross-reference was not 
a mindless, ministerial decision, but reflected a decision to choose an 
update of the cross reference instead of the text that was inserted 
into the Section 112 Exclusion by the House amendment. In mid-1989, the 
House and Senate introduced identical bills (H.R. 3030 and S. 1490, 
respectively) to provide for ``miscellaneous'' changes to the CAA. In 
both the Senate and House bills as they were introduced in mid-1989, 
the Section 112 Exclusion was to be amended by taking out ``or 
112(b)(1)(A)'' and inserting ``or emitted from a source category which 
is regulated under section 112.'' H.R. 3030, as introduced, 101st Cong. 
Sec.  108 (Jul. 27, 1989); S. 1490, as introduced, 101st Cong. Sec.  
108 (Aug. 3, 1989). See 1990 CAA Legis. Hist. at 3857 (noting that H.R. 
3030 and S.1490, as introduced, were the same). Although S. 1490 was 
identical to H.R. 3030 when they were introduced, the Senate reported a 
vastly different bill (S.1630) at the end of 1989. See S. 1630, as 
reported (Dec. 20, 1989), 1990 CAA Legis. Hist. at 7906. As reported 
and eventually passed, S. 1630 did not contain the text in the House 
amendment (``or emitted from a source category which is regulated under 
section 112'') and instead contained the substitution of cross 
references (changing ``section 112(b)(1)(A)'' to ``section 112(b)''). 
See S. 1630, as reported, 101st Cong. Sec.  305, 1990 CAA Legis. Hist. 
at 8153; S. 1630, as passed, Sec.  305 (Apr. 3, 1990), 1990 CAA Legis. 
Hist. at 4534. Though the EPA is not aware of any statements in the 
legislative history that expressly explain the Senate's intent in 
making these changes to the Senate bill, the sequence itself supports 
the conclusion that the Senate's substitution reflects a decision to 
retain the pre-1990 approach of using a cross-reference to 112(b) to 
define the scope of the Section 112 Exclusion. Whether the difference 
in approach between the final Senate amendment in S.1630 and the House 
amendment in H.R. 3030 creates a substantive difference or are simply 
two different means of achieving the same end depends on what 
interpretation one gives to the text in the House amendment, which we 
turn to next.
4. The House Amendment
    a. The House amendment is ambiguous. Before looking at the specific 
text of the House amendment, it is helpful to review some principles of 
statutory interpretation. First, statutory interpretation begins with 
the text, but does not end there. As the D.C. Circuit Court has 
explained, ``[t]he literal language of a provision taken out of context 
cannot provide conclusive proof of congressional intent.'' Bell 
Atlantic Telephone Cos. v. F.C.C., 131 F.3d 1044, 1047 (D.C. Cir. 
1977). See King v. Burwell, 2015 U.S. LEXIS 4248, *19(``[O]ftentimes 
the `meaning--or ambiguity--of certain words or phrases may only become 
evident when placed in context.' Brown & Williamson, 529 U. S., at 132, 
120 S. Ct. 1291, 146 L. Ed. 2d 121. So when deciding whether the 
language is plain, we must read the words `in their context and with a 
view to their place in the overall statutory scheme.' Id., at 133, 120 
S. Ct. 1291, 146 L. Ed. 2d 121 (internal quotation marks omitted). Our 
duty, after all, is `to construe statutes, not isolated provisions.' 
Graham County Soil and

[[Page 64713]]

Water Conservation Dist. v. United States ex rel. Wilson, 559 U. S. 
280, 290, 130 S. Ct. 1396, 176 L. Ed. 2d 225 (2010) (internal quotation 
marks omitted).''). In addition, statutes should not be given a 
``hyperliteral'' reading that is contrary to established canons of 
statutory construction and common sense. See RadLAX Gateway Hotel v. 
Amalgamated Bank, 132 S.Ct. 2065, 2070-71 (2012).
    Further, a proper reading of statutory text ``must employ all the 
tools of statutory interpretation, including text, structure, purpose, 
and legislative history.'' Loving v. I.R.S., 742 F.3d 1013, 1016 (D.C. 
Cir. 2014) (internal quotation omitted). See, also, Robinson v. Shell 
Oil Co., 519 U.S. 337, 341 (1997) (statutory interpretation involves 
consideration of ``the language itself, the specific context in which 
that language is used, and the broader context of the statute as a 
whole.''). Moreover, one principle of statutory construction that has 
particular application here is that provisions in a statute should be 
read to be consistent, rather than conflicting, if possible. This 
principle was discussed in the recent case of Scialabba v. Cuellar De 
Osorio, 134 S. Ct. 2191, 2214 (concurring opinion by Chief Justice 
Roberts and Justice Scalia), 2219-2220 (dissent by Justices Sotomayor, 
Breyer and Thomas)(2014). As Justice Sotomayor wrote (at 134 S. Ct. at 
2220):

    ``We do not lightly presume that Congress has legislated in 
self-contradicting terms. See A. Scalia & B. Garner, Reading Law: 
The Interpretation of Legal Texts 180 (2012) (``The provisions of a 
text should be interpreted in a way that renders them compatible, 
not contradictory. . . . [T]here can be no justification for 
needlessly rendering provisions in conflict if they can be 
interpreted harmoniously''). . . . Thus, time and again we have 
stressed our duty to ``fit, if possible, all parts [of a statute] 
into [a] harmonious whole.'' FTC v. Mandel Brothers, Inc., 359 U.S. 
385, 389, 79 S. Ct. 818, 3 L. Ed. 2d 893 (1959); see also Morton v. 
Mancari, 417 U.S. 535, 551, 94 S. Ct. 2474, 41 L. Ed. 2d 290 (1974) 
(when two provisions ``are capable of co-existence, it is the duty 
of the courts . . . to regard each as effective''). In reviewing an 
agency's construction of a statute, courts ``must,'' we have 
emphasized, ``interpret the statute `as a . . . coherent regulatory 
scheme' '' rather than an internally inconsistent muddle, at war 
with itself and defective from the day it was written. Brown & 
Williamson, 529 U.S., at 133, 120 S. Ct. 1291, 146 L. Ed. 2d 121.

    As amended by the House, CAA section 111(d)(1)(A)(i) limits CAA 
section 111(d) to any air pollutant ``for which air quality criteria 
have not been issued or which is not included on a list published under 
section 7408(a) of this title or emitted from a source category which 
is regulated under section 7412 of this title . . .'' This statutory 
text is ambiguous and subject to numerous possible readings.
    First, the text of the House-amended version of CAA section 111(d) 
could be read literally as authorizing the regulation of any pollutant 
that is not a criteria pollutant. This reading arises if one focuses on 
the use of ``or'' to join the three clauses:

    The Administrator shall prescribe regulations . . . under which 
each State shall submit to the Administrator a plan which 
establishes standards of performance for any existing source for any 
air pollutant [1] for which air quality criteria have not been 
issued or [2] which is not included on a list published under 
section 7408(a) of this title or [3] emitted from a source category 
which is regulated under section 7412 of this title. . . .

    42 U.S.C. 7411(d)(1) (emphasis and internal numbering added). 
Because the text contains the conjunction ``or'' rather than ``and'' 
between the three clauses, a literal reading could read the three 
clauses as alternatives, rather than requirements to be imposed 
simultaneously. In other words, a literal reading of the language of 
section 111(d) provides that the Administrator may require states to 
establish standards for an air pollutant so long as either air quality 
criteria have not been established for that pollutant, or one of the 
remaining criteria is met. If this reading were applied to determine 
whether the EPA may promulgate CAA section 111(d) regulations for 
CO2 from power plants, the result would be that 
CO2 from power plants could be regulated under CAA section 
111(b) because air quality criteria have not been issued for 
CO2 and therefore whether CO2 or power plants are 
regulated under CAA section 112 would be irrelevant. This reading, 
however, is not a reasonable reading of the statute because, among 
other reasons, it gives little or no meaning to the limitation covering 
HAP that are regulated under CAA section 112 and thus is contrary to 
both the CAA's comprehensive scheme created by the three sets of 
provisions (under which CAA section 111 is not intended to duplicate 
the regulation of pollutants regulated under section 112) and the 
principle of statutory construction that text should not be construed 
such that a provision does not have effect.
    A second reading of CAA section 111(d) as revised by the House 
amendment focuses on the lack of a negative before the third clause. 
That is, unlike the first and second clauses that each contain negative 
phrases (either ``has not been issued'' or ``which is not included''), 
the third clause does not. One could presume that the negative from the 
second clause was intended to carry over, implicitly inserting another 
``which is not'' before ``emitted from a source category which is 
regulated under section [112].'' But that is a presumption, and not the 
plain language of the statute. The text as amended by the House says 
that the EPA ``shall'' prescribe regulations for ``any air pollutant . 
. . emitted from a source category which is regulated under section 
[112].'' 42 U.S.C. 7411(d)(1). Thus, CAA section 111(d)(1)(A)(i) could 
be read as providing for the regulation of emissions of pollutants if 
they are emitted from a source category that is regulated under CAA 
section 112. Like the first reading discussed above, this reading would 
authorize the regulation of CO2 emissions from existing 
power plants under CAA section 111(d). But, this second reading is not 
reasonable because it would provide for the regulation of a source's 
HAP emissions under CAA section 111(d) when those same emissions were 
also subject to standards under CAA section 112. Thus, this reading 
would be contrary to Congress's intent that CAA section 111(d) 
regulation fill the gap between the other programs by covering 
pollutants that the other programs do not, but not duplicate the 
regulation of pollutants that the other programs cover.
    If one does presume that the ``which is not'' phrase is intended to 
carry over to the third clause, then CAA section 111(d) regulation 
under the House amendment would be limited to ``any air pollutant . . . 
which is not . . . emitted from a source category which is regulated 
under section [112].'' Even with this presumption, however, the House 
amendment contains further ambiguities with respect to the phrases ``a 
source category'' and ``regulated under section 112,'' and how those 
phrases are used within the structure of the provision limiting what 
air pollutants may be regulated under CAA section 111(d).
    The phrase ``regulated under section 112'' is ambiguous. As the 
Supreme Court has explained in the context of other statutes using a 
variation of the word ``regulate,'' an agency must consider what is 
being regulated. See Rush Prudential HMO, Inc. v. Moran, 536 U.S. 355, 
366 (2002) (It is necessary to ``pars[e] . . . the `what' '' of the 
term ``regulates.''); UNUM Life Ins. Co. of Am. v. Ward, 526 U.S. 358, 
363 (1999) (the term `` `regulates insurance' . . . requires 
interpretation, for [its] meaning is not plain.''). Here, one possible 
reading is that the phase modifies the words ``a source category'' 
without

[[Page 64714]]

regard to what pollutants are regulated under section 112, which then 
presents the issue of what meaning to give to the phrase ``a source 
category.''
    Under this reading, and assuming the phrase ``a source category'' 
is read to mean the particular source category, the House amendment 
would preclude the regulation under CAA section 111(d) of a specific 
source category for any pollutant if that source category has been 
regulated for any HAP under CAA section 112.\290\ The effect of this 
reading would be to preclude the regulation of CO2 from 
power plants under CAA section 111(d) because power plants have been 
regulated for HAP under CAA section 112. This is the interpretation 
that the EPA applied to the House amendment in connection with the CAMR 
rule in 2005, when looking at the question of whether HAP can be 
regulated under CAA section 111(d) for a source category that is not 
regulated for HAP under section 112, and some commenters have advocated 
for this interpretation here. But, after considering all of the 
comments and reconsidering this interpretation, the EPA has concluded 
that this interpretation of the House amendment is not a reasonable 
reading because it would disrupt the comprehensive scheme for 
regulating existing sources created by the three sets of provisions 
covering criteria pollutants, HAP and the other pollutants that fall 
outside of those two programs and frustrate the role that section 111 
is intended to play.\291\ Specifically, under this interpretation, the 
EPA could not regulate a source category's emissions of HAP under CAA 
section 112, and then promulgate regulations for other pollutants from 
that source category under CAA section 111(d).\292\ There is no reason 
to conclude that the House amendment was intended to abandon the 
existing structure and relationship between the three programs in this 
way. Indeed, Congress expressly provided that regulation under CAA 
section 112 was not to ``diminish or replace the requirements of'' the 
EPA's regulation of non-hazardous pollutants under section 7411. See 42 
U.S.C. 7412(d)(7). Further, consistent with CAA section 112's direction 
that EPA list ``all categories and subcategories of major sources and 
area [aka, non-major] sources'' of HAP and then establish CAA section 
112 standards for those categories and subcategories, 42 U.S.C. 
7412(c)(1) and (c)(2), the EPA has listed and regulated over 140 
categories of sources under CAA section 112. Thus, this reading would 
eviscerate the EPA's authority under section 111(d) and prevent it from 
serving as the gap-filling provision within the comprehensive scheme of 
the CAA as Congress intended.\293\ In short, it is not reasonable to 
interpret the Section 112 Exclusion in section 111(d) to mean that the 
existence of CAA section 112 standards covering hazardous pollutants 
from a source category would entirely eliminate regulation of non-
hazardous emissions from that source category under section 
111(d).\294\
---------------------------------------------------------------------------

    \290\ ``A source category'' could also be interpreted to mean 
``any source category.'' Under this interpretation, CAA 111(d) 
regulation would be limited to air pollutants that are not emitted 
by any source category for which the EPA has issued standards for 
HAP under CAA section 112. This interpretation is not reasonable 
because it would effectively read CAA 111(d) out of the statute. 
Given the extensive list of source categories regulated under CAA 
112 and the breadth of pollutants emitted by those categories 
collectively, literally all air pollutants would be barred from CAA 
111(d) regulation under this interpretation.
    \291\ In assessing any interpretation of section 111(d), EPA 
must consider how the three main programs set forth in the CAA work 
together. See UARG, 134 S. Ct. at 2442 (a ``reasonable statutory 
interpretation must account for . . . the broader context of the 
statute as a whole'') (quotation omitted).
    \292\ Supporters of this interpretation have noted that the EPA 
could regulate power plants under both CAA section 111(d) and CAA 
section 112 if it regulated under section 111(d) first, before the 
Section 112 Exclusion is triggered. But that argument actually 
further demonstrates another reason why this interpretation is 
unreasonable. There is no basis for concluding that Congress 
intended to mandate that section 111(d) regulation occur first, nor 
is there any logical reason why the need to regulate under section 
111(d) should be dependent on the timing of such regulation in 
relation to CAA 112 regulation of that source category.
    \293\ Some commenters have stated that EPA could choose to 
regulate both HAP and non-HAP under section 111(d), and thus could 
regulate HAP without creating a gap. But this presumes that Congress 
intended EPA to have the choice of declining to regulate a section 
112-listed source category for HAP under section 112, which is 
inconsistent with the mandatory language in section 112. See, e.g., 
section 112(d)(1)(``The Administrator shall promulgate regulations 
establishing emissions standards for each category or subcategory of 
major sources and area sources of hazardous air pollutants listed 
for regulation pursuant to subsection (c) of this section in 
accordance with the schedules provided in subsections (c) and (e) of 
this section.''). Moreover, given the prescriptive language that 
Congress added into section 112 concerning how to set standards for 
HAP, see section 112(d)(2) and (d)(3), it is unreasonable to 
conclude that Congress intended that the EPA could simply choose to 
ignore the provisions in section 112 and instead regulate HAP for a 
section 112 listed source category under section 111(d).
    Further, some supporters of this interpretation have suggested 
that EPA could regulate CO2 under section 112. But this 
suggestion fails to consider that sources emitting HAP are major 
sources if they emit 10 tons of any HAP. See CAA section 112(a)(1). 
Thus, if CO2 were regulated as a HAP, and because 
emissions of CO2 tend to be many times greater than 
emissions of other pollutants, a huge number of smaller sources 
would become regulated for the first time under the CAA.
    \294\ Even if one were to determine that this interpretation 
were the proper reading of the House amendment that would not be the 
end of the analysis. Instead, that reading would create a conflict 
between the Senate amendment and the House amendment that would need 
to be resolved. In that event, the proper resolution of a conflict 
between the two amendments would be the analysis and conclusion 
discussed in the Proposed Rule's legal memorandum (discussing EPA's 
analysis in the CAMR rule at 70 FR 15994, 16029-32): The two 
amendments must be read together so as to give some effect to each 
amendment and they are properly read together to provide that, where 
a source category is regulated under section 112, the EPA may not 
establish regulations covering the HAP emissions from that source 
category under section 111(d).
---------------------------------------------------------------------------

    b. The EPA's Interpretation of the House Amendment. Having 
concluded that the interpretations discussed above are not reasonable, 
the EPA now turns to what it has concluded is the best, and sole 
reasonable, interpretation of the House amendment as it applies to the 
issue here.
    The EPA's interpretation of the House amendment as applied to the 
issue presented in this rule is that the Section 112 Exclusion excludes 
the regulation of HAP under CAA section 112 if the source category at 
issue is regulated under CAA section 112, but does not exclude the 
regulation of other pollutants, regardless of whether that source 
category is subject to CAA section 112 standards. This interpretation 
reads the phrase ``regulated under section 112'' as modifying the words 
``source category'' (as does the interpretation discussed above) but 
also recognizes that the phrase ``regulated under section 112'' refers 
only to the regulation of HAP emissions. In other words, the EPA's 
interpretation recognizes that source categories ``regulated under 
section 112'' are not regulated by CAA section 112 with respect to all 
pollutants, but only with respect to HAP. Thus, it is reasonable to 
interpret the House amendment of the Section 112 Exclusion as only 
excluding the regulation of HAP emissions under CAA section 111(d) and 
only when that source category is regulated under CAA section 112. We 
note that this interpretation of the House amendment alone is the same 
as the 2005 CAMR interpretation of the two amendments combined: Where a 
source category has been regulated under CAA section 112, a CAA section 
111(d) standard of performance cannot be established to address any HAP 
listed under CAA section 112(b) that may be emitted from that 
particular source category. See 70 FR 15994, 16029-30 (March 29, 2005).

[[Page 64715]]

    There are a number of reasons why the EPA's interpretation is 
reasonable and avoids the issues discussed above.
    First, the EPA's interpretation reads the House amendment to the 
Section 112 Exclusion as determining the scope of what air pollutants 
are to be regulated under CAA section 111(d), as opposed to creating a 
wholesale exclusion for source categories. The other text in 
subsections 111(d)(1)(A)(i) and (ii) modify the phrase ``any air 
pollutant.'' Thus, reading the Section 112 Exclusion to also address 
the question of what air pollutants may be regulated under CAA section 
111(d) is consistent with the overall structure and focus of CAA 
section 111(d)(1)(A).
    Second, the EPA's interpretation furthers--rather than undermines--
the purpose of CAA section 111(d) within the long-standing structure of 
the CAA. That is, this interpretation supports the comprehensive 
structure for regulating various pollutants from existing sources under 
the criteria pollutant/NAAQS program under sections 108-110, the HAP 
program under section 112, and other pollutants under section 111(d), 
and avoids creating a gap in that structure. See King v. Burwell, 2015 
U.S. LEXIS 4248, *28 (2015)(``A provision that may seem ambiguous in 
isolation is often clarified by the remainder of the statutory scheme . 
. . because only one of the permissible meanings produces a substantive 
effect that is compatible with the rest of the law.'') (quoting United 
Sav. Assn. of Tex. v. Timbers of Inwood Forest Associates, Ltd., 484 U. 
S. 365, 371, 108 S. Ct. 626, 98 L. Ed. 2d 740 (1988)'')
    Third, by avoiding the creation of gaps in the statutory structure, 
the EPA's interpretation is consistent with the legislative history 
demonstrating that Congress's intent in the 1990 CAA Amendments was to 
expand the EPA's regulatory authority across the board, compelling the 
agency to regulate more pollutants, under more programs, more 
quickly.\295\ Conversely, the EPA is aware of no statement in the 
legislative history indicating that Congress simultaneously sought to 
restrict the EPA's authority under CAA section 111(d) or to create gaps 
in the comprehensive structure of the statute. If Congress had intended 
this amendment to make such a change, one would expect to see some 
indication of that in the legislative history.
---------------------------------------------------------------------------

    \295\ See S. Rep. No. 101-228 at 133 (``There is now a broad 
consensus that the program to regulate hazardous air pollutants . . 
. should be restructured to provide the EPA with authority to 
regulate industrial and area sources of air pollution . . . in the 
near term''), reprinted in 5 A Legislative History of the Clean Air 
Act Amendments of 1990 (``Legis. Hist.'') 8338, 8473 (Comm. Print 
1993); S. Rep. No. 101-228 at 14 (``The bill gives significant 
authority to the Administrator in order to overcome the deficiencies 
in [the NAAQS program]'') & 123 (``Experience with the mobile source 
provisions in Title II of the Act has shown that the enforcement 
authorities . . . need to be strengthened and broadened . . .''), 
reprinted in 5 Legis. Hist. at 8354, 8463; H.R. Rep. No. 101-952 at 
336-36, 340, 345 & 347 (discussing enhancements to Act's motor 
vehicle provisions, the EPA's new authority to promulgate chemical 
accident prevention regulations, the enactment of the Title V permit 
program, and enhancements to the EPA's enforcement authority), 
reprinted in 5 Legis. Hist. at 1786, 1790, 1795, & 1997.
---------------------------------------------------------------------------

    Fourth, when applied in the context of this rule, the EPA's 
interpretation of the House amendment is consistent with the Senate 
amendment. Thus, this interpretation avoids creating a conflict within 
the statute. See discussion above of Scialabba v. Cuellar De Osorio, 
134 S. Ct. 2191 at 2220 (citing and quoting, among other authorities, 
A. Scalia & B. Garner, Reading Law: The Interpretation of Legal Texts 
180 (2012) (``The provisions of a text should be interpreted in a way 
that renders them compatible, not contradictory. . . . [T]here can be 
no justification for needlessly rendering provisions in conflict if 
they can be interpreted harmoniously'')).
    In sum, when this interpretation of the House amendment is applied 
in the context of this rule, the result is that the EPA may promulgate 
CAA section 111(d) regulations covering carbon dioxide emissions from 
existing power plants notwithstanding that power plants are regulated 
for their HAP emissions under CAA section 112.
5. The Two Amendments Are Easily Reconciled and Can Be Given Full 
Effect
    Given that both the House and Senate amendments should be read 
individually as having the same meaning in the context presented in 
this rule, giving each amendment full effect is straight-forward: The 
Section 112 Exclusion in section 111(d) does not foreclose the 
regulation of non-HAP from a source category regardless of whether that 
source category is also regulated under CAA section 112. As applied 
here, the EPA has the authority to promulgate CAA section 111(d) 
regulations for CO2 from power plants notwithstanding that 
power plants are regulated for HAP under CAA section 112.

C. Authority To Regulate EGUs

    In a separate, concurrent action, the EPA is also finalizing a CAA 
section 111(b) rulemaking that regulates CO2 emissions from 
new, modified, and reconstructed EGUs. The promulgation of these 
standards provides the requisite predicate for applicability of CAA 
section 111(d).
    CAA section 111(d)(1) requires the EPA to promulgate regulations 
under which states must submit state plans regulating ``any existing 
source'' of certain pollutants ``to which a standard of performance 
would apply if such existing source were a new source.'' A ``new 
source'' is ``any stationary source, the construction or modification 
of which is commenced after the publication of regulations (or, if 
earlier, proposed regulations) prescribing a standard of performance 
under [CAA section 111] which will be applicable to such source.'' It 
should be noted that these provisions make clear that a ``new source'' 
includes one that undertakes either new construction or a modification. 
It should also be noted that the EPA's implementing regulations define 
``construction'' to include ``reconstruction,'' which the implementing 
regulations go on to define as the replacement of components of an 
existing facility to an extent that (i) the fixed capital cost of the 
new components exceeds 50 percent of the fixed capital cost that would 
be required to construct a comparable entirely new facility, and (ii) 
it is technologically and economically feasible to meet the applicable 
standards.
    Under CAA section 111(d)(1), in order for existing sources to 
become subject to that provision, the EPA must promulgate standards of 
performance under CAA section 111(b) to which, if the existing sources 
were new sources, they would be subject. Those standards of performance 
may include standards for sources that undertake new construction, 
modifications, or reconstructions.
    The EPA is finalizing a rulemaking under CAA section 111(b) for 
CO2 emissions from affected EGUs concurrently with this CAA 
section 111(d) rulemaking, which will provide the requisite predicate 
for applicability of CAA section 111(d).\296\
---------------------------------------------------------------------------

    \296\ In the past, the EPA has issued standards of performance 
under section 111(b) and emission guidelines under section 111(d) 
simultaneously. See ``Standards of Performance for new Stationary 
Sources and Guidelines for Control of Existing Sources: Municipal 
Solid Waste Landfills--Final Rule,'' 61 FR 9905 (March 12, 1996).
---------------------------------------------------------------------------

D. Definition of Affected Sources

    For the emission guidelines, an affected EGU is any fossil fuel-
fired electric utility steam generating unit (i.e., utility boiler or 
integrated gasification combined cycle (IGCC) unit) or stationary 
combustion turbine that was in operation or had commenced

[[Page 64716]]

construction as of January 8, 2014,\297\ and that meets the following 
criteria, which differ depending on the type of unit. To be an affected 
EGU, such a unit, if it is a fossil fuel-fired electric utility steam 
generating unit (i.e., a utility boiler or IGCC unit), must serve a 
generator capable of selling greater than 25 MW to a utility power 
distribution system and have a base load rating greater than 260 GJ/h 
(250 MMBtu/h) heat input of fossil fuel (either alone or in combination 
with any other fuel). If such a unit is a stationary combustion 
turbine, the unit must meet the definition of a combined cycle or 
combined heat and power combustion turbine, serve a generator capable 
of selling greater than 25 MW to a utility power distribution system, 
and have a base load rating of greater than 260 GJ/h (250 MMBtu/h).
---------------------------------------------------------------------------

    \297\ Under Section 111(a) of the CAA, determination of affected 
sources is based on the date that the EPA proposes action on such 
sources. January 8, 2014 is the date the proposed GHG standards of 
performance for new fossil fuel-fired EGUs were published in the 
Federal Register (79 FR 1430).
---------------------------------------------------------------------------

    When considering and understanding applicability, the following 
definitions may be helpful. Simple cycle combustion turbine means any 
stationary combustion turbine which does not recover heat from the 
combustion turbine engine exhaust gases for purposes other than 
enhancing the performance of the stationary combustion turbine itself. 
Combined cycle combustion turbine means any stationary combustion 
turbine which recovers heat from the combustion turbine engine exhaust 
gases to generate steam that is used to create additional electric 
power output in a steam turbine. Combined heat and power (CHP) 
combustion turbine means any stationary combustion turbine which 
recovers heat from the combustion turbine engine exhaust gases to heat 
water or another medium, generate steam for useful purposes other than 
exclusively for additional electric generation, or directly uses the 
heat in the exhaust gases for a useful purpose.
    We note that certain affected EGUs are exempt from inclusion in a 
state plan. Affected EGUs that may be excluded from a state's plan are 
(1) those units that are subject to subpart TTTT as a result of 
commencing modification or reconstruction; (2) steam generating units 
or IGCC units that are currently and always have been subject to a 
federally enforceable permit limiting net-electric sales to one-third 
or less of its potential electric output or 219,000 MWh or less on an 
annual basis; (3) non-fossil units (i.e., units that are capable of 
combusting 50 percent or more non-fossil fuel) that have historically 
limited the use of fossil fuels to 10 percent or less of the annual 
capacity factor or are subject to a federally enforceable permit 
limiting fossil fuel use to 10 percent or less of the annual capacity 
factor; (4) stationary combustion turbines that are not capable of 
combusting natural gas (i.e., not connected to a natural gas pipeline); 
(5) combined heat and power units that are subject to a federally 
enforceable permit limiting, or have historically limited, annual net 
electric sales to a utility power distribution system to the product of 
the design efficiency and the potential electric output or 219,000 MWh 
(whichever is greater) or less; (6) units that serve a generator along 
with other steam generating unit(s), IGCC(s), or stationary combustion 
turbine(s) where the effective generation capacity (determined based on 
a prorated output of the base load rating of each steam generating 
unit, IGCC, or stationary combustion turbine) is 25 MW or less; (7) 
municipal waste combustor unit subject to subpart Eb of Part 60; or (8) 
commercial or industrial solid waste incineration units that are 
subject to subpart CCCC of Part 60.
    The rationale for applicability of this final rule is multi-fold. 
We had proposed that affected EGUs were those existing fossil fuel-
fired EGUs that met the applicability criteria for coverage under the 
final GHG standards for new fossil fuel-fired EGUs being promulgated 
under section 111(b). However, we are finalizing that States need not 
include certain units that would otherwise meet the CAA section 111(b) 
applicability in this CAA section 111(d) emission guidelines. These 
include simple cycle turbines, certain non-fossil units, and certain 
combined heat and power units. The final 111(b) standards include 
applicability criteria for simple cycle combustion turbines, for 
reasons relating to implementation and minimizing emissions from all 
future combustion turbines. However, for the following reasons none of 
the building blocks would result in emission reductions from simple 
cycle turbines so we are not requiring that States including them in 
their CAA section 111(d) plans.
    First, even more than combined cycle units, simple cycle units have 
limited opportunities, compared to steam generating units, to reduce 
their heat rate. Most combustion turbines likely already follow the 
manufacturer's recommended regular preventive/restorative maintenance 
for both reliable and efficiency reasons. These regularly scheduled 
maintenance practices are highly effective methods to maintain heat 
rates, and additional fleet-wide reductions from simple cycle 
combustion turbines are likely less than 2 percent. In addition, while 
approximately one-fifth of overall fossil fuel-fired capacity (GW) 
consists of simple cycle turbines, these units historically have 
operated at capacity factors of less than 5 percent and only provide 
about 1 percent of the fossil fuel-fired generation (GWh). Combustion 
turbine capacity can therefore only contribute CO2 emissions 
amounting to approximately 2 percent of total coal-steam CO2 
emissions. Any single-digit percentage reduction in combustion turbine 
heat rates would therefore provide less than 1 percent reduction in 
total fossil-fired CO2 emissions.
    Further, we are not aware of an approach to estimate any limited 
opportunities that existing simple cycle turbines may have to reduce 
their heat rate. Similar to coal-steam EGUs, we do not have the unit-
specific detailed design information on existing individual simple 
cycle combustion turbines that is necessary for a detailed assessment 
of the heat rate improvement potential via best practices and upgrades 
for each unit. While the EPA could conduct a ``variability analysis'' 
of simple cycle historical hourly heat rate data (as was done for coal-
steam EGUs), the various simple cycle models in use and the 
historically lower capacity factors of the simple cycle fleet (less run 
time per start, and more part load operation) would require a simple 
cycle analysis that includes more complexity and likely more 
uncertainty than in the coal-steam analysis. Therefore, we do not 
consider it feasible to estimate potential reductions due to heat rate 
improvements from simple cycle turbines, and even if it were, we have 
concluded those reductions would be negligible compared to the 
reductions from steam generating units. Hence, we do not consider 
building block 1 as practically applicable to simple cycle units.
    Second, the vast majority of simple cycle turbines serve a specific 
need--providing power during periods of peak electric demand (i.e., 
peaking units). The existing block of simple cycle turbines are the 
only units that are able to start fast enough and ramp to full load 
quickly enough to serve as peaking units. If these units were to be 
used under building block 2 to displace higher emitting coal-fired 
units, they would no longer be available to serve as peaking units. 
Therefore, building block 2 could not be applied to simple cycle

[[Page 64717]]

combustion turbines without jeopardizing grid reliability.
    Third, many commenters on the CAA section 111(b) proposal stated 
that simple cycle turbines will be used to provide backup power to 
intermittent renewable sources of power such as wind and solar. 
Consequently, adding additional generation from intermittent renewable 
sources has the potential to actually increase emissions from simple 
cycle turbines. Therefore, applying building block 3 based on the 
capacity of simple cycle turbines would not result in emission 
reductions from simple cycle combustion turbines. Finally, the EPA 
expects existing simple cycle turbines to continue to operate as they 
historically have operated, as peaking units. Including simple cycle 
turbines in CAA section 111(d) applicability would impact the numerical 
value of state goals, but it would not impact the stringency of the 
plans. Such inclusion would increase burden but result in no 
environmental benefit.
    Additionally, under CAA section 111(b) final applicability 
criteria, new dedicated non-fossil and industrial CHP units are not 
affected sources if they include permit restrictions on the amount of 
fossil fuel they burn and the amount of electricity they sell. Such 
units historically have had no regulatory mandate to include permit 
requirements limiting the use of fossil fuel or electric sales. We are 
exempting them from inclusion in CAA section 111(d) state plans in the 
interest of consistency with CAA section 111(b) and based on their 
historical fuel use and electric sales.
    We discuss changes in applicability of units in relation to state 
plans in Section VIII of this preamble.

E. Combined Categories and Codification in the Code of Federal 
Regulations

    In this rulemaking, the EPA is combining the listing of sources 
from the two existing source categories for the affected EGUs, as 
listed in 40 CFR subpart Da and 40 CFR subpart KKKK, into a single 
location, 40 CFR subpart UUUU, for purposes of addressing the 
CO2 emissions from existing affected EGUs. The EPA is also 
codifying all of the requirements for the affected EGUs in a new 
subpart UUUU of 40 CFR part 60 and including all GHG emission 
guidelines for the affected sources--fossil fuel-fired electric utility 
steam generating units, as well as stationary combustion turbines--in 
that newly created subpart.\298\
---------------------------------------------------------------------------

    \298\ The EPA is not codifying any of the requirements of this 
rulemaking in subparts Da or KKKK.
---------------------------------------------------------------------------

    We believe that combining the emission guidelines for affected 
sources into a new subpart UUUU is appropriate because the emission 
guidelines the EPA is establishing do not vary by type of source. 
Combining the listing of sources into one location, subpart UUUU, will 
facilitate implementation of CO2 mitigation measures, such 
as shifting generation from higher to lower-carbon intensity generation 
among existing sources (e.g., shifting from utility boilers to NGCC 
units), and emission trading among sources in the source category.
    As discussed in the January 8, 2014 proposal for the CAA section 
111(b) standards for GHG emissions from EGUs (79 FR 1430), in 1971 the 
EPA listed fossil fuel-fired steam generating boilers as a new category 
subject to section 111 rulemaking, and in 1979 the EPA listed fossil 
fuel-fired combustion turbines as a new category subject to the CAA 
section 111 rulemaking. In the ensuing years, the EPA has promulgated 
standards of performance for the two categories and codified those 
standards, at various times, in 40 CFR part 60 subparts D, Da, GG, and 
KKKK.
    In the January 8, 2014 proposal, the EPA proposed separate 
standards of performance for new sources in the two categories and 
proposed codifying the standards in the same Da and KKKK subparts that 
currently contain the standards of performance for conventional 
pollutants from those sources. In addition, the EPA co-proposed 
combining the two categories into a single category solely for purposes 
of the CO2 emissions from new construction of affected EGUs, 
and codifying the proposed requirements in a new 40 CFR part 60 subpart 
TTTT. For the final standards of performance for new construction of 
affected EGUs, the EPA is codifying the final requirements in a new 40 
CFR part 60 subpart TTTT.
    In this rulemaking, the EPA is combining the two listed source 
categories into a single source category for purposes of the emission 
guidelines for the CO2 emissions from existing affected 
EGUs. Because the two source categories are pre-existing and the EPA 
would not be subjecting any additional sources to regulation, the 
combined source category is not considered a new source category that 
the EPA must list under CAA section 111(b)(1)(A). As a result, this 
final rule does not list a new source category under section 
111(a)(1)(A), nor does this final rule revise either of the two source 
categories--fossil fuel--fired electric utility steam generating units 
and stationary combustion turbines--that the EPA has already listed 
under that provision. Thus, the EPA is not required to make a finding 
that the combined source category causes or contributes significantly 
to air pollution which may reasonably be anticipated to endanger public 
health or welfare.

V. The Best System of Emission Reduction and Associated Building Blocks

    In the June 2014 proposal, the EPA proposed to determine that the 
best system of emission reduction adequately demonstrated (BSER) for 
reducing CO2 emissions from existing EGUs was a combination 
of measures--(1) increasing the operational efficiency of existing 
coal-fired steam EGUs, (2) substituting increased generation at 
existing NGCC units for generation at existing steam EGUs, (3) 
substituting generation from low- and zero-carbon generating capacity 
for generation at existing fossil fuel-fired EGUs, and (4) increasing 
demand-side EE to reduce the amount of fossil fuel-fired generation--
which we categorized as four ``building blocks.'' As an alternative to 
the proposed building blocks 2, 3, and 4, the EPA also identified 
reduced generation in the amount of those building blocks as part of 
the BSER. These measures are not the only approaches EGUs can take to 
reduce CO2, but are those that the EPA felt best met the 
statutory criteria. We solicited comment on all aspects of our BSER 
determination, including a broad array of other approaches. We have 
considered thoroughly the extensive comments submitted on a variety of 
topics related to the BSER and the individual building blocks, along 
with our own continued analysis, and we are finalizing the BSER based 
on the first three building blocks, with certain refinements.
    Consistent with the approach taken in the proposed rule, in 
determining the BSER we have taken account of the unique 
characteristics of CO2 pollution, particularly its global 
nature, huge quantities, and the limited means for controlling it; and 
the unique characteristics of the source category, particularly the 
exceptional degree of interconnectedness among individual affected EGUs 
and the longstanding practice of coordinating planning and operations 
across multiple sources, reflecting the fact that each EGU's function 
is interdependent with the function of other EGUs. Each building

[[Page 64718]]

block is a proven approach for reducing emissions from the affected 
source category that is appropriate in this pollutant- and industry-
specific context. The BSER also encompasses a variety of measures or 
actions that individual affected EGUs could take to implement the 
building blocks, including (i) direct investment in efficiency 
improvements and in lower- and zero-carbon generation, (ii) cross-
investment in these activities through mechanisms such as emissions 
trading approaches, where the state-established standards of 
performance to which sources are subject incorporate such approaches, 
and (iii) reduction of higher-carbon generation.
    With attention to emission reduction costs, electricity rates, and 
the importance of ensuring continued reliability of electricity 
supplies, the individual building blocks and the overall BSER have been 
defined not at the maximum possible degree of stringency but at a 
reasonable degree of stringency designed to appropriately balance 
consideration of the various BSER factors. Additional, non-building 
block-specific aspects of the BSER quantification methodology discussed 
below are similarly mindful of these considerations. This approach to 
determination of the BSER provides compliance headroom that ensures 
that the emission limitations reflecting the BSER are achievable by the 
source category, but nevertheless, as required by the CAA, will result 
in meaningful reductions in CO2 emissions from this sector. 
The wide range of actions encompassed in the building blocks, and a 
further wide range of possible emissions-reducing actions not included 
in the BSER but nevertheless available to help with compliance, ensure 
that those emission limitations are achievable by individual affected 
EGUs as well.
    The final BSER incorporates certain changes from the proposed rule, 
reflecting the EPA's consideration of comments responding to the 
approaches outlined in the proposal and our own further analysis. The 
principal changes are the exclusion from the BSER of emission 
reductions achievable through demand-side EE and through nuclear 
generation; a revised approach to determination of emission reductions 
achievable through increased RE generation; a consistent approach to 
determination of emission reductions achievable through all the 
building blocks that better reflects the regional nature of the 
electricity system and entails separate analyses for the Eastern, 
Western, and Texas Interconnections; and a revised interim goal period 
of 2022 to 2029 (instead of the proposed interim period of 2020 to 
2029). These changes to the BSER and the building blocks are discussed 
in more detail later in this section of the preamble.
    Also, to address concerns identified in the proposal and the 
October 30, 2014 NODA and in response to associated comments, in the 
final rule we have represented the emission limitations achievable 
through the BSER in the form of uniform CO2 emission 
performance rates for each of two affected source subcategories: Steam 
generating units and stationary combustion turbines. However, like the 
proposed rule, the final rule also provides weighted-average state-
specific goals that a state may choose as an alternative method for 
complying with its obligation to set standards of performance for its 
affected EGUs--an alternative, that is, to adopting the nationwide 
subcategory-based CO2 emission performance rates as the 
standard of performance for its affected EGUs. The reformulation of the 
emission limitations as uniform CO2 emission performance 
rates is discussed in this section and in section VI of the preamble, 
and the relation of the performance rates to the state-specific goals 
and states' section 111(d) plan options is discussed in sections VII 
and VIII of the preamble.
    Section V.A. describes our determination of the final BSER, 
including a discussion of the associated emissions performance level, 
and provides the rationale for our determination. In section V.B. we 
address certain legal issues in greater detail, including key issues 
raised in comments. Sections V.C. through V.E. contain more detailed 
discussions of the three individual building blocks included in the 
final BSER. Further information can be found in the GHG Mitigation 
Measures TSD for the CPP Final Rule, the CO2 Emission 
Performance Rate and Goal Computation TSD for the CPP Final Rule, the 
Response to Comments document, and, about certain topics, the Legal 
Memorandum for the Clean Power Plan Final Rule, all of which are 
available in the docket.

A. The Best System of Emission Reduction

    This section sets forth our determination of the BSER for reducing 
CO2 emissions from existing EGUs, including a discussion of 
the associated emissions performance level, and the rationale for that 
determination. In section V.A.1., we describe the legal framework for 
determination of the BSER in general. Section V.A.2. summarizes the 
determination of the BSER for this rule. In section V.A.3., we discuss 
changes from the proposal. Section V.A.4. provides more detail on our 
determination of the BSER, including our determinations regarding the 
individual elements of the BSER, as applied to the two subcategories of 
fossil steam units and combustion turbines. In section V.A.5., we 
explain the specific actions that individual affected EGUs in the two 
subcategories may take to implement the building blocks and thereby 
achieve the EPA-identified source subcategory-specific emission 
performance rates that, in turn, form the basis for the standards of 
performance that states must set. Because these actions implement the 
building blocks, they may be understood as part of the BSER. In this 
discussion, we recognize that states can choose to set sources' 
standards of performance in different forms and that the form of the 
standard affects how various types of actions can be used to comply 
with the standard. In section V.A.6., we discuss the substantial 
compliance flexibility provided by additional measures, not included in 
the BSER, that individual affected EGUs can use to achieve their 
standards of performance. Finally, section V.A.7. addresses the 
severability of the building blocks.
1. Legal Requirements for BSER in the Emission Guidelines
    a. Introduction. In the June 2014 proposal for this rule, we 
described the principal legal requirements for standards of performance 
under CAA section 111(d)(1) and (a)(1). We based our description in 
part on our discussion of the legal requirements for standards of 
performance under CAA section 111(b) and (a)(1), which we included in 
the January 2014 proposal for standards of performance for 
CO2 emissions from new fossil fuel-fired EGUs. In the latter 
proposal, we noted that the D.C. Circuit has handed down numerous 
decisions that interpret CAA section 111(a)(1), including its component 
elements, and we reviewed that case law in detail.\299\
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    \299\ 79 FR 1430, 1462 (January 8, 2014).
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    We received comments on our proposed interpretation, and in light 
of those comments, in this final rule, we are clarifying our 
interpretation in certain respects. We discuss our interpretation 
below.\300\
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    \300\ We also discuss our interpretation of the requirements for 
standards of performance and the BSER under section 111(b), for new 
sources, in the section 111(b) rulemaking that the EPA is finalizing 
simultaneously with this rule and in the Legal Memorandum for this 
rule. Our interpretations of these requirements in the two rules are 
generally consistent except to the extent that they reflect 
distinctions between new and existing sources. For example, as 
discussed in the section 111(b) rule, the legislative history 
indicates that Congress intended that the BSER for new industrial 
facilities, which were expected to have lengthy useful lives, would 
include the most advanced pollution controls available, but Congress 
had a broader conception of the BSER for existing facilities.

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[[Page 64719]]

    b. CAA requirements and court interpretation.\301\ Section 
111(d)(1) directs the EPA to promulgate regulations establishing a 
section 110-like procedure under which states submit state plans that 
establish ``standards of performance'' for emissions of certain air 
pollutants from sources which, if they were new sources, would be 
regulated under section 111(b), and that implement and enforce those 
standards of performance.
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    \301\ Our interpretation of the CAA provisions at issue is 
guided by Chevron U.S.A. Inc. v. NRDC, 467 U.S. 837, 842-43 (1984). 
In Chevron, the U.S. Supreme Court set out a two-step process for 
agency interpretation of statutory requirements: the agency must, at 
step 1, determine whether Congress's intent as to the specific 
matter at issue is clear, and, if so, the agency must give effect to 
that intent. If congressional intent is not clear, then, at step 2, 
the agency has discretion to fashion an interpretation that is a 
reasonable construction of the statute.\\
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    The term ``standard of performance'' is defined to mean--

a standard for emissions of air pollutants which reflects the degree 
of emission limitation achievable through the application of the 
best system of emission reduction which (taking into account the 
cost of achieving such reduction and any nonair quality health and 
environmental impact and energy requirements) the Administrator 
determines has been adequately demonstrated.

Section 111(a)(1).
    These provisions authorize the EPA to determine the BSER for the 
affected sources and, based on the BSER, to establish emission 
guidelines that identify the minimum amount of emission limitation that 
a state, in its state plan, must impose on its sources through 
standards of performance. Consistent with these CAA requirements, the 
EPA's regulations require that the EPA's guidelines reflect--

the degree of emission reduction achievable through the application 
of the best system of emission reduction which (taking into account 
the cost of such reduction) the Administrator has determined has 
been adequately demonstrated.\302\
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    \302\ 40 CFR 60.21(e). This definition was promulgated as part 
of the EPA's CAA 111(d) implementing regulations and was not updated 
to reflect the textual changes adopted by Congress in 1977. That 
said, Congress recognized that those changes ``merely make[] 
explicit what was implicit in the previous language.'' H.R. Rep. No. 
95-294, at 190 (May 12, 1977).

    The EPA's approach in this rulemaking is to determine the BSER on a 
source subcategory-wide basis, to determine the emission limitation 
that results from applying the BSER to the sources in the subcategory, 
and then to establish emission guidelines for the states that 
incorporate those emission limitations. The EPA expresses these 
emission limitations in the form of emission performance rates, and 
they must be achievable by the source subcategory through the 
application of the BSER.
    Following the EPA's promulgation of emission guidelines, each state 
must determine the standards of performance for its sources, which the 
EPA's regulations call ``designated facilities.'' \303\ A state has 
broad discretion in doing so. CAA section 111(d)(1) requires the EPA's 
regulations to ``permit the State in applying a standard of performance 
to any particular source . . . to take into consideration, among other 
factors, the remaining useful life of the . . . source. . .'' \304\ In 
addition, under CAA section 116, the state is authorized to set a 
standard of performance for any particular source that is more 
stringent than the emission limit contained in the EPA's emission 
guidelines.\305\ Thus, for any particular source, a state may apply a 
standard of performance that is either more stringent or less stringent 
than the performance level in the emission guidelines, as long as, in 
total, the state's sources achieve at least the same degree of emission 
limitation as included in the EPA's emission guidelines. The states 
must include the standards of performance in their state plans and 
submit the plans to the EPA for review.\306\ Under CAA section 
111(d)(2)(A), the EPA approves state plans as long as they are 
``satisfactory.''
---------------------------------------------------------------------------

    \303\ 40 CFR 60.24(b)(3).
    \304\ The EPA's regulations, promulgated prior to enactment of 
the ``remaining useful life'' provision of section 111(d)(1), 
provide: ``Unless otherwise specified in the applicable subpart on a 
case-by-case basis for particular designated facilities, or classes 
of facilities, States may provide for the application of less 
stringent emission standards or longer compliance schedules than 
those otherwise required'' by the corresponding emission guideline. 
40 CFR 60.24(f). Some of the factors that a state may consider for 
this case-by-case analysis include the ``cost of control resulting 
from plant age, location, or basic process design'' and the 
``physical impossibility of installing necessary control 
equipment,'' among other factors ``that make application of a less 
stringent standard or final compliance time significantly more 
reasonable.'' Id.
    \305\ In addition, CAA section 116 authorizes the state to set 
standards of performance for all of its sources that, together, are 
more stringent than the EPA's emission guidelines.
    \306\ 40 CFR 60.23.
---------------------------------------------------------------------------

    As noted in the January 2014 proposal and discussed in more detail 
above under section II.G, Congress first included the definition of 
``standard of performance'' when enacting CAA section 111 in the 1970 
Clean Air Act Amendments (CAAA), amended it in the 1977 CAAA, and then 
amended it again in the 1990 CAAA to largely restore the definition as 
it read in the 1970 CAAA. It is in the legislative history for the 1970 
and 1977 CAAA that Congress primarily addressed the definition as it 
read at those times and that legislative history provides guidance in 
interpreting this provision.\307\ In addition, although the D.C. 
Circuit has never reviewed a section 111(d) rulemaking, the Court has 
reviewed section 111(b) rulemakings on numerous occasions during the 
past 40 years, handing down decisions dated from 1973 to 2011,\308\ 
through which the Court has developed a body of case law that 
interprets the term ``standard of performance.''
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    \307\ In the 1970 CAAA, Congress defined ``standard of 
performance,'' under Sec.  111(a)(1), as:
    a standard for emissions of air pollutants which reflects the 
degree of emission limitation achievable through the application of 
the best system of emission reduction which (taking into account the 
cost of achieving such reduction) the Administrator determines has 
been adequately demonstrated.
    In the 1977 CAAA, Congress revised the definition to distinguish 
among different types of sources, and to require that for fossil 
fuel-fired sources, the standard (i) be based on, in lieu of the 
``best system of emission reduction . . . adequately demonstrated,'' 
the ``best technological system of continuous emission reduction . . 
. adequately demonstrated;'' and (ii) require a percentage reduction 
in emissions. In addition, in the 1977 CAAA, Congress expanded the 
parenthetical requirement that the Administrator consider the cost 
of achieving the reduction to also require the Administrator to 
consider ``any nonair quality health and environmental impact and 
energy requirements.''
    In the 1990 CAAA, Congress again revised the definition, this 
time repealing the requirements that the standard of performance be 
based on the best technological system and achieve a percentage 
reduction in emissions, and replacing those provisions with the 
terms used in the 1970 CAAA version of Sec.  111(a)(1) that the 
standard of performance be based on the ``best system of emission 
reduction . . . adequately demonstrated.'' This 1990 CAAA version is 
the current definition, which is applicable at present. Even so, 
because parts of the definition as it read under the 1977 CAAA were 
retained in the 1990 CAAA, the explanation in the 1977 CAAA 
legislative history, and the interpretation, in the case law, of 
those parts of the definition remain relevant to the definition as 
it reads today.
    \308\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375 (D.C. 
Cir. 1973); Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427, (D.C. 
Cir. 1973); Portland Cement Ass'n v. EPA, 665 F.3d 177 (D.C. Cir. 
2011). See also Delaware v. EPA, No. 13-1093 (D.C. Cir. May 1, 
2015).
---------------------------------------------------------------------------

    c. Key elements of interpretation. The emission guidelines 
promulgated by the Administrator must include emission limitations that 
are ``achievable'' by the source category by application of a ``system 
of emission reduction'' that is ``adequately demonstrated'' and that 
the EPA determines to be the ``best,''

[[Page 64720]]

``taking into account'' the factors of ``cost . . . nonair quality 
health and environmental impact and energy requirements.'' The D.C. 
Circuit has stated that in determining the ``best'' system, the EPA 
must also take into account ``the amount of air pollution'' \309\ 
reduced and the role of ``technological innovation.'' \310\ The Court 
has emphasized that the EPA has discretion in weighing those various 
factors.311 312
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    \309\ See Sierra Club v. Costle, 657 F.2d 298, 326 (D.C. Cir. 
1981).
    \310\ See Sierra Club v. Costle, 657 F.2d at 347.
    \311\ See Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. 
Cir. 1999).
    \312\ Although CAA section 111(a)(1) may be read to state that 
the factors enumerated in the parenthetical are part of the 
``adequately demonstrated'' determination, the D.C. Circuit's case 
law appears to treat them as part of the ``best'' determination. See 
Sierra Club v. Costle, 657 F.2d at 330 (recognizing that CAA section 
111 gives the EPA authority ``when determining the best 
technological system to weigh cost, energy, and environmental 
impacts''). Nevertheless, it does not appear that those two 
approaches would lead to different outcomes. See, e.g., Lignite 
Energy Council v. EPA, 198 F.3d at 933 (rejecting challenge to the 
EPA's cost assessment of the ``best demonstrated system''). In this 
rule, the EPA treats the factors as part of the ``best'' 
determination, but, as noted, even if the factors were part of the 
``adequately demonstrated'' determination, our analysis and outcome 
would be the same.
---------------------------------------------------------------------------

    Our overall approach to determining the BSER and emission 
guidelines, which incorporates the various elements, is as follows: In 
developing an emission guideline, we generally engage in an analytical 
approach that is similar to what we conduct under CAA section 111(b) 
for new sources. First, we identify ``system[s] of emission reduction'' 
that have been ``adequately demonstrated'' for a particular source 
category. Second, we determine the ``best'' of these systems after 
evaluating the amount of reductions, costs, any nonair health and 
environmental impacts, energy requirements, and, in the alternative, 
the advancement of technology (that is, we apply a formulation of the 
BSER with the above noted factors, and then, in the alternative, we 
apply a formulation of the BSER with those same factors plus the 
advancement of technology). And third, we select an achievable emission 
limit--here, the emission performance rates--based on the BSER.\313\ In 
contrast to subsection (b), however, subsection (d)(1) assigns to the 
states, not the EPA, the obligation of setting standards of performance 
for the affected sources. As discussed below in the following 
subsection, in examining the range of reasonable options for states to 
consider in setting standards of performance under these guidelines, we 
identified a number of considerations, including the interconnected 
operations of the affected sources and the characteristics of the 
CO2 pollutant.
---------------------------------------------------------------------------

    \313\ See, e.g., Oil and Natural Gas Sector: New Source 
Performance Standards and National Emission Standards for Hazardous 
Air pollutants Reviews, 77 FR 49490, 49494 (Aug. 16, 2012) 
(describing the three-step analysis in setting a standard of 
performance).
---------------------------------------------------------------------------

    The remainder of this subsection discusses the various elements in 
our general analytical approach.
(1) System of Emission Reduction
    As we discuss below, the CAA does not define the phrase ``system of 
emission reduction.'' The ordinary, everyday meaning of ``system'' is a 
set of things or parts forming a complex whole; a set of principles or 
procedures according to which something is done; an organized scheme or 
method; and a group of interacting, interrelated, or interdependent 
elements.\314\ With this definition, the phrase ``system of emission 
reduction'' takes a broad meaning: a set of measures that work together 
to reduce emissions. The EPA interprets this phrase to carry an 
important limitation: Because the emission guidelines for the existing 
sources must reflect ``the degree of emission limitation achievable 
through the application of the best system of emission reduction . . . 
adequately demonstrated,'' the system must be limited to measures that 
can be implemented--``appl[ied]''--by the sources themselves, that is, 
as a practical matter, by actions taken by the owners or operators of 
the sources. As we discuss below, this definition is sufficiently broad 
to include the building blocks.
---------------------------------------------------------------------------

    \314\ Oxford Dictionary of English (3rd ed.) (2010), available 
at http://www.oxforddictionaries.com/us/definition/american_english/system; see also American Heritage Dictionary (5th ed.) (2013), 
available at http://www.yourdictionary.com/system#americanheritage; 
and The American College Dictionary (C.L. Barnhart, ed. 1970) (``an 
assemblage or combination of things or parts forming a complex or 
unitary whole'').
---------------------------------------------------------------------------

(2) ``Adequately Demonstrated''
    Under section 111(a)(1), in order for a ``system of emission 
reduction'' to serve as the basis for an ``achievable'' emission 
limitation, the Administrator must determine that the system is 
``adequately demonstrated.'' This means, according to the D.C. Circuit, 
that the system is ``one which has been shown to be reasonably 
reliable, reasonably efficient, and which can reasonably be expected to 
serve the interests of pollution control without becoming exorbitantly 
costly in an economic or environmental way.'' \315\ It does not mean 
that the system ``must be in actual routine use somewhere.'' \316\ 
Rather, the Court has said, ``[t]he Administrator may make a projection 
based on existing technology, though that projection is subject to the 
restraints of reasonableness and cannot be based on `crystal ball' 
inquiry.'' \317\ Similarly, the EPA may ``hold the industry to a 
standard of improved design and operational advances, so long as there 
is substantial evidence that such improvements are feasible.'' \318\ 
Ultimately, the analysis ``is partially dependent on `lead time,''' 
that is, ``the time in which the technology will have to be 
available.'' \319\ Unlike for CAA section 111(b) standards that are 
applicable immediately after the effective date of their promulgation, 
under CAA section 111(e), compliance with CAA section 111(d) standards 
may be set sometime in the future. This is due, in part, to the period 
of time for states to submit state plans and for the EPA to act on 
them.
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    \315\ Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433 (D.C. 
Cir. 1973), cert. denied, 416 U.S. 969 (1974).
    \316\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 391 
(D.C. Cir. 1973) (citations omitted) (discussing the Senate and 
House bills and reports from which the language in CAA section 111 
grew).
    \317\ Ibid.
    \318\ Sierra Club v. Costle, 657 F.2d 298, 364 (1981).
    \319\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 391 
(D.C. Cir. 1973) (citations omitted).
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(3) ``Best''
    In determining which adequately demonstrated system of emission 
reduction is the ``best,'' the EPA considers the following factors:
(a) Costs
    Under CAA section 111(a)(1), the EPA is required to take into 
account ``the cost of achieving'' the required emission reductions. As 
described in the January 2014 proposal,\320\ in several cases the D.C. 
Circuit has elaborated on this cost factor and formulated the cost 
standard in various ways, stating that the EPA may not adopt a standard 
the cost of which would be ``exorbitant,'' \321\ ``greater than the 
industry could bear and survive,'' \322\ ``excessive,'' \323\ or 
``unreasonable.'' \324\ These formulations appear to be synonymous, and 
for convenience, in this rulemaking, we will use reasonableness as the 
standard,

[[Page 64721]]

so that a control technology may be considered the ``best system of 
emission reduction . . . adequately demonstrated'' if its costs are 
reasonable, but cannot be considered the best system if its costs are 
unreasonable.325 326
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    \320\ 79 FR 1430, 1464 (January 8, 2014).
    \321\ Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. 
Cir. 1999).
    \322\ Portland Cement Ass'n v. EPA, 513 F.2d 506, 508 (D.C. Cir. 
1975).
    \323\ Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981).
    \324\ Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981).
    \325\ These cost formulations are consistent with the 
legislative history of section 111. The 1977 House Committee Report 
noted:
    In the [1970] Congress [sic: Congress's] view, it was only right 
that the costs of applying best practicable control technology be 
considered by the owner of a large new source of pollution as a 
normal and proper expense of doing business.
    1977 House Committee Report at 184. Similarly, the 1970 Senate 
Committee Report stated:
    The implicit consideration of economic factors in determining 
whether technology is ``available'' should not affect the usefulness 
of this section. The overriding purpose of this section would be to 
prevent new air pollution problems, and toward that end, maximum 
feasible control of new sources at the time of their construction is 
seen by the committee as the most effective and, in the long run, 
the least expensive approach.
    S. Comm. Rep. No. 91-1196 at 16.
    \326\ We received comments that we do not have authority to 
revise the cost standard as established in the case law, e.g., 
``exorbitant,'' ``excessive,'' etc., to a ``reasonableness'' 
standard that the commenters considered less protective of the 
environment. We agree that we do not have authority to revise the 
cost standard as established in the case law, and we are not 
attempting to do so here. Rather, our description of the cost 
standard as ``reasonableness'' is intended to be a convenient term 
for referring to the cost standard as established in the case law.
---------------------------------------------------------------------------

    The D.C. Circuit has repeatedly upheld the EPA's consideration of 
cost in reviewing standards of performance. In several cases, the Court 
upheld standards that entailed significant costs, consistent with 
Congress's view that ``the costs of applying best practicable control 
technology be considered by the owner of a large new source of 
pollution as a normal and proper expense of doing business.'' \327\ See 
Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427, 440 (D.C. Cir. 
1973); \328\ Portland Cement Association v. Ruckelshaus, 486 F.2d 375, 
387-88 (D.C. Cir. 1973); Sierra Club v. Costle, 657 F.2d 298, 313 (D.C. 
Cir. 1981) (upholding standard imposing controls on SO2 
emissions from coal-fired power plants when the ``cost of the new 
controls . . . is substantial'').\329\
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    \327\ 1977 House Committee Report at 184.
    \328\ The costs for these standards were described in the 
rulemakings. See 36 FR 24876 (December 23, 1971), 37 FR 5767, 5769 
(March 21, 1972).
    \329\ Indeed, in upholding the EPA's consideration of costs 
under other provisions requiring consideration of cost, courts have 
also noted the substantial discretion delegated to the EPA to weigh 
cost considerations with other factors. Chemical Mfr's Ass'n v. EPA, 
870 F. 2d 177, 251 (5th Cir. 1989); Am. Iron & Steel Inst. v. EPA, 
526 F. 2d 1027, 1054 (3d Cir. 1975); Ass'n of Pacific Fisheries v. 
EPA, 615 F. 2d 794, 808 (9th Cir. 1980).
---------------------------------------------------------------------------

    As discussed below, the EPA may consider costs on both a source-
specific basis and a sector-wide, regional, or nationwide basis.
(b) Non-Air Health and Environmental Impacts
    Under CAA section 111(a)(1), the EPA is required to take into 
account ``any nonair quality health and environmental impact'' in 
determining the BSER. As the D.C. Circuit has explained, this 
requirement makes explicit that a system cannot be ``best'' if it does 
more harm than good due to cross-media environmental impacts.\330\
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    \330\ Portland Cement v. EPA, 486 F. 2d at 384; Sierra Club v. 
Costle, 657 F. 2d at 331; see also Essex Chemical Corp. v. 
Ruckelshaus, 486 F. 2d at 439 (remanding standard to consider solid 
waste disposal implications of the BSER determination).
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(c) Energy Considerations
    Under CAA section 111(a)(1), the EPA is required to take into 
account ``energy requirements.'' As discussed below, the EPA may 
consider energy requirements on both a source-specific basis and a 
sector-wide, region-wide, or nationwide basis. Considered on a source-
specific basis, ``energy requirements'' entails, for example, the 
impact, if any, of the system of emission reduction on the source's own 
energy needs.
(d) Amount of Emissions Reductions
    In the proposed rulemakings for this rule and the associated 
section 111(b) rule, we noted that although the definition of 
``standard of performance'' does not by its terms identify the amount 
of emissions from the category of sources or the amount of emission 
reductions achieved as factors the EPA must consider in determining the 
``best system of emission reduction,'' the D.C. Circuit has stated that 
the EPA must do so. See Sierra Club v. Costle, 657 F.2d 298, 326 (D.C. 
Cir. 1981) (``we can think of no sensible interpretation of the 
statutory words ``best . . . system'' which would not incorporate the 
amount of air pollution as a relevant factor to be weighed when 
determining the optimal standard for controlling . . . 
emissions'').\331\ The fact that the purpose of a ``system of emission 
reduction'' is to reduce emissions, and that the term itself explicitly 
incorporates the concept of reducing emissions, supports the Court's 
view that in determining whether a ``system of emission reduction'' is 
the ``best,'' the EPA must consider the amount of emission reductions 
that the system would yield. Even if the EPA were not required to 
consider the amount of emission reductions, the EPA has the discretion 
to do so, on grounds that either the term ``system of emission 
reduction'' or the term ``best'' may reasonably be read to allow that 
discretion.
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    \331\ Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. 1981) was 
governed by the 1977 CAAA version of the definition of ``standard of 
performance,'' which revised the phrase ``best system of emission 
reduction'' to read, ``best technological system of continuous 
emission reduction.'' As noted above, the 1990 CAAA deleted 
``technological'' and ``continuous'' and thereby returned the phrase 
to how it read under the 1970 CAAA. The court's interpretation of 
the 1977 CAAA phrase in Sierra Club v. Costle to require 
consideration of the amount of air emissions remains valid for the 
1990 CAAA phrase ``best system of emission reduction.''
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(e) Sector- or Nationwide Component of Factors in Determining the BSER
    As discussed in the January 2014 proposal for the section 111(b) 
rulemaking and the proposal for this rulemaking, another component of 
the D.C. Circuit's interpretations of CAA section 111 is that the EPA 
may consider the various factors it is required to consider on a 
national or regional level and over time, and not only on a plant-
specific level at the time of the rulemaking.\332\ The D.C. Circuit 
based this interpretation--which it made in the 1981 Sierra Club v. 
Costle case, which concerned the NSPS for new power plants--on a review 
of the legislative history, stating,
---------------------------------------------------------------------------

    \332\ 79 FR 1430, 1465 (January 8, 2014) (citing Sierra Club v. 
Costle, 657 F.2d at 351).

    [T]he Reports from both Houses on the Senate and House bills 
illustrate very clearly that Congress itself was using a long-term 
lens with a broad focus on future costs, environmental and energy 
effects of different technological systems when it discussed section 
111.\333\
---------------------------------------------------------------------------

    \333\ Sierra Club v. Costle, 657 F.2d at 331 (citations omitted) 
(citing legislative history).

The Court has upheld EPA rules that the EPA ``justified . . . in terms 
of the policies of the Act,'' including balancing long-term national 
---------------------------------------------------------------------------
and regional impacts:

    The standard reflects a balance in environmental, economic, and 
energy consideration by being sufficiently stringent to bring about 
substantial reductions in SO2 emissions (3 million tons 
in 1995) yet does so at reasonable costs without significant energy 
penalties . . . . By achieving a balanced coal demand within the 
utility sector and by promoting the development of less expensive 
SO2 control technology, the final standard will expand 
environmentally acceptable energy supplies to existing power plants 
and industrial sources.
    By substantially reducing SO2 emissions, the standard 
will enhance the potential for long term economic growth at both the 
national and regional levels.\334\
---------------------------------------------------------------------------

    \334\ Sierra Club v. Costle, 657 F.2d at 327-28 (quoting 44 FR 
at 33583/3-33584/1). In the January 2014 proposal, we explained that 
although the D.C. Circuit decided Sierra Club v. Costle before the 
Chevron case was decided in 1984, the D.C. Circuit's decision could 
be justified under either Chevron step 1 or 2. 79 FR 1430, 1466 
(January 8, 2014).

    In this rule, the EPA is considering costs and energy implications 
on the

[[Page 64722]]

basis of (i) their source-specific impacts and (ii) a sector-wide, 
regional, or national basis, both separately and in combination with 
each other.
(4) Achievability of the Emission Limitation in the Emission Guidelines
    Before discussing the requirement under section 111(d) that the 
emission limitation in the emission guidelines must be ``achievable,'' 
it is useful to discuss the comparable requirement under section 111(b) 
for new sources. For new sources, CAA section 111(b)(1)(B) and (a)(1) 
provides that the EPA must establish ``standards of performance,'' 
which are standards for emissions that reflect the degree of emission 
limitation that is ``achievable'' through the application of the BSER. 
According to the D.C. Circuit, a standard of performance is 
``achievable'' if a technology can reasonably be projected to be 
available to an individual source at the time it is constructed that 
will allow it to meet the standard.\335\ Moreover, according to the 
Court, ``[a]n achievable standard is one which is within the realm of 
the adequately demonstrated system's efficiency and which, while not at 
a level that is purely theoretical or experimental, need not 
necessarily be routinely achieved within the industry prior to its 
adoption.'' \336\ To be achievable, a standard ``must be capable of 
being met under most adverse conditions which can reasonably be 
expected to recur and which are not or cannot be taken into account in 
determining the `costs' of compliance.'' \337\ To show a standard is 
achievable, the EPA must ``(1) identify variable conditions that might 
contribute to the amount of expected emissions, and (2) establish that 
the test data relied on by the agency are representative of potential 
industry-wide performance, given the range of variables that affect the 
achievability of the standard.'' \338\
---------------------------------------------------------------------------

    \335\ Sierra Club v. Costle, 657 F.2d 298, 364, n. 276 (D.C. 
Cir. 1981).
    \336\ Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433-34 
(D.C. Cir. 1973), cert. denied, 416 U.S. 969 (1974).
    \337\ Nat'l Lime Ass'n v. EPA, 627 F.2d 416, 433, n.46 (D.C. 
Cir. 1980).
    \338\ Sierra Club v. Costle, 657 F.2d 298, 377 (D.C. Cir. 1981) 
(citing Nat'l Lime Ass'n v. EPA, 627 F.2d 416 (D.C. Cir. 1980). In 
considering the representativeness of the source tested, the EPA may 
consider such variables as the ```feedstock, operation, size and 
age' of the source.'' Nat'l Lime Ass'n v. EPA, 627 F.2d 416, 433 
(D.C. Cir. 1980). Moreover, it may be sufficient to ``generalize 
from a sample of one when one is the only available sample, or when 
that one is shown to be representative of the regulated industry 
along relevant parameters.'' Nat'l Lime Ass'n v. EPA, 627 F.2d 416, 
434, n.52 (D.C. Cir. 1980).
---------------------------------------------------------------------------

    The D.C. Circuit established these standards for achievability in 
cases concerning CAA section 111(b) new source standards of 
performance. There is no case law under CAA section 111(d). Assuming 
that those standards for achievability apply under section 111(d), in 
this rulemaking, we are taking a similar approach for the emission 
limitation that the EPA identifies in the emission guidelines. For 
existing sources, section 111(d)(1) requires the EPA to establish 
requirements for state plans that, in turn, must include ``standards of 
performance.'' Through long-standing regulations \339\ and consistent 
practice, the EPA has interpreted this provision to require the EPA to 
promulgate emission guidelines that determine the BSER for a source 
category and that identify the amount of emission limitation achievable 
by application of the BSER.
---------------------------------------------------------------------------

    \339\ 40 CFR 60.21(e).
---------------------------------------------------------------------------

    The EPA has promulgated these emission guidelines on the basis that 
the existing sources can achieve the limitation, even though the state 
retains discretion to apply standards of performance to individual 
sources that are more or less stringent.
    As indicated in the proposed rulemakings for this rule and the 
associated section 111(b) rule, the requirement that the emission 
limitation in the emission guidelines be ``achievable'' based on the 
``best system of emission reduction . . . adequately demonstrated'' 
indicates that the technology or other measures that the EPA identifies 
as the BSER must be technically feasible. See 79 FR 1430, 1463 (January 
8, 2014). At least in some cases, in determining whether the emission 
limitation is achievable, it is useful to analyze the technical 
feasibility of the system of emission reduction, and we do so in this 
rulemaking.
(5) Expanded Use and Development of Technology
    The D.C. Circuit has long held that Congress intended for CAA 
section 111 to create incentives for new technology and therefore that 
the EPA is required to consider technological innovation as one of the 
factors in determining the ``best system of emission reduction.'' See 
Sierra Club v. Costle, 657 F.2d at 346-47. The Court has grounded its 
reading in the statutory text.\340\ In addition, the Court's 
interpretation finds firm support in the legislative history.\341\ The 
legislative history identifies three different ways that Congress 
designed CAA section 111 to authorize standards of performance that 
promote technological improvement: (i) The development of technology 
that may be treated as the ``best system of emission reduction . . . 
adequately demonstrated;'' under section 111(a)(1); \342\ (ii) the 
expanded use of the best demonstrated technology; \343\ and (iii) the 
development of emerging technology.\344\ Even if the EPA were not 
required to consider technological innovation as part of its 
determination of the BSER, it would be reasonable for the EPA to 
consider it, either because technological innovation may be considered 
an element of the term ``best,'' or because the term ``best system of 
emission reduction'' is ambiguous as to whether technological 
innovation may be considered, and it is reasonable for the EPA to 
interpret it to authorize consideration of technological innovation in 
light of Congress's emphasis on technological innovation.
---------------------------------------------------------------------------

    \340\ Sierra Club v. Costle, 657 F. 2d at 346 (``Our 
interpretation of section 111(a) is that the mandated balancing of 
cost, energy, and nonair quality health and environmental factors 
embraces consideration of technological innovation as part of that 
balance. The statutory factors which EPA must weigh are broadly 
defined and include within their ambit subfactors such as 
technological innovation.'').
    \341\ See S. Rep. No. 91-1196 at 16 (1970) (``Standards of 
performance should provide an incentive for industries to work 
toward constant improvement in techniques for preventing and 
controlling emissions from stationary sources''); S. Rep. No. 95-127 
at 17 (1977) (cited in Sierra Club v. Costle, 657 F.2d at 346 n. 
174) (``The section 111 Standards of Performance . . . sought to 
assure the use of available technology and to stimulate the 
development of new technology'').
    \342\ See Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 
391 (D.C. Cir. 1973) (the best system of emission reduction must 
``look[ ] toward what may fairly be projected for the regulated 
future, rather than the state of the art at present'').
    \343\ See 1970 Senate Committee Report No. 91-1196 at 15 (``The 
maximum use of available means of preventing and controlling air 
pollution is essential to the elimination of new pollution 
problems'').
    \344\ See Sierra Club v. Costle, 657 F.2d at 351 (upholding a 
standard of performance designed to promote the use of an emerging 
technology).
---------------------------------------------------------------------------

    In any event, as discussed below, the EPA may justify the control 
measures identified in this rule as the BSER even without considering 
the factor of incentivizing technological innovation or development.
(6) EPA Discretion
    The D.C. Circuit has made clear that the EPA has broad discretion 
in determining the appropriate standard of performance under the 
definition in CAA section 111(a)(1), quoted above. Specifically, in 
Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. 1981), the Court 
explained that ``section 111(a) explicitly instructs the EPA to balance 
multiple concerns when promulgating a

[[Page 64723]]

NSPS,'' \345\ and emphasized that ``[t]he text gives the EPA broad 
discretion to weigh different factors in setting the standard.'' \346\ 
In Lignite Energy Council v. EPA, 198 F.3d 930 (D.C. Cir. 1999), the 
Court reiterated:
---------------------------------------------------------------------------

    \345\ Sierra Club v. Costle, 657 F.2d at 319.
    \346\ Sierra Club v. Costle, 657 F.2d at 321; see also New York 
v. Reilly, 969 F. 2d at 1150 (because Congress did not assign the 
specific weight the Administrator should assign to the statutory 
elements, ``the Administrator is free to exercise [her] discretion'' 
in promulgating an NSPS).

    Because section 111 does not set forth the weight that should be 
assigned to each of these factors, we have granted the agency a 
great degree of discretion in balancing them. . . . EPA's choice [of 
the `best system'] will be sustained unless the environmental or 
economic costs of using the technology are exorbitant. . . . EPA 
[has] considerable discretion under section 111.\347\
---------------------------------------------------------------------------

    \347\ Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. 
Cir. 1999) (paragraphing revised for convenience). See New York v. 
Reilly, 969 F.2d 1147, 1150 (D.C. Cir. 1992) (``Because Congress did 
not assign the specific weight the Administrator should accord each 
of these factors, the Administrator is free to exercise his 
discretion in this area.''); see also NRDC v. EPA, 25 F.3d 1063, 
1071 (D.C. Cir. 1994) (EPA did not err in its final balancing 
because ``neither RCRA nor EPA's regulations purports to assign any 
particular weight to the factors listed in subsection (a)(3). That 
being the case, the Administrator was free to emphasize or 
deemphasize particular factors, constrained only by the requirements 
of reasoned agency decisionmaking.'').

    d. Approach to the source category and subcategorizing. Section 111 
requires the EPA first to list source categories that may reasonably be 
expected to endanger public health or welfare and then to regulate new 
sources within each such source category. Section 111(b)(2) grants the 
EPA discretion whether to ``distinguish among classes, types, and sizes 
within categories of new sources for the purpose of establishing [new 
source] standards,'' which we refer to as ``subcategorizing.'' Section 
111(d)(1), in conjunction with section 111(a)(1), simply requires the 
EPA to determine the BSER, does not prescribe the method for doing so, 
and is silent as to whether the EPA may subcategorize. The EPA 
interprets this provision to authorize the EPA to exercise discretion 
as to whether and, if so, how to subcategorize. In addition, the 
regulations under CAA section 111(d) provide that the Administrator 
will specify different emission guidelines or compliance times or both 
``for different sizes, types, and classes of designated facilities when 
costs of the control, physical limitations, geographical location, or 
similar factors make subcategorization appropriate.'' \348\
---------------------------------------------------------------------------

    \348\ 40 CFR 60.22(b)(5).
---------------------------------------------------------------------------

    As with any of its own regulations, the EPA has authority to 
interpret or revise these regulations.
    Of course, regardless of whether the EPA subcategorizes within a 
source category for purposes of determining the BSER and the emissions 
performance level for the emission guideline, as part of its CAA 
section 111(d) plan, a state retains great flexibility in assigning 
standards of performance to its affected EGUs. Thus, the state may, if 
it wishes, impose different emission reduction obligations on different 
sources, as long as the overall level of emission limitation is at 
least as stringent as the emission guidelines.
2. The BSER for This Rule--Overview
    a. Summary. This section describes the EPA's overall approach to 
establishing the BSER. This rule, promulgated under CAA section 111(d), 
establishes emission guidelines for states to use in establishing 
standards of performance for affected EGUs, and the BSER is the central 
determination that the EPA must make in formulating the guidelines. In 
order to establish the BSER we have considered the subcategory of the 
steam affected EGUs as a whole, and the subcategory of the combustion 
turbine affected EGUs as a whole, and have identified the BSER for each 
subcategory as the measures that the sources, viewed together and 
operating under the standards of performance established for them by 
the states, can implement to reduce their emissions to an appropriate 
amount, and that meet the other requirements for the BSER including, 
for example, cost reasonableness.\349\ After identifying the BSER in 
this manner, the EPA determines the performance levels--in this case, 
the CO2 emission performance rates--for the steam generators 
and for the combustion turbines.
---------------------------------------------------------------------------

    \349\ In this rulemaking, our determination that the costs are 
reasonable means that the costs meet the cost standard in the case 
law no matter how that standard is articulated, that is, whether the 
cost standard is articulated through the terms that the case law 
uses, e.g., ``exorbitant,'' ``excessive,'' etc., or through the term 
we use for convenience, ``reasonableness''.
---------------------------------------------------------------------------

    In establishing the BSER the EPA also considered the set of actions 
that an EGU, operating under a standard of performance established by 
its state, may take to achieve the applicable performance rate, if the 
state adopts that rate as the standard of performance and applies it to 
the EGUs in its jurisdiction, or to achieve the equivalent mass-based 
limit, and that meet the other requirements for the BSER. These actions 
implement the BSER and may therefore be understood as part of the BSER.
    An example illustrating the relationship between the measures 
determined to constitute the BSER for the source category and the 
actions that may be undertaken by individual sources that are therefore 
also part of the BSER is the substitution of zero-emitting generation 
for CO2-emitting generation. This measure involves two 
distinct actions: Increasing the amount of zero-emitting generation and 
reducing the amount of CO2-emitting generation. From the 
perspective of the source category, the two actions are halves of a 
single balanced endeavor, but from the perspective of any individual 
affected EGU, the two actions are separable, and a particular affected 
EGU may decide to implement either or both of the actions. Further, an 
individual source may choose to invest directly in actions at its own 
facility or an affiliated facility or to cross-invest in actions at 
other facilities on the interconnected electricity system.
    To reiterate the overall context for the BSER: In this rule, the 
EPA determined the BSER, and applied it to the category of affected 
EGUs to determine the performance levels--that is, the CO2 
emission performance rates--for steam generators and for combustion 
turbines. States must impose standards of performance on their sources 
that implement the CO2 emission performance rates, or, as an 
alternative method of compliance, in total, achieve the equivalent 
emissions performance level that the CO2 emission 
performance rates would achieve if applied directly to each source as 
the standard or emissions limitation it must meet.\350\ Each state has 
flexibility in how it assigns the emission limitations to its affected 
EGUs--and in fact, the state can be more stringent than the guidelines 
require--but one of the state's choices is to convert the 
CO2 emission performance rates into standards of 
performance--which may incorporate emissions trading--for each of its 
affected EGUs. If a state does so, then the affected EGUs may achieve 
their emission limits by taking the actions that qualify as the BSER. 
Since the BSER and, in this case its constituent elements, reflect the 
criteria of reasonable cost and other BSER criteria, the BSER assures 
that there is at least one pathway--the CO2 emission 
performance rates--for the state and its affected EGUs to take that 
achieves the requisite level of emission reductions, while, again, 
assuring that the affected EGUs can achieve those emission limits

[[Page 64724]]

at reasonable cost and consistent with the other factors for the BSER.
---------------------------------------------------------------------------

    \350\ The approaches that states may take in their plans are 
discussed in section VIII.
---------------------------------------------------------------------------

    This section describes the EPA's process and basis for determining 
the BSER for the purpose of determining the CO2 emission 
performance rates.\351\ The EPA is identifying the BSER as a well-
established set of measures that have been used by EGUs for many years 
to achieve various business and policy purposes, and have been used in 
recent years for the specific purpose of reducing EGUs' CO2 
emissions, and that are appropriate for carbon pollution (given its 
global nature and large quantities, and the limited means to control 
it) and afforded by the highly integrated nature of the utility power 
sector. We evaluated these measures with a view to the states' 
obligation to establish standards of performance and included in our 
BSER determination consideration of the range of options available for 
states to employ in establishing those standards of performance. These 
measures include: (i) Improving heat rate at existing coal-fired steam 
EGUs on average by a specified percentage (building block 1); (ii) 
substituting increased generation from existing NGCC units for reduced 
generation at existing steam EGUs in specified amounts (building block 
2); and (iii) substituting increased generation from new zero-emitting 
RE generating capacity for reduced generation at existing fossil fuel-
fired EGUs in specified amounts (building block 3). It should be noted 
that building block 2 incorporates reduced generation from steam EGUs 
and building block 3 incorporates reduced generation from all fossil 
fuel-fired EGUs.\352\ Further, as discussed below, given the global 
nature of carbon pollution and the highly integrated utility power 
sector, each of the building blocks incorporates various mechanisms for 
facilitating cross-investment by individual affected EGUs in emission 
rate improvements or emission reduction activities at other locations 
on the interconnected electricity system. The range of mechanisms 
includes bilateral investment of various kinds; the issuance and 
acquisition of ERCs representing the emissions-reducing effects of 
specific activities, where available under state plans; and more 
general emissions trading using rate-based credits or mass-based 
allowances (as discussed in section V.A.2.f. below), where the affected 
EGUs are operating under standards of performance that incorporate 
emissions trading.\353\
---------------------------------------------------------------------------

    \351\ Other sections in this preamble describe how EPA 
calculated the CO2 emission performance rates based on 
the BSER.
    \352\ The building block measures are not designed to reduce 
electricity generation overall; they are focused on maintaining the 
same level of electricity generation, but through less polluting 
processes.
    \353\ Conditions for the use of these mechanisms under various 
state plans are discussed in section VIII.
---------------------------------------------------------------------------

    The set of measures identified as the BSER for the source category 
encompasses a menu of actions that are part of the BSER and that 
individual affected EGUs may implement in different amounts and 
combinations in order to achieve their emission limits at reasonable 
cost. This menu includes actions that: (i) Affected steam EGUs can 
implement to improve their heat rates; (ii) affected steam EGUs can 
implement to increase generation from lower-emitting existing NGCC 
units in specified amounts; (iii) all affected EGUs can implement to 
increase generation from new low- or zero-carbon generation sources in 
specified amounts; (iv) all affected EGUs can implement to reduce their 
generation in specified amounts; and (v) all affected EGUs operating 
under a standard of performance that incorporates emissions trading can 
implement by means of purchasing rate-based emission credits or mass-
based emission allowances from other affected EGUs, since the effect of 
the purchase would be the same as achieving the other listed actions 
through direct means.\354\
---------------------------------------------------------------------------

    \354\ Again, conditions for the use of these mechanisms under 
various state plans are discussed in section VIII.
---------------------------------------------------------------------------

    Importantly, affected EGUs also have available numerous other 
measures that are not included in the BSER but that could materially 
help the EGUs achieve their emission limits and thereby provide 
compliance flexibility. Examples include, among numerous other 
approaches, investment in demand-side EE, co-firing with natural gas 
(for coal-fired steam EGUs), and investment in new generating units 
using low- or zero-carbon generating technologies other than those that 
are part of building block 3.
    b. The EPA's review of measures for determining the BSER. The EPA 
described in the proposal for this rule the analytical process by which 
the EPA determined the BSER for this source category. The EPA is 
finalizing large parts of that analysis, but the EPA is also refining 
that analysis as informed by the information and data discussed by 
commenters and our further evaluation. What follows is the EPA's final 
determination.
    As described in the proposal, to determine the BSER, the EPA began 
by considering the characteristics of CO2 pollution and the 
utility power sector. Not surprisingly, whenever the EPA begins the 
regulatory process under section 111, it initially undertakes these 
same inquiries and then proceeds to fashion the rule to fit the 
industry. For example, in 1979, the EPA finalized new standards of 
performance to limit emissions of SO2 from new, modified, 
and reconstructed EGUs.\355\ In assessing the final SO2 
standard, the EPA carried out extensive analyses of a range of 
alternative SO2 standards ``to identify environmental, 
economic, and energy impacts associated with each of the alternatives 
considered at the national and regional levels.'' \356\ In identifying 
the best system underlying the final standard, the EPA evaluated ``coal 
cleaning and the relative economics of FGD [flue gas desulfurization] 
and coal cleaning'' together as the ``best demonstrated system for 
SO2 emission reduction.'' \357\ The EPA also took into 
account the unique features of power transmission along the 
interconnected grid and the unique commercial relationships that rely 
on those features.\358\
---------------------------------------------------------------------------

    \355\ The need for new standards was due in part to findings 
that in 1976, steam electric generating units were responsible for 
``65 percent of the SO2 . . . emissions on a national 
basis.'' 44 FR 33580, 33587 (June 11, 1979). The EPA explained that 
[u]nder the current performance standards for power plants, national 
SO2 emissions are projected to increase approximately 17 
percent between 1975 and 1995. Impacts will be more dramatic on a 
regional basis.'' Id. Thus, ``[o]n January 27, 1977, EPA announced 
that it had initiated a study to review the technological, economic, 
and other factors needed to determine to what extent the 
SO2 standard for fossil-fuel-fired steam generators 
should be revised.'' Id. at 33587-33588.
    \356\ 44 FR 33580, 33582 (June 11, 1979).
    \357\ 44 FR 33580, 33593. The EPA considered an investigation by 
the U.S. Department of the Interior regarding the amount of sulfur 
that could be removed from various coals by physical coal cleaning. 
Id. at 33593.
    \358\ See 44 FR 33580, 33597-33600 (taking into account ``the 
amount of power that could be purchased from neighboring 
interconnected utility companies'' and noting that ``[a]lmost all 
electric utility generating units in the United States are 
electrically interconnected through power transmission lines and 
switching stations'' and that ``load can usually be shifted to other 
electric generating units'').
---------------------------------------------------------------------------

    Similarly, in 1996, the EPA finalized section 111(b) standards and 
111(d) emission guidelines to ensure that certain municipal solid waste 
(MSW) landfills controlled landfill gases to the level achievable 
through application of the BSER.\359\ EPA's identification of this BSER 
was critically influenced by the ``unique emission pattern of

[[Page 64725]]

landfills.'' \360\ Unlike ``typical stationary source[s],'' which only 
generate emissions while in operation, MSW landfills can ``continue to 
generate and emit a significant quantity of emissions'' long after the 
facility has closed or otherwise stopped accepting waste.\361\ In 
recognition of this salient and unique characteristic of landfills, the 
EPA set the BSER based on an emission-reducing system of gas collection 
and control that remained in place as long as emissions remained above 
a certain threshold--even after the regulated landfill had permanently 
closed.\362\ The EPA acknowledged that for some landfills, it could 
take 50 to 100 years for emissions to drop below the cutoff.\363\
---------------------------------------------------------------------------

    \359\ 61 FR 9905, 9905 (March 12, 1996). In the rule, the EPA 
referred to the BSER for both new and existing MSW landfills as 
``the best demonstrated system of continuous emission reduction,'' 
as well as the ``BDT''--short for ``best demonstrated technology.'' 
See, e.g., id. at 9905-07, 9913-14.
    \360\ 61 FR 9905, 9908; see 56 FR 24468, 24478 (May 30, 1991) 
(explaining at proposal that because landfill-gas emission rates 
``gradually increase'' from zero after the landfill opens, and 
``gradually decrease'' from peak emissions after closure, the EPA's 
identification of the BSER for landfills inherently requires a 
determination of ``when controls systems must be installed and when 
they may be removed'').
    \361\ See U.S. EPA, Municipal Solid Waste Landfills, Volume 1: 
Summary of the Requirements for the New Source Performance Standards 
and Emission Guidelines for Municipal Solid Waste Landfills, Docket 
No. EPA-453R/96-004 at 1-3 (February 1999).
    \362\ 61 FR 9905, 9907-08.
    \363\ 61 FR 9905, 9908.
---------------------------------------------------------------------------

    For this rule, we discuss at length in the proposed rule and in 
section II above the unique characteristics of CO2 
pollution. The salient facts include the global nature of 
CO2, which makes the specific location of emission 
reductions unimportant; the enormous quantities of CO2 
emitted by the utility power sector, coupled with the fact that 
CO2 is relatively unreactive, which make CO2 much 
more difficult to mitigate by measures or technologies that are 
typically utilized within an existing power plant; the need to make 
large reductions of CO2 in order to protect human health and 
the environment; and the fact that the utility power sector is the 
single largest source category by a considerable margin.
    We also discuss at length in the proposal and in section II above 
the unique characteristics of the utility power sector. Topics of that 
discussion include the physical properties of electricity and the 
integrated nature of the electricity system. Here, we reiterate and 
emphasize that the utility power sector is unique in the extent to 
which it must balance supply and demand on a real-time basis, with 
limited electricity storage capacity to act as a buffer. In turn, the 
need for real-time synchronization across each interconnection has led 
to a uniquely high degree of coordination and interdependence in both 
planning and real-time system operation among the owners and operators 
of the facilities comprised within each of the three large electrical 
interconnections covering the contiguous 48 states. Given these unique 
characteristics, it is not surprising that the North American power 
system has been characterized as a ``complex machine.'' \364\ The core 
function of providing reliable electricity service is carried out not 
by individual electricity generating units but by the complex machine 
as a whole. Important subsidiary functions such as management of costs 
and management of environmental impacts are also carried out to a great 
extent on a multi-unit basis rather than an individual-unit basis. 
Generation from one generating unit can be and routinely is substituted 
for generation from another generating unit in order to keep the 
complex machine operating while observing the machine's technical, 
environmental, and other constraints and managing its costs.
---------------------------------------------------------------------------

    \364\ S. Massoud Amin, ``Securing the Electricity Grid,'' The 
Bridge, Spring 2010, at 13, 14; Phillip F. Schewe, The Grid: A 
Journey Through the Heart of Our Electrified World 1 (2007).
---------------------------------------------------------------------------

    The EPA also reviewed broad trends within the utility power 
sector.\365\ It is evident that, in the recent past, coal-fired 
electricity generation has been reduced, and projected future trends 
are for continued reduction. By the same token, lower-emitting NGCC 
generation and renewable generation have increased, and projected 
future trends are for continued increases.\366\ A survey of integrated 
resource plans (IRPs), included in the docket, shows that fossil fuel-
fired EGUs are taking actions to reduce emissions of both non-GHG air 
pollutants and GHGs.\367\ Some fossil fuel-fired EGUs are investing in 
lower- or zero-emitting generation. In fact, our review indicates that 
the great majority of fossil fuel-fired generators surveyed are 
including new RE resources in their planning. In addition, some fossil 
fuel-fired EGUs are using those measures to replace their higher-
emitting generation. Some fossil fuel-fired generators appear to be 
reducing their higher-emitting generation without fully replacing it 
themselves. These measures in aggregate result in the replacement of 
higher-emitting generation with lower- or zero-emitting generation, 
reflecting the integrated nature of the electricity system.
---------------------------------------------------------------------------

    \365\ These trends are discussed in more detail in sections V.D. 
and V.E. below.
    \366\ Demand-side energy efficiency measures have also 
increased, and the projected future trends are for continued 
increase.
    \367\ See memorandum entitled ``Review of Electric Utility 
Integrated Resource Plans'' (May 7, 2015) available in the docket.
---------------------------------------------------------------------------

    The EPA examined state and company programs intended at least in 
part to reduce CO2 from fossil fuel-fired power plants. 
These programs include GHG performance standards established by states 
including California, New York, Oregon, and Washington; utility 
planning approaches carried out by companies in Colorado and Minnesota; 
and renewable portfolio standards (RPS) established in more than 25 
states.\368\ They also include market-based initiatives, such as RGGI 
and the GHG emissions trading program established by the California 
Global Warming Solutions Act, and conservation and demand reduction 
programs.
---------------------------------------------------------------------------

    \368\ See 79 FR 34848-34850.
---------------------------------------------------------------------------

    We also examined federal legislative and regulatory programs, as 
well as state programs currently in operation, that address pollutants 
other than CO2 emitted by the power sector. These programs 
include, among others, the CAA Title IV program to reduce 
SO2 and NOX, the MATS program to reduce mercury 
and air toxic emissions, and the CSAPR program to reduce SO2 
and NOX.\369\ This analysis demonstrated that, among other 
measures, the application of control technology, fuel-switching, and 
improvements in the operational efficiency of EGUs all resulted in 
reductions in a range of pollutants. These programs also demonstrate 
that replacement of higher-emitting generation with lower-emitting 
generation--including generation shifts between coal-fired EGUs and 
natural gas-fired EGUs and generation shifts between fossil fuel-fired 
EGUs and RE generation--also reduces emissions. Some of these programs 
also include emissions trading among the power plants.
---------------------------------------------------------------------------

    \369\ Many of these programs are discussed in section II.
---------------------------------------------------------------------------

    In this rule, when evaluating the types and amounts of measures 
that the source category can take to reduce CO2 emissions, 
we have appropriately taken into account the global nature of the 
pollutant and the high degree to which each individual affected EGU is 
integrated into a ``complex machine'' that makes it possible for 
generation from one generating unit to be replaced with generation from 
another generating unit for the purpose of reducing generation from 
CO2-emitting generating units. We have also taken into 
account the trends away from higher-carbon generation toward lower- and 
zero-carbon generation. These factors strongly support consideration of 
emission reduction approaches that

[[Page 64726]]

focus on the machine as a whole--that is, the overall source category--
by shifting generation from dirtier to cleaner sources in addition to 
emission reduction approaches that focus on improving the emission 
rates of individual sources.
    The factors just discussed that support consideration of emission 
reduction measures at the source-category level likewise strongly 
support consideration of mechanisms such as emissions trading 
approaches, especially since, as discussed in section VIII, the states 
will have every opportunity to design their section 111(d) plans to 
allow the affected EGUs in their respective jurisdictions to employ 
emissions trading approaches to achieve the standards of performance 
established in those plans. In short, as discussed in more detail in 
section V.A.2.f. below, it is entirely feasible for states to establish 
standards of performance that incorporate emissions trading, and it is 
reasonable to expect that states will do so. These approaches lower 
overall costs, add flexibility, and make it easier for individual 
sources to address pollution control objectives. To the extent that the 
purchase of an emissions credit or allowance represents the purchase of 
surplus emission reductions by an emitting source, emissions trading 
represents, in effect, the investment in pollution control by the 
purchasing source, notwithstanding that the control activity may be 
occurring at another source. As noted above, the utility power sector 
has a long history of using the ``complex machine'' to address 
objectives and constraints of various kinds. When afforded the 
opportunity to address environmental objectives on a multi-unit basis, 
the industry has done so. Congress and the EPA have selected emissions 
trading approaches when addressing regional pollution from the utility 
power sector contributing to problems such as acid precipitation and 
interstate transport of ozone and particulate matter. Similarly, states 
have selected market-based approaches for their own programs to address 
regional and global pollutants. The industry has readily adapted to 
that form of regulation, taking advantage of the flexibility and 
incorporating those programs into the planning and operation of the 
``machine.'' Further reinforcing our conclusion that reliance on 
trading is appropriate is the extensive interest in using such 
mechanisms that states and utilities demonstrated through their formal 
comments and in discussions during the outreach process. The role of 
emissions trading is discussed further in section V.A.2.f. below.
    This entire review has made clear that there are numerous measures 
that, alone or in various combinations, merit analysis for inclusion in 
the BSER. The review has also made clear that the unique 
characteristics of CO2 pollution and the unique, 
interconnected and interdependent manner in which affected EGUs and 
other generating sources operate within the electricity sector make 
certain types of measures and mechanisms available and appropriate for 
consideration as the BSER for this rule that would not be appropriate 
for other pollutants and other industrial sectors. For purposes of this 
discussion, the measures can be categorized in terms of the essential 
characteristics of the four building blocks described in the proposal: 
measures that (i) reduce the CO2 emission rate at the unit; 
(ii) substitute generation from existing lower-emitting fossil fuel-
fired units for generation from higher-emitting fossil fuel-fired 
units; (iii) substitute generation from new low- or zero-emitting 
generating capacity, especially RE, for generation from fossil fuel-
fired units; and (iv) increase demand-side EE to avoid generation from 
fossil fuel-fired units. In the proposal, we described our evaluations 
of various measures in each of these categories. In this rule, with the 
benefit of comments, we have refined our evaluation of which specific 
measures should comprise the first three building blocks, and, for 
reasons discussed below, we have determined that the fourth building 
block, demand-side EE, should not be included in the BSER in these 
guidelines.
    The measures are discussed more fully below, but it should be noted 
here that because of the integrated nature of the utility power 
sector--in which individual EGUs' operations intrinsically depend on 
the operations of other generators--coupled with the sector's high 
degree of planning and reliability safeguards, the measures in the 
second and third categories (which involve generation shifts to lower- 
and zero-emitting sources) may occur through several different actions 
from the perspective of an individual source, all of which are 
equivalent from the perspective of the source category as a whole. 
First, a higher-emitting fossil unit may invest in cleaner generation 
without reducing its own generation, which, in the presence of 
requirements for the source category as a whole to reduce 
CO2 emissions, would result in less demand for, and 
therefore reductions in generation by, other higher-emitting units. 
Second, a higher-emitting fossil unit may reduce its generation, which, 
in the presence of requirements for the source category as a whole to 
reduce CO2 emissions, would result in increased demand for, 
and therefore increased amounts of, cleaner generation. Third, a 
higher-emitting fossil unit may do both of these things, directly 
replacing part of its generation with investments in lower- or zero-
emitting generation. In addition, for measures in all of the 
categories, multiple mechanisms exist by which an individual affected 
EGU may make these investments, ranging from bilateral investments, to 
purchase of credits representing the emissions-reducing benefits of 
specific activities, to purchase of general rate-based emissions 
credits or mass-based emission allowances. As discussed below, 
mechanisms involving tradable credits or allowances are well within the 
realm of consideration for the standards of performance states can 
choose to apply to their EGUs and hence, are entirely appropriate for 
EPA to consider in evaluating these measures in the course of making 
its BSER determination.
    c. State establishment of standards of performance and source 
compliance. Before identifying in detail the measures that the BSER 
comprises, it is useful to describe the process by which the states 
establish the standards of performance with which the affected EGUs 
must comply, and the implications for the sources that will be 
operating subject to those standards of performance. As part of the 
EPA's emission guidelines in this rule, and based on the BSER, the EPA 
is identifying CO2 emission performance rates that reflect 
the BSER and, pursuant to subsection 111(d)(1), requiring states to 
establish standards of performance for affected EGUs in order to 
implement those rates. States, of course, could simply impose those 
rates on each affected EGU in their respective jurisdictions, but we 
are also offering states alternative approaches to carrying out their 
obligations. For purposes of defining these alternatives and 
facilitating states' efforts to formulate compliance plans encompassing 
maximum flexibilities, we are aggregating the performance rates into 
goals for each state. The state, in turn, has the option of setting 
specific standards of performance for its EGUs such that the emission 
limitations from the EGUs operating under those standards of 
performance together meet the performance rates or the state goal. To 
do this, the state must adopt a plan that establishes the EGUs' 
standards of

[[Page 64727]]

performance and that implements and enforces those standards.
    Each state has significant flexibility in several respects. For 
example, as mentioned, a state may impose standards of performance on 
its steam EGU sources and on its combustion turbine sources that simply 
reflect the respective CO2 emission performance rates for 
those subcategories set in the emission guidelines. Alternatively, a 
state may impose standards with differing degrees of stringency on 
various sources, and, in fact, may be more stringent overall than its 
state goal requires. In addition--and most importantly for purposes of 
describing the BSER--a state may set standards of performance as mass 
limits (e.g., tons of CO2 per year) rather than as emission 
rates (e.g., lbs of CO2 per MWh). Moreover, a state may make 
the limits tradable (subject to conditions described in section VIII 
below), whether the limits are rate-based or mass-based. The form of 
the emission limits, whether emission rate limits or mass limits, has 
implications for what specific actions that are part of the BSER the 
individual affected EGUs may take to achieve those limits as well as 
what specific non-BSER measures are available to the individual 
affected EGUs for compliance flexibility. For example, if an individual 
source chooses to adopt building block 3 by both investing in lower- or 
zero-emitting generation and reducing its own generation, both those 
actions will be accounted for in its emission rate and both will 
therefore help the source meet its rate-based limit. If the same 
individual source takes the same actions but is subject to a mass-based 
limit, the action of reducing its generation will directly count in 
helping the source meet its own mass-based limit but the action of 
investing in cleaner generation will not. However, the investment in 
lower-or zero-emitting generation by that source and other sources 
collectively will help the overall source category achieve the emission 
limits consistent with the BSER and in doing so will make it easier for 
that source and other sources collectively to meet their mass-based 
limits.
    In instances where a state establishes standards of performance 
that incorporate emissions trading, the tradable credits or allowances 
can serve as a medium through which affected EGUs can invest in any 
emission reduction measure.
    d. Identification of the BSER measures. We now discuss the 
evaluation of potential measures for inclusion in the BSER for the 
source category as a whole.
    (1) Measures that reduce individual affected EGUs' CO2 
emission rates.
    As described in the proposal, the measures that the affected EGUs 
could implement to improve their CO2 emission rates include 
a set of measures that the EPA determined would result in improvements 
in heat rate at coal-fired steam EGUs in the amount of 6 percent on 
average, and the EPA proposed that this set of measures qualifies as a 
component of the BSER. In this final rule, the EPA concludes that those 
measures do qualify as a component of the BSER. However, as described 
in section V.C. below, based on responsive comments and further 
evaluation, the EPA has refined its approach to quantifying the 
emission reductions achievable through heat rate improvements and no 
longer includes a separate increment of emission reductions 
attributable to equipment upgrades. Also, rather than evaluating the 
emission reductions available from these measures on a nationwide basis 
as in the proposal, the EPA has quantified the emission reductions 
achievable through building block 1 on a regional basis, consistent 
with the EPA's proposals to better reflect the regional nature of the 
interconnected electrical system and the treatment of the other 
building blocks in this final rule. As a result of these refinements, 
the EPA is identifying the heat rate improvements achievable by coal-
fired steam EGUs as 4.3 percent for the Eastern Interconnection, 2.1 
percent for the Western Interconnection, and 2.3 percent for the Texas 
Interconnection. The refinements are based, in significant part, on the 
numerous comments we received on our proposed approaches, especially 
those from states and utilities.
    These heat rate improvement measures include best practices such as 
improved staff training, boiler chemical cleaning, cleaning air 
preheater coils, and use of various kinds of software, as well as 
equipment upgrades such as turbine overhauls. These are measures that 
the owner/operator of an affected coal-fired steam EGU may take that 
would have the effect of reducing the amount of CO2 the 
source emits per MWh. As a result, these measures would help the source 
achieve an emission limit expressed as either an emission rate limit or 
as a mass limit. We note again that in the context both of the 
integrated electricity system and of available and anticipated state 
approaches to setting standards of performance, emissions trading 
approaches could be used as mechanisms through which one affected EGU 
could invest in heat rate improvements at another EGU. We note this 
aspect below in describing the actions an individual affected EGU can 
take to implement the BSER and discuss it in more detail in section 
V.A.2.f.
    These heat rate improvements are a low-cost option that fit the 
criteria for the BSER, except that they lead to only small emission 
reductions for the source category.\370\ Given the magnitude of the 
environmental problem and projections by climate scientists that much 
larger emission reductions are needed from fossil fuel-fired EGUs to 
address climate change, the EPA looked at additional measures to reduce 
emission rates. This reflects our conclusion that, given the 
availability of other measures capable of much greater emission 
reductions, the emission reductions limited to this set of heat rate 
improvement measures would not meet one of the considerations critical 
to the BSER determination--the quantity of emissions reductions 
resulting from the application of these measures is too small for these 
measures to be the BSER by themselves for this source category.
---------------------------------------------------------------------------

    \370\ As further discussed below, if heat rate improvements at 
coal-fired steam EGUs were implemented in isolation, without other 
measures to reduce CO2 emissions, the heat rate 
improvements could lead to increases in competitiveness and 
utilization of the coal-fired EGUs--a so-called ``rebound effect''--
causing increases in CO2 emissions that could partially 
or even entirely offset the CO2 emission reductions 
achieved through the reductions in the amount of CO2 
emissions per MWh of generation.
---------------------------------------------------------------------------

    Specifically, as described in the proposal, the EPA also considered 
co-firing (including 100 percent conversion) with natural gas, a 
measure that presented itself in part because of the recent increase in 
availability and reduction in price of natural gas, and the industry's 
consequent increase in reliance on natural gas.\371\ The EPA also 
considered implementation of carbon capture and storage (CCS).\372\ The 
EPA found that some of these co-firing and CCS measures are technically 
feasible and within price ranges that the EPA has found to be cost 
effective in the context of other GHG rules, that a segment of the 
source category may implement these measures, and that the resulting 
emission reductions could be potentially significant.
---------------------------------------------------------------------------

    \371\ The EPA further addressed co-firing in the October 30, 
2014 NODA. 79 FR 64549-51.
    \372\ CCS is also sometimes referred to as carbon capture and 
sequestration.
---------------------------------------------------------------------------

    However, these co-firing and CCS measures are more expensive than 
other available measures for existing sources. This is because the 
integrated nature of the electricity system affords significantly lower 
cost options, ones that fossil fuel-fired power plants

[[Page 64728]]

throughout the U.S. and in foreign nations are already using to reduce 
their CO2 emissions.
    The less expensive options include shifting generation to existing 
NGCC units--an option that has become particularly attractive in light 
of the increased availability and lower prices of natural gas--as well 
as shifting generation to new RE generating units. A comparison of the 
costs of converting an existing coal-fired boiler to burn 100 percent 
natural gas compared to the cost of shifting generation to an existing 
NGCC unit illustrates this point. Because an NGCC unit burns natural 
gas significantly more efficiently than an affected steam EGU does, the 
cost of shifting generation from the steam EGU to an existing NGCC unit 
is significantly cheaper in most cases than more aggressive emission 
rate reduction measures at the steam EGU. As a result, as a practical 
matter, were the EPA to include co-firing and CCS in the BSER and 
promulgate performance standards accordingly, few EGUs would likely 
comply with their emission standards through co-firing and CCS; rather, 
the EGUs would rely on the lower cost options of substituting lower- or 
zero-emitting generation or, as a related matter, reducing 
generation.\373\
---------------------------------------------------------------------------

    \373\ Many EGUs would also rely on demand-side energy efficiency 
measures.
---------------------------------------------------------------------------

    The EPA also considered heat rate improvement opportunities at oil- 
and gas-fired steam EGUs and NGCC units and found that the available 
emission reductions would likely be more expensive or too small to 
merit consideration as a material component of the BSER.
    Thus, in reviewing the entire range of control options, it became 
clear that controlling CO2 from affected EGUs at levels that 
are commensurate with the sector's contribution to GHG emissions and 
thus necessary to mitigate the dangers presented by climate change, 
could depend in part, but not primarily, on measures that improve 
efficiency at the power plants. Rather, most of the CO2 
controls need to come in the form of those other measures that are 
available to the utility power sector thanks specifically to the 
integrated nature of the electricity system, and that involve, in one 
form or another, replacement of higher emitting generation with lower- 
or zero-emitting generation.
    Although the presence of lower-cost options that achieve the 
emission reduction goals means that the EPA is not identifying either 
natural gas co-firing or CCS at coal-fired steam EGUs, or heat rate 
improvements at other types of EGUs, as part of the BSER, those 
controls remain measures that some affected EGUs may be expected to 
implement and that as a result, will provide reductions that those 
affected EGUs may rely on to achieve their emission limits or may sell, 
through emissions trading, to other affected EGUs to achieve emission 
limits (to the extent permitted under the relevant section 111(d) 
plans). Another example of a non-BSER measure that an affected EGU in 
certain circumstances could choose to implement is the conversion of 
waste heat from electricity generation into useful thermal energy. The 
EPA further discusses the potential use of these non-BSER measures for 
compliance flexibility below.
    The EPA's quantification of the CO2 emission reductions 
achievable through heat rate improvements as a component of the BSER 
(building block 1) is discussed in section V.C. of this preamble and in 
the GHG Mitigation Measures TSD for the CPP Final Rule.
    (2) Measures available because of the integrated electricity 
system.
    To determine the BSER that meets the expectations and requirements 
of the CAA, including the achievement of meaningful reductions of 
CO2, the EPA turned next to the set of measures that 
presented themselves as a result of the fact that the operations of 
individual affected EGUs are interdependent on and integrated with one 
another and with the overall electricity system. Those are the measures 
in the categories represented in the proposal by building blocks 2, 3, 
and 4. This section discusses the components of the BSER that relate to 
building blocks 2 and 3, which the EPA is finalizing as components of 
the BSER. This section also discusses the measures comprising the 
proposed building block 4, which the EPA is not including in the BSER 
in this final rule.
    It bears reiterating that the extent to which the operations of 
individual affected EGUs are integrated with one another and with the 
overall electricity system is a highly salient and unique attribute of 
this source category. Because of this integration, the individual 
sources in the source category operate through a network that 
physically connects them to each other and to their customers, an 
interconnectedness that is essential to their operation under the 
status quo and by all indications is projected to be augmented further 
on a continual basis in the future to address fundamental objectives of 
reliability assurance and cost reduction. This physical 
interconnectedness exists to serve a set of interlocking regimes that, 
to a substantial extent, determine, if not dictate, any given EGU's 
operations on a nearly moment-to-moment basis. In analyzing BSER from 
the perspective of the overall source category, because the affected 
EGUs are connected to each other operationally, a combination of 
dispatching and investment in lower- and zero-emitting generation 
allows the replacement of higher-emitting generation with lower-
emitting and zero-emitting generation (measures in building blocks 2 
and 3), and thereby reduces emissions while continuing to serve load.
    As noted above, substitution of higher-emitting generation for 
lower- or zero-emitting generation may include reduced generation, 
depending on the specific action taken by the individual EGU. Likewise, 
when incorporated into standards of performance, emissions trading 
mechanisms may be readily used for implementing these building blocks. 
We discuss these aspects below in describing the actions that 
individual sources may take to implement the building blocks.
    (a) Substituting generation from lower-emitting affected EGUs for 
generation from higher-emitting affected EGUs.
    In the proposal, the EPA observed that substantial CO2 
emission reductions could be achieved at reasonable cost by increasing 
generation from existing NGCC units and commensurately reducing 
generation from steam EGUs. Because NGCC units produce much less 
CO2 per MWh of generation than steam EGUs--typically less 
than half as much CO2 as coal-fired steam EGUs, which 
account for most generation from steam EGUs--this generation shift 
reduces CO2 emissions. We also noted that because NGCC units 
can generate as much as 46 percent more electricity from a given 
quantity of natural gas than a steam unit can, generation shifting from 
coal-fired steam EGUs to existing NGCC units is a more cost-effective 
strategy for reducing CO2 emissions from the source category 
than converting coal-fired steam EGUs to combust natural gas or co-
firing coal and natural gas in steam EGUs. We proposed to find that 
shifting generation consistent with a 70 percent target utilization 
rate (based on nameplate capacity) for NGCC units was feasible and 
should be a component of the BSER.
    As described in section V.D. below, analysis reflecting 
consideration of the many comments we received on the EPA's proposal 
with respect to this issue supports the inclusion of generation 
shifting from higher-emitting to lower-emitting EGUs as a component of 
the BSER. Shifting of generation

[[Page 64729]]

among EGUs is an everyday occurrence within the integrated operations 
of the utility power sector that is used to ensure that electricity is 
provided to meet customer demands in the most economic manner 
consistent with system constraints. Generation shifting to lower-
emitting units has been recognized as an approach for reducing 
emissions in other EPA rules such as CSAPR.
    The EPA's analysis continues to show that the magnitude of emission 
reductions included in the proposed rule from generation shifting is 
achievable. In response to our request for comment on the proposed 
target utilization rates, some commenters stated that summer capacity 
ratings are a more appropriate basis upon which to compute a target 
utilization than nameplate capacity ratings used at proposal. We agree, 
and accordingly, using the same data on historical generation as at 
proposal, we have reanalyzed feasible NGCC utilization levels expressed 
in terms of summer capacity ratings and have found that a 75 target 
utilization rate based on summer capacity ratings is feasible.
    The EPA is finalizing a determination that generation shift from 
higher-emitting affected EGUs to lower-emitting affected EGUs is a 
component of the BSER (building block 2). Our quantification of the 
associated emission reductions is discussed in section V.D. of this 
preamble and in the GHG Mitigation Measures TSD for the CPP Final Rule.
    (b) Substituting increased generation from new low- or zero-carbon 
generating capacity for generation from affected EGUs.
    Reducing generation from fossil fuel-fired EGUs and replacing it 
with generation from lower- or zero-emitting EGUs is another method for 
reducing CO2 emissions from the utility power sector. In the 
proposal, the EPA identified RE generating capacity and nuclear 
generating capacity as potential sources of lower- or zero-
CO2 generation that could replace higher-CO2 
generation from affected EGUs.
    (i) Increased generation from new RE generating capacity.
    The EPA's survey of trends and actions already being taken in the 
utility power sector indicated that RE generating capacity and 
generation have grown rapidly in recent years, in part because of the 
environmental benefits of shifting away from fossil fuel-fired 
generation and in part because of improved economics of RE generation 
relative to fossil fuel-fired generation. It is clear that increasing 
the amount of new RE generating capacity and allowing the increased RE 
generation to replace generation from fossil fuel-fired EGUs can reduce 
CO2 emissions from the affected source category. 
Accordingly, we proposed to include replacement of defined quantities 
of fossil generation by RE generation in the BSER.
    The EPA is finalizing the determination that substitution of RE 
generation from new RE generating capacity is a component of the BSER 
but, with the benefit of comments responding to the EPA's proposals on 
regionalization and techno-economic analytic approaches, the EPA has 
adjusted the approach for determining the quantities of RE generation. 
As part of the adjustment in approach, we have also refocused the 
quantification solely on generation from new RE generating capacity 
rather than total (new and existing) RE generating capacity as in the 
proposal. Our quantification of the RE generation component of the BSER 
is discussed in section V.E. of the preamble and in the GHG Mitigation 
Measures TSD for the CPP Final Rule.
    (ii) Increased and preserved generation from nuclear generating 
capacity.
    In the June 2014 proposal, the EPA also identified the replacement 
of generation from fossil fuel-fired EGUs with generation from nuclear 
units as a potential approach for reducing CO2 emissions 
from the affected source category. We proposed to include two elements 
of nuclear generation in the BSER: An element representing projected 
generation from nuclear units under construction; and an element 
representing preserved generation from existing nuclear generating 
capacity at risk of retirement, and we took comment on all aspects of 
these proposals.
    Like generation from new RE generating capacity, generation from 
new nuclear generating capacity can clearly replace fossil fuel-fired 
generation and thereby reduce CO2 emissions. However, there 
are also important differences between these types of low- or zero-
CO2 generation. Investments in new nuclear capacity are very 
large capital-intensive investments that require substantial lead 
times. By comparison, investments in new RE generating capacity are 
individually smaller and require shorter lead times. Also, important 
recent trends evidenced in RE development, such as rapidly growing 
investment and rapidly decreasing costs, are not as clearly evidenced 
in nuclear generation. We view these factors as distinguishing the 
under-construction nuclear units from RE generating capacity, 
indicating that the new nuclear capacity is likely of higher cost and 
therefore less appropriate for inclusion in the BSER. Accordingly, as 
described in section V.A.3., the EPA is not finalizing increased 
generation from under-construction nuclear capacity as a component of 
the BSER.
    The EPA is likewise not finalizing the proposal to include a 
component representing preserved existing nuclear generation in the 
BSER. On further consideration, we believe it is inappropriate to base 
the BSER on elements that will not reduce CO2 emissions from 
affected EGUs below current levels. Existing nuclear generation helps 
make existing CO2 emissions lower than they would otherwise 
be, but will not further lower CO2 emissions below current 
levels. Accordingly, as described in section V.A.3., the EPA is not 
finalizing preservation of generation from existing nuclear capacity as 
a component of the BSER.
    (iii) Generation from new NGCC units.
    New NGCC units--that is, units that had not commenced construction 
as of January 8, 2014, the date of publication of the proposed 
CO2 standards of performance for new EGUs under section 
111(b)--are not subject to the standards of performance that will be 
established for existing sources under section 111(d) plans based on 
the BSER determined in this final rule. In the June 2014 proposed 
emission guidelines for existing EGUs, the EPA solicited comment on 
whether to include this measure in the BSER. Commenters raised numerous 
concerns, and after consideration of the comments, we are not including 
replacement of generation from affected EGUs through the construction 
of new NGCC capacity in the BSER. In this section, we discuss the 
reasons for our approach.
    The EPA did not include reduced generation from affected EGUs 
achieved through construction and operation of new NGCC capacity in the 
proposed BSER because we expected that the CO2 emission 
reductions achieved through such actions would, on average, be more 
costly than CO2 emission reductions achieved through the 
proposed BSER measures. However, our determination not to include new 
construction and operation of new NGCC capacity in the BSER in this 
final rule rests primarily on the achievable magnitude of emission 
reductions rather than costs.
    Unlike emission reductions achieved through the use of any of the 
building blocks, emission reductions achieved through the use of new 
NGCC capacity require the construction of additional CO2-
emitting generating capacity, a consequence that is inconsistent with

[[Page 64730]]

the long-term need to continue reducing CO2 emissions beyond 
the reductions that will be achieved through this rule. New generating 
assets are planned and built for long lifetimes--frequently 40 years or 
more--that are likely longer than the expected remaining lifetimes of 
the steam EGUs whose CO2 emissions would initially be 
displaced be the generation from the new NGCC units. The new capacity 
is likely to continue to emit CO2 throughout these longer 
lifetimes, absent decisions to retire the units before the end of their 
planned lifetimes or to install CCS technology in the future at 
substantial additional cost. Because of the likelihood of 
CO2 emissions for decades, the overall net emission 
reductions achievable through the construction and operation of new 
NGCC are less than for the measures including in the BSER, such as 
increased generation at existing NGCC capacity, which would be expected 
to reach the end of its useful life sooner than new NGCC capacity, or 
construction and operation of zero-emitting RE generating capacity. We 
view the production of long-term CO2 emissions that 
otherwise would not be created as inconsistent with the BSER 
requirement that we consider the magnitude of emissions reductions that 
can be achieved. For this reason, we are not including replacement of 
generation from affected EGUs through the construction and operation of 
new NGCC capacity in the final BSER.
    Commenters also raised a concern with the interrelation of section 
111(b) and section 111(d). New NGCC capacity is distinguished from the 
other non-BSER measures discussed above by the fact that its 
CO2 emissions would be subject to the CO2 
standards for new EGUs being established under section 111(b). Section 
111 creates an express distinction between the sources subject to 
section 111(b) and the sources subject to section 111(d), and 
commenters expressed concern that to allow section 111(b) sources to 
play a direct role in setting the BSER under section 111(d) would be 
inconsistent with congressional intent to treat the two sets of sources 
separately. Section VIII of this preamble includes a discussion of ways 
to address new NGCC capacity in the context of different types of 
section 111(d) plans.
    (c) Increasing demand-side EE to avoid generation and emissions 
from fossil fuel-fired EGUs.
    The final category of approaches for reducing generation and 
CO2 emissions from affected EGUs that the EPA considered in 
the proposal involves increasing demand-side EE. When demand-side EE is 
increased, energy consumers need less electricity in order to provide 
the same level of electricity-dependent services--e.g., heating, 
cooling, lighting, and use of motors and electronic devices. Through 
the integrated electricity system, including the connection of 
customers to affected EGUs through the electricity grid, reduced demand 
for electricity, in turn, leads to reduced generation and reduced 
CO2 emissions. Our examination of actions and trends 
underway in the utility power sector confirmed that investments in 
demand-side EE programs are increasing. We proposed to include 
avoidance of defined quantities of fossil fuel-fired generation through 
increased demand-side EE as a component of the BSER (proposed building 
block 4). However, we also took comment on which building blocks should 
comprise the BSER and on our determination as to whether each building 
block met the various statutory factors.
    Commenters expressed a wide range of views on the proposed reliance 
on demand-side EE in the BSER. Some commenters strongly supported the 
proposal, with suggestions for improvements, while some commenters 
strongly opposed the proposal and took the position that it exceeded 
the EPA's legal authority. We do not address the merits of these 
comments here because, for the reasons discussed in section V.B.3.c.(8) 
below, we are not finalizing the proposal to include avoided generation 
achieved through demand-side EE as a component of the BSER. However, we 
note that most commenters also supported the use of demand-side EE for 
compliance whether or not it is used in determining the BSER, and we 
are allowing demand-side EE to be used for that purpose. (We also 
emphasize that the emission limitations reflective of the BSER are 
achievable even if aggregate generation is not reduced through demand-
side EE.)
    (3) Further analysis to quantify the BSER.
    While the discussion above summarizes how and why the components of 
the BSER were determined in terms of qualitative characteristics, it 
still leaves a wide range of potential stringencies for the BSER. As 
explained in sections V.C., V.D., and V.E. below, discussing building 
blocks 1, 2, and 3 respectively, the EPA has determined a reasonable 
level of stringency for each of the building blocks rather than the 
maximum possible level of stringency. We have taken this approach in 
part to ensure that there is ``headroom'' within the BSER measures that 
provides greater assurance of the achievability of the BSER for the 
source category and for individual sources. We believe this approach is 
permissible under the CAA. Another aspect of our methodology for 
computing the CO2 emission performance rates, further 
described in section V.A.3.f. and section VI, is that the 
CO2 emission performance rate applicable to a given source 
subcategory in all three interconnections reflects the emission rate 
achievable by that source subcategory through application of the 
building blocks in the interconnection where that achievable emission 
rate is the highest (i.e., least stringent).\374\ This aspect of our 
methodology not only ensures that the nationwide CO2 
emission performance rates are achievable by affected EGUs in all three 
interconnections but also provides additional headroom within the BSER 
for affected EGUs in the two interconnections that did not set the 
CO2 emission performance rates ultimately used. Additional 
headroom within the BSER is available through the use of emissions 
trading approaches, because the final rule does not limit the use of 
these mechanisms to sources within the same interconnections. In fact, 
in response to proposals that emerged from the comment record and 
direct engagement with states and stakeholders reflecting their strong 
interest in pursuing multi-state approaches, the guidelines include 
mechanisms for implementing standards of performance that incorporate 
interstate trading, as discussed in section VIII. (In addition, as 
further discussed below, the rule also permits section 111(d) plans to 
allow the use of non-BSER measures for compliance in certain 
circumstances, increasing both compliance flexibility and the assurance 
that the emission limitations reflecting application of the BSER are 
achievable.)
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    \374\ Specifically, the annual CO2 emission 
performance rates applicable to steam EGUs in all three 
interconnections are the annual emission rates achievable by that 
subcategory in the Eastern Interconnection through application of 
the building blocks. Similarly, the annual CO2 emission 
performance rates applicable to stationary combustion turbines in 
all three interconnections are the annual emission rates achievable 
by that subcategory in the Texas Interconnection for years from 2022 
to 2026, and in the Eastern Interconnection for years from 2027 to 
2030, through application of the building blocks. Additional 
information is provided in the CO2 Emission Performance 
Rate and State Goal Computation TSD in the docket.
---------------------------------------------------------------------------

    Further, the sets of measures in each of these individual building 
blocks, in the stringency assigned in this rule, meet the criteria for 
the BSER. That is, they each achieve the appropriate level of 
reductions, are of reasonable cost, do not impose energy penalties on 
the

[[Page 64731]]

affected EGUs and do not result in non-air quality pollutants, and have 
acceptable cost and energy implications on a source-by-source basis and 
for the energy sector as a whole. In addition, as explained below, each 
is adequately demonstrated. Importantly, past industry practice and 
current trends strongly support each of the building blocks, as do 
federal and state pollution control programs that require or result in 
similar measures.
    For example, all of the measures in building blocks 2 and 3 have 
been implemented for decades, initially for reasons unrelated to 
pollution control, then in recent years in order to control non-GHG air 
pollutants, and more recently, for purposes of CO2-emission 
control by states and companies. Moreover, Congress itself recognized 
in enacting the acid rain provisions of CAA Title IV that RE measures 
reduce CO2 from affected EGUs. In addition, the EPA has 
relied on the measures in building blocks 2 and 3 in other rules.
    It should also be noted that building blocks 2 and 3 also meet the 
criteria for the BSER in combination with one another and with building 
block 1, as described below.
    e. Actions that individual affected EGUs could take to apply or 
implement the building blocks. We now turn to a summary of measures or 
actions that individual EGUs could take to apply or implement the 
building blocks and that are therefore, in that sense, part of the 
BSER.
    (1) Improvement in CO2 emission rate at the unit.
    An affected EGU may take steps to improve its CO2 
emission rate as discussed above for the source category as a whole. As 
discussed in section V.C., the record makes clear that coal-fired steam 
EGUs can make, and have made, heat rate improvements to a greater or 
lesser degree, resulting in reductions in CO2 emissions. The 
resulting improvement in an EGU's CO2 emission rate would 
help the EGU achieve an emission limit imposed in the form of an 
emission rate. If the EGU's emission limit is imposed in the form of a 
mass standard, the heat rate improvement would also lower the EGU's 
mass emissions provided that the EGU held the amount of its generation 
constant or increased its generation by a smaller percentage than the 
efficiency improvement. Under a mass-based standard that incorporates 
emission trading, an EGU that improves its heat rate would need fewer 
emission allowances for each MWh of generation whatever level of 
generation it chose to produce.
    (2) Actions to implement measures in building blocks 2 and 3.
    Viewing the BSER from the perspective of an individual EGU, there 
are several ways that affected EGUs can access the measures in building 
blocks 2 and 3, thanks to the integrated nature of the electricity 
system, coupled with the system's high degree of planning and 
reliability mechanisms. The affected EGUs can: (a) Invest in lower- or 
zero-emitting generation, which will lead to reductions in higher-
emitting generation at other units in the integrated system; (b) reduce 
their generation, which in the presence of emission reduction 
requirements applicable to the source category as a whole will have the 
effect of increasing demand for, and thereby incentivize investment in, 
the measures in the building blocks elsewhere in the integrated system; 
or (c) both invest in the measures in the building blocks and reduce 
their own generation, effectively replacing their generation with 
cleaner generation. The availability of these options is further 
enhanced where the individual EGU is operating under a standard of 
performance that incorporates emissions trading.
    (a) Investment in measures in building blocks 2 and 3.
    An affected EGU may take the following actions to invest in the 
measures in building blocks 2 and 3. For building block 2, the owner/
operator of a steam EGU may increase generation at an existing NGCC 
unit it already owns, or one that it purchases or invests in. In 
addition, the owner/operator may, through a bilateral transaction with 
an existing NGCC unit, pay the unit to increase generation, and acquire 
the CO2-reducing effects of that increased generation in the 
form of a credit, as discussed below.
    Similarly, for building block 3, an owner/operator of an affected 
EGU may build, or purchase an ownership interest in, new RE generating 
capacity and acquire the CO2-reducing effects of that 
increased generation. Alternatively, an owner/operator may, through 
bilateral transactions, purchase the CO2-reducing effects of 
that increased generation from renewable generation providers, again, 
in the form of a credit.
    In case of an investment in either building block 2 or building 
block 3 by a unit subject to a rate-based form of CO2 
performance standard, it would be reasonable for state plans to 
authorize affected EGUs to use an approved and validated instrument 
such as an ``emission rate credit'' (ERC) representing the emissions-
reducing benefit of the investment.\375\
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    \375\ Criteria for issuance of valid ERCs and for tracking 
credits after issuance are discussed in section VIII below.
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    When combined with reduced generation, either at the affected EGU 
or elsewhere in the interconnected system, the types of actions listed 
above would be fully equivalent to building blocks 2 and 3 when viewed 
from the perspective of the overall source category. Thus, a source 
could achieve a standard of performance identical to the applicable 
CO2 emission performance rate in the EPA emission 
guidelines, through implementation of the actions described above for 
building blocks 2 and 3, along with the actions described further above 
for building block 1.
    The EPA anticipates that in instances where section 111(d) plans 
provide for the use of instruments such as ERCs as a mechanism to 
facilitate use of these measures, organized markets will develop so 
that owner/operators of affected EGUs that have invested in measures 
eligible for the issuance of ERCs will be able to sell those credits 
and other affected EGUs will be able to purchase them. Such markets 
have developed for other instruments used for emissions trading 
purposes. For example, liquid markets for SO2 allowances 
developed rapidly following the implementation of Title IV of the 1990 
Clean Air Act Amendments establishing the Acid Rain Program. Members of 
Congress and industry had expressed concern during the legislative 
debate that the lack of a liquid SO2 allowance market would 
create challenges for affected sources that needed to acquire 
allowances to meet their compliance obligations. Congress added 
statutory provisions to ensure that, should a market not develop, 
sources could purchase needed allowances directly from the EPA. In 
fact, these provisions went unused because a liquid market for 
allowances did develop very quickly. Sources engaged in allowance 
transactions directly with other sources as they sought to lower 
compliance costs. Market intermediaries offered services to sources to 
match allowance buyers and sellers and helped sources understand their 
compliance options. Trade associations worked with members to develop 
standardized contracts and other tools to facilitate allowance 
transactions, thereby reducing transaction costs. Similar developments 
have occurred in state-

[[Page 64732]]

level renewable portfolio standard programs.\376\
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    \376\ The emergence of markets under the Acid Rain Program and 
other environmental programs where trading has been permitted, as 
well as state and industry support for the development of markets 
under states' section 111(d) plans, is discussed in a recent report 
by the Advanced Energy Economy Institute. AEE Institute, Markets 
Drive Innovation--Why History Shows that the Clean Power Plan Will 
Stimulate a Robust Industry Response (July 2015), available at 
https://www.aee.net/aeei/initiatives/epa-111d.html#epa-reports-and-white-papers.
---------------------------------------------------------------------------

    If states choose to allow through their section 111(d) plans 
mechanisms or standards of performance involving instruments such as 
ERCs, the EPA believes that there would be an ample supply of such 
credits, for several reasons. First, as discussed in sections V.D. and 
V.E., the EPA has established the stringencies for building blocks 2 
and 3 at levels that are reasonable and not at the maximum achievable 
levels, providing headroom for investment in the measures in these 
building blocks beyond the amounts reflected in the CO2 
emission performance rates reflecting application of the BSER. In 
addition, if emission limits are set at the CO2 emission 
performance rates, affected EGUs in two of the three interconnections 
on average do not need to implement the building blocks to their full 
available extent in order to achieve their emission limits (because the 
performance rates for each source category are the emission rates 
achievable by that source subcategory through application of the 
building blocks in the interconnection where that achievable emission 
rate is the highest), providing further opportunities in those 
interconnections to generate surplus emission reductions that could be 
used as the basis for issuance of ERCs. Further, to the extent that 
section 111(d) plans take advantage of the latitude the final 
guidelines provide for states to set standards of performance 
incorporating emissions trading on an interstate basis among affected 
EGUs in different interconnections, all sources can take advantage of 
the headroom available in other interconnections. As a result, 
significant amounts of existing NGCC capacity and potential for RE 
remain available to serve as the basis for issuance of ERCs for all 
affected EGUs in both source subcategories to rely on to achieve their 
emission limits. Because we recognize the ready availability to states 
of standards of performance that incorporate emissions trading--and 
because such standards can easily encompass interstate trading--this 
rule includes by express design a variety of options that states and 
utilities can select to pursue interstate compliance regimes that 
mirror the interconnected operation of the electricity system. As a 
result, the EPA believes that it is reasonable to anticipate that a 
virtually nationwide emissions trading market for compliance will 
emerge, and that ERCs will be effectively available to any affected EGU 
wherever located, as long as its state plan authorizes emissions 
trading among affected EGUs.\377\
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    \377\ There is a theoretical possibility--which we view as 
extremely unlikely--that the affected EGUs in a given state or group 
of states that has chosen to pursue a technology-specific rate-based 
approach could have insufficient access to ERCs because of the 
choices of certain other states to pursue mass-based or blended-rate 
approaches. We view this as very unlikely in part because of the 
conservative assumptions used in calculating the emission reductions 
available through the building blocks and the broad availability of 
non-BSER emission reduction opportunities, such as energy 
efficiency, that will generate ERCs. If such a situation arises, and 
the state or states implementing the technology-specific rates does 
not have, within the state or states, sufficient ERC-generation 
potential to match their compliance requirements, the EPA will work 
with the state or states to ensure that there is a mechanism that 
the state or states can include in their state plans to allow the 
affected EGUs in the state or states to generate additional ERCs 
where the state or states can demonstrate that the ERCs do not 
represent double-counting under other state programs. One potential 
mechanism would be to assume for purposes of demonstrating 
compliance with their standards of performance that the generation 
replacing any reductions in generation at those affected EGUs that 
was not paired with verified ERCs came from existing NGCC units in 
other states from which ERCs were not accessible. In other words, 
any reductions in fossil steam generation from 2012 levels in a 
state or states that was implementing technology-specific rates that 
could not be matched by increases in NGCC generation or by ERCs from 
zero-emitting sources, and for which it could be demonstrated that 
no further ERCs can be procured, could generate building block 2 
ERCs as if that level of displaced generation were NGCC generation. 
A demonstration that no further ERCs are procurable would have to 
include demonstrations that the capacity factor of all NGCC 
generation in the state or states was expected to be greater than 75 
percent and that further deployment of RE would go beyond the 
amounts found available in the BSER. States could distribute these 
additional ERCs to ensure compliance by affected EGUs. Before such 
ERCs could be created by a state or states, a framework would have 
to be submitted to the EPA for approval including documentation of 
the levels of fossil steam and NGCC generation in the state or 
states, a demonstration that no further ERCs are accessible, and the 
total amount of building block 2 ERCs to be created.
---------------------------------------------------------------------------

    It should also be noted that although in a state that sets emission 
limits in a rate-based form the measures in building blocks 2 and 3 can 
be taken into account directly in computations to determine whether an 
individual affected EGU has achieved its emission limit, in a state 
that sets emission limits in a mass-based form these measures are not 
taken into account directly in computations to determine whether an 
individual affected EGU has achieved its emission limit. However, by 
reducing generation and therefore CO2 emissions from the 
group of affected EGUs within a region, in a state with mass-based 
limits implementation of these measures facilitates the ability of the 
individual EGUs within the region to achieve their limits by choosing 
to reduce their own generation and emissions.
    (b) Reduced generation.
    In addition, the owner/operator of an affected EGU may help itself 
meet its emission limit by reducing its generation. If the owner/
operator reduces generation and therefore the amount of its 
CO2 emissions, then, if the affected EGU is subject to an 
emission rate limit, the owner/operator will need to implement fewer of 
the building block measures, e.g., buy fewer ERCs, to achieve its 
emission rate; and if the affected EGU is subject to a mass emission 
limit, the owner/operator will need fewer mass allowances. As discussed 
below, at the levels that the EPA has selected for the BSER, reduced 
generation at higher-emitting EGUs does not decrease the amount of 
electricity available to the system and end users because lower-
emitting (or zero-emitting) generation will be available from other 
sources.
    An owner/operator may take actions to ensure that it reduces its 
generation. For example, it may accept a permit restriction on the 
amount of hours that it generates. In addition or alternatively, it may 
represent the cost of additional emission credits or allowances that 
would be required due to incremental generation as an additional 
variable cost that increases the total variable cost considered when 
dispatch decisions are made for the unit.
    Because of the integrated nature of the electricity system, 
combined with the system's high degree of planning and reliability 
safeguards, as well as the long planning horizon afforded by this rule, 
individual affected EGUs can implement the building blocks by reducing 
generation to achieve their emission performance standards.\378\ 
Individual affected steam EGUs can reduce their generation in the 
amounts of building blocks 2 and 3, while individual affected NGCC 
units can reduce their generation in the amount of building block 3. 
With emission limits for the source category as a whole in place, the 
resulting reduction in supply of higher-emitting generation will 
incentivize additional utilization of existing NGCC capacity, the 
resulting reduction in overall fossil fuel-fired

[[Page 64733]]

generation will incentivize investment in additional RE generating 
capacity, and the integrated system's response to these incentives will 
ensure that there will be sufficient electricity generated to continue 
to meet the demand for electricity services.
---------------------------------------------------------------------------

    \378\ For purposes of this discussion, we assume that coal-fired 
steam generators also implement building block 1 measures so that 
they will implement the full set of measures needed to achieve their 
emission limit.
---------------------------------------------------------------------------

    (c) Emissions trading.
    As described above, viewed from the perspective of the source 
category as a whole, it is reasonable for our analysis of the BSER to 
include an element of source-category-wide multi-unit compliance which 
could be implemented via a state-set standard of performance 
incorporating emissions trading, under which EGUs could engage in 
trading of rate-based emission credits or mass-based emission 
allowances. By the same token, viewed from the perspective of an 
individual EGU, consideration of the ready availability to states of 
the opportunity to establish standards of performance that incorporate 
emissions trading is integral to our analysis. Accordingly, our 
assessment of the actions available to individual EGUs for achieving 
standards of performance reflecting the BSER includes the purchase of 
rate-based emission credits or mass-based emission allowances, because 
one of the things an affected EGU can do to achieve its emission limit 
is to buy a credit or an allowance from another affected EGU that has 
over-complied. The use of purchased credits or allowances would have to 
be authorized, of course, in the purchasing EGUs' states' section 
111(d) plans and would have to meet conditions set out for such 
approaches in section VIII below. The role of emissions trading in the 
BSER analysis is discussed further in section V.A.2.f. below.
    f. The role of emissions trading. In making its BSER determination 
here, the EPA examined a number of technologies and emission reduction 
measures that result in lower levels of CO2 emissions and 
evaluated each one on the basis of the several criteria on which the 
EPA relies in determining the BSER. In contrast to section 111(b), 
however, section 111(d)(1) obliges the states, not the EPA, to set 
standards of performance for the affected EGUs in order to implement 
the BSER. Accordingly, with respect to each measure or control strategy 
under consideration, the EPA also evaluated whether or not the states 
could establish standards of performance for affected EGUs that would 
allow those sources to adopt the measure in question. In this case, the 
EPA identified a host of factors that persuaded us that states could-- 
and, in fact, may be expected to--establish standards of performance 
that incorporate emissions trading.\379\ These wide-ranging factors 
include (i) the global nature of the air pollutant in question--i.e., 
CO2; (ii) the transactional nature of the industry; (iii) 
the interconnected functioning of the industry and the coordination of 
generation resources at the level of the regional grid; (iv) the 
extensive experience that states--and EGUs--already have with emissions 
trading; and (v) material in the record demonstrating strong interest 
on the part of many states and affected EGUs in using emissions trading 
to help meet their obligations.\380\
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    \379\ As an alternative to authorizing trading that would still 
provide a degree of multi-unit flexibility, a state could choose in 
its state plan to give an owner of multiple affected EGUs 
flexibility regarding how the owner distributes any credits or 
allowances it acquires among its affected EGUs.
    \380\ Numerous states submitted comments urging the EPA to allow 
states to develop trading programs, as suggested in the proposal, 
including interstate trading programs. They include, for example, 
Alabama (EPA should develop and issue guidelines that allow options 
for multi[hyphen]state plans and interstate credit trading programs, 
comment 23584), California (EPA should provide flexibility for 
allowance trading programs to be integrated into state plans, 
comment 23433), Hawaii (supports use of emission credit trading with 
other entities to achieve compliance, comment 23121), Massachusetts 
(EPA should explore possibility of hosting a third[hyphen]party 
emissions trading bank that can allow states interested in allowance 
trading to plug and play in to a wider, more cost[hyphen]effective 
market, comment 31910), Michigan (supports emissions trading 
programs, comment 23987), Minnesota (develop model trading rule that 
states could incorporate by reference as part of plan and 
automatically be included in multi-state mass trading program, 
comment 23987), North Carolina (EPA should examine a system of 
banking and trading for energy efficiency, comment 23542), Oregon 
(EPA should expand the explicit options for multi[hyphen]state plans 
beyond cap[hyphen]and-trade, comment 20678), Washington (supporting 
trading, comment 22764), Wisconsin (requesting EPA to develop a 
national trading program, Post[hyphen]111(d) Proposal Questions to 
EPA WI Questions for 7/16 Hub call).
    In addition, several groups of states supported trading 
programs: Georgetown Climate Center (a group of state environmental 
agency leaders, energy agency leaders, and public utility 
commissioners from California, Colorado, Connecticut, Delaware, 
Illinois, Maine, Maryland, Massachusetts, Minnesota, New Hampshire, 
New York, Oregon, Rhode Island, Vermont, and Washington) (``We 
believe states should have maximum flexibility to determine what 
kinds of collaborations might work for them. These could include 
submission of joint plans, standardized approaches to trading 
renewable or energy efficiency credits. . . . We also encourage EPA 
to help facilitate such interstate agreements or multi-state 
collaborations by working with states to either identify or provide 
a platform or framework that states may elect to use for the 
tracking and trading of avoided generation or emissions credits due 
to interstate efficiency or renewable energy.'' comment 23597, at 
39-40); RGGI (including Connecticut, Delaware, Maine, Maryland, 
Massachusetts, New Hampshire, New York, Rhode Island, Vermont) 
(``[E]very serious proposal to reduce carbon emissions from EGUs, 
from proposed US legislation to programs in place in California and 
Europe, has identified allowance trading as the best approach.'' 
Comment 22395 at 7-8); Western States Center for New Energy Economy 
(including Arizona, California, Colorado, Idaho, Montana, Nevada, 
Oregon, South Dakota, Utah, Washington) (``Some degree of RE and EE 
credit trading among states may support compliance, even in the 
absence of a comprehensive regional plan. Therefore, EPA should 
support approaches which allow states flexibility to allocate credit 
for these zero-carbon resources, along with approaches which allow 
states to reach agreements on the allocation of carbon liabilities. 
This includes ensuring that existing tracking mechanisms for 
renewable energy in the West, such as the Western Renewable Energy 
Generation Information System (WREGIS), are compatible with the 
final proposal.'' Comment 21787 at 5); Midcontinent States 
Environmental and Energy Regulators (including Arkansas, Illinois, 
Michigan, Minnesota Missouri, Wisconsin) (EPA should also provide 
states with optional . . . systems (or system) for tracking 
emissions, allowances, reduction credits, and/or generation 
attributes that states may choose to use in their 111(d) plans,'' 
comment 22535 at 3).
    In addition, trading programs were supported by, among others, a 
group of Attorneys General from 11 states and the District of 
Columbia. Comment 25433 (Attorneys General from New York, 
California, Connecticut, Maine, Maryland, Massachusetts, New Mexico, 
Oregon, Rhode Island, Vermont, Washington, District of Columbia, and 
New York City Corporation Counsel).
    Numerous industry commenters also supported trading, including 
Alliant Energy Corporate Services, Inc. (comment 22934), Calpine 
(comment 23167), DTE Energy (comment 24061), Exelon (comment 23428 
and 23155), Michigan Municipal Electric Association (MMEA) (comment 
23297), National Climate Coalition (comment 22910), Pacific Gas and 
Electric Company (comment 23198), Western Power Trading Forum (WPTF) 
(comment 22860). Environmental advocates also supported trading, 
including Clean Air Task Force (comment 22612), Environmental 
Defense Fund (comment 23140), Institute for Policy Integrity, New 
York University School of Law (comment 23418).
---------------------------------------------------------------------------

    The states' and EGUs' interest in emissions trading is rooted in 
the well-recognized benefits that trading provides. The experience of 
multiple trading programs over many years has shown that some units can 
achieve emission reductions at lower cost than others, and a system 
that allows for those lower-cost reductions to be maximized is more 
cost-effective overall to the industry and to society. Trading provides 
an affected EGU other options besides direct implementation of emission 
reduction measures in its own facility or an affiliated facility when 
lower-cost emission reduction opportunities exist elsewhere. 
Specifically, the affected EGU can cross-invest, that is, invest in 
actions at facilities owned by others, in exchange for rate-based 
emission credits or mass-based emission allowances. Through cross-
investment, trading allows each affected EGU to access the control 
measures that other affected EGUs decide to implement, which in this 
case include all the building blocks as well as other measures.
    Accordingly, our analysis of the measures under consideration in 
our BSER determination reflected the well-

[[Page 64734]]

founded conclusion that it is reasonable for states to incorporate 
emissions trading in the standards of performance they establish for 
affected EGUs and that many, if not all, would do so.\381\
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    \381\ As discussed in the Legal Memorandum, the EPA has 
promulgated other rulemakings, including the transport rulemakings--
the NOX SIP Call and CAIR, which required states to 
submit SIPs, and CSAPR, which allows SIPs--on the premise of 
interstate emission trading.
---------------------------------------------------------------------------

    Whether viewed from the perspective of an individual EGU or the 
source category as a whole, emissions trading is thus an integral part 
of our BSER analysis. Again, we concluded that this is reasonable given 
the global nature of the pollutant, the transactional and 
interconnected nature of this industry, and the long history and 
numerous examples demonstrating that, in this sector, trading is 
integral to how regulators have established, and sources have complied 
with, environmental and similar obligations (such as RE standards) when 
it was appropriate to do so given the program objective. The 
reasonableness is further demonstrated by the numerous comments (some 
of which are noted above) from industry, states, and other stakeholders 
in this rulemaking that supported allowing states to adopt trading 
programs to comply with section 111(d) and encouraged EPA to facilitate 
trading across state lines through the use of trading-ready state 
plans. The EPA's reliance on trading in its BSER determination does not 
mean, however, that states are required to establish trading programs 
(just as states are not required to implement the building blocks that 
comprise BSER). Nor does it mean that trading is the only transactional 
approach that we could have considered in setting the BSER or that 
states could use to effectuate the building blocks were they to decide 
that they did not want to take on the responsibility of running a 
trading program. Rather, it is simply a recognition of the nature of 
this industry and the long history of trading as an important 
regulatory tool in establishing regulatory regimes for this industry 
and its reasonable availability to states in establishing standards of 
performance.
    As an initial matter, trading is permissible for these emission 
guidelines because CO2 is a global pollutant; the location 
of its emission does not affect the location of the environmental harm 
it causes. For CO2, it is the total amount of emissions from 
the source category that matters, not the specific emissions from any 
one EGU. The fact that trading allows sources to shift emissions from 
one location to another does not impede achievement of the 
environmental goal of reducing CO2 pollution. In its 
character as a pollutant whose impacts extend beyond local areas, 
CO2 pollution resembles to some extent the regional 
SO2 pollution that Congress chose to address with the 
emissions trading program enacted in Title IV of the 1990 CAA 
Amendments. The argument in support of trading approaches is even 
stronger for CO2 pollution, whose adverse effects are global 
rather than merely regional like the SO2 emissions 
contributing to acid precipitation.
    Further, as discussed elsewhere in the preamble, the utility power 
sector--and the affected EGUs and other generation assets that it 
encompasses--has a long history of working on a coordinated basis to 
meet operating and environmental objectives, necessitated and 
facilitated by the unique interconnectedness and interdependence of the 
sector. That history includes joint dispatch for economic and 
reliability purposes, both within large utility systems and in multi-
utility power pools that have evolved into RTOs; joint power plant 
ownership arrangements; and long-term and short-term bilateral power 
purchase arrangements. More recently, the sector's history also 
includes emissions trading programs designed by Congress, the EPA, and 
the states to address regional environmental problems and, most 
recently, climate change. Examples of such programs are noted below.
    Essentially, trading does nothing more than commoditize compliance, 
with the following two important results emerging from that: It reduces 
the overall costs of controls and spreads those costs among the entire 
category of regulated entities while providing a greater range of 
options for sources that may not want to make on-site investments for 
controlling their emissions and may prefer to make the same investment, 
via the purchase of the tradable compliance instrument, at another 
generating source. Building blocks 2 and 3 entail affected EGUs 
investing in increased generation from existing NGCC units and RE. The 
affected EGUs could do so in any number of ways, including acquiring 
ownership interests in existing NGCC or RE facilities or entering into 
bilateral transactions with the owners of existing NGCC facilities or 
RE sources. As discussed elsewhere, it is reasonable to expect that 
these actions can develop into discrete, tradable commodities (e.g., an 
ERC) and that liquid markets will develop, which would reduce 
transaction costs and allow an affected EGU to comply with its emission 
limits by purchasing discrete units in amounts tailored closely to its 
compliance needs. The existence of such tradable commodities also 
incentivizes over-compliance by affected EGUs, which can then sell 
their over-compliance in the form of ERCs or allowances to other 
affected EGUs. Moreover, as noted elsewhere, the opportunity to trade 
is consistent with the EPA's regional approach for the building blocks.
    By the same token, the opportunity to trade incentivizes affected 
EGUs to over-comply with building block 1. Thus, the opportunity to 
trade supports the EPA's assumptions about what an average affected EGU 
can achieve with regards to heat rate improvement even if each and 
every affected EGU cannot achieve that level of improvement. In 
addition, trading incentivizes affected EGUs to consider low-cost, non-
BSER methods to reduce emissions as well, and, as discussed below, 
there are numerous non-BSER methods, ranging from implementation of 
demand-side EE programs to natural gas co-firing.
    Trading has become an important mechanism for achieving 
environmental goals in the electricity sector in part because trading 
allows environmental regulators to set an environmental goal while 
preserving the ability of the operators of the affected EGUs to decide 
the best way to meet it taking account of the full range of 
considerations that govern their overall operations. For example, 
commenters were concerned that because of building block 2, the 
emission guidelines would require state environmental regulators to 
make dispatch decisions for the electricity markets, a role that state 
environmental regulators do not currently play. Although building block 
2 entails substituting existing NGCC generation for steam generation, 
implementing the emission limits that are based in part on building 
block 2 through a trading program provides the individual affected EGUs 
with a great deal of control over their own generation while the 
industry as a whole achieves the environmental goals. For example, 
individual steam generators have the option of maintaining their 
generation as long as they acquire additional ERCs. Moreover, trading 
provides a way for states to set standards of performance that realize 
the required emissions reduction without requiring any form of 
``environmental dispatch'' because, as many existing trading programs 
have shown, monetization of the environmental constraint is consistent 
with a least-cost dispatch system. Trading also supports the EPA's 
approach to the ``remaining useful life'' provision in section 
111(d)(1) because with trading, an affected EGU with a

[[Page 64735]]

limited remaining useful life can avoid the need to implement long-term 
emission reduction measures and can instead purchase ERCs or other 
tradable instruments, such as mass-based allowances, thereby allowing 
the state to meet the requirements of this rule.
    The EPA's job in issuing these emission guidelines is to determine 
the BSER that has been adequately demonstrated and to set emission 
limitations that are achievable through the application of the BSER and 
implementable through standards of performance established by the 
states. The three building blocks are the EPA's determination of what 
technology is adequately demonstrated. We also consider trading an 
integral part of the BSER analysis because, in addition to being 
available to states for incorporation in the standards of performance 
they set for affected EGUs, trading has been adequately demonstrated 
for this industry in circumstances where systemic rather than unit-
level reductions are central. Congress, the EPA, and state regulators 
have established successful environmental programs for this industry 
that allow trading of environmental (or similar) attributes, and 
trading has been widely used by the industry to comply with these 
programs. Examples include the CAA Title IV Acid Rain Program, the 
NOX SIP Call (currently referred to as the NOX 
Budget Trading Program), the Clean Air Interstate Rule (CAIR), the 
Cross-State Air Pollution Rule (CSAPR),\382\ the Regional Haze trading 
programs, the Clean Air Mercury Rule,\383\ RGGI, the trading program 
established by California AB32, and the South Coast Air Quality 
Management District RECLAIM program. We describe these programs in 
section II.E. of this preamble. In addition, we note in the Legal 
Memorandum accompanying this preamble that Congress, in enacting the 
Title IV acid rain trading program, and the EPA, in promulgating the 
regulatory trading programs listed, recognized both the suitability of 
trading for the EGU industry and the benefits of trading in reducing 
costs, spreading costs to affected EGUs throughout the sector, and 
facilitating the ability of affected EGUs to comply with their emission 
limits. In addition, as we discuss in section V.E. of this preamble, 
many states have adopted RE standards that promote RE through the 
trading of renewable energy certificates (RECs).
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    \382\ For example, in CSAPR, which covered the states in the 
eastern half of the U.S., the EPA assumed the existence of trading 
across those states in the rule's cost estimates contained in the 
RIA. ``Regulatory Impact Analysis for the Federal Implementation 
Plans to Reduce Interstate Transport of Fine Particulate Matter and 
Ozone in 27 States; Correction of SIP Approvals for 22 States'' 32 
(June 2011), http://www.epa.gov/airtransport/CSAPR/pdfs/FinalRIA.pdf. In addition, the rule is being implemented either 
through federal implementation plans (FIPs) that authorize 
interstate emission trading or SIPs that authorize interstate 
emissions trading.
    \383\ Although the CAMR trading program never took effect 
because the rule was vacated on other grounds, it consisted of a 
nationwide trading program that the EPA adopted under CAA section 
111(d). Some states declined to allow their sources to participate 
in the trading program on the grounds that nationwide trading was 
not appropriate for the air pollutant at issue, mercury, a HAP that 
caused adverse local impacts.
---------------------------------------------------------------------------

    Based on this history, it is reasonable for the EPA to determine 
that states can establish standards of performance that incorporate 
trading and, as a result, for the purpose of making a BSER 
determination here to evaluate prospective emission control measures in 
light of the availability of trading. Trading is a regulatory mechanism 
that works well for this industry. The environmental attributes in the 
preceding programs (representing emissions of air pollutants) are 
identical to or similar in nature to the environmental attribute here 
(CO2 emissions). The markets for RECs show that robust 
markets for RE, in particular, already exist.
    Given the benefits of trading and the background of multi-unit 
coordination grounded in the nature of the utility power sector, it is 
natural for sources and states to look for opportunities to apply 
similar coordination to a regional problem such as reduction of 
CO2 emissions from the sector. As noted earlier, the EPA 
heard this interest expressed during the outreach process for this 
rulemaking and saw it reflected in comments on the proposal. Emissions 
trading was prominent in these expressions of interest; while the 
proposal allowed trading and encouraged the development of multi-state 
plans which would allow the benefits of trading to extend over larger 
regions, we heard that interest was even greater in ``trading-ready'' 
plans that would use trading mechanisms and market-based coordination, 
rather than state-to-state coordination, as the primary means of 
facilitating multi-unit approaches to compliance. The general industry 
and state preference for multi-unit compliance approaches makes great 
sense in the context of the industry and this pollutant, as does the 
specific preference for trading-ready section 111(d) plans, and we have 
made efforts in the final rule to accommodate trading-ready plans as 
described in section VIII.
    g. Measures that reduce CO2 emissions or CO2 
emission rates but are not included in the BSER. There are numerous 
other measures that are available to at least some affected EGUs to 
help assure that they can achieve their emission limits, even though 
the EPA is not identifying these measures as part of the BSER. These 
measures include demand-side EE implementable by affected EGUs; new or 
uprated nuclear generation; renewable measures other than those that 
are part of building block 3, including distributed generation solar 
power and off-shore wind; combined heat and power and waste heat power; 
and transmission and distribution improvements. In addition, a state 
may implement measures that yield emission reductions for use in 
reducing the obligations on affected EGUs, such as demand-side EE 
measures not implementable by affected EGUs, including appliance 
standards, building codes, and drinking water or wastewater system 
efficiency measures. The availability of these measures further assures 
that the appropriate level of emission reductions can be achieved and 
that affected EGUs will be able to achieve their emission limits.
    h. Ability of EGUs to implement the BSER. The EPA's analysis, based 
in part on observed decades-long behavior of EGUs, shows that all types 
and sizes of affected EGUs in all locations are able to undertake the 
actions described as the BSER, including investor-owned utilities, 
merchant generators, rural cooperatives, municipally-owned utilities, 
and federal utilities. Some may need to focus more on certain measures; 
for example, an owner of a small generation portfolio consisting of a 
single coal-fired steam EGU may need to rely more on cross-investment 
approaches, possibly including the purchase of emission credits or 
allowances, because of a lack of sufficient scale to diversify its own 
portfolio to include NGCC capacity and RE generating capacity in 
addition to coal-fired capacity. As a legal matter, it is not necessary 
that each affected EGU be able to implement the BSER, but in any event, 
in this rule, all affected EGUs can do so. Since states can reasonably 
be expected to establish standards of performance incorporating 
emissions trading, affected EGUs may rely on emissions trading 
approaches authorized under their states' section 111(d) plans to, in 
effect, invest in building block measures that are physically 
implemented at other locations. As discussed above, the EPA's 
quantification of the CO2 emission performance rates in a 
manner that provides headroom within the BSER also contributes to the 
ability of all

[[Page 64736]]

affected EGUs to implement the BSER and achieve emissions limitations 
consistent with those performance rates.
    i. Subcategorization. As noted above, in this rule, we are treating 
all fossil fuel-fired EGUs as a single category, and, in the emission 
guidelines that we are promulgating with this rule, we are treating 
steam EGUs and combustion turbines as separate subcategories. We are 
determining the BSER for steam EGUs and the BSER for combustion 
turbines, and applying the BSER to each subcategory to determine a 
performance rate for that subcategory. We are not further 
subcategorizing among different types of steam EGUs or combustion 
turbines. As we discuss below, this approach is fully consistent with 
the provisions of section 111(d), which simply require the EPA to 
determine the BSER, do not prescribe the method for doing so, and are 
silent as to subcategorization. This approach is also fully consistent 
with other provisions in section 111, which require the EPA first to 
list source categories that may reasonably be expected to endanger 
public health or welfare and then to regulate new sources within each 
such source category, and which grant the EPA discretion whether to 
subcategorize the sources for purposes of determining the BSER.
    As discussed below, each affected EGU can achieve the performance 
rate by implementing the BSER, specifically, by taking a range of 
actions--some of which depend on features of the section 111(d) plan 
chosen by the state, such as the choice of rate-based or mass-based 
standards of performance and the choice of whether and how to permit 
emissions trading--including investment in the building blocks, 
replaced or reduced generation, and purchase of emission credits or 
allowances. Further, in the case of a rate-based state plan, several 
other compliance options not included in the BSER for this rule are 
also available to all affected EGUs, including investment in demand-
side EE measures. Such compliance options may also indirectly help 
affected EGUs achieve compliance under a mass-based plan.
    Our approach of subcategorizing between steam EGUs and combustion 
turbines is reasonable because building blocks 1 and 2 apply only to 
steam EGUs. Moreover, our approach of not further subcategorizing as 
between different types of steam EGUs or combustion turbines reflects 
the reasonable policy that affected EGUs with higher emission rates 
should reduce their emissions by a greater percentage than affected 
EGUs with lower emission rates and can do so at a reasonable cost using 
the approaches we have identified as the BSER as well as other 
available measures.
    Of course, a state retains great flexibility in assigning standards 
of performance to its affected EGUs and can impose different emission 
reduction obligations on its sources, as long as the overall level of 
emission limitation is at least as stringent as the emission 
guidelines, as discussed below.
3. Changes From Proposal
    For the BSER determined in this final rule, based on consideration 
of comments responding to a broad array of topics considered in the 
proposal, the EPA has adopted certain modifications to the proposed 
BSER. In this subsection we describe the most important modifications, 
including some that relate to individual building blocks and some that 
are more general. Additional modifications that relate to individual 
building blocks are discussed in the respective sections for those 
building blocks below (sections V.C. through V.E.).
    We note that taken together, the modifications yield emission 
reductions requirements that commence more gradually than the proposed 
goals but are projected to produce greater overall annual emission 
reductions by 2030.\384\ We also note that the modifications lead to 
requirements that are more uniform across states than the proposed 
state goals (consistent with the direction of certain alternatives on 
which we sought comment in the proposal), with the final requirements 
generally becoming more stringent (compared to the proposal) in states 
with the highest 2012 CO2 emission rates and less stringent 
in states with lower 2012 CO2 emission rates.
---------------------------------------------------------------------------

    \384\ For the proposed rule, the EPA projected total 
CO2 emission reductions from 2005 levels of 29% in 2025 
and 30% in 2030. For the final rule, the EPA projects total 
CO2 emissions reductions from 2005 levels of 28% in 2025 
and 32% in 2030. See Regulatory Impact Analysis for the CPP Proposed 
Rule, Table 3-6, and Regulatory Impact Analysis for the CPP Final 
Rule, Table 3-6, available in the docket.
---------------------------------------------------------------------------

    a. Interpretations of CAA section 111. In the June 2014 proposal, 
the EPA proposed interpretations of section 111(a)(1) and (d), and 
applied these interpretations to existing fossil fuel-fired EGUs.\385\ 
Informed by comments, the EPA has clarified some of these 
interpretations, and has developed a more refined understanding of how 
some of these interpretations should be applied. The clarified and more 
refined interpretations replace the proposed interpretations.
---------------------------------------------------------------------------

    \385\ The June 2014 proposal in part referenced proposed 
interpretations of section 111(a)(1) that the EPA explained in the 
January 2014 proposal to address CO2 emissions from new 
fossil fuel-fired EGUs under section 111(b).
---------------------------------------------------------------------------

    Two of these points merit mention here. First, the EPA is 
clarifying in this rule that the interpretation of ``system of emission 
reduction'' does not include emission reduction measures that the 
states have authority to mandate without the affected EGUs being able 
to implement the measures themselves (e.g., appliance standards or 
building codes). In the final rule, we have clarified that the 
components of the BSER must be implementable by the affected EGUs, not 
just by the states, and we show that all the components of the BSER 
have been demonstrated to be achievable on that basis without reliance 
on actions that can be accomplished only through government mandates. 
Further discussion of these points can be found throughout this section 
on the BSER and the following sections on the individual building 
blocks.
    Second, the EPA has adopted a combined interpretation of sections 
111(a)(1) and 111(d) that, compared to the proposal, better reflects 
the historical interpretations of section 111(a)(1), which have 
generally supported emissions standards that are nationally uniform for 
sources incorporating a given technology, and gives less weight to the 
state-focused character of section 111(d), which calls for emissions 
standards to be implemented through the development of individual state 
plans. The proposed state goals were heavily (although not entirely) 
dependent on the emission reduction opportunities available to the EGUs 
in each individual state, and because the relative magnitudes of these 
opportunities varied by state, states with similar EGU fleet 
compositions could have faced state goals of different stringencies, 
potentially making it difficult for multiple states to set the same 
standards of performance for affected EGUs using the same technologies 
(assuming the states were interested in setting standards of 
performance for their various affected EGUs in such a manner). Some 
commenters viewed this potential result as inconsistent with section 
111(a)(1), inequitable, or both. In response, we took further comment 
on these potential disparities in the October 30, 2014 NODA. In this 
final rule, we are obviating those concerns by assessing the emission 
reduction opportunities at an appropriate regional scale, consistent 
with alternatives on which we sought comment, and using this regional 
information to reformulate the proposed emissions standards as 
nationally

[[Page 64737]]

uniform emissions standards for the emission guidelines.\386\ National 
uniformity is consistent with prior section 111 rulemaking and advances 
a number of other goals central to this rulemaking. The methodological 
refinements related to regional assessment of emission reduction 
opportunities and the use of uniform emissions standards by technology 
subcategory are further discussed below.
---------------------------------------------------------------------------

    \386\ Of course, a source in one state may face different 
requirements than similar sources in other states, depending on 
whether the state adopts the state measures approach or, if it 
adopts the emission standards approach, whether it imposes a mass 
limit or an emission rate and, if the latter, at what level.
---------------------------------------------------------------------------

    b. Approach to quantification of emission reductions from increased 
RE generation. In the June 2014 proposal, the EPA described two 
possible approaches for quantifying the amount of emission reductions 
achievable from affected EGUs through the use of RE generation. The 
proposed approach used information on state RPS aggregated at a 
regional level along with historical RE generation data to project the 
amount of RE generation used in quantifying the emission reductions 
achievable through the BSER. The alternative approach used information 
on the technical and market potential for development of renewable 
resources in each state to project the RE-related emission reductions. 
In the October 30, 2014 NODA, we sought comment on an additional 
approach of aggregating the state-level information to a regional 
level, as suggested by some commenters. In this final rule we are 
adopting a combination of these approaches that uses historical RE 
generating capacity deployment data aggregated to a regional level, 
supported and confirmed by projections of market potential developed 
through a techno-economic approach.
    In the June 2014 proposal, RE generation was also quantified as 
generation from total--that is, existing and new--RE generating 
capacity, a formulation that was consistent with the formulation of 
most RPS, which are typically framed in terms of total rather than 
incremental generation. In response to the EPA's request for comment on 
this approach, commenters observed that the approach was inconsistent 
with the approach taken for other building blocks, and that generation 
from RE generating capacity that already existed as of 2012 should not 
be treated as reducing emissions of affected EGUs from 2012 levels. As 
just noted, we are not using the RPS-based methodology in the final 
rule, and we agree with comments that quantification of RE generation 
on an incremental basis is both more consistent with the treatment of 
other building blocks and more consistent with the general principle 
that the BSER should comprise incremental measures that will reduce 
emissions below existing levels, not measures that are already in 
place, even if those in-place measures help current emission levels be 
lower than would be the case without the measures. The final rule 
therefore defines the RE component of the BSER in terms of incremental 
rather than total RE generation.\387\ Further details regarding the 
final rule's quantification of RE generation are provided in section 
V.E. below.
---------------------------------------------------------------------------

    \387\ Generation from existing RE capacity will continue to make 
compliance with mass-based standards easier to achieve by making the 
overall amount of fossil fuel-fired generation that is required to 
meet the demand for energy services lower than it would otherwise 
be, thereby keeping CO2 emissions lower than they would 
otherwise be.
---------------------------------------------------------------------------

    c. Exclusion from the BSER of emission reductions from use of 
under-construction or preserved nuclear capacity. In the June 2014 
proposal, the EPA included in building block 3 provisions reflecting 
the ability for nuclear generation to replace fossil generation and 
thereby reduce CO2 emissions at affected EGUs. We proposed 
to include in building block 3 the potential generation from five 
under-construction nuclear generating units whose construction had 
commenced prior to the issuance of the proposal. In addition, to 
address the potential that some currently operating nuclear facilities 
may shut down prior to 2030, the proposal incorporated into the BSER 
for each state with nuclear capacity a projected 5.8 percent reduction 
in nuclear generation, based on an estimate of potential nationwide 
loss of nuclear generation from existing units. We sought comment on 
all aspects of these proposed approaches. While we recognize the 
important role nuclear power plants have to play in providing carbon-
free generation in an all-of-the-above energy system, for this final 
rule, the BSER does not include either of the components related to 
nuclear generation.
    The EPA received numerous comments on the proposed BSER components 
related to nuclear power. With respect to generation from under-
construction nuclear units, some commenters expressed strong opposition 
to the inclusion of this generation in the BSER and the setting of 
state goals, stating that inclusion would result in very stringent 
state goals for the states where the units are being built and that the 
inclusion of the generation in the goals is premature because the 
units' actual completion dates could be delayed. Commenters also stated 
that inclusion of the under-construction nuclear generation in the BSER 
would be inequitable because states where the same heavy investment in 
zero-CO2 generation was not being made would have relatively 
less stringent goals.
    With respect to generation from existing nuclear units, some 
commenters stated that our method of accounting for potential unit 
shutdowns was flawed, observing that even if the prediction of a 5.8 
percent nationwide loss of nuclear generation were accurate, the actual 
shutdowns would occur in a handful of states, resulting in much larger 
losses of generation in those particular states.
    Upon consideration of comments and the accompanying data, the EPA 
has determined that the BSER should not include either of the 
components related to nuclear generation from the proposal. With 
respect to nuclear units under construction, although we believe that 
other refinements to this final rule would address commenters' concerns 
that goals for the particular states where the units are located would 
be overly stringent either in absolute terms or relative to other 
states, we also acknowledge that, in comparison to RE generating 
technology, investments in new nuclear units tend to be individually 
much larger and to require longer lead times. Also, important recent 
trends evidenced in RE development, such as rapidly growing investment 
and rapidly decreasing costs, are not as clearly evidenced in nuclear 
generation. We view these factors as distinguishing the under-
construction nuclear units from RE generating capacity, indicating that 
the new nuclear capacity is likely of higher cost and therefore less 
appropriate for inclusion in the BSER. Excluding the under-construction 
nuclear units from the BSER, but allowing emission reductions 
attributable to generation from the units to be used for compliance as 
discussed below and in section VIII, will recognize the CO2 
emission reduction benefits achievable through the significant ongoing 
commitment required to complete these major investments.
    With respect to existing nuclear units, although again we believe 
that other refinements in the final rule would address the concern 
about disparate impacts on particular states, we acknowledge that we 
lack information on shutdown risk that would enable us to improve the 
estimated 5.8 percent factor for nuclear capacity at risk of

[[Page 64738]]

retirement. Further, based in part on comments received on another 
aspect of the proposal--specifically, the proposed inclusion of 
existing RE generation in the goal-setting computations--we believe 
that it is inappropriate to base the BSER in part on the premise that 
the preservation of existing low- or zero-carbon generation, as opposed 
to the production of incremental, low- or zero-carbon generation, could 
reduce CO2 emissions from current levels. Accordingly, we 
have determined not to reflect either of the nuclear elements in the 
final BSER.
    Generation from under-construction or other new nuclear units and 
capacity uprates at existing nuclear units would still be able to help 
sources meet emission rate-based standards of performance through the 
creation and use of credits, as noted in section V.A.6.b. and section 
VIII.K.1.a.(8), and would help sources meet mass-based standards of 
performance through reduced utilization of fossil generating capacity 
leading to reduced CO2 emissions at affected EGUs. However, 
consistent with the reasons just discussed for not reflecting 
preservation of existing nuclear capacity in the BSER--namely, that 
such preservation does not actually reduce existing levels of emissions 
from affected EGUs--the rule does not allow preservation of generation 
from existing or relicensed nuclear capacity to serve as the basis for 
creation of credits that individual affected EGUs could use for 
compliance, as further discussed in section VIII.K.1.a.(8).\388\
---------------------------------------------------------------------------

    \388\ As with generation from existing RE capacity, generation 
from existing nuclear capacity will continue to make compliance with 
mass-based standards easier to achieve by making the overall amount 
of fossil fuel-fired generation that is required to meet the demand 
for energy services lower than it would otherwise be, thereby 
keeping CO2 emissions lower than they would otherwise be.
---------------------------------------------------------------------------

    d. Exclusion from the BSER of emission reductions from demand-side 
EE. The June 2014 proposal included demand-side EE measures in building 
block 4 as part of the BSER. The EPA took comment on the attributes of 
each of the proposed building blocks, and building block 4 was a topic 
of considerable controversy among commenters. While many commenters 
recognized demand-side EE as an integral part of the electricity 
system, emphasized its cost-effectiveness as a means of reducing 
CO2 emissions from the utility power sector, and strongly 
supported its inclusion in the BSER, other commenters expressed 
significant concerns.
    As explained in section V.B.3.c.(8) below, our traditional 
interpretation and implementation of CAA section 111 has allowed 
regulated entities to produce as much of a particular good as they 
desire provided that they do so through an appropriately clean (or low-
emitting) process. While building blocks 1, 2, and 3 fall squarely 
within this paradigm, the proposed building block 4 does not. In view 
of this, since the BSER must serve as the foundation of the emission 
guidelines, the EPA has not included demand-side EE as part of the 
final BSER determination.
    It should be noted that commenters also took the position that the 
EPA should allow demand-side EE as a means of compliance with the 
requirements of this rule, and, as discussed in section V.A.6.b. and 
section VIII below, we agree.
    e. Consistent regionalized approach to quantification of emission 
reductions from all building blocks. In the June 2014 proposal, the EPA 
treated each of the building blocks differently with respect to the 
regional scale on which the building block was applied for purposes of 
assessing the emission reductions achievable through use of that 
building block. Building block 1 was quantified at a national scale, 
identifying a single heat rate improvement opportunity applicable on 
average to all coal-fired steam EGUs. Building block 2 was quantified 
at the scale of each individual state, considering the amount of 
generation that could be shifted from steam EGUs to NGCC units within 
the state, although we solicited comment on considering generation 
shifts at a broader regional scale. The RE component of building block 
3 was quantified at a regional scale using RPS information as a proxy 
for RE development potential, and the regional results were then 
applied to each state in the region using the state's baseline data; an 
alternative methodology on which we requested comment quantified the RE 
component using a techno-economic approach on a state-specific basis. 
In the October 2014 NODA, we requested comment on using a techno-
economic approach to quantify RE generation potential at a regional 
scale and took broad comment on strategies for better aligning the BSER 
with the regionally interconnected electrical grid.\389\ We also 
solicited comment on the appropriate regional boundaries or regional 
structure to facilitate this approach.
---------------------------------------------------------------------------

    \389\ 79 FR 64543, 64551-52.
---------------------------------------------------------------------------

    For the final rule, with the benefit of comments received in 
response to these proposals and alternatives, we have adopted a 
consistent regionalized approach to quantification of emission 
reductions achievable through all the building blocks. Under this 
approach, each of the building blocks is quantified and applied at the 
regional level, resulting in the computation for each region of a 
performance rate for steam EGUs and a performance rate for NGCC units. 
For each of the technology subcategories, we identify the most 
conservative--that is, the least stringent --of the three regional 
performance rates. We then apply these least stringent subcategory-
specific performance rates to the baseline data for the EGU fleet in 
each state to establish state goals of consistent stringency across the 
country. (Note that the actual state goals vary among states to reflect 
the differences in generation mix among states in the baseline year.) 
Further description of the steps in this overall process is contained 
in the preamble sections addressing the individual building blocks 
(sections V.C., V.D., and V.E.), CO2 emission performance 
rate computation (section VI), and state goal computation (section 
VII), as well as the GHG Mitigation Measures TSD for the CPP Final Rule 
and the CO2 Emission Performance Rate and Goal Computation 
TSD for the CPP Final Rule available in the docket.
    Compared to the more state-focused quantification approach selected 
in the proposal, and as recognized in the NODA, a regionalized approach 
better reflects the interconnected system within which interdependent 
affected EGUs actually carry out planning and operations in order to 
meet electricity demand. We have already discussed the relevance of the 
interconnected system and the interdependent operations of EGUs as 
factors supporting consideration of building blocks 2 and 3 as elements 
of the BSER for this pollutant and this industry, and these same 
factors support quantifying the emission reductions achievable through 
building blocks 2 and 3 on a regionalized basis. Because it better 
reflects how the industry works, a regionalized approach also better 
represents the full scope of emission reduction opportunities available 
to individual affected EGUs through the normal transactional processes 
of the industry, which do not stop at state borders but rather extend 
throughout these interconnected regions. With respect to building block 
1, which comprises types of emission reduction measures that in other 
rulemakings under CAA section 111 would typically be evaluated on a 
nationwide basis, for this rule, as discussed in section V.C. below, we 
are quantifying the emission reductions achievable through building

[[Page 64739]]

block 1 on a regional basis in order to treat the building blocks 
consistently and to ensure that for each region the quantification of 
the BSER represents only as much potential emission reduction from 
building block 1 as our analysis of historical data indicates can be 
achieved on average by the affected EGUs in that region.
    Characterizing and quantifying the measures included in the BSER on 
a regional basis rather than a state-limited basis is also appropriate 
because states can establish standards of performance that incorporate 
emissions trading, including trading between and among EGUs operating 
in different states, and thus provide EGUs the opportunity to trade. 
Emissions trading provides at least one mechanism by which owners of 
affected EGUs can access any of the building blocks at other locations. 
With emissions trading, an affected EGU whose access to heat rate 
improvement opportunities, incremental generation from existing NGCC 
units, or generation from new RE generating capacity is relatively 
favorable can overcomply with its own standard of performance and sell 
rate-based emission credits or mass-based emission allowances to other 
affected EGUs. Purchase of the credits or allowances by the other EGUs 
represents cross-investment in the emission reduction opportunities, 
and such cross-investment can be carried out on as wide a geographic 
scale as trading rules allow.
    The regions we have determined to be appropriate for the 
regionalized approach in the final rule are the Eastern, Western, and 
Texas Interconnections.\390\ In determining that the appropriate 
regional level for quantification of the BSER was the level of the 
interconnection, the EPA considered several factors. First, consistent 
with our goal of aligning regulation with the reality of the 
interconnected electricity system, we considered the regional scale on 
which electricity is actually produced, physically coordinated, and 
consumed in real time--specifically the Eastern, Western, and Texas 
Interconnections. The Bulk Power System (BPS) in the contiguous U.S. 
(including adjacent portions of Canada and Mexico) consists of these 
three interconnections, which are alternating current (AC) power grids 
where power flows freely from generating sources to consuming loads. 
These interconnections are separately planned and operated; they are 
connected to each other only through low-capacity direct current (DC) 
tie lines. Each interconnection is managed to maintain a single 
frequency and to maintain stable voltage levels throughout the 
interconnection. Physically, each interconnection functions as a large 
pool, where all electricity delivered to the electric grid flows by 
displacement over all transmission lines in the interconnection and 
must be continually balanced with load to ensure reliable electricity 
service to customers throughout each interconnection. ``Since power 
flows on all transmission paths, it is not uncommon to find 
circumstances in which part of a power delivery within one balancing 
area flows on transmission lines in adjoining areas, or part of a power 
delivery between two balancing areas flows over the transmission 
facilities of a third area.'' \391\ The interconnections are the 
``complex machines'' within which EGUs plan, coordinate, and operate, 
manifesting a degree of both long-term and real-time interdependence 
that is unique to this industry. We concluded that, absent a compelling 
reason to adopt a smaller regional scale for evaluation of 
CO2 emission reduction opportunities for the electric power 
sector--which we have not found, as discussed below--the 
interconnections should be the regions used for evaluation of the BSER 
for CO2 emission reductions from the electric power sector 
because of the fundamental characteristics of electricity, the 
industry's basic interconnected physical infrastructure, and the 
interdependence of the affected EGUs within each interconnection.
---------------------------------------------------------------------------

    \390\ The Texas Interconnection encompasses the portion of the 
Texas electricity system commonly known as ERCOT (for the Electric 
Reliability Council of Texas). The state of Texas has areas within 
the Eastern and Western Interconnections as well as the Texas 
Interconnection.
    \391\ Casazza, J. and Delea, F., Understanding Electric Power 
Systems, IEEE Press, at 188 (2d ed. 2010).
---------------------------------------------------------------------------

    Second, we considered whether the interconnection subregions for 
which various planning and operational functions are carried out by 
separate institutional actors would represent more appropriate regions 
than the entire interconnnections, and concluded that they would not. 
Interconnection planning and management follows the NERC functional 
model, which defines subregional areas and regional entities within 
each interconnection for the purposes of balancing generation with load 
and ensuring that reliability is maintained. While a variety of 
organizations plan and operate these subregions, those activities 
always occur in the context of the interconnections, and the subregions 
cannot be operated autonomously. The need to maintain common frequency 
and stable voltage levels throughout the interconnections requires 
constantly changing flows of electricity between the planning and 
operating subregions within each interconnection.
    Because each interconnection is a freely flowing AC grid, any power 
generated or consumed flows through the entire interconnection in real 
time; as a result of this highly interconnected nature of the power 
system, the management of generation and load on the grid must be 
carefully maintained. This management is carried out principally by 
subregional entities responsible for the operation of the grid, but 
this operation must be coordinated in real time to ensure the 
reliability of the system. Regional operators must coordinate the 
dispatch of power, not only in their own areas, but also with the other 
subregions within the interconnection. Although this coordination has 
always been important, grid planning and management has evolved to be 
increasingly interconnection-wide, through the development of larger 
regional entities, such as RTO/ISOs, or large-utility dispatch across 
multiple balancing areas. As a result, the fact that much of the 
necessary coordination for the interconnections is performed regionally 
on a partially decentralized basis (at least in the case of the Eastern 
and Western Interconnections) or occurs through the operation of 
automated equipment and the physics of the grid does not render the 
subregions more relevant than the interconnections as the ultimate 
regions within which electricity supply and demand must balance.
    Moreover, some planning and standard setting activities are 
undertaken explicitly at the interconnection level. For example, 
interconnections also have interconnection reliability operating limits 
(IROLs).\392\ A joint FERC-NERC report on the September 8, 2011 
Arizona-Southern California outages outlined the importance of 
IROLs.\393\

[[Page 64740]]

The report noted that to ensure the reliable operation of the bulk 
power system, entities must identify a plan for IROLs to avoid 
cascading outages. ``In order to ensure the reliable operation of the 
BPS, entities are required to identify and plan for IROLs, which are 
SOLs that, if violated, can cause instability, uncontrolled separation, 
and cascading outages. Once an IROL is identified, system operators are 
then required to create plans to mitigate the impact of exceeding such 
a limit to maintain system reliability.'' \394\
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    \392\ For example, the Eastern Interconnection has Reliability 
Standard IRO-006-EAST-1, Transmission Loading Relief Procedure for 
the Eastern Interconnection, available at http://www.nerc.com/files/IRO-006-EAST-1.pdf (providing an ``Interconnection-wide transmission 
loading relief procedure (TLR) for the Eastern Interconnection that 
can be used to prevent and/or mitigate potential or actual System 
Operating Limit (SOL) and Interconnection Reliability Operating 
Limit (IROL) exceedances to maintain reliability of the Bulk 
Electric System (BES).'').
    \393\ FERC-NERC, Arizona-Southern California Outages on 
September 8, 2011: Causes and Recommendations (Apr. 2012), available 
at http://www.ferc.gov/legal/staff-reports/04-27-2012-ferc-nerc-report.pdf.
    \394\ FERC-NERC, Arizona-Southern California Outages on 
September 8, 2011: Causes and Recommendations, at 97 (Apr. 2012), 
available at http://www.ferc.gov/legal/staff-reports/04-27-2012-ferc-nerc-report.pdf.
---------------------------------------------------------------------------

    Congress recognized the significance of the three interconnections 
in the American Recovery and Reinvestment Act of 2009 (Recovery Act) 
when it provided $80 million in funding for interconnection-based 
transmission planning.\395\ In order to fulfill this Congressional 
mandate, DOE and FERC signed a memorandum of understanding to enumerate 
their roles ``for activities related to the Resource Assessment and 
Interconnection Planning project funded by the American Recovery and 
Reinvestment Act of 2009 (Recovery Act). Among the objectives of the 
project is to facilitate the development or strengthening of 
capabilities in each of the three interconnections serving the 
contiguous lower forty-eight States, to prepare analyses of 
transmission requirements under a broad range of alternative futures 
and develop long-term interconnection-wide transmission plans.'' \396\ 
DOE issued awards to five organizations that performed work in the 
Western, Eastern, and Texas Interconnections to develop long-term 
interconnection-wide transmission expansion plans.\397\
---------------------------------------------------------------------------

    \395\ American Reinvestment and Recovery Act of 2009, Title IV, 
Public Law 111-5 (2009).
    \396\ Memorandum of Understanding Between the U.S. Department of 
Energy and the Federal Energy Regulatory Commission, available at 
http://www.ferc.gov/legal/mou/mou-doe-ferc.pdf.
    \397\ DOE, Recovery Act Interconnection Transmission Planning, 
available at http://energy.gov/oe/services/electricity-policy-coordination-and-implementation/transmission-planning/recovery-act.
---------------------------------------------------------------------------

    In Order No. 1000, FERC also took a broader regional view of 
transmission planning.\398\ FERC required each public utility 
transmission provider to participate in a regional transmission 
planning process that produces a regional transmission plan. FERC also 
required neighboring transmission planning regions to coordinate with 
each other. This interregional coordination includes identifying 
methods for evaluating interregional transmission facilities as well as 
establishing a common method or methods of cost allocation for 
interregional transmission facilities.
---------------------------------------------------------------------------

    \398\ Transmission Planning and Cost Allocation by Transmission 
Owning and Operating Public Utilities, Order No. 1000, FERC Stats. & 
Regs. ] 31,323 (2011), order on reh'g, Order No. 1000-A, 139 FERC ] 
61,132, order on reh'g, Order No. 1000-B, 141 FERC ] 61,044 (2012), 
aff'd sub nom. S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 41 (D.C. Cir. 
2014).
---------------------------------------------------------------------------

    In addition to Congressional, DOE, and FERC recognition of the 
importance of the three interconnections, NERC also considers them to 
be significant. NERC Organizational Standards ``are based upon certain 
Reliability Principles that define the foundation of reliability for 
North American bulk electric systems.'' \399\ These principles take a 
broad view of electric system reliability, considering the reliability 
of interconnected bulk electric systems. For example, Reliability 
Principle 1 states, ``Interconnected bulk electric systems shall be 
planned and operated in a coordinated manner to perform reliably under 
normal and abnormal conditions as defined in the NERC standards.'' 
\400\ NERC took a similarly broad view of system reliability when it 
delegated its authority to monitor and enforce mandatory reliability 
standards to a single Regional Entity in both the Western and Texas 
Interconnections (WECC in the West and the Texas Reliability Entity in 
the ERCOT region of Texas).\401\ Moreover, both WECC and ERCOT have 
interconnection-wide reliability standards.\402\ The Eastern 
Interconnection has multiple reliability regions with some differences 
in standards, but power flows and reliability are managed through a 
single Reliability Coordinator Information System that tracks power 
flows for all transmission transactions.\403\
---------------------------------------------------------------------------

    \399\ NERC, Reliability and Market Interface Principles, at 1, 
available at http://www.nerc.com/pa/Stand/Standards/ReliabilityandMarketInterfacePrinciples.pdf.
    \400\ NERC, Reliability and Market Interface Principles, at 1, 
available at http://www.nerc.com/pa/Stand/Standards/ReliabilityandMarketInterfacePrinciples.pdf.
    \401\ NERC, Key Players, available at http://www.nerc.com/AboutNERC/keyplayers/Pages/default.aspx.
    \402\ WECC, Standards, available at https://www.wecc.biz/Standards/Pages/Default.aspx (last visited July 3, 2015); Texas 
Reliability Entity, Reliability Standards, available at http://www.texasre.org/standards_rules/Pages/Default.aspx (last visited 
July 3, 2015).
    \403\ The NERC glossary defines the Reliability Coordinator 
Information System as the ``system that Reliability Coordinators use 
to post messages and share operating information in real time.'' 
NERC, Glossary of Terms Used in Reliability Standards (Apr. 20, 
2009), available at http://www.eia.gov/electricity/data/eia411/nerc_glossary_2009.pdf.
---------------------------------------------------------------------------

    The importance that Congress, DOE, FERC, and NERC each place upon 
the interconnections for electric reliability and operational issues is 
another factor supporting our decision to set the interconnections as 
the regional boundaries for the establishment of BSER. The utilization 
of the three interconnections for both planning and reliability 
purposes is a clear indication of the importance that electricity 
system regulators, operators, and industry place upon the 
interconnections. Those responsible for the electricity system 
recognize the need to ensure that there is a free flow of electricity 
throughout each interconnection such that transmission planning and 
reliability analysis are occurring at the interconnection level. 
Further, this vigilance with respect to considering reliability from an 
interconnection-wide basis recognizes that each of the interconnections 
behaves as a single machine where ``outages, generation, transmission 
changes, and problems in any one area in the synchronous network can 
affect the entire network.'' \404\ By setting the three 
interconnections as the regions for purposes of BSER, we are acting 
consistent with the way in which planning, reliability, and industry 
experts view the electricity system.
---------------------------------------------------------------------------

    \404\ Casazza, J. and Delea, F., Understanding Electric Power 
Systems, IEEE Press, at 159 (2d ed. 2010).
---------------------------------------------------------------------------

    An additional factor weighing against the use of planning or 
operational subregions of the interconnections as the regions for our 
BSER analysis for this rule is that the borders of those subregions 
occasionally change as planning and management functions evolve or as 
owners of various portions of the grid change affiliations. This is not 
a merely theoretical consideration; numerous ISO/RTO and other regional 
boundaries have substantially changed in recent years. For example, in 
2012, Duke Energy Ohio and Duke Energy Kentucky integrated into 
PJM.\405\ The following year, in December 2013, Entergy and its six 
utility operating companies joined MISO, creating the MISO South 
Region.\406\ The integration

[[Page 64741]]

of MISO South correspondingly led to changes in NERC's regional 
assessment areas.\407\ FERC also recently approved the integration of 
the Western Areas Power Administration--Upper Great Plains, Basin 
Electric Power Cooperative, and Heartland Consumers Power District into 
SPP.\408\ Additionally, PacifiCorp and the CAISO recently began 
operating the western Energy Imbalance Market (EIM).\409\ Other 
entities such as NV Energy, Arizona Public Service Co., and Puget Sound 
Energy are planning to participate in the EIM in the future.\410\ The 
EIM ``creates significant reliability and renewable integration 
benefits for consumers by sharing and economically dispatching a broad 
array of resources.'' \411\ This history of changing regional 
boundaries leads us to the conclusion that selecting smaller regional 
boundaries for purposes of setting the BSER would merely represent a 
snapshot of current, changeable regional boundaries. As we have seen 
with recent, large-scale changes regarding ISO/RTO boundaries and NERC 
reliability assessment areas, such regions would likely not stand the 
test of the time, nor would smaller regional boundaries accurately 
reflect electricity flows on the grid. The EPA believes that the 
interconnections are the most stable and reasonable regional boundaries 
for setting BSER.
---------------------------------------------------------------------------

    \405\ PJM, Duke Energy Ohio, Inc., and Duke Energy Kentucky, 
Inc., Successfully Integrated Into PJM (Jan. 3, 2012), available at 
http://www.pjm.com/~/media/about-pjm/newsroom/2012-releases/
20120103-duke-ohio-and-kentucky-integrate-into-pjm.ashx.
    \406\ South Region Integration, available at https://www.misoenergy.org/WhatWeDo/StrategicInitiatives/SouthernRegionIntegration/Pages/SouthernRegionIntegration.aspx 
(noting that the creation of the MISO South Region ``brought over 
18,000 miles of transmission, ~50,000 megawatts of generation 
capacity, and ~30,000 MW of load into the MISO footprint.'').
    \407\ NERC previously included Entergy and its six operating 
areas as part of the SERC Assessment Areas. NERC, 2014 Summer 
Reliability Assessment (May 2014), available at http://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/2014SRA.pdf. ``MISO now 
coordinates all RTO activities in the newly combined footprint, 
consisting of all or parts of 15 states with the integration of 
Entergy and other MISO South entities. This transition has led to 
substantial changes to MISO's market dispatch, creating the 
potential for unanticipated flows across the following systems: 
Tennessee Valley Authority (TVA), Associated Electric Cooperative 
Inc. (AECI), and Southern Balancing Authority.'' Id. at 7.
    \408\ SPP, FERC approves Integrates System joining SPP (Nov. 12, 
2014), available at http://www.spp.org/publications/FERC%20approves%20IS%20membership.pdf.
    \409\ NREL, Energy Imbalance Market, available at http://www.nrel.gov/electricity/transmission/energy_imbalance.html.
    \410\ CAISO, EIM Company Profiles (May 2015), available at 
http://www.caiso.com/Documents/EIMCompanyProfiles.pdf.
    \411\ CAISO, Energy Imbalance Market, available at http://www.caiso.com/informed/pages/stakeholderprocesses/energyimbalancemarket.aspx.
---------------------------------------------------------------------------

    Third, we considered whether transmission constraints, and the fact 
that the specific locations of generation resources and loads within 
each interconnection clearly matter to grid planning and operations, 
necessitate evaluation of the emission reductions available from the 
building blocks at scales smaller than the interconnections. We 
concluded that no reduction in scale was needed due to such 
constraints. The same industry trends that are reflected in the BSER--
the changing efficiencies and mix of existing fossil EGUs and the 
development of RE throughout each interconnection--as well as the 
management of the interconnected grid as loads are reduced through EE, 
which is not reflected in the final BSER, are already driving power 
system development and are being managed through interconnection-wide 
planning, coordination and operations, and will continue to be managed 
in that manner in the future with or without this rule. While 
electricity supply and demand must be balanced in real time in a manner 
that observes all security constraints at that point in time, and key 
aspects of that management are carried out at a subregional scale, the 
emissions standards established in this rule can be met over longer 
timeframes through processes managed at larger geographic scales, just 
as they are today. We believe this rule will reinforce these 
developments and help provide a secure basis for moving forward. If a 
local transmission constraint requires that for reliability reasons a 
higher-emitting resource must operate during a certain period of time 
in preference to a lower-emitting resource that would otherwise be the 
more economic choice when all costs are considered, nothing in this 
rule prevents the higher-emitting source from being operated. If the 
same transmission constraint causes the same conditions to occur 
frequently, the extra cost associated with finding alternative ways to 
reduce emissions will provide an economic incentive for concerned 
parties to explore ways to relieve the transmission constraint. If 
relieving the constraint would be more costly than employing 
alternative measures to reduce emissions, the rule allows parties to 
pursue those alternative emission reduction measures. Accommodation of 
intermittent constraints and evaluation of alternatives for relieving 
or working around them have been routine operating and planning 
practices within the utility power sector for many years; the rule will 
not change these basic economic practices that occur today. The 2022-29 
schedule for the rule's interim goals and the 2030 schedule for the 
rule's final goals allow time for planning and investment comparable to 
the sector's typical planning horizons.
    Finally, the EPA also considered whether the smaller geographic 
scales on which affected EGUs may typically engage in energy and 
capacity transactions necessitate evaluating the emission reductions 
available from the building blocks at scales smaller than the 
interconnections, and again concluded that a smaller scale was not 
necessary or justified. We first note that electricity trading occurs 
today throughout the interconnection through RTO/ISO markets and active 
spot markets, often over large areas such as RTO/ISOs, or managed over 
large dispatch areas outside RTOs. These trades result in 
interconnection-wide changes in flow that are managed in real time. 
Moreover, the exchange of power is not limited to these areas. For 
example, RTOs regularly manage flows between RTOs, and EGUs near the 
boundaries of RTOs impact multiple subregions across the 
interconnections, so that any subregional boundaries that might be 
evaluated for potential relevance as trading region boundaries will 
change as conditions and EGU choices change, while interconnection 
boundaries will remain stable.
    In addition, the final rule permits trading of rate-based emission 
credits or mass-based emission allowances. Emission allowances and 
other commodities associated with electricity generation activities, 
such as RECs, which, again, represent investments in pollution control 
measures, are already traded separately from the underlying electric 
energy and capacity. There is no reason that whatever geographic limits 
may exist for electricity and capacity transactions by an affected EGU 
should also limit the EGU's transactions for validly issued rate-based 
emission credits or mass-based emission allowances. In fact, as 
discussed below, the final rule not only allows national trading 
without regard to the interconnection boundaries, but also includes a 
number of options that readily facilitate states' and utilities' very 
extensive reliance on emissions trading. It is appropriate for the rule 
to take this approach, in part, because the non-local nature of the 
impacts of CO2 pollution do not necessitate geographic 
constraints, and in the absence of a policy reason to constrain the 
geographic scope of trading, the largest possible scope is the most 
efficient scope.
    f. Uniform CO2 emission performance rates by technology 
subcategory. In conjunction with the refinements to the interpretations 
of section 111 reflected in the final rule, the EPA has refined the 
methodology for applying the BSER to the affected EGUs so as to 
incorporate performance rates that are uniform across technology 
subcategories.

[[Page 64742]]

    Specifically, the final rule establishes a performance rate of 1305 
lbs. per net MWh for all affected steam EGUs nationwide and a 
performance rate of 771 lbs. per net MWh for all affected stationary 
combustion turbines nationwide. The computations of these performance 
rates and the determinations of state goals reflecting the performance 
rates are described in sections VI and VII of the preamble, 
respectively. As described above, in its proposed rule and NODA, the 
EPA solicited comment on a number of proposals to reflect the regional 
nature of the electricity system in the methodology for quantifying the 
emission limitations reflective of the BSER. At the same time, the EPA 
also consistently emphasized the need for strategies to ensure the 
achievability and flexibility of the established emission limitations 
and to increase opportunities for interstate and industry-wide 
coordination. This modification is consistent with a number of comments 
we received in response to those proposals. The commenters took the 
position that the proposed state goals varied too much among states and 
unavoidably implied, or would inevitably result in, states establishing 
inconsistent standards of performance for sources of the same 
technology type in their respective states, which in the commenters' 
view was not appropriate under section 111.
    Having determined to adopt regional alternatives for computing the 
emission reductions achievable under each building block, the EPA has 
further determined to exercise discretion not to subcategorize based on 
the regions, and instead to apply a nationally uniform CO2 
emission performance rate for each source subcategory. Evaluating the 
emission reduction opportunities achievable through application of the 
BSER on a broad regionalized basis, which is appropriate for the 
reasons discussed above, makes it possible to express the degree of 
emission limitation reflecting the BSER as CO2 emission 
performance rates that are uniform for all affected EGUs in a 
technology subcategory within each region. However, the goals and 
strategies embodied in the EPA's proposed rule are best effected by 
setting uniform emission performance rates nationally and not just 
regionally, as recognized by commenters favoring the use of nationally 
uniform performance rates by technology subcategory. Nationally uniform 
emission performance rates create greater parity among the emission 
reduction goals established for states across the contiguous U.S. and 
increase the ability of states and affected EGUs to coordinate emission 
reduction strategies, including through the use of emission trading 
mechanisms if states choose to allow such mechanisms, which we consider 
likely.
    Having determined that the performance rates computed on a regional 
basis merit consideration as nationally applicable performance rates, 
we are also determining that the objectives of achievability and 
flexibility would best be met by using the least stringent of the 
regional performance rates for the three interconnections for each 
technology subcategory as the basis for nationally uniform performance 
rates for that technology subcategory rather than by using the most 
stringent of the regional performance rates.\412\ Under this approach, 
the CO2 emission performance rate reflecting the BSER for 
all steam EGUs is uniform across the contiguous U.S., regardless of the 
state or interconnection where the steam EGUs are located. While it is 
true that steam EGUs in the Western and Texas Interconnections have 
opportunities to implement the measures in the building blocks to a 
greater extent than the steam EGUs in the Eastern Interconnection--for 
example, under building block 2, they have relatively greater amounts 
of incremental NGCC generation available to replace their generation in 
all years for which performance rates were computed--we do not conclude 
that this means that the EGUs in all three interconnections should be 
assigned the most stringent CO2 emission performance rate 
computed for any of the three regions. Applying nationally the 
performance rate computed for the interconnection with the lease 
stringent rate ensures that the emission limitations are achievable by 
the affected EGUs in all three interconnections. The use of a common 
CO2 emission performance rate across all of the steam EGUs 
in all three regions also allocates the burdens of the BSER equally 
across the steam EGU source subcategory. The same is true for the 
combustion turbine source subcategory, even though, in any year for 
which emission performance rates are computed, the combustion turbines 
in two of the interconnections have relatively greater opportunities to 
replace their generation with generation from new RE generating 
capacity than combustion turbines in the third interconnection.\413\
---------------------------------------------------------------------------

    \412\ The Eastern, Western, and Texas Interconnections each 
encompass large and diverse populations of EGUs with numerous and 
diverse opportunities to reduce CO2 emissions through 
application of the measures in each of the three building blocks. 
Based on these considerations of scale and diversity, we conclude 
that each of the interconnections is sufficiently representative of 
the source subcategories and emission reduction opportunities 
encompassed in the BSER to potentially serve as the basis for 
CO2 emission performance rates applicable to the 
respective source subcategories on a nationwide basis.
    \413\ As discussed in section VI and the CO2 Emission 
Performance Rate and State Goal Computation TSD, the emission 
performance rates for each technology subcategory are computed by 
region for each year from 2022 through 2030, and the region with the 
least stringent emission rate for a particular subcategory, whose 
rate therefore is used for all three regions, can differ across 
years. In the case of the steam EGU subcategory, the nationwide rate 
for all years is the rate computed for the Eastern Interconnection. 
In the case of the NGCC subcategory, the nationwide rate is the rate 
computed for the Texas Interconnection for the years from 2022 
through 2026 and the rate computed for the Eastern Interconnection 
for the years from 2027 through 2030.
---------------------------------------------------------------------------

    In addition, using the least stringent rate provides greater 
``headroom''--that is, emission reduction opportunities beyond those 
reflected in the performance rates--to affected EGUs in the 
interconnections that do not set the nationwide level. This greater 
``headroom'' provides greater nationwide compliance flexibility and 
assurance that the standards set by the states based on the emission 
guidelines will be achievable at reasonable cost and without adverse 
impacts on reliability. This is because affected EGUs in the 
interconnections that do not set the nationwide level have more 
opportunities to directly invest in each of the building blocks in 
their respective regions, and affected EGUs in the interconnection that 
does set the nationwide level may in effect invest in the opportunities 
in the other interconnections through trading. At the same time, our 
approach still represents the degree of emission limitation achievable 
through use of an appropriately large and diverse set of emission 
reduction opportunities and can therefore reasonably be considered the 
``best'' system of emission reduction for each technology subcategory.
    Our approach in this rulemaking thus not only addresses the 
comments we received regarding potentially disparate impacts of the 
approach presented in the proposal, it is also generally consistent 
with the approach we have taken in other NSPS rulemakings, where 
standards of performance or emission guidelines have typically been 
established at uniform stringencies for all units in a given source 
subcategory, and where once the best system of emission reduction has 
been identified, stringencies are generally set based on what is 
reasonably achievable using that system.

[[Page 64743]]

    Providing each state with a state-specific weighted average rate-
based goal allows the state to determine how the emission reduction 
requirements should be allocated among the state's affected EGUs. We 
continue to believe that, as in the proposal, this is an important 
source of flexibility for states in developing their section 111(d) 
plans. Accordingly, in this final rule we are providing uniform 
CO2 emission performance rates for each source subcategory 
and also translating those rates to state-specific weighted average 
rate-based goals. For additional flexibility, we are also translating 
the state-specific rate-based goals into state-specific mass-based 
goals. Our determinations of the emission performance rates are 
described in section VI below, and our determinations of the rate-based 
and mass-based state goals are described in section VII below.
    We note here that the weighted-average state goals reflect the 
application of the uniform CO2 emission performance rates 
for affected steam EGUs and affected NGCC units to the respective units 
in each subcategory in each state. Each state goal therefore reflects 
uniform stringency of emission reduction requirements with respect to 
affected units in each source subcategory, but also reflects the EGU 
fleet composition and historical generation specific to that particular 
state. Compared to the computation approach reflected in the proposed 
state goals, the revised approach to quantify the BSER on a regional 
basis and to translate the results into nationally uniform emission 
performance rates by source subcategory results in more stringent goals 
(compared to the proposal) for states whose generation has historically 
been most heavily concentrated at coal-fired steam EGUs. This shift is 
an expected consequence of the use of uniform performance rates by 
source subcategory. At proposal, these states' goals reflected 
artificial assumptions in the selected goal quantification methodology 
that to a considerable extent limited their emission reduction 
opportunities based on their states' borders, and the proposed goals 
therefore were less stringent in states which had substantial coal 
generation and little local NGCC capacity. The final rule more 
realistically recognizes that emission reduction opportunities, like 
other aspects of the interconnected electricity system, are regional 
and are not constrained by state borders. The final rule also reflects 
the EPA's emphasis in the proposal on ensuring the achievability and 
flexibility of the emission guidelines and increasing opportunities for 
interstate and industry-wide coordination. We consequently apply the 
same emission performance rates to coal-fired units in states with 
heavy reliance on coal-fueled generation as we do to coal-fired units 
in other states, which produces more stringent state goals than at 
proposal for the states with the highest concentrations of coal-fired 
generation. At the same time, the final goals for some states are less 
stringent than their proposed goals. For example, a goal based on the 
least stringent regional rates is less stringent for some states than a 
goal based on state-specific emission reduction opportunities would be. 
Accordingly, the differences among the final state goals are generally 
smaller than the differences among the proposed state goals. All of the 
final rate-based state goals are necessarily in the range bounded by 
the CO2 emission performance rate for NGCC units and the 
CO2 emission performance rate for steam EGUs because all of 
the state goals are computed as a weighted average of those two 
performance rates, and this range is narrower than the range of state 
goals in the proposal.
    The computations of the uniform CO2 emission performance 
rates are shown in the CO2 Emission Performance Rate and 
Goal Computation TSD for the CPP Final Rule. These uniform emission 
performance rates are applicable to the states and areas of Indian 
country \414\ located in the contiguous U.S. that have affected 
EGUs.\415\ We have not in this rule applied the uniform emission 
performance rates to Alaska, Hawaii, Puerto Rico, or Guam--states and 
territories that have otherwise affected EGUs but are isolated from the 
three major interconnections--and will determine how to address the 
requirements of section 111(d) with respect to these jurisdictions at a 
later time. Further discussion regarding the isolated jurisdictions can 
be found in section VII.F. of the preamble.
---------------------------------------------------------------------------

    \414\ As explained in section III.A. above, an Indian tribe 
whose area of Indian country has affected EGUs will have the 
opportunity but not the obligation to seek authority to develop and 
implement a section 111(d) plan. If no tribal plan is approved, the 
EPA has the responsibility to establish a plan if it determines that 
such a plan is necessary or appropriate.
    \415\ As noted earlier, there are currently no affected EGUs in 
Vermont or the District of Columbia.
---------------------------------------------------------------------------

    g. Establishment of a 2022-2029 interim compliance period. The June 
2014 proposal separately quantified emission limitations applicable to 
an interim 2020-29 period and to the period beginning in 2030. The EPA 
took broad comment on this proposed timing. Although the proposal 
provided flexibility in the timing with which emission reductions could 
be made over the course of the 2020-2029 period in order to achieve 
compliance with the emission limitations applicable to that interim 
period, many commenters perceived the start of the period as too soon 
and stated that it provided insufficient time for planning and 
investments necessary for sources to begin implementation activities 
while maintaining reliable electricity supplies.
    The EPA has considered these comments and in the final rule has 
established an interim compliance period of 2022-2029, providing two 
additional years for planning and investment before the start of 
compliance. We are persuaded by comments and by our own further 
analysis that this timeframe is appropriate and will, in combination 
with the glide path of emission reductions reflected in the final 
building blocks and the states' flexibility to define their own paths 
of emission reductions over the interim period (as discussed in section 
VIII), provide adequate time for necessary planning and investment 
activities. This will enable the final rule's requirements to be 
implemented in an orderly manner while reliability of electricity 
supplies is maintained. Further discussion is provided in the sections 
of the preamble addressing the individual building blocks (sections 
V.C., V.D., and V.E.) and on electricity system reliability (section 
VIII.G.2.).
    The initial compliance date of 2022, coupled with the fact that the 
2030 standard is phased in over the subsequent eight years, affords 
affected EGUs the benefit of having an extended planning period before 
they need to incur any significant obligations. Where needed, states 
may take the period through September 2018 to develop their final 
plans, and affected EGUs will be able to work with the states during 
that period to develop compliance approaches. States will also have the 
flexibility to select their own emissions trajectories in such a way 
that certain emission reduction measures could be implemented later in 
the interim period (again, provided that their affected EGUs still meet 
the interim performance rates or interim goal over the interim period 
as a whole). As a result, if the affected EGUs in those states need to 
incur any expenses before the adoption of the final state plans, those 
expenses need not be more than minimal. It is worth noting that an 
earlier state plan submission date provides regulated sources with more 
certainty and time to

[[Page 64744]]

plan for compliance, but has no effect on the time when compliance must 
be achieved, as the mandatory compliance period begins in 2022 for all 
states. Some states that already have established programs for limiting 
CO2 emissions from power plants may adopt and submit to the 
EPA state plans by September 6, 2016. In those states, sources will 
already have developed compliance approaches to meet state law 
requirements. Other states that submit plans by September 6, 2016, may 
be expected to work with their affected EGUs to determine a reasonable 
compliance approach, in light of the fact that compliance is not 
required to begin until 2022. It is also possible that some states will 
submit neither final state plans nor initial submittals by September 6, 
2016, and that the EPA will promulgate federal plans. Sources in those 
states will have more than five years to meet their 2022 compliance 
obligations, a lengthy period that will afford them the opportunity to 
plan before incurring significant expenditures.
    These periods of time are consistent with current industry practice 
in changing generation or adding new generation. For example, in June 
2015, Alabama Power Company announced plans to acquire 500 MW of RE 
generation over the next six years. This amount would make up between 
four and five percent of Alabama Power's generation mix.\416\ In 
addition, the study of utility IRPs placed in the docket for this 
rulemaking \417\ shows that sources are able to replace coal-fired 
generation with natural-gas fired generation and add incremental 
amounts of RE (as well as take other actions, such as implement demand-
side EE programs), on a gradual basis, after a several-year lead time, 
over an extended period, as provided for under the final rule.
---------------------------------------------------------------------------

    \416\ Alabama Power Co., ``Petition for a Certificate of 
Convenience and Necessity,'' submitted to the Alabama Public Service 
Commission (June 25, 2015) (petition requests ``a certificate of 
convenience and necessity for the construction or acquisition of 
renewable energy and environmentally specialized generating 
resources and the acquisition of rights and the assumption of 
payment obligations under power purchase arrangements pertaining to 
renewable energy and environmentally specialized generating 
resources, together with all transmission facilities, fuel supply 
and transportation arrangements, appliances, appurtenances, 
equipment, acquisitions and commitments necessary for or incident 
thereto'') (included in the docket for this rulemaking). See Swartz, 
Kristi, ``Alabama Power plan would dramatically boost its renewables 
portfolio,'' E&E Publishing, July 16, 2015.
    \417\ See memorandum entitled ``Review of Electric Utility 
Integrated Resource Plans'' (May 7, 2015) available in the docket.
---------------------------------------------------------------------------

    h. Refinements to stringency for individual building blocks. For 
each individual building block, the EPA has reexamined the data and 
assumptions used at proposal in light of comments solicited and has 
made a number of refinements in the final rule based on that 
information. The refinements are discussed in the preamble sections for 
each building block (sections V.C., V.D., and V.E.) and emission 
performance rate computation (section VI) and in the GHG Mitigation 
Measures TSD for the CPP Final Rule and the CO2 Emission 
Performance Rate and Goal Computation TSD for the CPP Final Rule. As 
previously noted, viewed in terms of projected nationwide emission 
reductions (but not necessarily with respect to each individual state), 
these refinements generally tend to make the interim goals somewhat 
less stringent than at proposal and the 2030 goals somewhat more 
stringent than at proposal. In addition to the changes described above, 
the refinements include the following:

     Use of regional rates ranging from 2.1 percent to 4.3 
percent (rather than 6 percent) as the average heat rate improvement 
opportunity achievable by steam units under building block 1.
     Use of 75 percent of summer capacity (rather than 70 
percent of nameplate capacity) as the target capacity factor for 
existing NGCC units under building block 2.
     Use of updated information from the National Renewable 
Energy Laboratory (NREL) on RE costs and potential, and revision of 
the list of quantified RE technologies to exclude landfill gas under 
building block 3.
4. Determination of the BSER
    In this rule, the EPA is finalizing as the BSER a combination of 
building blocks 1, 2, and 3, with refinements as discussed below. The 
building blocks constitute the BSER from the perspective of the source 
category as a whole. Each building block can be implemented through 
standards of performance set by the states and includes a set of 
actions that individual sources can use to achieve the emission 
limitations reflecting the BSER. These actions and mechanisms, which 
include reduced generation and emissions trading approaches where the 
state-set standards of performance incorporate trading and which may be 
understood as part of the BSER, will be discussed below in section 
V.A.5. Each of the building blocks consists of measures that the source 
category and individual affected EGUs have already demonstrated the 
ability to implement. In quantifying the application of each building 
block, the EPA has identified reasonable levels of stringency rather 
than the maximum possible levels.
    As discussed above, one of the modifications being made in this 
rule is the establishment of uniform performance rates by technology 
subcategory, which enhances the rule's achievability and flexibility 
and facilitates coordination among the states and across the industry. 
However, in the first instance, the emission reductions achievable 
through use of the building blocks are being evaluated on a regional 
basis that reflects the regional nature of the interconnected 
electricity system and the region-wide scope of opportunities available 
for affected EGUs to access emission reduction measures. The EPA 
recognizes that the emission reduction opportunities under these 
building blocks vary by region because of regional differences in the 
existing mix of types of fossil fuel-fired EGUs and the available 
opportunities to increase low- and zero-carbon generation. 
Consequently, in order to achieve uniform performance rates by 
technology subcategory, while respecting these regional differences in 
emission reduction opportunities, we have determined that it is 
reasonable not to establish the stringency of the BSER separately by 
region based on the maximum emission reduction that would be achievable 
in that region, but instead to establish uniform stringency across all 
regions at a level that is achievable at reasonable cost in any region. 
Thus, for each technology subcategory, the BSER is the combination of 
the elements described above at the combined stringency that is 
reasonably achievable in the region where the CO2 emission 
performance rates determined to be achievable at reasonable cost by the 
EGUs in that subcategory through application of the building blocks 
were least stringent.\418\
---------------------------------------------------------------------------

    \418\ The determinations of stringency for each source 
subcategory were made independently for each year from 2022 through 
2030, and in the case of the NGCC category, the limiting region 
changed over time. Thus, for the NGCC category, the uniform 
CO2 emission performance rate is based on the stringency 
achievable in the Texas Interconnection for the years from 2022 
through 2026 and the stringency achievable in the Eastern 
Interconnection for the years from 2027 through 2030. For the steam 
EGU subcategory, the uniform CO2 emission performance 
rate is based on the stringency achievable in the Eastern 
Interconnection in all years.
---------------------------------------------------------------------------

    This approach is consistent with the EPA's efforts to enhance the 
achievability and flexibility of the rule and to promote interstate and 
industry coordination and reflects the regional strategies emphasized 
in the proposal and the NODA. It is also consistent with the approach 
we have taken in other NSPS rulemakings, where the degree of emission 
limitation achievable through

[[Page 64745]]

the application of the BSER for each subcategory of affected sources 
generally has been determined not on the basis of what is achievable by 
the sources that can reduce emissions most easily, but instead on the 
basis of what is reasonably achievable through the application of the 
BSER across a range of sources. This approach also provides compliance 
headroom--in addition to the headroom provided by our approach to 
setting the stringency for each individual building block--for affected 
EGUs in regions where additional emission reductions can be achieved at 
reasonable cost, thereby promoting nationwide compliance flexibility. 
Further, because we are authorizing states to establish standards of 
performance that incorporate trading without geographic restrictions, 
the opportunity of affected EGUs to engage in emissions trading, to the 
extent allowed under the relevant section 111(d) plans, ensures the 
availability of additional, lower-cost emission reduction opportunities 
in other regions that will also promote compliance flexibility and 
reduce compliance costs.
    As discussed in section XI of the preamble and the Regulatory 
Impact Analysis, application of the BSER determined as summarized above 
is projected to result in substantial and meaningful reductions of 
CO2 emissions.
    Briefly, the elements of the BSER are:

Building block 1: Improving heat rate at affected coal-fired steam EGUs 
in specified percentages.
Building block 2: Substituting increased generation from existing 
affected NGCC units for generation from affected steam EGUs in 
specified quantities.
Building block 3: Substituting generation from new zero-emitting RE 
generating capacity for generation from affected EGUs in specified 
quantities.

    a. Building block 1. Building block 1--improving heat rate at 
affected coal-fired steam EGUs--is a component of the BSER with respect 
to coal-fired steam EGUs \419\ because the measures the affected EGUs 
may undertake to achieve heat rate improvements are technically 
feasible and of reasonable cost, and perform well with respect to other 
factors relevant to a determination of the ``best system of emission 
reduction . . . adequately demonstrated.'' Building block 1 is a 
``system of emission reduction'' for steam EGUs because owners of these 
EGUs can take actions that will improve their heat rates and thereby 
reduce their rates of CO2 emissions with respect to 
generation.
---------------------------------------------------------------------------

    \419\ For the reasons discussed in the proposal, the EPA is not 
determining that heat rate improvements at other types of affected 
EGUs, such as NGCC units and oil-fired and natural gas-fired steam 
EGUs, are components of the BSER. However, all types of affected 
EGUs would be able to employ heat rate improvements as measures to 
help achieve compliance with their assigned standards of 
performance.
---------------------------------------------------------------------------

    The EPA has analyzed the technical feasibility, costs, and 
magnitude of CO2 emission reductions achievable through heat 
rate improvements at coal-fired steam EGUs based on engineering studies 
and on these EGUs' reported operating and emissions data. We conclude 
that taking action to improve heat rates is a common and well-
established practice within the industry that is capable of achieving 
meaningful reductions in CO2 emissions at reasonable cost, 
although, as discussed earlier, we also conclude that the quantity of 
emission reductions achievable through heat rate improvement measures 
is insufficient for these measures alone to constitute the BSER. 
Specifically, we have determined that an average heat rate improvement 
ranging from 2.1 to 4.3 percent by all affected coal-fired EGUs, 
depending on the region, is an element of the BSER, based on the 
inclusion of those amounts of improvement in the three regions, 
determined through our regional analysis. Our analysis and conclusions 
are discussed in Section V.C. below and in the GHG Mitigation Measures 
TSD for the CPP Final Rule. Additional analysis and conclusions with 
respect to cost reasonableness are discussed in section V.A.4.d. below.
    Consideration of other BSER factors also favors a conclusion that 
building block 1 is a component of the BSER. For example, with respect 
to non-air health and environmental impacts, heat rate improvements 
cause fuel to be used more efficiently, reducing the volumes of, and 
therefore the adverse impacts associated with, disposal of coal 
combustion solid waste products. By definition, heat rate improvements 
do not cause increases in net energy usage. Although we are justifying 
building block 1 as part of the BSER without reference to technological 
innovation, we also consider technological innovation in the 
alternative, and we note that building block 1 encourages the spread of 
more advanced technology to EGUs currently using components with older 
designs.
    As noted in the June 2014 proposal, the EPA is concerned about the 
potential ``rebound effect'' associated with building block 1 if 
applied in isolation. More specifically, we noted that in the context 
of the integrated electricity system, absent other incentives to reduce 
generation and CO2 emissions from coal-fired EGUs, heat rate 
improvements and consequent variable cost reductions at those EGUs 
would cause them to become more competitive compared to other EGUs and 
increase their generation, leading to smaller overall reductions in 
CO2 emissions (depending on the CO2 emission 
rates of the displaced generating capacity). Unless mitigated, the 
occurrence of a rebound effect would reduce the emission reductions 
achieved by building block 1, exacerbating the inadequacy of emission 
reductions that is the basis for our conclusion that building block 1 
alone would not represent the BSER for this industry. However, we 
believe that our concern about the potential rebound effect can be 
readily addressed by ensuring that the BSER also reflects other 
CO2 reduction strategies that encourage increases in 
generation from lower- or zero-carbon EGUs, thereby allowing building 
block 1 to be considered an appropriate part of the BSER for 
CO2 emissions at affected EGUs as long as the building block 
is applied in combination with other building blocks.
    b. Building block 2. Building block 2--substituting generation from 
less carbon-intensive affected EGUs (specifically ``existing'' NGCC 
units, meaning units that were operating or had commenced construction 
as of January 8, 2014) for generation from the most carbon-intensive 
affected EGUs--is a component of the BSER for steam EGUs because 
generation shifts that will reduce the amount of CO2 
emissions at higher-emitting EGUs and from the source category as a 
whole are technically feasible, are of reasonable cost, and perform 
well with respect to other factors relevant to a determination of the 
``best system of emission reduction . . . adequately demonstrated.'' 
Building block 2 is a ``system of emission reduction'' for steam EGUs 
because incremental generation from existing NGCC units will result in 
reduced generation and emissions from steam EGUs, and owners of steam 
EGUs can, and many do, invest in incremental generation from NGCC units 
through a variety of possible mechanisms. A steam EGU investing in 
incremental generation from NGCC units may choose to reduce its own 
generation or may maintain its generation level and choose to allow the 
reduction in generation to occur at other steam EGUs through the 
coordinated planning and operation of the interconnected electricity 
system. An

[[Page 64746]]

affected EGU may also invest in emission reductions from building block 
2 through the mechanism of engaging in emissions trading where the EGU 
is operating under a standard of performance that incorporates trading.
    The EPA's analysis and conclusions regarding the technical 
feasibility, costs, and magnitude of CO2 emission reductions 
achievable at high-emitting EGUs through generation shifts to lower-
emitting affected EGUs are discussed in Section V.D. below. Additional 
analysis and conclusions with respect to cost reasonableness are 
discussed in section V.A.4.d. below. We consider generation shifts 
among the large number of diverse EGUs that are linked to one another 
and to customers by extensive regional transmission grids to be a 
routine and well-established operating practice within the industry 
that is used to facilitate the achievement of a wide variety of 
objectives, including environmental objectives, while meeting the 
demand for electricity services. In the interconnected and integrated 
electricity industry, fossil fuel-fired steam EGUs are able to reduce 
their generation and NGCC units are able to increase their generation 
in a coordinated manner through mechanisms--in some cases centralized 
and in others not--that regularly deal with such changes on both a 
short-term and a longer-term basis. Our analysis demonstrates that the 
emission reductions that can be achieved or supported by such 
generation shifts are substantial and of reasonable cost. Further, both 
the achievability of this building block and the reasonableness of its 
costs are supported by the fact that there has been a long-term trend 
in the industry away from coal-fired generation and toward NGCC 
generation for a variety of reasons.
    Building block 2 is adequately demonstrated as a ``system of 
emission reduction'' for affected steam EGUs. As discussed in section 
V.B., since the time of the 1970 CAA Amendments, the utility power 
sector has recognized that generation shifts are a means of controlling 
air pollutants; in the 1990 CAA Amendments, Congress recognized that 
generation shifts among EGUs are a means of reducing emissions from 
this sector; and generation shifts similarly have been recognized as a 
means of reducing emissions under trading programs established by the 
EPA to implement the Act's provisions. It is common practice in the 
industry to account for the cost of emission allowances as a variable 
cost when making security-constrained, cost-based dispatch decisions; 
doing so integrates generation shifts into the operating practices used 
to achieve compliance with environmental requirements in an economical 
manner. These industry trends are further discussed in section V.D. 
Thus, legislative history, regulatory precedent, and industry practice 
support interpreting the broad term ``system of emission reduction'' as 
including substituting lower-emitting generation for higher-emitting 
generation through generation shifts among affected EGUs.
    An important additional consideration supporting the determination 
that building block 2 is adequately demonstrated as a ``system of 
emission reduction'' is that owners of affected steam EGUs have the 
ability to invest in generation shifts as a way of reducing emissions. 
The owner of an affected EGU could invest in such generation shifts in 
several ways, including by increasing operation of an NGCC unit that it 
already owns or by purchasing an existing NGCC unit and increasing 
operation of that unit. Increases in generation by NGCC units over 
baseline levels can also serve as the basis for creation of 
CO2 ERCs--that is, instruments representing the ability of 
incremental electricity generated by NGCC units to cause emission 
reductions at affected steam EGUs, as distinct from the incremental 
electricity itself. Again, it is important to note that the acquisition 
of such ERCs represents an investment in the actions of the facility or 
facilities whose alteration of utilization levels generated the 
emissions rate improvement or reduction. In the context of the BSER, 
purchase of instruments representing the emissions-reducing benefit of 
an action is simply a medium of investment in the underlying emissions 
reduction action. These mechanisms are discussed further in section 
V.A.5. In this rule, the EPA is establishing minimum criteria for the 
creation of valid ERCs by NGCC units and for the use of such ERCs by 
affected steam EGUs for demonstrating compliance with emission rate-
based standards of performance established under state plans. The 
existence of minimum criteria will ensure that crediting mechanisms are 
feasible and will facilitate the development of organized markets to 
simplify the process of buying and selling ERCs. The minimum criteria 
are discussed in section VIII of this preamble.
    We note that an affected EGU investing in building block 2 to 
reduce emissions may, but need not, also choose to reduce its own 
generation as part of its approach for meeting the standard of 
performance assigned to it by its state. Through the coordinated 
operation of the integrated electricity system, subject to the 
collective emission reduction requirements that will be imposed on 
affected EGUs in order to meet the emissions standards representing the 
BSER, an increase in NGCC generation will be offset elsewhere in the 
interconnection by a decrease in other generation. Because of the need 
to meet the collective emission reduction requirements, the decrease in 
generation resulting from that coordinated operation is most likely to 
be generation from an affected steam EGU. Measures taken by affected 
EGUs that result in emission reductions from other EGUs in the source 
category may appropriately be deemed measures to implement or apply the 
``system of emission reduction'' of substituting lower-emitting 
generation for higher-emitting generation.
    Consideration of other BSER factors also supports a determination 
to include building block 2 as a component of the BSER. For example, we 
expect that building block 2 would have positive non-air health and 
environmental impacts. Coal combustion for electricity generation 
produces large volumes of solid wastes that require disposal, with some 
potential for adverse environmental impacts; these wastes are not 
produced by natural gas combustion. The intake and discharge of water 
for cooling at many EGUs also carries some potential for adverse 
environmental impacts; NGCC units generally require less cooling water 
than steam EGUs.\420\ With respect to energy impacts, building block 2 
represents replacement of electrical energy from one generator with 
electrical energy from another generator that consumes less fuel, so 
the overall energy impact should be a reduction in fuel consumption by 
the overall source category as well as by individual affected coal-
fired steam EGUs. Although for purposes of this rule we consider the 
incentive for technological innovation only in the alternative, we note 
that building block 2 promotes greater use of the NGCC technology 
installed in the existing fleet of NGCC units, which is newer and more 
advanced than the technology installed in much of the older existing 
fleet of steam EGUs. For all these reasons, the

[[Page 64747]]

measures in building block 2 qualify as a component of the ``best 
system of emission reduction . . . adequately demonstrated.''
---------------------------------------------------------------------------

    \420\ For example, according to a DOE/NETL study, the relative 
amount of water consumption for a new pulverized coal plant is 2.5 
times the consumption for a new NGCC unit of similar size. ``Cost 
and Performance Baseline for Fossil Energy Plants: Volume 1: 
Bituminous Coal and Natural Gas to Electricity,'' Rev 2a, September 
2013, National Energy Technology Laboratory Report DOE/NETL-2010/
1397. EPA believes the difference would on average be even more 
pronounced when comparing existing coal and NGCC units.
---------------------------------------------------------------------------

    It should be observed that, by definition of the elements of this 
building block, the shifts in generation taking place under building 
block 2 occur entirely among existing EGUs subject to this 
rulemaking.\421\ Through application of this building block considered 
in isolation, some affected EGUs--mostly coal-fired steam EGUs--would 
reduce their generation and CO2 emissions, while other 
affected EGUs--NGCC units--would increase their generation and 
CO2 emissions. However, because for each MWh of generation, 
NGCC units produce fewer CO2 emissions than coal-fired steam 
EGUs, the total quantity of CO2 emissions from all affected 
EGUs in aggregate would decrease without a reduction in total 
electricity generation. In the context of the integrated electricity 
system, where the operation of affected EGUs of multiple types is 
routinely coordinated to provide a highly substitutable service, and in 
the context of CO2 emissions, where location is not a 
consideration (in contrast with other pollutants), a measure that takes 
advantage of that integration to reduce CO2 emissions from 
the overall set of affected EGUs is readily understood as a means to 
implement a ``system of emission reduction'' for CO2 
emissions at affected EGUs even if the measure would increase 
CO2 emissions from a subset of those affected EGUs. Indeed, 
some industry participants are already moving in this direction for 
this purpose (while other participants are moving in the same direction 
for other purposes). Standards of performance that incorporate 
emissions trading can facilitate the implementation of such a 
``system'' and such approaches have already been used in the 
electricity industry to address CO2 as well as other 
pollutants, as discussed above.
---------------------------------------------------------------------------

    \421\ For purposes of this rulemaking, ``existing'' EGUs include 
units under construction as of January 8, 2014, the date of 
publication in the Federal Register of the proposed carbon pollution 
standards for new fossil fuel-fired EGUs.
---------------------------------------------------------------------------

    c. Building block 3. Building block 3--substituting generation from 
expanded RE generating capacity for generation from affected EGUs--is a 
component of the BSER because the expansion and use of renewable 
generating capacity to reduce emissions from affected EGUs is 
technically feasible, is of reasonable cost, and performs well with 
respect to other factors relevant to a determination of the ``best 
system of emission reduction . . . adequately demonstrated.'' Building 
block 3 is a ``system of emission reduction'' for all affected EGUs 
because incremental RE generation will result in reduced generation and 
emissions from affected EGUs, and owners or operators of affected EGUs 
can apply or implement building block 3 through a number of actions. 
For example, they can invest in incremental RE generation either 
directly or through the purchase of ERCs. An affected EGU investing in 
incremental RE generation may choose to reduce its own generation by a 
corresponding amount or may choose to allow the reduction in generation 
to occur at other affected EGUs through the coordinated planning and 
operation of the interconnected electricity system. An affected EGU can 
also invest in RE generation by means of engaging in emissions trading 
where the EGU is operating under a standard of performance that 
incorporates trading.
    The EPA's analysis and conclusions regarding the technical 
feasibility, costs, and magnitude of the measures in building block 3 
are discussed in Section V.E. below. Additional analysis and 
conclusions with respect to cost reasonableness are discussed in 
section V.A.4.d. below. We consider construction and operation of 
expanded RE generating capacity to be proven, well-established 
practices within the industry consistent with recent industry trends. 
States are already pursuing policies that encourage production of 
greater amounts of RE, such as the establishment of targets for 
procurement of renewable generating capacity. Moreover, as discussed 
earlier, markets are likely to develop for ERCs that would facilitate 
investment in increased RE generation as a means of helping sources 
comply with their standards of performance; indeed, markets for RECs, 
which similarly facilitate investment in RE for other purposes, are 
already well-established. As noted in Section V.A.5. below, an 
allowance system or tradable emission rate system would provide 
incentives for affected EGUs to reduce their emissions as much as 
possible where such reductions could be achieved economically (taking 
into account the value of the emission credits or allowances), 
including by substituting generation from new RE generating capacity 
for their own generation, or could provide a mechanism, as stated 
above, for such sources to invest in or acquire such generation.
    Building block 3 is adequately demonstrated as a ``system of 
emission reduction'' for all affected EGUs. As discussed in section II, 
RE generation has been relied on since the 1970s to provide energy 
security by replacing some fossil fuel-fired generation. Both Congress 
and the EPA have previously established frameworks under which RE 
generation could be used as a means of achieving emission reductions 
from the utility power sector, as discussed in section V.B. Investment 
in RE generation has grown rapidly, such that in recent years the 
amount of new RE generating capacity brought into service has been 
comparable to the amount of new fossil fuel-fired capacity. Rapid 
growth in RE generation is projected to continue as costs of RE 
generation fall relative to the costs of other generation technologies. 
These trends are further discussed in section V.E. Interpretation of a 
``system of emission reduction'' as including RE generation for 
purposes of this rule is thus supported by legislative history, 
regulatory precedent, and industry practice.
    Also supporting the determination that building block 3 is 
adequately demonstrated as a ``system of emission reduction'' is the 
fact that owners of affected EGUs have the ability to invest in RE 
generation as a way of reducing emissions. As with building block 2, 
this can be accomplished in several ways. For example, the owner of an 
affected EGU could invest in new RE generating capacity and operate 
that capacity in order to obtain ERCs. Alternatively, the affected EGU 
could purchase ERCs created based on the operation of an unaffiliated 
RE generating facility, effectively investing in the actions at another 
site that allow CO2 emission reductions to occur. These 
mechanisms are discussed further in section V.A.5. As with building 
block 2, in this rule the EPA is establishing minimum criteria for the 
creation of valid ERCs by new RE generators and for the use of such 
ERCs by affected EGUs for demonstrating compliance with emission rate-
based standards of performance established under state plans. The 
existence of minimum criteria will ensure that crediting mechanisms are 
feasible and will facilitate the development of organized markets to 
simplify the process of buying and selling credits. The minimum 
criteria are discussed in section VIII of the preamble.
    As with building block 2, an affected EGU investing in building 
block 3 to reduce emissions may, but need not, also choose to reduce 
its own generation as part of its approach for meeting the standard of 
performance assigned to it by its state. Through the coordinated 
operation of the integrated electricity system, subject to the 
collective requirements that will be imposed on affected EGUs in order 
to meet the

[[Page 64748]]

emissions standards representing the BSER, an increase in RE generation 
will be offset elsewhere in the interconnection by a decrease in other 
generation. Because of the need to meet the collective requirements, 
the decrease in generation resulting from that coordinated operation is 
most likely to be generation from an affected EGU. Measures taken by 
affected EGUs that result in emission reductions from other sources in 
the source category may appropriately be deemed methods to implement 
the ``system of emission reduction.''
    The renewable capacity measures in building block 3 generally 
perform well against other BSER criteria. Generation from wind turbines 
and solar voltaic installations, two common renewable technologies, 
does not produce solid waste or require cooling water, a better 
environmental outcome than if that amount of generation had instead 
been produced at a typical range of fossil fuel-fired EGUs. With 
respect to energy impacts, fossil fuel consumption will decrease both 
for the source category as a whole and for individual affected EGUs. 
Although the variable nature of generation from renewable resources 
such as wind and solar units requires special consideration from grid 
operators to address possible changes in operating reserve 
requirements, renewable generation has grown quickly in recent years, 
as discussed above, and grid planners and operators have proven capable 
of addressing any consequent changes in requirements through ordinary 
processes. The EPA believes that planners and operators will be 
similarly capable of addressing any changes in requirements due to 
future growth in renewable generation through ordinary processes, but 
notes that in addition, the reliability safety valve in this rule, 
discussed in section VIII.G.2, will ensure the absence of adverse 
energy impacts. With respect to technological innovation, which we 
consider for the BSER only in the alternative, incentives for expansion 
of renewable capacity encourage technological innovation in improved 
renewable technologies as well as more extensive deployment of current 
advanced technologies. For all these reasons, the measures in building 
block 3 qualify as a component of the ``best system of emission 
reduction . . . adequately demonstrated.''
    d. Combination of all three building blocks. The final BSER 
includes a combination of all three building blocks. For the reasons 
described below, and similar to each of the building blocks, the 
combination must be considered a ``system of emission reduction.'' 
Moreover, as also discussed below, the combination qualifies as the 
``best'' system that is ``adequately demonstrated.'' The combination is 
technically feasible; it is capable of achieving meaningful reductions 
in CO2 emissions from affected EGUs at a reasonable cost; it 
also performs well against the other BSER factors; and its components 
are well-established. The combination of the three building blocks will 
achieve greater CO2 emission reductions at reasonable costs 
than possible combinations with fewer building blocks and will also 
perform better against other BSER factors. We therefore find the 
combination of all three building blocks to be the ``best system of 
emission reduction . . . adequately demonstrated'' for reducing 
CO2 emissions at affected EGUs.
    As already discussed, each of the individual building blocks 
generally performs well with respect to the BSER factors identified by 
the statute and the D.C. Circuit. (The exception, which we have pointed 
out above, is that building block 1, if implemented in isolation, would 
achieve an insufficient magnitude of emission reductions to be 
considered the BSER.) The EPA expects that combinations of the building 
blocks would perform better than the individual building blocks. 
Beginning with the most obvious and important advantage, combinations 
of the building blocks will achieve greater emission reductions than 
the individual building blocks would in isolation, assuming that the 
building blocks are applied with the same stringency. Because fossil 
fuel-fired EGUs generally have higher variable costs than other EGUs, 
it will generally be fossil fuel-fired generation that is replaced when 
low-variable cost RE generation is increased. At the levels of 
stringency determined to be reasonable in this rule, opportunities to 
deploy building block 2 to replace higher-emitting generation and to 
deploy building block 3 to replace any emitting generation are not 
exhausted. Thus, as the system of emission reduction is expanded to 
include each of these building blocks, the emission reductions that 
will be achieved increase.
    Because the stringency and timing of emission reductions achievable 
through use of each individual building block have been set based on 
what is achievable at reasonable cost rather than the maximum 
achievable amount, the stringency of the combination of building blocks 
is also reasonable, and the combination provides headroom and 
additional flexibility for states in setting standards of performance 
and for sources in complying with those standards to choose among 
multiple means of reducing emissions.
    With respect to the quantity of emission reductions expected to be 
achieved from building block 1 in particular, the BSER encompassing all 
three building blocks is a substantial improvement over building block 
1 in isolation. As noted earlier, the EPA is concerned that 
implementation of building block 1 in isolation not only would achieve 
insufficient emission reductions assuming generation levels from 
affected steam EGUs were held constant, but also has the potential to 
result in a ``rebound effect.'' The nature of the potential rebound 
effect is that by causing affected steam EGUs to improve their heat 
rates and thereby lower their variable operating costs, building block 
1 if implemented in isolation would make those EGUs more competitive 
relative to other, lower-emitting fossil fuel-fired EGUs, possibly 
resulting in increased generation and higher emissions from the 
affected steam EGUs in spite of their lower emission rates. Combining 
building block 1 with the other building blocks addresses this concern 
by ensuring that owner/operators of affected steam EGUs as a group 
would have appropriate incentives not only to improve the steam EGUs' 
efficiency but also to reduce generation from those EGUs consistent 
with replacement of generation by low- or zero-emitting EGUs. While 
combining building block 1 with either building block 2 or 3 should 
address this concern, the combination of all three building blocks 
addresses it more effectively by strengthening the incentives to reduce 
generation from affected steam EGUs.
    The combination of all three building blocks is also of reasonable 
cost, for a number of independent reasons described below. The emission 
reductions associated with the BSER determined in this rule are 
significant, necessary, and achievable. As discussed in section V.A.1. 
above, the Administrator must take cost into account when determining 
that the measures constituting the BSER are adequately demonstrated, 
and the Administrator has done so here. Below, we summarize information 
on the cost of the building block measures and discuss the several 
independent reasons for the Administrator's determination that the 
costs of the building block 1, 2, and 3 measures, alone or in 
combination, are reasonable. In considering whether these costs are 
reasonable, the EPA considered the costs in light of both the observed 
and projected effects of GHGs in the atmosphere, their effect on 
climate, and

[[Page 64749]]

the public health and welfare risks and impacts associated with such 
climate change, as described in Section II.A. The EPA focused on public 
health and welfare impacts within the U.S., but the impacts in other 
world regions strengthen the case for action because impacts in other 
world regions can in turn adversely affect the U.S. or its citizens. In 
looking at whether costs were reasonable, the EPA also considered that 
EGUs are by far the largest emitters of GHGs among stationary sources 
in the U.S., as more fully set forth in section II.B.
    As described in sections V.C. through V.E. and the GHG Mitigation 
Measures TSD, the EPA has determined that the cost of each of the three 
building blocks is reasonable. In summary, these cost estimates are $23 
per ton of CO2 reductions for building block 1, $24 per ton 
for building block 2, and $37 per ton for building block 3. The EPA 
estimates that, together, the three building blocks are able to achieve 
CO2 reductions at an average cost of $30 per ton, which the 
EPA likewise has determined is reasonable. The $30 per ton estimate is 
an average of the estimates for each building block, weighted by the 
total estimated cumulative CO2 reductions for each of these 
building blocks over the 2022-2030 period. While it is possible to 
weight each building block by other amounts, the EPA believes that 
weighting by cumulative CO2 reductions best reflects the 
average cost of total reduction potential across the three building 
blocks. The EPA considers each of these cost levels reasonable for 
purposes of the BSER established for this rule.
    The EPA views the weighted average cost estimate as a 
conservatively high estimate of the cost of deploying all three 
building blocks simultaneously. The simultaneous application of all 
three building blocks produces interactive dynamics, some of which 
could increase the cost and some of which could decrease the cost 
represented in the individual building blocks. For example, one dynamic 
that would tend to raise costs (and whose omission would therefore make 
the weighted average understate costs) is that the emission reduction 
measures associated with building blocks 2 and 3 both prioritize the 
replacement of higher-cost generation (from affected steam EGUs in the 
case of building block 2 and from all affected EGUs in the case of 
building block 3). The EPA recognizes that the increased magnitude of 
generation replacement when building blocks 2 and 3 are implemented 
together necessitates that some of the generation replacement will 
occur at more efficient affected EGUs, at a relatively higher cost; 
however, this is a consequence of the greater emission reductions that 
can be achieved by combining building blocks, not an indication that 
any individual building block has become more expensive because of the 
combined deployment.
    Also, the EPA recognizes that when building block 1 is combined 
with the other building blocks, the combination has the potential to 
raise the cost of the portion of the overall emission reductions 
achievable through heat rate improvements relative to the cost of those 
same reductions if building block 1 were implemented in isolation 
(assuming for purposes of this discussion that the rebound effect is 
not an issue and that the affected steam EGUs would in fact reduce 
their emissions if building block 1 were implemented in 
isolation).\422\ However, we believe that the cost of emission 
reductions achieved through heat rate improvements in the context of a 
three-building block BSER will remain reasonable for two reasons. 
First, as discussed in section V.C. below, even when conservatively 
high investment costs are assumed, the cost of CO2 emission 
reductions achievable through heat rate improvements is low enough that 
the cost per ton of CO2 emission reductions will remain 
reasonable even if that cost is substantially increased. Second, 
although under a BSER encompassing all three building blocks the volume 
of coal-fired generation will decrease, that decrease is unlikely to be 
spread uniformly among all coal-fired EGUs. It is more likely that some 
coal-fired EGUs will decrease their generation slightly or not at all 
while others will decrease their generation by larger percentages or 
cease operations altogether. We would expect EGU owners to take these 
changes in EGU operating patterns into account when considering where 
to invest in heat rate improvements, with the result that there will be 
a tendency for such investments to be concentrated in EGUs whose 
generation output is expected to decrease the least. This enlightened 
bias in spending on heat rate improvements--that is, focusing 
investments on EGUs where such improvements will have the largest 
impacts and produce the highest returns, given consideration of 
projected changes in dispatch patterns--will tend to mitigate any 
deterioration in the cost of CO2 emission reductions 
achievable through heat rate improvements.
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    \422\ If an EGU produces less generation output, then an 
improvement in that EGU's heat rate and rate of CO2 
emissions per unit of generation produces a smaller reduction in 
CO2 emissions. If the investment required to achieve the 
improvement in heat rate and emission rate is the same regardless of 
the EGU's generation output, then the cost per unit of 
CO2 emission reduction will be higher when the EGU's 
generation output is lower. Commenters have also stated that 
operating at lower capacity factors may cause units to experience 
deterioration in heat rates.
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    In contrast with those prior examples, combining the building 
blocks also produces interactive dynamics that significantly reduce the 
cost for CO2 reductions represented in the individual 
building blocks (and whose omission would therefore make the weighted 
average overstate costs). Foremost among these dynamics is the 
stabilization of wholesale power prices. When assessed individually, 
building blocks 2 and 3 have opposite impacts on wholesale power 
prices, although in each case, the direction of the wholesale power 
price impact corresponds to an increasing cost of that building block 
in isolation. For example, building block 2 promotes more utilization 
of existing NGCC capacity, which (assessed on its own) would increase 
natural gas consumption and therefore price, in turn raising wholesale 
power prices (which are often determined by gas-fired generators as the 
power supplier on the margin); this dynamic puts upward pressure on the 
cost of achieving CO2 reductions through shifting generation 
from steam EGUs to NGCC units.\423\ Meanwhile, building block 3 
increases RE deployment; because RE generators have very little 
variable cost, an increase in RE generation replaces other supply with 
higher variable cost, which would yield lower wholesale power prices. 
Lower wholesale power prices would make further RE deployment less 
competitive against generation from existing emitting sources; while 
this dynamic would generally reduce electricity prices to consumers, it 
also puts upward pressure on the cost of achieving CO2 
reductions through increased RE deployment.\424\ Applying building 
blocks 2 and 3 together produces significantly more CO2 
reductions at a relatively lower cost because the countervailing nature 
of these wholesale power price dynamics mitigates the primary cost 
drivers for each building block.\425\
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    \423\ The EPA's cost-effectiveness estimate of $24 per ton for 
building block 2 reflects these market dynamics.
    \424\ The EPA's cost-effectiveness estimate of $37 per ton for 
building block 3 reflects these market dynamics.
    \425\ Notwithstanding the interactive dynamics that improve the 
cost effectiveness of emission reductions when building blocks 2 and 
3 are implemented together, we also consider each of these building 
blocks to be independently of reasonable cost, so that either 
building block 2 or 3 alone, or combinations of the building blocks 
that include either but not both of these two building blocks, could 
be the BSER if a court were to strike down the other building block, 
as discussed in section V.A.7. below. (We also note in section 
V.A.7. that a combination of building blocks 2 and 3 without 
building block 1 could be the BSER if a court were to strike down 
building block 1.)

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[[Page 64750]]

    The EPA believes the dynamics tending to cause the weighted average 
above to overstate costs of the combination of building blocks are 
greater than the dynamics tending to cause costs to be understated, and 
that the weighted average costs are therefore conservatively high. 
Analysis performed by the EPA at an earlier stage of the rulemaking 
supports this conclusion. At proposal, the EPA evaluated the cost of 
increasing NGCC utilization (building block 2) and deploying 
incremental RE generation (building block 3) independently, as well as 
the cost of simultaneously increasing NGCC utilization and incremental 
RE generation. The average cost (in dollars per ton of CO2 
reduced) was less for the combined building block scenario, showing 
that the net outcome of the interactivity effects described above is a 
reduction in cost per ton when compared to cost estimates that do not 
incorporate this interactivity.\426\
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    \426\ Specifically, at proposal the EPA quantified the average 
cost, in dollar per ton of CO2 reduced, of building 
blocks 1, 2, and 3 ($22.5 per ton) to be less than the cost of 
either building block 2 ($28.9 per ton) or building block 3 ($23.4 
per ton) alone.
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    A final reason why the EPA considers the weighted-average cost 
above conservatively high is that simply combining the building blocks 
at their full individual stringencies overstates the stringency of the 
BSER. As discussed in section V.A.3.f and section VI, the BSER reflects 
the combined degree of emission limitation achieved through application 
of the building blocks in the least stringent region. By definition, in 
the other two regions, the BSER is less stringent than the simple 
combination of the three building blocks whose stringency is 
represented in the weighted-average cost above.
    The cost estimates for each of the three building blocks cited 
above--$23, $24, and $37 per ton of CO2 reductions from 
building blocks 1, 2, and 3, respectively--are each conservatively high 
for the reasons discussed in section V.C., V.D., and V.E. below. 
Likewise, the $30 per ton weighted-average cost of all three building 
blocks is a conservatively high estimate of the cost of the combination 
of the three individual building block costs, as described above. While 
conservatively high, and especially so in the case of the $30 per ton 
weighted-average cost, these estimates fall well within the range of 
costs that are reasonable for the BSER for this rule.
    In assessing cost reasonableness for the BSER determination for 
this rule, the EPA has compared the estimated costs discussed above to 
two types of cost benchmark. The first type of benchmark comprises 
costs that affected EGUs incur to reduce other air pollutants, such as 
SO2 and NOX. In order to address various 
environmental requirements, many coal-fired EGUs have been required to 
decide between either shutting down or installing and operating flue 
gas desulfurization (FGD) equipment--that is, wet or dry scrubbers--to 
reduce their SO2 emissions. The fact that many of these EGUs 
have chosen scrubbers in preference to shutting down is evidence that 
scrubber costs are reasonable, and we believe that the cost of these 
controls can reasonably serve as a cost benchmark for comparison to the 
costs of this rule. We estimate that for a 300-700 MW coal-fired steam 
EGU with a heat rate of 10,000 Btu per kWh and operating at a 70 
percent utilization rate, the annualized costs of installing and 
operating a wet scrubber are approximately $14 to $18 per MWh and the 
annualized costs of installing and operating a dry scrubber are 
approximately $13 to $16 per MWh.\427\
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    \427\ For details of these computations, see the memorandum 
``Comparison of building block costs to FGD costs'' available in the 
docket.
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    In comparison, we estimate that for a coal-fired steam EGU with a 
heat rate of 10,000 Btu per kWh, assuming the conservatively high cost 
of $30 per ton of CO2 removed through the combination of all 
three building blocks, the cost of reducing CO2 emissions by 
the amount required to achieve the uniform CO2 emission 
performance rate for steam EGUs of 1,305 lbs. CO2 per MWh 
would be equivalent to approximately $11 per MWh. The comparable costs 
for achieving the required emission performance rate for steam EGUs 
through use of the individual building blocks range from $8 to $14 per 
MWh. For an NGCC unit with a heat rate of 7,800 Btu per kWh, assuming a 
conservatively high cost of $37 per ton of CO2 removed 
through the use of building block 3,\428\ the cost of reducing 
CO2 emissions by the amount required to achieve the uniform 
CO2 emission performance rate for NGCC units of 771 lbs. 
CO2 per MWh would be equivalent to approximately $3 per 
MWh.\429\ These estimated CO2 reduction costs of $3 to $14 
per MWh to achieve the CO2 emission performance rates are 
either less than the ranges of $14 to $18 and $13 to $16 per MWh to 
install and operate a wet or dry scrubber, or in the case of 
CO2 emission reductions at a steam unit achieved through 
building block 3, near the low end of the ranges of scrubber costs. 
This comparison demonstrates that the costs associated with the BSER in 
this rule are reasonable compared to the costs that affected EGUs 
commonly face to comply with other environmental requirements.
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    \428\ The comparison for an NGCC unit considers only building 
block 3 because building blocks 1 and 2 do not apply to NGCC units.
    \429\ For details of these computations, see the memorandum 
``Comparison of building block costs to FGD costs'' available in the 
docket.
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    The second type of benchmark comprises CO2 prices that 
owners of affected EGUs use for planning purposes in their IRPs. 
Utilities subject to requirements to prepare IRPs commonly include 
assumptions regarding future environmental regulations that may become 
effective during the time horizon covered by the IRP, and assumptions 
regarding CO2 regulations are often represented in the form 
of assumed prices per ton of CO2 emitted or reduced. A 
survey of the CO2 price assumptions from 46 recent IRPs 
shows a range of CO2 prices in the IRPs' reference cases of 
$0 to $30 per ton, and a range of CO2 prices in the IRPs' 
high cases from $0 to $110 per ton.\430\ In comparison, the 
conservatively high, weighted-average cost of $30 per ton removed 
described above is at the high end of the range of reference case 
assumptions but at the low end of the range of the high case 
assumptions. The costs of the individual building blocks are likewise 
well within the range of the high case assumptions, and either at or 
slightly above the high end of the reference case assumptions. This 
comparison demonstrates that the costs associated with the BSER in this 
rule are reasonable compared to the expectations of the industry for 
the potential costs of CO2 regulation.
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    \430\ See Synapse Energy Economics Inc., 2015 Carbon Dioxide 
Price Forecast (March 3, 2015) at 25-28, available at http://www.synapse-energy.com/sites/default/files/2015%20Carbon%20Dioxide%20Price%20Report.pdf.
---------------------------------------------------------------------------

    In addition to comparison to these benchmarks, there is a third 
independent way in which EPA has considered cost. In light of the 
severity of the observed and projected climate change effects on the 
U.S., U.S. interests, and U.S. citizens, combined with EGUs' large 
contribution to U.S. GHG emissions, the costs of the BSER measures are 
reasonable when compared to other potential control measures for this 
sector available under

[[Page 64751]]

section 111. Given EGUs' large contribution to U.S. GHG emissions, any 
attempt to address the serious public health and environmental threat 
of climate change must necessarily include significant emission 
reductions from this sector. The agency would therefore consider even 
relatively high costs--which these are not--to be reasonable. Imposing 
only the lower cost reduction measures in building block 1 would not 
achieve sufficient reductions given the scope of the problem and EGUs' 
contribution to it. While the EPA also considered measures such as CCS 
retrofits for all fossil-fired EGUs or co-firing at all steam units, 
the EPA determined that these costs were too high when considered on a 
sector-wide basis. Furthermore, the EPA has not identified other 
measures available under section 111 that are less costly and would 
achieve emission reductions that are commensurate with the scope of the 
problem and EGUs' contribution to it. Thus, the EPA determined that the 
costs of the measures in building blocks 1, 2 and 3, individually or in 
combination, are reasonable because they achieve an appropriate balance 
between cost and amount of reductions given the other potential control 
measures under section 111.
    As required under Executive Order 12866, the EPA conducts benefit-
cost analyses for major Clean Air Act rules.\431\ While benefit-cost 
analysis can help to inform policy decisions, as permissible and 
appropriate under governing statutory provisions, the EPA does not use 
a benefit-cost test (i.e., a determination of whether monetized 
benefits exceed costs) as the sole or primary decision tool when 
required to consider costs or to determine whether to issue regulations 
under the Clean Air Act, and is not using such a test here.\432\ 
Nonetheless, the EPA observes that the costs of the building block 1, 2 
and 3 measures, both individually and combined as discussed in this 
section above, are less than the central estimates of the social cost 
of carbon. Developed by an interagency workgroup, the social cost of 
carbon (SC-CO2) is an estimate of the monetary value of 
impacts associated with marginal changes in CO2 emissions in 
a given year.\433\ It is typically used to assess the avoided damages 
as a result of regulatory actions (i.e., benefits of rulemakings that 
lead to an incremental reduction in cumulative global CO2 
emissions).\434\ The central values for the SC-CO2 range 
from $40 per short ton in 2020 to $48 per short ton in 2030.\435\ The 
weighted-average cost estimate of $30 per ton is well below this range.
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    \431\ The EPA's regulatory impact analysis for this rule, which 
appropriately includes a representation of the flexibility available 
under the rule to comply using a combination of BSER and non-BSER 
measures (such as demand-side energy efficiency) is discussed in 
section XI of the preamble.
    \432\ See memo entitled ``Consideration of Costs and Benefits 
Under the Clean Air Act'' available in the docket.
    \433\ Estimates are presented in the Technical Support Document: 
Technical Update of the Social Cost of Carbon for Regulatory Impact 
Analysis Under Executive Order 12866 (May 2013, Revised July 2015), 
Interagency Working Group on Social Cost of Carbon, with 
participation by Council of Economic Advisers, Council on 
Environmental Quality, Department of Agriculture, Department of 
Commerce, Department of Energy, Department of Transportation, 
Environmental Protection Agency, National Economic Council, Office 
of Energy and Climate Change, Office of Management and Budget, 
Office of Science and Technology Policy, and Department of Treasury 
(May 2013, Revised July 2015). Available at: https://www.whitehouse.gov/sites/default/files/omb/inforeg/scc-tsd-final-july-2015.pdf> Accessed 7/11/2015.
    \434\ The SC-CO2 estimates do not include all 
important damages because of current modeling and data limitations. 
The 2014 IPCC report observed that SC-CO2 estimates omit 
various impacts that would likely increase damages. See IPCC, 2014: 
Climate Change 2014: Impacts, Adaptation, and Vulnerability. 
Contribution of Working Group II to the Fifth Assessment Report of 
the Intergovernmental Panel on Climate Change. Cambridge University 
Press, Cambridge. https://www.ipcc.ch/report/ar5/wg2/.
    \435\ The 2010 and 2013 TSDs present SC-CO2 in 2007$ 
per metric ton. The unrounded estimates from the current TSD were 
adjusted to (1) 2011$ using GDP Implicit Price Deflator (1.061374), 
http://www.bea.gov/iTable/index_nipa.cfm and (2) short tons using 
the conversion factor of 0.90718474 metric tons in a short ton. 
These estimates were rounded to two significant digits.
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    Finally, the EPA notes that the combination of all three building 
blocks would perform consistently with the individual building blocks 
with respect to non-air energy and environmental impacts. There is no 
reason to expect an adverse non-air environmental or energy impact from 
deployment of the combination of the three building blocks, whether 
considered on a source-by-source basis, on a sector-wide or national 
basis, or both. In fact, the combination of the building blocks, like 
the building blocks individually, as discussed above, would be expected 
to produce non-air environmental co-benefits in the form of reduced 
water usage and solid waste production (and, in addition to these non-
air environmental co-benefits, would also be expected to reduce 
emissions of non-CO2 air pollutants such as SO2, 
NOX, and mercury). Likewise, with respect to technological 
innovation, which we consider only in the alternative, the building 
blocks in combination would have the same positive effects that they 
would have if implemented independently.
    e. Other combinations of the building blocks. The EPA has 
considered whether other combinations of the building blocks, such as a 
combination of building blocks 1 and 2 or a combination of building 
blocks 1 and 3, could be the BSER. We believe that any such combination 
is technically feasible and would be a ``system of emission reduction'' 
capable of achieving meaningful reductions in CO2 emissions 
from affected EGUs at a reasonable cost. As with the combination of 
three building blocks discussed above, any combination of building 
blocks would achieve greater emission reductions than the individual 
building blocks encompassed in that combination would achieve if 
implemented in isolation. Further, the cost of any combination would be 
driven principally by the combined stringency and would remain 
reasonable in aggregate, such that the conclusions on cost 
reasonableness discussed in section V.A.4.d. would continue to apply. 
We have already noted our determination that building block 1 in 
isolation is not the BSER because it would not produce a sufficient 
quantity of emission reductions. A combination of building block 1 with 
one of the other building blocks would produce greater emission 
reductions and would not be subject to this concern. Any combination of 
building blocks including building block 1 and at least one other 
building block would also address the concern about potential ``rebound 
effect,'' discussed above, that could occur if building block 1 were 
implemented in isolation. Finally, there is no reason to expect any 
combination of the building blocks to have adverse non-air energy or 
environmental impacts, and the implications for technological 
innovation, which we consider only in the alternative, would likewise 
be positive for any combination of the building blocks because those 
implications are positive for the individual building blocks and there 
is no reason to expect negative interaction from a combination of 
building blocks.
    For these reasons, any combination of the building blocks (but not 
a BSER comprising building block 1 in isolation) could be the BSER if 
it were not for the fact that a BSER comprising all three of the 
building blocks will achieve greater emission reductions at a 
reasonable cost and is therefore ``better.'' As discussed below in 
section V.A.7., we intend for the individual building blocks to be 
severable, such that if a court were to deem building block 2 or 3 
defective, but not both, the BSER would comprise the remaining building 
blocks.
    f. Achievability of emission limits. As noted, based on the BSER, 
the EPA has

[[Page 64752]]

established a source subcategory-specific emission performance rate for 
fossil steam units and one for NGCC units. As discussed in section 
V.A.1.c., for new sources, standards of performance must be 
``achievable'' under CAA section 111(a)(1), and the D.C. Circuit has 
identified criteria for achievability.\436\ In this rule, the EPA is 
taking the approach that while the states are not required to adopt 
those source subcategory-specific emission performance rates as the 
standards of performance for their affected EGUs, those rates must be 
achievable by the steam generator and NGCC subcategories, respectively. 
In addition, the EPA is assuming that the achievability criteria in the 
case law for new sources apply to existing sources under section 
111(d). For the reasons discussed next, for this rule, the source 
subcategory-specific emission performance rates are achievable in 
accordance with those criteria in the case law.
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    \436\ See Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433-34 
(D.C. Cir. 1973), cert. denied, 416 U.S. 969 (1974); Nat'l Lime 
Ass'n v. EPA, 627 F.2d 416, 433, n.46 (D.C. Cir. 1980); Sierra Club 
v. Costle, 657 F.2d 298, 377 (D.C. Cir. 1981) (citing Nat'l Lime 
Ass'n v. EPA, 627 F.2d 416 (D.C. Cir. 1980).
---------------------------------------------------------------------------

    As noted, the building blocks include several features that assure 
that affected EGUs may implement them. The building blocks may be 
implemented through a range of methods, including through the purchase 
of ERCs and emission trading. In addition, the building blocks 
incorporate ``headroom.'' Moreover, the source subcategory-specific 
emission performance rates apply on an annual or longer basis, so that 
short-term issues need not jeopardize compliance. In addition, we 
quantify the emission performance rates based on the degree of emission 
limitation achievable by affected EGUs in the region where application 
of the combined building blocks results in the least stringent emission 
rate. Because the means to implement the building blocks are widely 
available and because of the just-noted flexibilities and approaches to 
the emission performance rates, all types of affected steam generating 
units, operating throughout the lower-48 states and under all types of 
regulatory regimes, are able to implement building blocks 1, 2 and 3 
and thereby achieve the emission performance rate for fossil steam 
units, and all types of NGCC units operating in all states under all 
types of regulatory requirements are able to implement building block 3 
and thereby achieve the emission performance rate for NGCC units.\437\
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    \437\ We discuss the ability of affected EGUs to implement the 
building blocks in more detail in sections V.C., V.D., and V.E. and 
the accompanying support documents.
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    Commenters have raised questions about whether particular 
circumstances could arise, such as the sudden loss of certain 
generation assets, that would cause the implementation of the building 
blocks to cause reliability problems, and have cautioned that these 
circumstances could preclude implementation of the building blocks and 
thus achievement of the emission performance rates. Commenters have 
also raised concerns about whether affected EGUs with limited remaining 
useful lives can implement the building blocks and achieve the emission 
performance rates. We address those concerns in section VIII, where we 
authorize state plans to include a reliability mechanism and discuss 
affected EGUs with limited remaining useful lives. Accordingly, we 
conclude that the source subcategory-specific emission performance 
standards are achievable in accordance with the case law.
5. Actions Under the BSER That Sources Can Take To Achieve Standards of 
Performance
    Based on the determination of the BSER described above, the EPA has 
identified a performance rate of 1305 lbs. per net MWh for affected 
steam EGUs and a performance rate of 771 lbs. per net MWh for affected 
stationary combustion turbines. The computations of these performance 
rates and the determinations of state goals reflecting these rates are 
described in sections VI and VII of the preamble, respectively.
    Under section 111(d), states determine the standards of performance 
for individual sources. The EPA is authorizing states to express the 
standards of performance applicable to affected EGUs as either emission 
rate-based limits or mass-based limits. As described above, the sets of 
actions that sources can take to comply with these standards implement 
or apply the BSER and, in that sense, may be understood as part of the 
BSER.
    A source to which a state applies an emission rate-based limit can 
achieve the limit through a combination of the following set of 
measures (to the extent allowed by the state plan), all of which are 
components of the BSER, again, in the sense that they implement or 
apply it:
     Reducing its heat rate (building block 1).
     Directly investing in, or purchasing ERCs created as a 
result of, incremental generation from existing NGCC units (building 
block 2).
     Directly investing in, or purchasing ERCs created as a 
result of, generation from new or uprated RE generators (building 
block 3).
     Reducing its utilization, coupled with direct 
investment in or purchase of ERCs representing building blocks 2 and 
3 as indicated above.
     Investing in surplus emission rate reductions at other 
affected EGUs through the purchase or other acquisition of rate-
based emission credits.

    A source to which a state applies a mass-based limit can achieve 
the limit through a combination of the following set of measures (to 
the extent allowed by the state plan), all of which are likewise 
components of the BSER:

     Reducing its heat rate (building block 1).
     Reducing its utilization and allowing its generation to 
be replaced or avoided through the routine operation of industry 
reliability planning mechanisms and market incentives.
     Investing in surplus emission reductions at other 
affected EGUs through the purchase or other acquisition of mass-
based emission allowances.

    The EPA has determined appropriate CO2 emission 
performance rates for each of the two source subcategories as a whole 
achievable through application of the building blocks. The wide ranges 
of measures included in the BSER and available to individual sources as 
indicated above provide assurance that the source category as a whole 
can achieve standards of performance consistent with those emissions 
standards using components of the BSER, whether states choose to 
establish emission rate-based limits or mass-based limits. The wide 
ranges of measures included in the BSER also provide assurance that 
each individual affected EGU could achieve the standard of performance 
its state establishes for it using components of the BSER. Of course, 
sources may also employ measures not included in the BSER, to the 
extent allowed under the applicable state plan.
    In the remainder of this subsection, we discuss further how 
affected EGUs can use each of the measures listed above to achieve 
emission rate-based forms of performance standards and mass-based forms 
of performance standards, indicating that all types of owner/operators 
of affected EGUs--i.e., vertically integrated utilities and merchant 
generators; investor-owned, government-owned, and customer-owned 
(cooperative) utilities; and owner/operators of large, small, and 
single-unit fleets of generating units--have the ability to implement 
each of the building blocks in some way. In the following subsection we 
discuss the use

[[Page 64753]]

of measures not in the BSER that can help sources achieve the standards 
of performance.
    a. Use of BSER measures to achieve an emission rate-based standard. 
Under an emission-rate based form of performance standards, compliance 
is nominally determined through a comparison of the affected EGU's 
emission rate to the emission rate standard. The emissions-reducing 
impact of BSER measures that reduce CO2 emissions through 
reductions in the quantity of generation rather than through reductions 
in the amount of CO2 emitted per unit of generation would 
not be reflected in an affected EGU's emission rate computed solely 
based on measured stack emissions and measured electricity generation 
but can readily be reflected in an emission rate computation by 
averaging ERCs acquired by the affected EGU into the rate computation.
    In section VIII.K, we discuss the processes for issuance and use of 
ERCs that can be included in the emission rate computations that 
affected EGUs perform to demonstrate compliance with an emission rate 
standard. This ERC mechanism is analogous to the approach the EPA has 
used to reflect building blocks 2 and 3 in the uniform emission rates 
representing the BSER, as discussed in section VI below. As summarized 
below and as discussed in greater detail in section VIII.K, the 
existence of a clearly feasible path for usage of ERCs ensures that 
emission reductions achievable through implementation of the measures 
in building blocks 2 and 3 are available to assist all affected EGUs in 
achieving compliance with standards of performance based on the BSER.
    (1) Building block 1.
    The owner/operator of an affected steam EGU can take steps to 
reduce the unit's heat rate, thereby lowering the unit's CO2 
emission rate. Examples of actions in this category are included in 
section V.C. below and in the GHG Mitigation Measures TSD for the CPP 
Final Rule. Any type of owner/operator can take advantage of this 
measure.
    (2) Building block 2.
    The owner/operator of an affected EGU can average the EGU's 
emission rate with ERCs issued on the basis of incremental generation 
from an existing NGCC unit. As permitted under the EGU's state's 
section 111(d) plan, the owner/operator of the affected EGU could 
accomplish this through either common ownership of the NGCC unit, a 
bilateral transaction with the owner/operator of the NGCC unit, or a 
transaction for ERCs through an intermediary, which could but need not 
involve an organized market.\438\ As discussed earlier, based on 
observation of market behavior both inside and outside the electricity 
industry, we expect that intermediaries will seek opportunities to 
participate in such transactions and that organized markets are likely 
to develop as well if section 111(d) plans authorize the use of ERCs. 
While the opportunity to acquire ERCs through common ownership of NGCC 
facilities might not extend to owner/operators of single EGUs or small 
fleets, all owner/operators would have the ability to engage in 
bilateral or intermediated purchase transactions for ERCs just as they 
can engage in transactions for other kinds of goods and services.
---------------------------------------------------------------------------

    \438\ Each of these methods of implementing building block 2 
meets the criteria for the BSER in that (i) as we discuss in section 
V.D. and supporting documents, each of these methods is adequately 
demonstrated;(ii) the costs of each of these methods on a source-by-
source basis are reasonable, as discussed above; and (iii) none of 
these methods causes adverse energy impacts or non-quality 
environmental impacts.
---------------------------------------------------------------------------

    In section VIII.K below, the EPA sets out the minimum criteria that 
must be satisfied for generation and issuance of a valid ERC based upon 
incremental electricity generation by an existing NGCC unit. Those 
criteria generally concern ensuring that the physical basis for the 
ERC--i.e., qualifying generation by an existing NGCC unit and the NGCC 
unit CO2 emissions associated with that qualifying 
generation--is adequately monitored and that there is an adequate 
administrative process for tracking credits to avoid double-counting. 
In the case of ERCs related to building block 2, the monitoring 
criteria would generally be satisfied by standard 40 CFR part 75 
monitoring.
    The owner/operator of an affected steam EGU would use the ERCs it 
has acquired for compliance--whether acquired through ownership of NGCC 
capacity, a bilateral transaction, or an intermediated transaction--by 
adding the ERCs to its measured net generation when computing its 
CO2 emission rate for purposes of demonstrating compliance 
with its emission rate-based standard of performance.
    (3) Building block 3.
    The owner/operator of an affected EGU can average the EGU's 
emission rate with ERCs issued on the basis of generation from new 
(i.e., post-2012) RE generating capacity, including both newly 
constructed capacity and new uprates to existing RE generating 
capacity. As permitted under the EGU's state's section 111(d) plan, the 
owner/operator of the affected EGU could accomplish this through either 
common ownership of the RE generating capacity, a bilateral transaction 
with the owner/operator of the RE generating capacity, or a transaction 
for ERCs through an intermediary, which could, but need not, involve an 
organized market.\439\ As discussed earlier, based on observation of 
market behavior both inside and outside the electricity industry, we 
expect that intermediaries will seek opportunities to participate in 
such transactions and that organized markets are likely to develop as 
well if section 111(d) plans authorize the use of ERCs. While the 
opportunity to acquire ERCs through common ownership of RE generating 
facilities might not extend to owner/operators of single EGUs or small 
fleets, all owner/operators would have the ability to engage in 
bilateral or intermediated purchase transactions for ERCs just as they 
can engage in transactions for other kinds of goods and services.
---------------------------------------------------------------------------

    \439\ As with building block 2, each of these methods of 
implementing building block 3 meets the criteria for the BSER in 
that (i) as we discuss in section V.E. and supporting documents, 
each of these methods is adequately demonstrated; (ii) the costs of 
each of these methods on a source-by-source basis are reasonable, as 
discussed above; and (iii) none of these methods causes adverse 
energy impacts or non-quality environmental impacts.
---------------------------------------------------------------------------

    In section VIII.K below, the EPA sets out the minimum criteria that 
must be satisfied for generation and issuance of a valid ERC based upon 
generation from new RE generating capacity. Those criteria generally 
concern assuring that the physical basis for the ERC--i.e., generation 
by qualifying new RE capacity--is adequately monitored and that there 
is an adequate administrative process for tracking credits to avoid 
double-counting.\440\
---------------------------------------------------------------------------

    \440\ The possible use of types of RE generating capacity that 
are not included in the BSER is discussed in section V.A.6. and 
section VIII of the preamble.
---------------------------------------------------------------------------

    As with building block 2, the owner/operator of an affected EGU 
would use the ERCs it has acquired for compliance--whether acquired 
through ownership of qualifying RE generating capacity, a bilateral 
transaction, or an intermediated transaction--by adding the ERCs to its 
measured net generation when computing its CO2 emission rate 
for purposes of demonstrating compliance with its emission rate-based 
standard of performance.
    (4) Reduced generation.
    The owner/operator of an affected EGU can reduce the unit's 
generation and reflect that reduction in the form of a lower emission 
rate provided that the owner/operator also acquires some amount of ERCs 
to use in computing the unit's emission rate for purposes of 
demonstrating compliance. As

[[Page 64754]]

permitted under the EGU's state's section 111(d) plan, the ERCs could 
be acquired through investment in incremental generation from existing 
NGCC capacity, generation from new RE generating capacity, or purchase 
from an entity with surplus ERCs. If the owner/operator does not 
average any ERCs into the unit's emission rate, reducing the unit's own 
generation will proportionately reduce both the numerator and 
denominator of the fraction and therefore will not affect the computed 
emission rate (unless the unit retires, reducing its emission rate to 
zero). However, if the owner/operator does average ERCs into the unit's 
emission rate, then a proportional reduction in both the numerator and 
the portion of the denominator representing the unit's measured 
generation will amplify the effect of the acquired ERCs in the 
computation, with the result that the more the unit reduces its 
generation, the fewer ERCs will be needed to reach a given emission 
rate-based standard of performance. All owner/operators have the 
ability to reduce generation, and as discussed above all also would be 
capable of acquiring ERCs, so all would be capable of reflecting 
reduced utilization in their emission rates for purposes of 
demonstrating compliance.
    (5) Emissions trading approaches.
    To the extent allowed under standards of performance that 
incorporate emissions trading or otherwise through the relevant section 
111(d) plans, the owner/operator of an affected EGU can acquire 
tradable rate-based emission credits representing an investment in 
surplus emission rate reductions not needed by another affected EGU and 
can average those credits into its own emission rate for purposes of 
demonstrating compliance with its rate-based standard of performance. 
The approach would have to be authorized in the appropriate section 
111(d) plan and would have to conform to the minimum conditions for 
such approaches described in section VIII below. As we have repeatedly 
noted, based on our reading of the comment record and the discussions 
that occurred during the outreach process, it is reasonable to presume 
that such authorization will be forthcoming from states that submit 
plans establishing rate-based standards of performance for their 
affected EGUs.
    Under a rate-based emissions trading approach, credits are 
initially created and issued according to processes defined in the 
state plan. After credits are initially issued, the owner/operator of 
an affected EGU needing additional credits can acquire credits through 
common ownership of another affected EGU or through a bilateral 
transaction with the other affected EGU, or the owner/operator of the 
affected EGU can acquire credits in a transaction through an 
intermediary, which could, but need not, involve an organized market. 
As discussed earlier, based on observation of market behavior both 
inside and outside the electricity industry, we expect that 
intermediaries will seek opportunities to participate in such 
transactions and that organized markets are likely to develop as well 
if section 111(d) plans and/or standards of performance established 
thereunder authorize emissions trading. While the opportunity to 
acquire credits through common ownership might not extend to owner/
operators of single EGUs or small fleets, all owner/operators would 
have the ability to engage in bilateral or intermediated purchase 
transactions for credits just as they can engage in transactions for 
other kinds of goods and services.
    Further details regarding the possible use of rate-based emission 
credits in a state plan (using ERCs issued on the basis of investments 
in building blocks 2 and 3 and potentially other measures as the 
credits) are provided in section VIII.K.
    b. Use of BSER measures to achieve a mass-based standard. Under a 
mass-based form of the standard, compliance is determined through a 
comparison of the affected EGU's monitored mass emissions to a mass-
based emission limit. Although a state could choose to impose specific 
mass-based limits that each EGU would be required to meet on a physical 
basis, in past instances where mass-based limits have been established 
for large numbers of sources it has been typical for the limit on each 
affected EGU to be structured as a requirement to periodically 
surrender a quantity of emission allowances equal to the source's 
monitored mass emissions. The EPA believes that section 111(d) 
encompasses the flexibility for plans to impose mass-based standards in 
the typical manner where the standard of performance for each affected 
EGU consists of a requirement to surrender emission allowances rather 
than a requirement to physically comply with a unit-specific emissions 
cap.
    Measurements of mass emissions at a given affected EGU capture 
reductions in the EGU's emissions arising from both reductions in 
generation and reductions in the emission rate per MWh. Accordingly, 
under a mass-based standard there is no need to provide a mechanism 
such as the ERC mechanism described above in order to properly account 
for emission reductions attributable to particular types of BSER 
measures. The relative simplicity of the mechanics of monitoring and 
determining compliance are significant advantages inherent in the use 
of mass-based standards rather than emission rate-based standards.
    (1) Building block 1.
    The owner/operator of an affected steam EGU can take steps to 
reduce the unit's heat rate, thereby lowering the unit's CO2 
mass emissions. Examples of actions in this category are included in 
section V.C. below and in the GHG Mitigation Measures TSD for the CPP 
Final Rule. Any type of owner/operator can take advantage of this 
measure.
    (2) Reduced generation.
    The owner/operator of an affected EGU can reduce its generation, 
thereby lowering the unit's CO2 mass emissions. Any type of 
owner/operator can take advantage of this measure. Although some action 
or combination of actions to increase lower-carbon generation or reduce 
electricity demand somewhere in the interconnected electricity system 
of which the affected EGU is a part will be required to enable 
electricity supply and demand to remain in balance, the affected EGU 
does not need to monitor or track those actions in order to use its 
reduction in generation to help achieve compliance with the mass-based 
standard. Instead, multiple participants in the interconnected 
electricity system will act to ensure that supply and demand remain in 
balance, subject to the complex and constantly changing set of 
constraints on operation of the system, just as those participants have 
routinely done for years.
    Of course, if the owner/operator of the affected EGU wishes to play 
a direct role in driving the increase in lower-carbon generation or 
demand-side EE required to offset a reduction in the affected EGU's 
generation, the owner/operator may do so as part of whatever role it 
happens to play as a participant in the interconnected electricity 
system. However, the owner/operator will achieve the benefit that 
reduction in generation brings toward compliance with the mass-based 
standard whether it takes those additional actions itself or instead 
allows other participants in the interconnected electricity system to 
play that role.
    (3) Emissions trading approaches.
    To the extent allowed under the relevant section 111(d) plans--as 
the record indicates that it is reasonable to expect it will be--the 
owner/operator of an affected EGU can acquire tradable mass-based 
emission allowances representing investment in surplus emission 
reductions not needed by another affected EGU and can aggregate those 
allowances with any other

[[Page 64755]]

allowances it already holds for purposes of demonstrating compliance 
with its mass-based standard of performance. The approach would have to 
be authorized in the appropriate section 111(d) plan and would have to 
conform to the minimum conditions for such approaches described in 
section VIII below.
    Under a mass-based emissions trading approach, the total number of 
allowances to be issued is defined in the state plan, and affected EGUs 
may obtain an initial quantity of allowances through an allocation or 
auction process. After that initial process, the owner/operator of an 
affected EGU needing additional allowances can acquire allowances 
through common ownership of another affected EGU or through a bilateral 
transaction with the other affected EGU, or the owner/operator of the 
affected EGU can acquire allowances in a transaction through an 
intermediary, which could but need not involve an organized market. As 
discussed earlier, based on observation of market behavior both inside 
and outside the electricity industry, we expect that intermediaries 
will seek opportunities to participate in such transactions and that 
organized markets are likely to develop as well if section 111(d) plans 
authorize the use of emissions trading. While the opportunity to 
acquire allowances through common ownership might not extend to owner/
operators of single EGUs or small fleets, all owner/operators would 
have the ability to engage in bilateral or intermediated purchase 
transactions for allowances just as they can engage in transactions for 
other kinds of goods and services.
    Further details regarding the possible use of mass-based emission 
allowances in a state plan are provided in section VIII.J.
6. Use of Non-BSER Measures To Achieve Standards of Performance
    In addition to the BSER-related measures that affected EGUs can use 
to achieve the standards of performance set in section 111(d) plans, 
there are a variety of non-BSER measures that could also be employed 
(to the extent permitted under a given plan). This final rule does not 
limit the measures that affected EGUs may use for achieving standards 
of performance to measures that are included in the BSER; thus, the 
existence of these non-BSER measures provides flexibility allowing the 
individual affected EGUs and the source category to achieve emission 
reductions consistent with application of the BSER at the levels of 
stringency reflected in this final rule even if one or more of the 
building blocks is not implemented to the degree that the EPA has 
determined to be reasonable for purposes of quantifying the BSER. In 
this way, non-BSER measures provide additional flexibility to states in 
establishing standards of performance for affected EGUs through section 
111(d) plans and to individual affected EGUs for achieving those 
standards.
    Any of the non-BSER measures described below would help the 
affected source category as a whole achieve emission limits consistent 
with the BSER. The non-BSER measures either reduce the amount of 
CO2 emitted per MWh of generation from the set of affected 
EGUs or reduce the amount of generation, and therefore associated 
CO2 emissions, from the set of affected EGUs. However, the 
manner in which the various non-BSER measures would help individual 
affected EGUs meet their individual standards of performance varies 
according to the type of measure and the type of standard of 
performance--i.e., whether the standard is emission rate-based or mass-
based.
    In general, a non-BSER measure that reduces the amount of 
CO2 emitted per MWh of generation at an affected EGU will 
reduce the amount of CO2 emissions monitored at the EGU's 
stack (assuming the quantity of generation is held constant). Measures 
of this type can help the EGU meet either an emission rate-based or 
mass-based standard of performance.
    Other non-BSER measures do not reduce an affected EGU's 
CO2 emission rate but rather facilitate reductions in 
CO2 emissions by reducing the amount of generation from 
affected EGUs. Under a mass-based standard, the collective reduction in 
emissions from the set of affected EGUs is reflected in the collective 
monitored emissions from the set of affected EGUs. An individual EGU 
that reduces its generation and emissions will be able to use the 
measure to help achieve its mass-based limit. Individual EGUs that do 
not reduce their generation and emissions will be able to use the 
measure, if the relevant section 111(d) plans provide for allowance 
trading, by purchasing emission allowances no longer needed by EGUs 
that have reduced their emissions.
    Under an emission rate-based standard, non-BSER measures that 
reduce generation from affected EGUs but do not reduce an affected 
EGU's emission rate generally can facilitate compliance by serving as 
the basis for ERCs that affected EGUs can average into their emission 
rates for purposes of demonstrating compliance. Section VIII.K. 
includes a discussion of the issuance of ERCs based on various non-BSER 
measures. Affected EGUs could use such ERCs to the extent permitted by 
the relevant section 111(d) plans.
    The remainder of this section discusses some specific types of non-
BSER measures. The first set discussed includes measures that can 
reduce the amount of CO2 emitted per MWh of generation, and 
the second set discussed includes measures that can reduce 
CO2 emissions by reducing the amount of generation from 
affected EGUs. In some cases, considerations related to use of these 
measures for compliance are discussed below in section VIII on state 
plans. The EPA notes that this is not an exhaustive list of non-BSER 
measures that could be employed to reduce CO2 emissions from 
affected EGUs, but merely a set of examples that illustrate the extent 
of the additional flexibility such measures provide to states and 
affected EGUs under the final rule.
    a. Non-BSER measures that reduce CO2 emissions per MWh 
generated. In the June 2014 proposal, the EPA discussed several 
potential measures that could reduce CO2 emissions per MWh 
generated at affected EGUs but that were not proposed to be part of the 
BSER. The measures discussed included heat rate improvements at 
affected EGUs other than coal-fired steam EGUs; fuel switching from 
coal to natural gas at affected EGUs, either completely (conversion) or 
partially (co-firing); and carbon capture and storage by affected EGUs. 
One reason for not proposing to consider these measures to be part of 
the BSER was that they were more costly than the BSER measures. Another 
reason was that the emission reduction potential was limited compared 
to the potential available from the measures that were proposed to be 
included in the BSER. However, we also noted that circumstances could 
exist where these measures could be sufficiently attractive to deploy, 
and that the measures could be used to help affected EGUs achieve 
emission limits consistent with the BSER.
    In the final rule, the EPA has reached determinations consistent 
with the proposal with respect to these measures: namely, that they do 
not merit inclusion in the BSER, but that they are capable of helping 
affected EGUs achieve compliance with standards of performance and are 
likely to be used for that purpose by some units. To the extent that 
they are selectively employed, they provide flexibility for the source 
category as a whole and for individual affected EGUs to achieve 
emission limits reflective of the BSER, as discussed above.

[[Page 64756]]

    (1) Heat rate improvement at affected EGUs other than coal-fired 
steam EGUs.
    Building block 1 reflects the opportunity to improve heat rate at 
coal-fired steam EGUs but not at other affected EGUs. As the EPA stated 
at proposal, the potential CO2 reductions available from 
heat rate improvements at coal-fired steam EGUs are much larger than 
the potential CO2 reductions available from heat rate 
improvements at other types of EGUs, and comments offered no persuasive 
basis for reaching a different conclusion. Nevertheless, we recognize 
that there may be instances where an owner/operator finds heat rate 
improvement to be an attractive option at a particular non-coal-fired 
affected EGU, and nothing in the rule prevents the owner/operator from 
implementing such a measure and using it to help achieve a standard of 
performance.
    (2) Carbon capture and storage at affected EGUs.
    Another approach for reducing CO2 emissions per MWh of 
generation from affected EGUs is the application of carbon capture and 
storage (CCS) technology. Consistent with the June 2014 proposal, we 
are determining that use of full or partial CCS technology should not 
be part of the BSER for existing EGUs because it would be more 
expensive than the measures determined to be part of the BSER, 
particularly if applied broadly to the overall source category. At the 
same time, we note that retrofit of CCS technology may be a viable 
option at some individual facilities, particularly where the captured 
CO2 can be used for enhanced oil recovery (EOR). For 
example, construction of one CCS retrofit application with EOR has 
already been completed at a unit at the Boundary Dam plant in Canada, 
and construction of another CCS retrofit application with EOR is 
underway at the W.A. Parish plant in Texas. We expect the costs of CCS 
to decline as implementation experience increases. CO2 
emission rate reductions achieved through retrofit of CCS technology 
would be available to help affected EGUs achieve emission limits 
consistent with the BSER. State plan considerations related to CCS are 
discussed in section VIII.I.2.a.
    (3) Fuel switching to natural gas at affected EGUs.
    In the proposal we discussed the opportunity to reduce 
CO2 emissions at an individual affected EGU by switching 
fuels at the EGU, particularly by switching from coal to natural gas. 
Most coal-fired EGUs could be modified to burn natural gas instead, and 
the potential CO2 emission reductions from this measure are 
large--approximately 40 percent in the case of conversion from 100 
percent coal to 100 percent natural gas, and proportionately smaller 
for partial co-firing of coal with natural gas. The primary reason for 
not considering this measure part of the BSER, both at proposal and in 
this final rule, is that it is more expensive than the BSER measures. 
In particular, combusting natural gas in a steam EGU is less efficient 
and generally more costly than combusting natural gas in an NGCC unit. 
For the category as a whole, CO2 emissions can be achieved 
far more cheaply by combusting additional natural gas in currently 
underutilized NGCC capacity and reducing generation from coal-fired 
steam EGUs (building block 2) than by combusting natural gas instead of 
coal in steam EGUs.
    Some owner/operators are already converting some affected EGUs from 
coal to natural gas, and it is apparent that the measure can be 
attractive compared to alternatives in certain circumstances, such as 
when a unit must meet tighter unit-specific limits on emissions of non-
GHG pollutants, the options for meeting those emission limits are 
costly, and retirement of the unit would necessitate transmission 
upgrades that are costly or cannot be completed quickly. CO2 
emission reductions achieved in these situations are available to help 
achieve emission limits consistent with the BSER.
    (4) Fuel switching to biomass at affected EGUs.
    Some affected EGUs may seek to co-fire qualified biomass with 
fossil fuels. The EPA recognizes that the use of some biomass-derived 
fuels can play an important role in controlling increases of 
CO2 levels in the atmosphere. As with the other non-BSER 
measures discussed in this section, the EPA expects that use of biomass 
may be economically attractive for certain individual sources even 
though on a broader scale it would likely be more expensive or less 
achievable than the measures determined to be part of the BSER. Section 
VIII.I.2.c describes the process and considerations for states 
proposing to use different kinds of biomass in state plans.
    (5) Waste heat-to-energy conversion at affected EGUs.
    Certain affected EGUs in urban areas or located near industrial or 
commercial facilities with needs for thermal energy may be able add new 
equipment to capture some of the waste heat from their electricity 
generation processes and use it to create useful thermal output, 
thereby engaging in combined heat and power (CHP) production. While the 
set of affected EGUs in locations making this measure feasible may be 
limited, where feasible the potential CO2 emission rate 
improvements can be substantial: Depending on the process used, the 
efficiency with which fuel is converted to useful energy can be 
increased by 25 percent or more. The final rule allows an owner/
operator applying CHP technology to an affected EGU to account for the 
increased efficiency by counting the useful thermal output as 
additional MWh of generation, thereby lowering the unit's computed 
emission rate and assisting with achievement of an emission rate-based 
standard of performance. (The EPA notes that unless the unit also 
reduced its fuel usage, the addition of the capability to capture waste 
heat and produce useful thermal output would not reduce the unit's mass 
emissions and therefore would not directly help the unit achieve a 
mass-based standard of performance.\441\)
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    \441\ However, the EPA notes that a state could establish a 
mechanism for encouraging affected EGUs to apply CHP technology 
under a mass-based plan, for example, through awards of emission 
allowances to CHP projects.
---------------------------------------------------------------------------

    b. Non-BSER measures that reduce CO2 emissions by 
reducing fossil fuel-fired generation.
    A second group of non-BSER measures has the potential to reduce 
CO2 emissions from affected EGUs by reducing the amount of 
generation from those EGUs. As discussed above, under a section 111(d) 
plan with mass-based standards of performance, no special action is 
required to enable measures of this nature to help the source category 
as a whole and individual affected EGUs achieve their emission limits, 
because the CO2-reducing effects are captured in monitored 
stack emissions. However, under a section 111(d) plan with rate-based 
standards of performance, affected EGUs would need to acquire ERCs 
based on the non-BSER activities that could be averaged into their 
emission rate computations for purposes of determining compliance with 
their standards of performance.
    (1) Demand-side EE.
    One of the major approaches available for achieving CO2 
emission reductions from the utility power sector is demand-side EE. In 
the June 2014 proposal, the EPA identified demand-side EE as one of the 
four proposed building blocks for the BSER. We continue to believe that 
significant emission reductions can be achieved by the source category 
through use of such measures at reasonable costs. In fact, we believe 
that the potential emission reductions from demand-side EE rival those 
from building blocks 2 and 3 in magnitude, and that demand-side EE is 
likely to

[[Page 64757]]

represent an important component of some state plans, particularly in 
instances where a state prefers to develop a plan reflecting the state 
measures approach discussed in section VIII below. We also expect that 
many sources would be interested in including demand-side EE in their 
compliance strategies to the extent permitted, and we received comment 
that it should be permitted.
    For the reasons discussed in section V.B.3.c.(8) below, the EPA has 
determined not to include demand-side EE in the BSER in this final 
rule. However, the final rule authorizes generation avoided through 
investments in demand-side EE to serve as the basis for issuance of 
ERCs when appropriate conditions are met. In section VIII.K below, the 
EPA sets out the minimum criteria that must be satisfied for generation 
and issuance of a valid ERC based upon implementation of new demand-
side EE programs. Those criteria generally concern ensuring that the 
physical basis for the ERC--in this case, generation avoided through 
implementation of demand-side EE measures--is adequately evaluated, 
measured, and verified and that there is an adequate administrative 
process for tracking credits.
    Through their authority over legal requirements such as building 
codes, states have the ability to drive certain types of demand-side EE 
measures that are beyond the reach of private-sector entities. The EPA 
recognizes that, by definition, this type of measure is beyond the 
ability of affected EGUs to invest in either directly or through 
bilateral arrangements. However, the final rule also authorizes 
generation avoided through such state policies to serve as the basis 
for issuance of ERCs that in turn can be used by affected EGUs. The 
section 111(d) plan would need to include appropriate provisions for 
evaluating, measuring, and verifying the avoided MWh associated with 
the state policies, consistent with the criteria discussed in section 
VIII.K below.
    (2) New or uprated nuclear generating capacity.
    In the June 2014 proposal, the EPA included generation from the 
five nuclear units currently under construction as part of the proposed 
BSER. As discussed above in section V.A.3.c., upon consideration of 
comments, we have determined that generation from these units should 
not be part of the BSER. However, we continue to observe that the zero-
emitting generation from these units would be expected to replace 
generation from affected EGUs and thereby reduce CO2 
emissions, and the continued commitment of the owner/operators to 
completion of the units is essential in order to realize that result. 
Accordingly, a section 111(d) plan may rely on ERCs issued on the basis 
of generation from these units and other new nuclear units. For the 
same reason, a plan may rely on ERCs issued on the basis of generation 
from uprates to the capacity of existing nuclear units. Requirements 
for state plan provisions intended to serve this purpose are discussed 
in section VIII.K.
    (3) Zero-emitting RE generating technologies not reflected in the 
BSER.
    The range of available zero-emitting RE generating technologies is 
broader than the range of RE technologies determined to be suitable for 
use in quantification of building block 3 as an element of the BSER. 
Examples of additional zero-emitting RE technologies not included in 
the BSER that could be used to achieve emission limits consistent with 
the BSER include offshore wind, distributed solar, and fuel cells. 
These technologies were not included in the range of RE technologies 
quantified for the BSER because they are generally more expensive than 
the measures that were included and the other measures in the BSER. 
However, these technologies are equally capable of replacing generation 
from affected EGUs and thereby reducing CO2 emissions. 
Further, as with any technology, there are likely to be certain 
circumstances where the costs of these technologies are more attractive 
relative to alternatives, making the technologies likely to be deployed 
to some extent. Indeed, distributed solar is already being widely 
deployed in much of the U.S. and offshore wind, while still unusual in 
this country, has been extensively deployed in some other parts of the 
world. We expect innovation in RE generating technologies to continue, 
making such technologies even more attractive over time. A section 
111(d) plan may rely on ERCs issued on the basis of generation from new 
and uprated installations of these technologies. The necessary state 
plan provisions are discussed in section VIII.K.
    (4) Non-zero-emitting RE generating technologies.
    Generation from new or expanded facilities that combust qualified 
biomass or biogenic portions of municipal solid waste (MSW) to produce 
electricity can also replace generation from affected EGUs and thereby 
control CO2 levels in the atmosphere.\442\ While the EPA 
believes it is reasonable to consider generation from these fuels and 
technologies to be forms of RE generation, the fact that they can 
produce stack emissions containing CO2 means that a section 
111(d) plan seeking to permit use of such generation to serve as the 
basis for issuance of ERCs must include appropriate consideration of 
feedstock characteristics and climate benefits. Specifically, the use 
of some kinds of biomass has the potential to offer a wide range of 
environmental benefits, including carbon benefits. However these 
benefits can only be realized if biomass feedstocks are sourced 
responsibly and attributes of the carbon cycle related to the biomass 
feedstock are taken into account. Section VIII.I.2.c describes the 
process and considerations for states proposing to use biomass in state 
plans. Section VIII.K describes additional provisions related to ERCs.
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    \442\ The EPA and many states have recognized the importance of 
integrated waste materials management strategies that emphasize a 
hierarchy of waste prevention and all other productive uses of waste 
materials to reduce the volume of disposed waste materials (see 
section VIII for more discussion of waste-to-energy strategies).
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    (5) Waste heat-to-electricity conversion at non-affected 
facilities.
    Industrial facilities that install new equipment to capture waste 
heat from an existing combustion process and then use the waste heat to 
generate electricity--a form of combined heat and power (CHP) 
production--can produce generation that replaces generation from 
affected EGUs and thereby reduces CO2 emissions. A section 
111(d) plan may rely on ERCs issued on the basis of generation of this 
nature provided that the facility does not generate and sell sufficient 
electricity to qualify as a new EGU for purposes of section 111(b) and 
is not covered under section 111(d) for another source category. More 
information is provided in section VIII.K.
    (6) Reduction in transmission and distribution line losses.
    Reductions of electricity line losses incurred from the 
transmission and distribution system between the points of generation 
and the points of consumption by end-users allow the same overall 
demand for electricity services to be met with a smaller overall 
quantity of electricity generation. Such reductions in generation 
quantities would tend to reduce generation by affected EGUs, thereby 
reducing CO2 emissions. The opportunity for improvement is 
large because, on average, line losses account for approximately seven 
percent of all electricity generation. The EPA recognizes that, in 
general, only the

[[Page 64758]]

owner/operators of the transmission and distribution facilities have 
the ability to undertake line loss reduction investments, and that 
merchant generators may have little opportunity to engage a contractor 
to pursue such opportunities on a bilateral basis. Nevertheless, for 
entities that do have the opportunity to make such investments, 
generation avoided through investment that reduces transmission and 
distribution line losses may serve as the basis for issuance of ERCs 
that in turn can be used by affected EGUs. Further information is 
provided in section VIII.K.
7. Severability
    The EPA intends that the components of the BSER summarized above be 
severable. It is reasonable to consider the building blocks severable 
because the building blocks do not depend on one another. Building 
blocks 2 and 3 are feasible and demonstrated means of reducing 
CO2 emissions from the utility power sector that can be 
implemented independently of the other building blocks. If implemented 
in combination with at least one of the other building blocks, building 
block 1 is also a feasible and demonstrated means of reducing 
CO2 emission from the utility power sector.\443\ As 
discussed in sections V.C. through V.E. below, we have determined that 
each building block is independently of reasonable cost whether or not 
the other building blocks are applied, and that alternative 
combinations of the building blocks are likewise of reasonable cost, 
and we have determined reasonable schedules and stringencies for 
implementation of each building block independently, based on factors 
that generally do not vary depending on the implementation of other 
building blocks.
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    \443\ The heat rate improvement measures included in building 
block 1 are capable of being implemented independently of the 
measures in the other building blocks but, as discussed earlier, 
unless at least one other building block is also implemented, a 
``rebound effect'' arising from improved competitiveness and 
increased generation at the EGUs implementing heat rate improvements 
could weaken or potentially even eliminate the ability of building 
block 1 to achieve CO2 emission reductions.
---------------------------------------------------------------------------

    Further, building block 2, building block 3, and all combinations 
of the building blocks (implemented on the schedules and at the 
stringencies determined to be reasonable in this rule) would achieve 
meaningful degrees of emission reductions,\444\ although less than the 
combination of all three building blocks. No combination of the 
building blocks would lead to adverse non-air environmental or energy 
impacts or impose a risk to the reliability of electricity supplies.
---------------------------------------------------------------------------

    \444\ This conclusion would not extend to a BSER comprising 
solely building block 1, in part because of the possibility of 
rebound effects discussed earlier.
---------------------------------------------------------------------------

    In the event that a court should deem building block 2 or 3 
defective, but not both, the standards and state goals can be 
recomputed on the basis of the remaining building blocks. All of the 
data and procedures necessary to determine recomputed state goals using 
any combination of the building blocks are set forth in the 
CO2 Emission Performance Rate and Goal Computation TSD for 
the CPP Final Rule available in the docket.

B. Legal Discussion of Certain Aspects of the BSER

    This section includes a legal analysis of various aspects of EPA's 
determination of the BSER, including responses to some of the major 
adverse comments. These aspects include (1) the EPA's authority to 
determine the BSER; (2) the approach to subcategorization; (3) the 
EPA's basis for determining that building blocks 2 and 3 qualify as 
part of the BSER under CAA sections 111(d)(1) and (a)(1), 
notwithstanding commenters' arguments that these building blocks cannot 
be considered part of the BSER because they are not based on measures 
integrated into the design or operation of the affected source's own 
production processes or methods or because they are dependent on 
actions by entities other than the affected source; (4) the 
relationship between an affected EGU's implementation of building 
blocks 2 and 3 and CO2 emissions reductions; (5) how reduced 
generation relates to the BSER; (6) reasons why, contrary to assertions 
by commenters, this rule is within the EPA's statutory authority, is 
not inconsistent with the Federal Power Act or state laws governing 
public utility commissions, and does not result in what the U.S. 
Supreme Court described as ``an enormous and transformative expansion 
in [the] EPA's regulatory authority''; \445\ and (7) reasons that, 
contrary to assertions by commenters, the stringency of the BSER for 
this rule for CO2 emissions from existing affected EGUs is 
not inconsistent with the stringency of the BSER for the rules the EPA 
is promulgating at the same time for CO2 emissions from new 
or modified affected EGUs.
---------------------------------------------------------------------------

    \445\ Util. Air Reg. Group v. EPA, 134 S. Ct. 2427, 2444 (2014).
---------------------------------------------------------------------------

1. The EPA's Authority To Determine the BSER
    In this section, we explain why the EPA, and not the states, has 
the authority to determine the BSER and, therefore, the level of 
emission limitation required from the existing sources in the source 
category in section 111(d) rulemaking and the associated state plans.
    CAA section 111(d)(1) requires the EPA to establish a section 110-
like procedure under which each state submits a plan that ``establishes 
standards of performance for any existing source of air pollutant'' and 
``provides for the implementation and enforcement of such standards of 
performance.'' As CAA section 111(d) was originally adopted in the 1970 
CAA Amendments, however, state plans were required to establish 
``emission standards''--an undefined term--rather than ``standards of 
performance,'' a term that was limited to CAA section 111(b).\446\ The 
1970 provision was in effect when the EPA issued the 1975 implementing 
regulations for CAA section 111(d),\447\ which remain in effect to this 
day.
---------------------------------------------------------------------------

    \446\ See 1970 CAA Amendments, Sec.  4, 84 Stat. at 1683-84. 
Subsequently, in 1977, Congress replaced the term ``emission 
standard'' with ``standards of performance.'' See 1977 CAA 
Amendments, Sec.  109, 91 Stat. at 699.
    \447\ See ``State Plans for the Control of Certain Pollutants 
From Existing Facilities,'' 40 FR 53340 (Nov. 17, 1975).
---------------------------------------------------------------------------

    These regulations establish a cooperative framework that is similar 
to that under CAA section 110. First, the EPA develops ``emission 
guidelines'' for source categories, which are defined as a final 
guideline document reflecting ``the degree of emission reduction 
achievable through the application of the best system of emission 
reduction . . . which the Administrator has determined has been 
adequately demonstrated.'' Then, the states submit implementation plans 
to regulate any existing sources.\448\
---------------------------------------------------------------------------

    \448\ See ``State Plans for the Control of Certain Pollutants 
From Existing Facilities,'' 40 FR 53340 (Nov. 17, 1975).
---------------------------------------------------------------------------

    The preamble to these regulations carefully considered the 
allocation of responsibilities as between the EPA and the states for 
purposes of CAA section 111(d), and concluded that the EPA is 
responsible for determining the level of emission limitation from the 
source category, while the states have the responsibility of assigning 
emission requirements to their sources that assured their achievement 
of that level of emission limitation.\449\ The EPA

[[Page 64759]]

explained ``that some substantive criterion was intended to govern not 
only the Administrator's promulgation of standards but also [her] 
review of state plans.'' \450\ The EPA added, ``it would make no sense 
to interpret [CAA] section 111(d) as requiring the Administrator to 
base approval or disapproval of state plans solely on procedural 
criteria. Under that interpretation, states could set extremely lenient 
standards--even standards permitting greatly increased emissions--so 
long as [the] EPA's procedural requirements were met.'' \451\ The EPA 
concluded that ``emission guidelines, each of which will be subjected 
to public comment before final adoption, will serve [the] function'' of 
providing substantive criteria ``in advance to the states, to industry, 
and to the general public'' to aid states in ``developing and enforcing 
control plans under [CAA] section 111(d).'' \452\ Thus, the 
implementing regulations make clear that the EPA is responsible for 
determining the level of emission limitation that the state plans must 
achieve.
---------------------------------------------------------------------------

    \449\ As we made clear in the proposed rulemaking, we are not 
re-opening these regulations (on the issue of the authority to 
determine the BSER or any other issue, unless specifically indicated 
otherwise) in this rulemaking, and our discussion of these 
regulations in responding to comments does not constitute a re-
opening.
    \450\ ``State Plans for the Control of Certain Pollutants from 
Existing Facilities,'' 40 FR 53340, 53342 (Nov. 17, 1975).
    \451\ ``State Plans for the Control of Certain Pollutants from 
Existing Facilities,'' 40 FR 53340, 53343 (Nov. 17, 1975).
    \452\ ``State Plans for the Control of Certain Pollutants from 
Existing Facilities,'' 40 FR 53340, 53343 (Nov. 17, 1975).
---------------------------------------------------------------------------

    In 1977, Congress revised CAA section 111(d) to require that the 
states adopt ``standards of performance,'' as defined under CAA section 
111(a)(1). As noted above, a standard of performance is defined as ``a 
standard for emissions of air pollutants which reflects the degree of 
emission limitation achievable through the application of the best 
system of emission reduction which . . . the Administrator determines 
has been adequately demonstrated.'' (Emphasis added.) By its terms, 
this provision provides that the EPA has the responsibility of 
determining whether the ``best system of emission reduction'' is 
``adequately demonstrated.'' By giving the EPA this responsibility, 
this provision is clear that Congress assigned the role of determining 
the ``best system of emission reduction'' to the EPA. Even if the 
provision may be considered to be silent or ambiguous on that question, 
the EPA reasonably interprets the provision to assign the 
responsibility of identifying the ``best system of emission reduction'' 
to the Administrator for the same reasons discussed in the preamble to 
the 1975 implementing regulations.
    In addition, in the legislative history of the 1977 CAA Amendments, 
when Congress replaced the term ``emission standards'' under CAA 
section 111(d)(1) with the term ``standards of performance,'' Congress 
endorsed the overall approach of the implementing regulations, which 
lends further credence to the proposition that the EPA has the 
responsibility for determining the ``best system of emission 
reduction'' and the amount of emission limitation from the existing 
sources. Specifically, in the House report that introduced the 
substantive changes to CAA section 111, the Committee explained that 
``[t]he Administrator would establish guidelines as to what the best 
system for each category of existing sources is.'' \453\ States, on the 
other hand, ``would be responsible for determining the applicability of 
such guidelines to any particular source or sources.'' \454\ The use of 
the term ``guidelines,'' which does not appear in CAA section 111(d), 
indicates Congress was aware of and approved of the approach taken in 
the EPA's implementing regulations for establishing guidelines, which 
determine the BSER. At a minimum, if Congress disapproved of the EPA's 
implementing regulations, we would not expect the House report to adopt 
the EPA's terminology to clarify CAA section 111(d).
---------------------------------------------------------------------------

    \453\ H.R. Rep. No. 95-294, at 195 (May 12, 1977) (emphasis 
added).
    \454\ H.R. Rep. No. 95-294, at 195 (May 12, 1977) (emphasis 
added).
---------------------------------------------------------------------------

    In addition, Congress expressly referred to our ``guidelines'' in 
CAA section 129, added as part of the 1990 CAA Amendments. Congress 
added CAA section 129 to address solid waste combustion and 
specifically directed the Administrator to establish ``guidelines 
(under section 111(d) and this section) and other requirements 
applicable to existing units.'' \455\ This reference also indicates 
that Congress was aware of and approved the EPA's regulations under 
section 111(d).
---------------------------------------------------------------------------

    \455\ CAA section 129(a)(1)(A) (emphasis added).
---------------------------------------------------------------------------

    The EPA has followed the same approach described in the 
implementation regulations in all its rulemakings under section 111(d). 
Thus, in all cases, the EPA has identified the type of emission 
controls for the source category and the level of emission limitation 
based on those controls.\456\ The EPA's longstanding and consistent 
interpretation of CAA section 111(d) is also ``evidence showing that 
the statute is in fact not ambiguous,'' and that the EPA's 
interpretation should be adopted.\457\
---------------------------------------------------------------------------

    \456\ See 40 CFR part 60, subpart Ca (large municipal waste 
combustors), 56 FR 5514 (Feb. 11, 1991), 40 CFR 60.30a-.39a 
(subsequently withdrawn and superseded by Subpart Cb, see 60 FR 
65387 (Dec. 19, 1995)); Subpart Cb (large municipal waste combustors 
constructed on or before September 20, 1994), 60 FR 65387 (Dec. 19, 
1995), 40 CFR 60.30b-.39b (as amended in 1997, 2001, and 2006); 
Subpart Cc (municipal solid waste landfills), 61 FR 9905 (Mar. 12, 
1996), 40 CFR 60.30c-.36c (as amended in 1998, 1999, and 2000); 
Subpart Cd (sulfuric acid production units), 60 FR 65387 (Dec. 19, 
1995), 40 CFR 60.30d-.32d; Subpart Ce (hospital/medical/infectious 
waste incinerators), 62 FR 48348 (Sept. 15, 1997), 40 CFR 
60.30e-.39e (as amended in 2009 and 2011); Subpart BBBB (small 
municipal waste combustion units constructed on or before August 30, 
1999), 65 FR 76738 (Dec. 6, 2000), 40 CFR 60.1500-.1940; Subpart 
DDDD (commercial and industrial solid waste incineration units that 
commenced construction on or before November 30, 1999), 65 FR 75338 
(Dec. 1, 2000), 40 CFR 60.2500-.2875 (as amended in 2005, 2011, and 
2013); Subpart FFFF (other solid waste incineration units that 
commenced construction on or before December 9, 2004), 70 FR 74870 
(Dec. 16, 2005), 40 CFR 60.2980-.3078 (as amended in 2006); Subpart 
HHHH (coal-electric utility steam generating units), 70 FR 28606 
(May 18, 2005) (subsequently vacated by the D.C. Circuit in New 
Jersey v. EPA, 517 F.3d 574 (D.C. Cir. 2008)); Subpart MMMM 
(existing sewage sludge incineration units), 76 FR 15372 (Mar. 21, 
2011), 40 CFR 60.5000-.5250; ``Phosphate Fertilizer Plants, Final 
Guideline Document Availability,'' 42 FR 12022 (Mar. 1, 1977) (not 
codified); ``Kraft Pulp Mills; Final Guideline Document; 
Availability,'' 44 FR 29828 (May 22, 1979) (not codified); and 
``Primary Aluminum Plants; Availability of Final Guideline 
Document,'' 45 FR 26294 (Apr. 17, 1980) (not codified).
    \457\ Scalia, Antonin, Judicial Deference to Administrative 
Interpretations of Law, 1989 Duke L.J. 511, 518; see Riverkeeper v. 
Entergy, 556 U.S. 208, 235 (2009).
---------------------------------------------------------------------------

    Lastly, this interpretation is consistent with the Supreme Court's 
reading of CAA section 111(d) in American Electric Power Co. There, the 
Court explained that ``EPA issues emissions guidelines, see 40 CFR 
60.22, .23 (2009); in compliance with those guidelines and subject to 
federal oversight, the States then issue performance standards for 
stationary sources within their jurisdiction, Sec.  7411(d)(1).'' \458\
---------------------------------------------------------------------------

    \458\ Am. Elec. Power Co. v. Connecticut, 131 S. Ct. 2527, 2537-
38 (2011).
---------------------------------------------------------------------------

    As noted in the response to comment document, some commenters 
agreed with our interpretation, just discussed, while others argued 
that the states should be given the authority to determine the best 
system of emission reduction and, therefore, the level of emission 
limitation from their sources. For the reasons just discussed, this 
latter interpretation is an incorrect interpretation of CAA section 
111(d)(1) and (a)(1), and we are not compelled to abandon our 
longstanding practice.
2. Approach to Subcategorization
    As noted above, in this rule, we are treating all fossil fuel-fired 
EGUs as a single category, and, in the emission

[[Page 64760]]

guidelines that we are promulgating with this rule, we are treating 
steam EGUs and combustion turbines as separate subcategories. We are 
determining the BSER for steam EGUs and the BSER for combustion 
turbines, and applying the BSER to each subcategory to determine a 
performance rate for that subcategory. We are not further 
subcategorizing among different types of steam EGUs or combustion 
turbines.
    This approach is fully consistent with the provisions of section 
111(d), which simply require the EPA to determine the BSER, do not 
prescribe the method for doing so, and are silent as to 
subcategorization. This approach is also fully consistent with other 
provisions in CAA section 111, which require the EPA first to list 
source categories that may reasonably be expected to endanger public 
health or welfare \459\ and then to regulate new sources within each 
such source category,\460\ and which grant the EPA discretion whether 
to subcategorize new sources for purposes of determining the BSER.\461\
---------------------------------------------------------------------------

    \459\ CAA section 111(b)(1)(A).
    \460\ CAA section 111(b)(1)(B).
    \461\ CAA section 111(b)(2).
---------------------------------------------------------------------------

    For this rule, our approach of subcategorizing between steam EGUs 
and combustion turbines is reasonable because building blocks 1 and 2 
apply only to steam EGUs. No further subcategorization is appropriate 
because each affected EGU can achieve the performance rate by 
implementing the BSER. Specifically, as noted, each affected EGU may 
take a range of actions including investment in the building blocks, 
replacing or reducing generation, and emissions trading, as enabled or 
facilitated by the implementation programs the states adopt. Further, 
in the case of a rate-based state plan, several other compliance 
options not included in the BSER for this rule are also available to 
all affected sources, including investment in demand-side EE measures. 
Such compliance options help affected sources achieve compliance under 
a mass-based plan, even if indirectly. Our approach to 
subcategorization in this rule is consistent with our approach to 
subcategorization in previous section 111 rules for this industry, in 
which we determined whether or not to subcategorize on the basis of the 
ability of affected EGUs with different characteristics (e.g., size or 
type of fuel used) to implement the BSER and achieve the emission 
limits).\462\
---------------------------------------------------------------------------

    \462\ Compare ``Revision of Standards of Performance for 
Nitrogen Oxide Emissions From New Fossil-Fuel Fired Steam Generating 
Units; Revisions to Reporting Requirements for Standards of 
Performance for New Fossil-Fuel Fired Steam Generating Units: Final 
Rule,'' 63 FR 49442 (Sept. 16, 1998) and ``Proposed Revision of 
Standards of Performance for Nitrogen Oxide Emissions From New 
Fossil-Fuel Fired Steam Generating Units: Proposed Revisions,'' 62 
FR 36948, 36943 (July 9, 1997) (establishing a single NOX 
emission limit for new fossil-fuel fired steam generating units, and 
not subcategorizing, because the affected units could implement the 
BSER of SCR and achieve the promulgated emission limits) with 
``National Emission Standards for Hazardous Air Pollutants From Coal 
and Oil-Fired Electric Utility Steam Generating Units and Standards 
of Performance for Fossil-Fuel-Fired Electric Utility, Industrial-
Commercial-Institutional, and Small Industrial-Commercial-
Institutional Steam Generating Units: Final Rule,'' 77 FR 9304 (Feb. 
16, 2012) (MATS rule) and ``National Emission Standards for 
Hazardous Air Pollutants From Coal and Oil-Fired Electric Utility 
Steam Generating Units and Standards of performance for Fossil-Fuel-
Fired Electric Utility, Industrial-Commercial-Institutional, and 
Small Industrial-Commercial-Institutional Steam Generating Units: 
Proposed Rule,'' 76 FR 24976, 25036-37 (May 3, 2011) 
(subcategorizing coal fired units designed to burn coal with greater 
than or equal to 8,300 Btu/lb (for Hg emissions only), coal-fired 
units designed to burn coal with less than 8,300 Btu/lb (for Hg 
emissions only), IGCC units, liquid oil units, and solid oil-derived 
units; evaluating ``subcategorization of lignite coal vs. other coal 
ranks; subcategorization of Fort Union lignite coal vs. Gulf Coast 
lignite coal vs. other coal ranks; subcategorization by EGU size 
(i.e., MWe); subcategorization of base load vs. peaking units (e.g., 
low capacity utilization units); subcategorization of wall-fired vs. 
tangentially-fired units; and subcategorization of small, non-
profit-owned units vs. other units;'' but deciding not to adopt 
those latter subcategorizations).
---------------------------------------------------------------------------

    In addition, there are numerous possible criteria to use in 
subcategorizing, including, among others, subcategorizing on the basis 
of age; size; steam conditions (i.e., subcritical or supercritical); 
type of fuel, including type of coal (i.e., lignite, bituminous, and 
sub-bituminous), and coal refuse; and method of combustion (i.e., 
fluidized bed combustion, pulverized coal combustion, and 
gasification). In addition, there are different possible combinations 
of those categories. At least some of those criteria do not have 
logical cut-points. Furthermore, we have not been presented with, nor 
can we discern, a method of subcategorizing based on these or other 
criteria that is appropriate in light of the BSER for the affected EGUs 
and their ability to meet the emission limits. Moreover, our approach 
of not further subcategorizing as between different types of steam EGUs 
or combustion turbines reflects the reasonable policy that affected 
EGUs with higher emission rates should reduce their emissions by a 
greater percentage than affected EGUs with lower emission rates, and 
can do so by implementing the BSER we are identifying.
    In addition, a section 111(d) rule presents less of a need to 
subcategorize because the states retain great flexibility in assigning 
standards of performance to their affected EGUs. Thus, a state can, if 
it wishes, impose different emission reduction obligations on its 
sources, as long as the overall level of emission limitation is at 
least as stringent as the emission guidelines, as discussed below. This 
means that if a state is concerned that its different sources have 
different capabilities for compliance, it can adjust the standards of 
performance in imposes on its sources accordingly.
3. Building Blocks 2 and 3 as a ``System of Emission Reduction''
    a. Overview.
    As we explain above, the emission performance rates that we include 
in this rule's emission guidelines are achievable by the affected EGUs 
through the application of the BSER, which includes the three building 
blocks. Commenters object that building blocks 2 (generation shift) and 
3 (RE) cannot, as a legal matter, be considered part of the BSER under 
CAA section 111(d)(1) and (a)(1). These commenters explain that in 
their view, under CAA section 111, the emission performance rates must 
be based on, and therefore the BSER must be limited to, methods for 
emission control that the owner/operator of the affected source can 
integrate into the design or operation of the source itself, and cannot 
be based on actions taken beyond the source or actions involving third-
party entities.\463\ For these reasons, these commenters argue that the 
phrase ``system of emission reduction'' cannot be

[[Page 64761]]

interpreted to include building blocks 2 and 3.
---------------------------------------------------------------------------

    \463\ See, e.g., comments by UARG at 6-7 (``Standards 
promulgated under section 111 must be source-based and reflect 
measures that the source's owner can integrate into the design or 
operation of the source itself. A standard cannot be based on 
actions taken beyond the source itself that somehow reduce the 
source's utilization.''); comments by UARG at 31 (the building 
blocks other than building block 1 take a `` `beyond-the-source' 
approach'' and ``impermissibly rely on measures that go beyond the 
boundaries of individual affected EGUs and that are not within the 
control of individual EGU owners and operators''); comments by UARG 
at 33 (the ``system'' of emission reduction ``can refer only to 
reductions resulting from measures that are incorporated into the 
source itself;'' section 111 is ``designed to improve the emissions 
performance of new and existing sources in specific categories based 
on the application of achievable measures implemented in the design 
or production process of the source at reasonable cost.''); comments 
by American Chemistry Council et al. (``Associations'') at 60-61 
(EPA's proposed BSER analysis is unlawful because it ``looks beyond 
the fence line of the fossil fuel-fired EGUs that are the subject of 
this rulemaking;'' ``the standard of performance must . . . be 
limited to the types of actions that can be implemented directly by 
an existing source within [the appropriate] class or category.'').
---------------------------------------------------------------------------

    We disagree with these comments, and note that other commenters 
were supportive of our determination to include building blocks 2 and 
3. Under CAA section 111(d)(1) and (a)(1), the EPA's emission 
guidelines must establish achievable emission limits based on the 
``best system of emission reduction . . . adequately demonstrated.'' 
While some commenters assert that emission guidelines must be limited 
in the manner summarized above, the phrase ``system of emission 
reduction,'' by its terms and when read in context, contains no such 
limits. To the contrary, its plain meaning is deliberately broad and is 
capacious enough to include actions taken by the owner/operator of a 
stationary source designed to reduce emissions from that affected 
source, including actions that may occur off-site and actions that a 
third party takes pursuant to a commercial relationship with the owner/
operator, so long as those actions enable the affected source to 
achieve its emission limitation. Such actions include the measures in 
building blocks 2 and 3, which, when implemented by an affected source, 
enable the source to achieve their emission limits because of the 
unique characteristics of the utility power sector. For purposes of 
this rule, we consider a ``system of emission reduction''--as defined 
under CAA section 111(a)(1) and applied under CAA section 111(d)(1)--to 
encompass a broad range of pollution-reduction actions, which includes 
the measures in building blocks 2 and 3. Furthermore, the measures in 
building blocks 2 and 3 fall squarely within EPA's historical 
interpretation of section 111, pursuant to which the focus for the BSER 
has been on how to most cleanly produce a good, not on how much of the 
good should be produced.
    Our interpretation that a ``system of emission reduction'' is broad 
enough to include the measures in building blocks 2 and 3 is supported 
by the following: Our interpretation of the phrase ``system of emission 
reduction'' is consistent with its plain meaning and statutory context; 
our interpretation accommodates the very design of CAA section 
111(d)(1), which covers a range of source categories and air 
pollutants; \464\ our interpretation is supported by the legislative 
history of CAA section 111(d)(1) and (a)(1), which indicates Congress's 
intent to give the EPA broad discretion in determining the basis for 
CAA section 111 control requirements, particularly for existing 
sources, and Congress's intent to authorize the EPA to consider 
measures that could be carried out by parties other than the affected 
sources; and our interpretation is reasonable in light of comparisons 
to CAA provisions that give the EPA similar authority to consider such 
measures and to CAA provisions that would preclude the EPA from 
considering such measures.
---------------------------------------------------------------------------

    \464\ Because it is designed to apply to a range of air 
pollutants not regulated under other provisions, CAA section 111(d) 
may be described as a ``catch-all'' or ``gap-filler.'' As such, a 
``system of emission reduction'' as applied under CAA section 111(d) 
should be interpreted flexibly to accommodate this role.
---------------------------------------------------------------------------

    In addition to the reasons stated above, the EPA's interpretation 
is also reasonable for the following reasons: (i) Building blocks 2 and 
3 fit well within the structure and economics of the utility power 
sector. (ii) Fossil fuel-fired EGUs are already implementing the 
measures in these building blocks for various reasons, including for 
purposes of reducing CO2 emissions. (iii) Interpreting the 
phrase ``system of emission reduction'' to incorporate building blocks 
2 and 3 is consistent with (a) other provisions in the CAA, including 
the acid rain provisions in Title IV and the SIP provisions in CAA 
section 110, along with the EPA's regulations implementing the CAA SIP 
requirements concerning interstate transport and regional haze, each of 
which is based on at least some of the same measures included in 
building blocks 2 and 3; (b) prior EPA action under CAA section 111(d), 
including the 2005 Clean Air Mercury Rule,\465\ which is based on some 
of the same measures in building blocks 2 and 3; (c) the various 
provisions of the CAA that authorize emissions trading, because 
emissions trading entails a source meeting its emission limitation 
based on the actions of another entity; and (d) the pollution 
prevention provisions of the CAA, which make clear that a primary goal 
of the CAA is to encourage federal and state actions that reduce or 
eliminate, through any measures, the amount of pollution produced at 
the source.\466\ (iv) Lastly, interpreting the phrase ``system of 
emission reduction'' to authorize the EPA, in formulating its BSER 
determination, to weigh a broad range of emission-reducing measures 
that includes building blocks 2 and 3 is consistent with Congress's 
intent to address urgent environmental problems and to protect public 
health and welfare against risks, as well as Congress's expectation 
that American industry would be able to develop the innovative 
solutions necessary to protect public health and welfare.
---------------------------------------------------------------------------

    \465\ This rule was vacated by the D.C. Circuit on other 
grounds. New Jersey v. EPA, 517 F.3d 574, 583-84 (D.C. Cir. 2008), 
cert. denied sub nom. Util. Air Reg. Group v. New Jersey, 555 U.S. 
1169 (2009).
    \466\ As noted in the Legal Memorandum, in several of these 
rulemakings and in the course of litigation, the fossil fuel-fired 
electric power sector has taken positions that are consistent with 
the EPA's interpretation that the BSER may include building blocks 2 
and 3.
---------------------------------------------------------------------------

    Congress passed the CAA, including its several amendments, to 
protect public health and welfare from ``mounting dangers,'' including 
``injury to agricultural crops and livestock, damage to and the 
deterioration of property, and hazards to air and ground 
transportation.'' \467\ In doing so, Congress established numerous 
programs to address air pollution problems and provided the EPA with 
guidance and flexibility in carrying out many of those programs. Even 
if we were to accept commenters' view that the system of emission 
reduction identified as best here is not integrated into the design or 
operation of the regulated sources, in the context of this industry and 
this pollutant it is reasonable to reject the narrow interpretation 
urged by some commenters that the ``system of emission reduction'' 
applicable to the affected EGUs must be limited to only those measures 
that can be integrated into the design or operation of the source 
itself. The plain language of the statute does not support such an 
interpretation, and to adopt it would limit the ``system of emission 
reduction'' to measures that are either substantially more expensive or 
substantially less effective at reducing emissions than the measures in 
building blocks 2 and 3, notwithstanding the absence of any statutory 
language imposing such a limit. Such a result would be contrary to the 
goals of the CAA and would ignore the facts that sources in the 
electric generation industry routinely address planning and operating 
objectives on a broad, multi-source basis using the measures in 
building blocks 2 and 3 and would seek to use building blocks 2 and 3 
(as well as non-BSER measures) to comply with whatever emission 
standards are set as a result of this rule. Indeed, as already 
observed, building blocks 2 and 3 are already being used to reduce 
emissions, and to do so specifically by operation of the industry's 
inherent multi-source functions.
---------------------------------------------------------------------------

    \467\ CAA section 101(a)(2).
---------------------------------------------------------------------------

    Although the BSER provisions are sufficiently broad to include, for 
affected EGUs, the measures in building blocks 2 and 3, they also 
incorporate significant constraints on the types of

[[Page 64762]]

measures that may be included in the BSER. We discuss those constraints 
at the end of this section. They include the section 111(d)(1) and 
(a)(1) requirements that emission reductions occur from the affected 
sources; that the emission performance standards for which the BSER 
forms the basis be achievable; that the system of emission reduction be 
adequately demonstrated; and that the EPA account for cost, non-air 
quality impacts, and energy requirements in determining the ``best'' 
system of emission reduction that is adequately demonstrated. The 
constraints included in these statutory requirements do not preclude 
building blocks 2 and 3 from the BSER. In interpreting these statutory 
requirements for determining the BSER, the EPA is consistent with past 
practice and current policy for both section 111 regulatory actions as 
well as regulatory actions under other CAA provisions for the electric 
power sector, under which the EPA has generally taken the approach of 
basing regulatory requirements on controls and measures designed to 
reduce air pollutants from the production process without limiting the 
aggregate amount of production. This approach has been inherent in our 
past interpretation and application of section 111 and we maintain this 
interpretation in this rulemaking.\468\ While inclusion of building 
blocks 2 and 3 is consistent with our interpretation of the statutory 
requirements, inclusion of building block 4 is not, and for that 
reason, we are declining to include building block in the BSER. 
Finally, we briefly note additional constraints that focus the BSER 
identified for new sources under section 111(b) on controls that assure 
that sources are well-controlled at the time of construction.
---------------------------------------------------------------------------

    \468\ As we note in section V.A., this rulemaking presents a 
unique set of circumstances, including the global nature of 
CO2 and the emission control challenges that 
CO2 presents (which limit the availability and 
effectiveness of control measures), combined with the facts that the 
electric power industry (including fossil fuel-fired steam 
generators and combustion turbines) is highly integrated, 
electricity is fungible, and generation is substitutable (which all 
facilitate the generation shifting measures encompassed in building 
blocks 2 and 3). Our interpretation of section 111 as focusing on 
limiting emissions without limiting aggregate production must take 
into account those unique circumstances.
---------------------------------------------------------------------------

    b. System of emission reduction as a broad range of measures.
    (1) Plain meaning and context of ``system of emission reduction.''
    The phrase ``system of emission reduction'' appears in the 
definition of a ``standard of performance'' under CAA section 
111(a)(1). That definition reads:

a standard for emissions of air pollutants which reflects the degree 
of emission limitation achievable through the application of the 
best system of emission reduction which (taking into account the 
cost of achieving such reduction and any nonair quality health and 
environmental impact and energy requirements) the Administrator 
determines has been adequately demonstrated.

Pursuant to this definition, it is clear that a ``system of emission 
reduction'' serves as the basis for emission limits embodied by CAA 
section 111 standards. For this reason, emission limits must be 
``achievable'' through the ``application'' of the ``best'' ``system of 
emission reduction'' ``adequately demonstrated.'' Under CAA section 
111(d)(1), such a limit is established for ``any existing source,'' 
which is defined as any existing ``building, structure, facility, or 
installation which emits or may emit any air pollutant.'' \469\
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    \469\ See CAA section 111(d)(1) (applying a standard of 
performance to any existing source); (a)(6) (defining the term 
``existing source'' as any stationary source other than a new 
source); and (a)(3) (defining the term ``stationary source'' as 
``any building, structure, facility, or installation which emits or 
may emit any air pollutant,'' however, explaining that ``[n]othing 
in subchapter II [i.e., Title II] of this chapter relating to 
nonroad engines shall be construed to apply to stationary internal 
combustion engines.'')
---------------------------------------------------------------------------

    Although a ``system of emission reduction'' lays the groundwork for 
CAA section 111 standards, the term ``system'' is not defined in the 
CAA. As a result, we look first to its ordinary meaning.
    Abstractly, the term ``system'' means a set of things or parts 
forming a complex whole; a set of principles or procedures according to 
which something is done; an organized scheme or method; and a group of 
interacting, interrelated, or interdependent elements.\470\ As a 
phrase, ``system of emission reduction'' takes a broad meaning to serve 
a singular purpose: It is a set of measures that work together to 
reduce emissions.
---------------------------------------------------------------------------

    \470\ Oxford Dictionary of English (3rd ed.) (2010), available 
at http://www.oxforddictionaries.com/us/definition/american_english/system; see also American Heritage Dictionary (5th ed.) (2013), 
available at http://www.yourdictionary.com/system#americanheritage; 
and The American College Dictionary (C.L. Barnhart, ed. 1970) (``an 
assemblage or combination of things or parts forming a complex or 
unitary whole'').
---------------------------------------------------------------------------

    When read in context, the phrase ``system of emission reduction'' 
carries important limitations: because the ``degree of emission 
limitation'' must be ``achievable through the application of the best 
system of emission reduction,'' (emphasis added), the ``system of 
emission reduction'' must be limited to a set of measures that work 
together to reduce emissions and that are implementable by the sources 
themselves.
    As a practical matter, the ``source'' includes the ``owner or 
operator'' of any building, structure, facility, or installation for 
which a standard of performance is applicable. For instance, under CAA 
section 111(e), it is the ``owner or operator'' of a source who is 
prohibited from operating ``in violation of any standard of performance 
applicable to such source.'' \471\
---------------------------------------------------------------------------

    \471\ While this section provides for enforcement in the context 
of new sources, a CAA section 111(d) plan must provide for the 
enforcement of a standard of performance for existing sources.
---------------------------------------------------------------------------

    Thus, a ``system of emission reduction'' for purposes of CAA 
section 111(d) means a set of measures that source owners or operators 
can implement to achieve an emission limitation applicable to their 
existing source.\472\
---------------------------------------------------------------------------

    \472\ Some commenters read the proposed rulemaking as taking the 
position that the phrase ``system of emission reduction'' includes 
anything whatsoever that reduces emissions, and criticized that 
interpretation as too broad. See UARG comment, at 3-4. We are not 
taking that interpretation here. In this final rule, we agree that 
the phrase should be limited to exclude, inter alia, actions beyond 
the ability of the owners/operators to control.
---------------------------------------------------------------------------

    In contrast, a ``system of emission reduction'' does not include 
actions that only a state or other governmental entity could take that 
would have the effect of reducing emissions from the source category, 
and that are beyond the ability of the affected sources' owners/
operators to take or control. Additionally, actions that a source owner 
or operator could take that would not have the effect of reducing 
emissions from the source category, such as purchasing offsets, would 
also not qualify as a ``system of emission reduction.''
    Building blocks 2 and 3 each fall within the meaning of a ``system 
of emission reduction'' because they consist of measures that the 
owners/operators of the affected EGUs can implement to achieve their 
emission limits. In doing so, the affected EGUs will achieve the 
overall emission reductions the EPA identifies in this rule. We 
describe these building block 2 and 3 measures in detail elsewhere in 
this rule, including the specific actions that owners/operators of 
affected EGUs can take to implement the measures.
    It should be noted that defining the scope of a ``system of 
emission reduction'' is not the end of our inquiry under CAA section 
111(a)(1); rather, as noted above, a standard of performance must 
reflect the application of the ``best system of emission reduction . . 
. adequately demonstrated.'' (Emphasis

[[Page 64763]]

added.) Thus, in determining the BSER, the Administrator must first 
determine whether the available systems of emission reduction are 
``adequately demonstrated,'' based on the criteria, described above, 
set out by Congress in the legislative history and the D.C. Circuit in 
case law. After identifying the ``adequately demonstrated'' systems of 
emission reduction, the Administrator then selects the ``best'' of 
these, based on several factors, including amount of emission 
reduction, cost, non-air quality health and environmental impact and 
energy requirements. Only after the Administrator weighs all of these 
considerations can she determine the BSER and, based on that, establish 
a standard of performance under CAA section 111(b) or an emission 
guideline under CAA section 111(d).
    For purposes of this final rule, it is not necessary to enumerate 
all of the types of measures that do or do not constitute a ``system of 
emission reduction.'' What is relevant is that building blocks 2 and 3 
each qualify as part of the ``system of emission reduction.'' As noted, 
they focus on supply-side activities and they each constitute measures 
that the affected EGUs can implement that will allow those EGUs to 
achieve the degree of emission limitation that the EPA has identified 
based on those building blocks. Further, these building blocks also 
satisfy the other statutory criteria enumerated in CAA section 
111(a)(1).
    (2) Other indications that the BSER provisions encompass a broad 
range of measures.
    The EPA's plain meaning interpretation that the BSER provisions in 
CAA section 111(d)(1) and (a)(1) are designed to include a broad range 
of measures, including building blocks 2 and 3, is supported by several 
other indications in the CAA and the legislative history of section 
111.
    (a) Scope of CAA section 111(d)(1).
    First, the broad scope of CAA section 111(d)(1) supports our 
interpretation of the BSER because a wide range of control measures is 
appropriate for the wide range of source categories and air pollutants 
covered under CAA section 111(d).
    In the 1970 CAA Amendments, Congress established a regulatory 
regime for existing stationary sources of air pollutants that may be 
envisioned as a three-legged stool, designed to address ``three 
categories of pollutants emitted from stationary sources'': (1) 
Criteria pollutants (identified under CAA section 109 and regulated 
under section 110); (2) hazardous air pollutants (identified and 
regulated under section 112); and (3) ``pollutants that are (or may be) 
harmful to public health or welfare but are not'' criteria or hazardous 
air pollutants.\473\ Congress enacted CAA section 111(d) to cover this 
third category of air pollutants and, in this sense, Congress designed 
it to apply to any air pollutants that were not otherwise regulated as 
toxics or NAAQS pollutants.\474\ This would include air pollutants that 
the EPA might later, when more information became available, designate 
as NAAQS or hazardous air pollutants, as well as air pollutants that 
Congress may not have been aware of at the time.\475\ In addition, the 
indications are that Congress expected CAA section 111(d) to be a 
significant source of regulatory activity, by some measures, more 
active than CAA section 112. This is evident because Congress expected 
that CAA section 111(d) would cover more air pollutants than either CAA 
section 109/110 (criteria pollutants) or CAA section 112 (hazardous air 
pollutants).\476\ In addition, in the 1990 CAA Amendments, Congress 
enacted CAA section 129 to achieve emission reductions from a major 
source category, solid waste incinerators, and established CAA section 
111(d) as the basic mechanism for that provision. The EPA subsequently 
promulgated a number of CAA section 129/111(d) rulemakings.\477\ 
Finally, it should be noted that Congress designed CAA section 111(d) 
to cover a wide range of source categories--including any source 
category that the EPA identifies under subsection 111(b)(1)(A) as 
meeting the criteria of, in general, causing or contributing 
significantly to air pollution that may reasonably be anticipated to 
endanger public health or welfare--along with the wide range of air 
pollutants.
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    \473\ 40 FR 53340, 53340 (Nov. 17, 1975) (EPA regulations 
implementing CAA section 111(d)).
    \474\ See S. Rep. No. 91-1196, at 20 (Sept. 17, 1970), 1970 CAA 
Legis. Hist. at 420 (``It should be noted that the emission 
standards for pollutants which cannot be considered hazardous (as 
defined in section 115 [i.e., the bill's version of CAA section 112] 
could be established under section 114 [i.e., the bill's version CAA 
section 111]. Thus, there should be no gaps in control activities 
pertaining to stationary source emissions that pose any significant 
danger to public health or welfare.'').
    \475\ See S. Rep. No. 91-1196, at 20 (Sept. 17, 1970), 1970 CAA 
Legis. Hist. at 420.
    \476\ See S. Rep. No. 91-1196, at 9; 18-20, 1970 CAA Legis. 
Hist. at 418-20. The Senate Committee Report identified 14 
substances as subject to the provision that became section 111(d), 
four substances as hazardous air pollutants that would be regulated 
under the provision that became section 112, and 5 substances as 
criteria pollutants that would be regulated under the provisions 
that became sections 109-110 (and more ``as knowledge increases''). 
In particular, the Report recognized that in particular, relatively 
few air pollutants may qualify as hazardous air pollutants, but that 
other air pollutants that did not qualify as hazardous air 
pollutants would be regulated under what became section 111(d).
    \477\ See, e.g., Standards of Performance for New Stationary 
Sources and Emission Guidelines for Existing Sources: Hospital/
Medical/Infectious Waste Incinerators, 62 FR 48348, 48359 (Sept. 15, 
1997); Standards of Performance for New Stationary Sources and 
Emission Guidelines for Existing Sources: Commercial and Industrial 
Solid Waste Incineration Units, 65 FR 75338, 75341 (Dec. 1, 2000).
---------------------------------------------------------------------------

    Because Congress designed CAA section 111(d) to cover a wide range 
of air pollutants--including ones that Congress may not have been aware 
of at the time it enacted the provision--and a wide range of 
industries, it is logical that Congress intended that the BSER 
provision, as applied to CAA section 111(d), have a broad scope so as 
to accommodate the range of air pollutants and source categories.
    (b) Legislative history of CAA section 111.
    (i) Breadth of ``system of emission reduction.''
    The phrase ``system of emission reduction,'' particularly as 
applied under CAA section 111(d), should be broadly interpreted 
consistent with its plain meaning but also in light of its legislative 
history. The version of CAA section 111(d)(1) that Congress adopted as 
part of the 1970 CAA Amendments read largely as CAA section 111(d)(1) 
does at present, except that it required states to impose ``emission 
standards'' on any existing source. (Congress replaced that term with 
``standards of performance'' in the 1977 CAA Amendments.) The 1970 CAA 
Amendments version of CAA section 111(d)(1) neither defined ``emission 
standards'' nor imposed restrictions on the EPA in determining the 
basis for the emission standards.\478\
---------------------------------------------------------------------------

    \478\ Although not defined under CAA section 111, the term was 
used in other provisions and defined in some of them. The term was 
defined under the CAA's citizen suit provision. See 1970 CAA 
Amendments, Pub. L. 91-604, Sec.  12, 84 Stat. 1676, 1706 (Dec. 31, 
1970) (defined as ``(1) a schedule or timetable of compliance, 
emission limitation, standard of performance or emission standard, 
or (2) a control or prohibition respecting a motor vehicle fuel or 
fuel additive . . . . .''). Congress also used it in the CAA's NAAQS 
provisions and in CAA section 112. Under the CAA's NAAQS provisions 
(i.e., the ``Ambient Air Quality and Emission Standards'' 
provisions), Congress directed the EPA to issue information on ``air 
pollution control techniques,'' and include data on ``available 
technology and alternative methods of prevention and control of air 
pollution'' as well as on ``alternative fuels, processes, and 
operating methods which will result in elimination or significant 
reduction of emissions.'' Id., Sec.  4, 84 Stat. at 1679. Similarly, 
under CAA section 112, the Administrator was required to ``from time 
to time, issue information on pollution control techniques for air 
pollutants'' subject to emission standards. Id., 84 Stat. at 1685. 
These statements provide additional context for the term's broad 
intent.
---------------------------------------------------------------------------

    For new sources, CAA section 111(b)(1)(B), as enacted in the 1970 
CAA Amendments (and as it largely still

[[Page 64764]]

reads), required the EPA to promulgate ``standards of performance,'' 
and defined that term, much like the present definition, as emission 
standards based on the ``best system of emission reduction . . . 
adequately demonstrated.'' This quoted phrase was not included in 
either the House or Senate versions of the provision, and, instead, was 
added during the joint conference between the House and Senate. The 
conference report accompanying the text offers no clarifications.
    The House and Senate bills do, however, provide some insights. The 
House bill, H.R. 17255, would have required new sources of non-
hazardous air pollutants to ``prevent and control such emissions to the 
fullest extent compatible with the available technology and economic 
feasibility, as determined by the Secretary.'' \479\ The Senate bill, 
S. 4358, would have established ``Federal standards of performance for 
new sources,'' which, in turn, were to ``reflect the greatest degree of 
emission control which the Secretary determines to be achievable 
through application of the latest available control technology, 
processes, operating methods, or other alternatives.'' \480\ The Senate 
Committee Report explains that ``performance standards should be met 
through application of the latest available emission control technology 
or through other means of preventing or controlling air pollution.'' 
\481\ This Report further elaborates that the term ``standards of 
performance''

    \479\ H.R. 17255, Sec.  5, 1970 CAA Legis. Hist. at 921-22. The 
reference to ``Secretary'' was to the Secretary of Health Education 
and Welfare, which, at the time, was the agency with responsibility 
for air pollution regulations.
    \480\ S. 4358, Sec.  6, 1970 Legis. Hist. at 554-55 (emphasis 
added).
    \481\ S. Rep. No. 91-1196, at 15-16 (Sept. 17, 1970), 1970 CAA 
Legis. Hist. at 415-16 (emphasis added).

refers to the degree of emission control which can be achieved 
through process changes, operation changes, direct emission control, 
or other methods. The Secretary should not make a technical judgment 
as to how the standard should be implemented. He should determine 
the achievable limits and let the owner or operator determine the 
most economic, acceptable technique to apply.\482\
---------------------------------------------------------------------------

    \482\ S. Rep. No. 91-1196, at 15-16 (Sept. 17, 1970), 1970 CAA 
Legis. Hist. at 415-16 (emphasis added).

Thus, the Senate bill clearly envisioned that standards of performance 
would not be based on a particular technology or even a particular 
method to prevent or control air pollution.\483\ This vision contrasted 
with the House bill, which would have restricted performance standards 
to economically feasible technical controls.
---------------------------------------------------------------------------

    \483\ Notably, the Senate report identifies pollution control 
and pollution prevention as objectives of the Senate provision. 
Pollution prevention is discussed more generally below as a 
``primary purpose'' of the CAA, however, the report makes clear that 
pollution prevention measures--which the EPA understands to include 
such measures as building blocks 2 and 3--are appropriate under CAA 
section 111.
---------------------------------------------------------------------------

    Following the House-Senate Conference, the enacted version of the 
legislation defined a ``standard of performance'' to mean

a standard for emissions of air pollutants which reflects the degree 
of emission limitation achievable through the application of the 
best system of emission reduction which (taking into account the 
cost of achieving such reduction) the Administrator determines has 
been adequately demonstrated.\484\
---------------------------------------------------------------------------

    \484\ CAA section 111(a)(1) under the 1970 CAA Amendments 
(emphasis added).

While the phrase ``system of emission reduction'' was not discussed in 
the Conference Report, an exhibit titled ``Summary of the Provisions of 
Conference Agreement on the Clean Air Amendments of 1970'' was added to 
the record during the Senate's consideration of the Conference Report 
and sheds some light on the phrase. According to the summary, ``[t]he 
agreement authorizes regulations to require that new major industry 
plants such as power plants, steel mills, and cement plants achieve a 
standard of emission performance based on the latest available control 
technology, processes, operating methods, and other alternatives.'' 
\485\ In light of this summary, the phrase ``system of emission 
reduction'' appears to blend the broad spirit of S. 4358 (which 
required the ``latest available control technology, processes, 
operating methods, or other alternatives'') with the cost concerns 
identified in H.R. 17255 (which required consideration of ``economic 
feasibility'' when establishing federal emission standards for new 
stationary sources). This history strongly suggests that Congress 
intended to authorize the EPA to consider a wide range of measures in 
calculating a standard of performance for stationary sources. At a 
minimum, there is no indication that Congress intended to preclude 
measures or actions such as the ones in building blocks 2 and 3 from 
the EPA's assessment of the BSER.
---------------------------------------------------------------------------

    \485\ Sen. Muskie, S. Consideration of H.R. Conf. Rep. No. 91-
1783 (Dec. 17, 1970), 1970 CAA Legis. Hist. at 130.
---------------------------------------------------------------------------

    Notwithstanding this broad approach, as we discuss in the Legal 
Memorandum, the legislative history of the 1970 CAA Amendments also 
indicates that Congress intended that new sources be well-controlled at 
the source, in light of their expected lengthy useful lives.
    In 1977, Congress amended CAA section 111(a)(1) to limit the types 
of controls that could be the basis of standards of performance for new 
sources to technological controls. Congress was clear, however, that 
existing source standards, which were no longer developed as ``emission 
standards,'' would not be limited to technological measures. 
Specifically, the 1977 CAA Amendments revised CAA section 111(a)(1) to 
require all new sources to meet emission standards based on the 
reductions achievable through the use of the ``best technological 
system of continuous emission reduction.'' \486\ According to the 
legislative history, [t]his mean[t] that new sources may not comply 
merely by burning untreated fuel, either oil or coal.'' \487\ The new 
requirement stemmed in part from Congress's concern over the shocks 
that the country experienced during the 1973-74 Arab Oil Embargo, which 
led Congress to revise CAA section 111 to ``encourage and facilitate 
the increased use of coal, and to reduce reliance (by new and old 
sources alike), upon petroleum to meet emission requirements.'' \488\ 
Imposing a new technological requirement (along with a new percentage 
reduction requirement) under CAA section 111 was designed to ``force 
new sources to burn high-sulfur fuel thus freeing low-sulfur fuel for 
use in existing sources where it is harder to control emissions and 
where low-sulfur fuel is needed for compliance.'' \489\ Congress 
nonetheless recognized that despite narrowing new source standards to 
the best ``technological system of continuous emission reduction,'' 
many ``innovative approaches may in fact reduce the economic and energy 
impact of emissions control,'' and the Administrator should still be 
encouraged to consider other technologically based techniques for 
emissions reduction, including ``precombustion cleaning or treatment of 
fuels.'' \490\ This is discussed in more detail below.
---------------------------------------------------------------------------

    \486\ CAA section 111(a)(1) (1977).
    \487\ H.R. Rep. No. 95-294 (May 12, 1977), 1977 CAA Legis. Hist. 
at 2659.
    \488\ H.R. Rep. No. 95-294 (May 12, 1977), 1977 CAA Legis. Hist. 
at 2659.
    \489\ New Stationary Sources Performance Standards; Electric 
Utility Steam Generating Units, 44 FR 33580, 33581-33582 (June 11, 
1979).
    \490\ H.R. Rep. No. 95-294, at 189 (May 12, 1977), 1977 CAA 
Legis. Hist. at 2656.
---------------------------------------------------------------------------

    Despite these changes with respect to new sources, the 1977 CAA 
Amendments further reinforce the

[[Page 64765]]

notion that with respect to existing sources, the BSER was never 
intended to be narrowly applied. In 1977, Congress changed CAA section 
111(d)(1) to require that states adopt ``standards of performance'' and 
made clear that such standards were to be based on the ``best system of 
continuous emission reduction . . . adequately demonstrated,'' \491\ 
but generally maintained the breadth of that term. Although Congress 
inserted the word ``continuous'' into the phrase, Congress explained 
that ``standards in the Section 111(d) state plan would be based on the 
best available means (not necessarily technological) for categories of 
existing sources to reduce emissions.'' \492\ This was intended to 
distinguish existing source standards from new source standards, for 
which ``the requirement for [BSER] has been more narrowly redefined as 
best technological system of continuous emission reduction.'' 
493 494
---------------------------------------------------------------------------

    \491\ CAA section 111(a)(1)(C) under the 1977 CAA Amendments.
    \492\ H.R. Rep. No. 95-294 (May 12, 1977), 1977 CAA Legis. Hist. 
at 2662 (emphasis added). Congress also endorsed the EPA's practice 
of establishing ``emission guidelines'' under CAA section 111(d). 
See H.R. Rep. No. 95-294 (May 12, 1977), 1977 CAA Legis. Hist. at 
2662 (``The Administrator would establish guidelines as to what the 
best system for each such category of existing sources is. However, 
the state would be responsible for determining the applicability of 
such guidelines to any particular source or sources.'').
    \493\ Sen. Muskie, S. Consideration of the H.R. Conf. Rep. No. 
95-564 (Aug. 4, 1977), 1977 CAA Legis. Hist. at 353.
    \494\ In 1977, Congress added a new substantive definition for 
``emission standard'' generally applicable throughout the CAA. 1977 
CAA Amendments, Public Law 95-95, Sec.  301, 91 Stat. 685, 770 (Aug. 
7, 1977) (defining ``emission limitation'' and ``emission standard'' 
as ``a requirement established by the State or the Administrator 
which limits the quantity, rate, or concentration of emissions of 
air pollutants on a continuous basis, including any requirement 
relating to the operation or maintenance of a source to assure 
continuous emission reduction.''). Congress also added a generally 
applicable definition of standard of performance, defined as ``a 
requirement of continuous emission reduction, including any 
requirement relating to the operation or maintenance of a source to 
assure continuous emission reduction.'' Id.
---------------------------------------------------------------------------

    In the 1990 CAA Amendments, Congress restored the 1970s vintage 
definition of a standard of performance as applied to both new and 
existing sources. With respect to existing sources, this had the effect 
of no longer requiring that the BSER be ``continuous.'' \495\ Further, 
nothing in the 1990 CAA Amendments or their legislative history 
indicates that Congress intended to impose new constraints on the types 
of systems of emission reduction that could be considered under CAA 
section 111(d)(1) and (a)(1). In contrast, Congress retained the 
definition of the term ``technological system of continuous emission 
reduction,'' which means ``a technological process for production or 
operation by any source which is inherently low-polluting or 
nonpolluting,'' CAA section 111(a)(7)(A), or ``a technological system 
for continuous reduction of the pollution generated by a source before 
such pollution is emitted into the ambient air, including precombustion 
cleaning or treatment of fuels,'' CAA section 111(a)(7)(B).
---------------------------------------------------------------------------

    \495\ We note that the general definition of a standard of 
performance at CAA section 302(l) still uses ``continuous.'' Even if 
this provision applies to section 111, it does not affect our 
analysis in this rule, including our interpretation that BSER 
includes building blocks 2 and 3.
---------------------------------------------------------------------------

    That term continues to be used in reference to new sources in 
certain circumstances, under CAA section 111(b), (h), and (j).\496\ 
However, it is not and never has been used to regulate existing 
sources. In this manner, the 1990 CAA Amendments further reinforce the 
breadth and flexibility of the phrase ``system of emission reduction,'' 
particularly as it applies to existing sources under CAA section 
111(d).
---------------------------------------------------------------------------

    \496\ There are numerous reasons to find that particular CAA 
section 111(b) standards of performance should be based on controls 
installed at the source at the time of new construction. This is due 
in part to the recognition that new sources have long operating 
lives over which initial capital costs can be amortized, as 
recognized in the legislative history for section 111. Thus, new 
construction is the preferred time to drive capital investment in 
emission controls. See, e.g., S. Rep. No. 91-1196, at 15-16, 1970 
CAA Legis. Hist. at 416 (``[t]he overriding purpose of this section 
[concerning new source performance standards] would be to prevent 
new air pollution problems, and toward that end, maximum feasible 
control of new sources at the time of their construction is seen by 
the committee as the most effective and, in the long run, the least 
expensive approach.''); see also 1977 CAA Amendments, Sec.  109, 91 
Stat. at 700, (redefining, with respect to new sources, CAA section 
111(a)(1) to reflect the best ``technological system of continuous 
emission reduction'' and adding CAA section 111(a)(7) to define this 
new term). However, as a result of the 1990 revisions to CAA section 
111(a)(1), which replaced the phrase ``technological system of 
continuous emission reduction'' with ``system of emission 
reduction,'' new source standards would not be restricted to being 
based on technological control measures.
---------------------------------------------------------------------------

    For these reasons, the 1970, 1977, and 1990 legislative histories 
support the EPA's interpretation in this rule that the term is 
sufficiently broad to encompass building blocks 2 and 3.
    (ii) Reliance on actions taken by other entities.
    The legislative history supports the EPA's interpretation of 
``system of emission reduction'' in another way as well: The 
legislative history makes clear that Congress intended that standards 
of performance for electric power plants could be based on measures 
implemented by other entities, for example, entities that ``wash,'' or 
desulfurize, coal (or, for oil-fired EGUs, that desulfurize oil). This 
legislative history is consistent with the EPA's view that the ``system 
of emission reduction'' may include actions taken by an entity with 
whom the owner/operator of the affected source enters into a 
contractual relationship as long as those actions allow the affected 
source to meet its emission limitation. By the same token, this 
legislative history directly refutes commenters' assertions that the 
phrase ``system of emission reduction'' must not include actions taken 
by entities other than the affected sources.\497\
---------------------------------------------------------------------------

    \497\ See, e.g., comments by UARG at 31 (the building blocks 
other than building block 1 take a `` `beyond-the-source' approach'' 
and ``impermissibly rely on measures that go beyond the boundaries 
of individual affected EGUs and that are not within the control of 
individual EGU owners and operators''); comments by American 
Chemistry Council et al. (``Associations'') at 60-61 (EPA's proposed 
BSER analysis is unlawful because it ``looks beyond the fence line 
of the fossil fuel-fired EGUs that are the subject of this 
rulemaking;'' ``the standard of performance must . . . be limited to 
the types of actions that can be implemented directly by an existing 
source within [the appropriate] class or category.'').
---------------------------------------------------------------------------

    As noted above, in the 1977 CAA Amendments, Congress revised the 
basis for standards of performance for new fossil fuel-fired stationary 
sources to be a ``technological system of continuous emission 
reduction,'' including ``precombustion cleaning or treatment of 
fuels.'' \498\ Precombustion cleaning or treatment reduces the amount 
of sulfur in the fuel, which means that the fuel can be combusted with 
fewer SO2 emissions, and that in turn means that the source 
can achieve a lower emission limit. Congress understood that these fuel 
cleaning techniques would not necessarily be accomplished at the 
affected source and, in revising CAA section 111(a)(1), wanted to 
ensure that such techniques would not be overlooked. For example, the 
1977 House Committee report indicates that an assessment of the best 
technological system of continuous emission reduction for fossil fuel-
fired power plants would include off-site or third-party pre-combustion 
techniques for reducing emissions at the source (``e.g., various coal-
cleaning technologies such as solvent refining, oil desulfurization at 
the refinery'').\499\

[[Page 64766]]

Thus, the standard of performance reflecting the best technological 
system implementable by an affected source could be based, in part, on 
technologies used at off-site facilities owned and operated by third-
parties.
---------------------------------------------------------------------------

    \498\ 1977 CAA Amendments, Sec.  109, 91 Stat. at 700; see also 
CAA section 111(a)(7).
    \499\ H.R. Rep. No. 95-294 (May 12, 1977), 1977 CAA Legis. Hist. 
at 2655 (emphasis added). Generally speaking, coal cleaning 
activities also are conducted by third parties. For instance, EPA 
recognized in a regulatory analysis of new source performance 
standards for industrial-commercial-institutional steam generating 
units that the technology ``requires too much space and is too 
expensive to be employed at individual industrial-commercial-
institutional steam generating units.'' U.S. EPA, Summary of 
Regulatory Analysis for New Source Performance Standards: 
Industrial-Commercial-Institutional Steam Generating Units of 
Greater than 100 Million Btu/hr Heat Input, EPA-450/3-86-005, p. 4-4 
(June 1986).
---------------------------------------------------------------------------

    In the 1990 CAA Amendments, Congress eliminated many of the 
restrictions and other provisions added in the 1977 CAA Amendments by 
largely reinstating the 1970 CAA Amendments' definition of ``standard 
of performance.'' Nevertheless, there is no indication that in doing 
so, Congress intended to preclude the EPA from considering coal 
cleaning by third parties (which had been considered within the scope 
of the best system of emission reduction even under the 1970 CAA 
Amendments),\500\ and in fact, the EPA's regulations promulgated after 
the 1990 CAA Amendments continue to impose standards of performance 
that are based on third-party coal cleaning.\501\
---------------------------------------------------------------------------

    \500\ See U.S. EPA, Background Information for Proposed New-
Source Performance Standards: Steam Generators, Incinerators, 
Portland Cement Plants, Nitric Acid Plants, Sulfuric Acid Plants, 
Office of Air Programs Tech. Rep. No. APTD-0711, p. 7 (Aug. 1971) 
(indicating the ``desirability of setting sulfur dioxide standards 
that would allow the use of low-sulfur fuels as well as fuel 
cleaning, stack-gas cleaning, and equipment modifications'' 
(emphasis added)).
    \501\ 40 CFR 60.49b(n)(4); see also Amendments to New Source 
Performance Standards (NSPS) for Electric Utility Steam Generating 
Units and Industrial-Commercial-Institutional Steam Generating 
Units; Final Rule, 72 FR 32742 (June 13, 2007).
---------------------------------------------------------------------------

    (c) Consistency of a broad interpretation of CAA section 111 with 
the overall structure of the CAA.
    Interpreting CAA section 111(d)(1) and (a)(1) to authorize the 
EPA's consideration of the building block 2 and 3 measures is 
consistent with the overall structure of the CAA, particularly as it 
was amended in 1970, when Congress added CAA section 111 in much the 
same form that it reads today.
    In the 1970 CAA Amendments, for the most part, and particularly for 
stationary source provisions, Congress painted with broad brush 
strokes, giving broad authority to the EPA or the states. That is, 
Congress established general requirements that were intended to produce 
stringent results, but gave the EPA or the states great discretion in 
fashioning the types of measures to achieve those results.
    For example, under CAA section 109, Congress authorized the EPA to 
promulgate national ambient air quality standards (NAAQS) for air 
pollutants, and Congress established general criteria and procedural 
requirements, but left to the EPA discretion to identify the air 
pollutants and select the standards. Under CAA section 110, Congress 
required the states to submit to the EPA SIPs, required that the plans 
attain the NAAQS by a date certain, and established procedural 
requirements, but allowed the states broad discretion in determining 
the substantive requirements of the SIPs.
    Under CAA section 111(b), Congress directed the EPA to list source 
categories that endanger public health or welfare and established 
procedural requirements, but did not include other substantive 
requirements, and instead gave the EPA broad discretion to determine 
the criteria for endangerment.
    Under CAA section 112, Congress required the EPA to regulate 
certain air pollutants and to set ``emission standards'' that meet 
general criteria, and established procedural requirements, but did not 
include other substantive requirements and, instead, gave the EPA broad 
discretion in identifying the types of pollutants and in determining 
the standards.\502\ By and large, Congress left these provisions intact 
in the 1977 CAA Amendments.503 504
---------------------------------------------------------------------------

    \502\ By comparison, under the 1990 CAA Amendments, Congress 
substantially transformed CAA section 112 to be significantly more 
prescriptive in directing EPA rulemaking, which reflected Congress's 
increased knowledge of hazardous air pollutants and impatience with 
the EPA's progress in regulating.
    \503\ In the 1977 CAA Amendments, Congress applied the same 
broad drafting approach to the stratospheric ozone provisions it 
adopted in CAA sections 150-159. There, Congress authorized the EPA 
to determine whether, ``in the Administrator's judgment, any 
substance, practice, process, or activity may reasonably be 
anticipated to affect the stratosphere, especially ozone in the 
stratosphere, and such effect may reasonably be anticipated to 
endanger public health or welfare,'' and then directed the EPA, if 
it made such a determination, to ``promulgate regulations respecting 
the control of such process practice, process, or activity. . . .'' 
CAA section 157(a). This provision does not further specify 
requirements for the regulations.
    \504\ On the other hand, in those instances in which Congress 
had a clear idea as to the emission limitations that it thought 
should be imposed, it mandated those emission limits, e.g., in Title 
II concerning motor vehicles.
---------------------------------------------------------------------------

    Congress drafted the CAA section 111(d) requirements in the 1970 
CAA Amendments, and revised them in the 1977 CAA Amendments, in a 
manner that is similar to the other stationary source requirements, 
just described, in CAA sections 109, 110, 111(b), and 112. The CAA 
section 111(d) requirements are broadly phrased, include procedural 
requirements but no more than very general substantive requirements, 
and give broad discretion to the EPA to determine the basis for the 
required emission limits and to the states to set the standards. It 
should be noted that this drafting approach is not unique to the CAA; 
on the contrary, Congress ``usually does not legislate by specifying 
examples, but by identifying broad and general principles that must be 
applied to particular factual instances.'' \505\
---------------------------------------------------------------------------

    \505\ Pub. Citizen v. U.S. Dept. of Justice, 491 U.S. 440, 475 
(1989) (Kennedy, J., concurring).
---------------------------------------------------------------------------

    In light of this statutory framework, it is clear that Congress 
delegated to the EPA the authority to administer CAA section 111, 
including by authorizing the EPA to apply the ``broad and general 
principles'' contained in CAA section 111(a)(1) to the particular 
circumstances we face today.
    (3) Comments and responses.
    While some commenters support the EPA's interpretation of section 
111 to authorize the inclusion of building blocks 2 and 3 in the BSER, 
other commenters assert that the emission standards must be based on 
measures that the sources subject to CAA section 111--in this rule, the 
affected EGUs--apply to their own design or operations, and, as a 
result, in this rule, cannot include measures implemented at entities 
other than the affected EGUs that have the effect of reducing 
generation, and therefore emissions, from the affected EGUs. The 
commenters assert that various provisions in CAA section 111 make this 
limitation clear. We do not find those arguments persuasive.
    First, some commenters state that under CAA section 111(d)(1) and 
(a)(1), the existing sources subject to the standards of performance 
must be able to achieve their emission limit, but that they are able to 
do so only through measures integrated into the source's own design and 
operation. As a result, according to these commenters, those are the 
only types of measures that may qualify as a ``system of emission 
reduction'' that may form the basis of the emissions standards. We 
disagree. We see nothing in CAA section 111(d)(1) or (a)(1) which by 
its terms limits CAA section 111 to measures that must be integrated 
into the sources' own design or operation. Rather, we recognize that in 
order for an emission limitation based on the BSER to be 
``achievable,'' the BSER must consist of measures that can be 
undertaken by an affected source--that is, its owner or operator. As 
noted elsewhere in the

[[Page 64767]]

preamble, the affected sources subject to this rule are fully able to 
meet their emission standards by undertaking the measures described in 
all three building blocks. Moreover, as discussed, the measures in 
building blocks 2 and 3 are highly effective in achieving 
CO2 emission reductions from these affected EGUs, given the 
unique characteristics of the industry. This reinforces the conclusion 
that the term ``system of emission reduction'' is broad enough to 
include these measures.
    The broad nature of CAA section 111(d)(1) and (a)(1) is also 
confirmed by comparing it to CAA provisions that explicitly require 
controls on the design or operations of an affected source. The most 
notable comparison is at CAA section 111(a)(7). The term 
``technological system of continuous emission reduction,'' which was 
added in 1977 and remains as a separately defined term means, in part, 
``a technological process for production or operation by any source 
which is inherently low-emitting or nonpolluting.'' (Emphasis added.) 
With respect to this portion of the definition (and ignoring the 
additional text, which includes ``precombustion cleaning or treatment 
of fuels'' and clearly encompasses off-site activities), it could be 
argued that between 1977 and 1990 new source performance standards 
should be restricted to measures that could be integrated into the 
design or operation of a source. However, commenters' assertion that 
the BSER must be limited in a similar fashion ignores the deliberate 
change in 1990 to restore the broader definition of a standard of 
performance (i.e., that it be based on the BSER and not the TSCER). In 
any case, the narrower scope of CAA section 111(a)(7) was never 
applicable to the regulation of existing sources under CAA section 
111(d).
    Several other examples of standard setting in the CAA shed light on 
ways in which Congress has constrained the EPA's review. CAA section 
407(b)(2) provides that the EPA base NOX emission limits for 
certain types of boilers ``on the degree of reduction achievable 
through the retrofit application of the best system of continuous 
emission reduction.'' (Emphasis added.) Likewise, in determining best 
available retrofit technology under CAA section 169A, the state (or 
Administrator) must ``take into consideration the costs of compliance, 
the energy and nonair quality environmental impacts, any existing 
pollution control technology in use at the source, the remaining useful 
life of the source, and the degree of improvement in visibility which 
may reasonably be anticipated to result from the use of such 
technology.'' \506\ (Emphasis added.) These provisions make clear that 
Congress knew how to constrain the basis for emission limits to 
measures that are integrated into the design or operation of the 
affected source, and that its choice to base CAA section 111(d)(1) and 
(a)(1) standards of performance on a ``system of emission reduction'' 
indicates Congress' intent to authorize a broader basis for those 
standards.
---------------------------------------------------------------------------

    \506\ Even under BART, the EPA is authorized to allow emissions 
trading between sources. See, e.g., 40 CFR 51.308(e)(1) & (2); Util. 
Air Reg. Group v. EPA, 471 F.3d 1333 (D.C. Cir. 2006); Ctr. for 
Econ. Dev. v. EPA, 398 F.3d 653 (D.C. Cir. 2005); and Cent. Ariz. 
Water Dist. v. EPA, 990 F.2d 1531 (9th Cir. 1993).
---------------------------------------------------------------------------

    Some commenters also argue that other provisions in CAA section 111 
indicate that Congress intended that CAA section 111(d)(1) and (a)(1) 
be limited to measures that are integrated into the source's design or 
operations. This argument is unpersuasive for several reasons. First, 
it would be unreasonable to presume that Congress intended to limit the 
BSER, indirectly through these other provisions, to measures that are 
integrated into the affected source's design or operations, when 
Congress could have done so expressly, as it did for the above-
discussed CAA section 407(b)(2) NOX requirements.
    Second, the interpretations that commenters offer for these various 
provisions misapply the text. For example, commenters note that under 
CAA section 111(d)(1), (a)(3), and (a)(6), the standards of performance 
apply to ``any existing source,'' and an ``existing source'' is defined 
to include ``any stationary source,'' which, in turn, is defined as 
``any building, structure, facility, or installation which emits or may 
emit any air pollutant.'' Commenters assert that these applicability 
and definitional provisions indicate that the BSER provisions in CAA 
section 111(d)(1) and (a)(1) must be interpreted to require that the 
control measures must be integrated into the design or operations of 
the source itself.
    We disagree. These applicability and definitional provisions are 
jurisdictional in nature. Their purpose is simply to identify the types 
of sources whose emissions are to be addressed under CAA section 
111(d), i.e., stationary sources, as opposed to other types of sources, 
e.g., mobile sources, whose emissions are addressed under other CAA 
provisions (such as CAA Title II). This purpose is made apparent by the 
terms of CAA section 111(a)(3), which contains two sentences (the 
second of which commenters seem to ignore). The first sentence 
provides: ``The term `stationary source' means any building, structure, 
facility, or installation which emits or may emit any air pollutant.'' 
The second sentence provides: ``Nothing in subchapter II of this 
chapter relating to nonroad engines shall be construed to apply to 
stationary internal combustion engines.'' This second sentence explains 
that stationary internal combustion engines are to be regulated under 
CAA section 111, and not Title II (relating to mobile sources), which 
confirms that the purpose of the definition of stationary source is 
jurisdictional in nature--to identify the emissions that are to be 
regulated under section 111, as opposed to other CAA provisions.
    These applicability and definitional provisions say nothing about 
the system of emission reduction--whether it is limited to measures 
integrated into the design or operation of the source itself or may be 
broader--that may form the basis of the standards for those emissions 
that are to be promulgated under CAA section 111.
    Third, this argument by commenters does not account for the 
commonsense proposition that it is the owner/operator of the stationary 
source, not the source itself, who is responsible for taking actions to 
achieve the emission rate, so that actions that the owner/operator is 
able to take should be considered in determining the appropriate 
standards for the source's emissions. Again, it is common sense that 
buildings, structures, facilities, and installations can take no 
actions--only owners and operators can install and maintain pollution 
control equipment; only owners and operators can solicit precombustion 
cleaning or treatment of fuel services; and only owners and operators 
can apply for a permit or trade allowances.\507\ Other provisions in 
CAA section 111 make clear the role of the owner/operator. CAA section 
111(e) provides that for new sources, the burden of compliance falls on 
the ``owner or operator.'' \508\ The same is necessarily true for 
existing sources. This supports the EPA's view that the basis for 
whether a control measure qualifies as a ``system of emission 
reduction'' under CAA section 111(d)(1)

[[Page 64768]]

and (a)(1) is whether it is something that the owner/operator can 
implement in order to achieve the emissions standard assigned to the 
source--if so, the control measure should qualify as a ``system of 
emission reduction''--and not whether the control measure is integrated 
into the source's own design or operation.
---------------------------------------------------------------------------

    \507\ Industry commenters also acknowledged that it is the owner 
or operator that implements the control requirements. See UARG 
comment at 19 (section 111(d) ``provides for the regulation of 
individual emission sources through performance standards that are 
based on what design or process changes an individual source's owner 
can integrate into its facility'').
    \508\ CAA section 111(e) provides: (``[I]t shall be unlawful for 
any owner or operator of any new source to operate such source in 
violation of any [applicable] standard of performance.'')
---------------------------------------------------------------------------

    Commenters also argue that CAA section 111(h), which authorizes 
``design, equipment, work practice or operational standard[s]'' 
(together, ``design standards'') only when a source's emissions are not 
emitted through a conveyance or cannot be measured, makes clear that 
CAA section 111 standards of performance must be based on measures 
integrated into a source's own design or operations. We disagree. CAA 
section 111(h) concerns the relatively rare situation in which an 
emission standard, which entails a numerical limit on emissions, is not 
appropriate because emissions cannot be measured, due either to the 
nature of the pollutant (i.e., the pollutant is not emitted through a 
conveyance) or the nature of the source category (i.e., the source 
category is not able to conduct measurements). CAA section 111(h) 
provides that in such cases, the EPA may instead impose design 
standards rather than establish an emission standard (i.e., the EPA can 
require sources to implement a particular design, equipment, work 
practice, or operational standard). When an emissions standard is 
appropriate, as in the present rule, CAA section 111(h) is silent as to 
what types of measures--whether limited to a source's own design or 
operations--may be considered as the system of emission reduction.\509\ 
In any event, CAA section 111(h) applies only to standards promulgated 
by the Administrator, and therefore appears by its terms to be limited 
to CAA section 111(b) rulemakings for new, modified, or reconstructed 
sources, not CAA section 111(d) rulemakings for existing sources.
---------------------------------------------------------------------------

    \509\ For this same reason, the fact that CAA section 111(h) 
authorizes the EPA to impose certain types of standards--such as, 
among others, work practice or operational standards--only in 
limited circumstances not present in this rulemaking, does not mean 
that the EPA cannot consider those same measures as the BSER in 
promulgating a standard of performance.
---------------------------------------------------------------------------

    Some commenters identify other provisions of CAA section 111 that, 
in their view, prove that CAA section 111 is limited to control 
measures that are integrated within the design or operations of the 
source. We do not find those arguments persuasive, for the reasons 
discussed in the supporting documents for this rule.
    Commenters also argue, more generally, that Congress knew how to 
authorize control measures such as RE, as indicated by Congress's 
inclusion of those measures in Title IV (relating to acid rain), so the 
fact that Congress did not explicitly include these measures in the 
BSER provisions of CAA section 111(d)(1) and (a)(1) indicates that 
Congress did not intend that they be included as part of the BSER, and 
instead intended that the BSER be limited to measures integrated into 
the sources' design or operations. This argument misses the mark. The 
provisions of CAA section 111(d)(1) and (a)(1) do not explicitly 
include any specific emission reduction measures--neither RE measures 
(like the ones Congress wanted to incentivize under Title IV), nor 
measures that are integrated into the sources' design or operations 
(like the retrofit control measures Congress required under CAA section 
407(b)). But this contrast with other CAA provisions does not mean that 
Congress did not intend the BSER to include any of those types of 
measures. Rather, this contrast supports viewing a ``system of emission 
reduction'' under CAA section 111 as sufficiently broad to encompass a 
wide range of measures for the purpose of emission reduction of a wide 
range of pollutants from a wide range of stationary sources.\510\
---------------------------------------------------------------------------

    \510\ It should also be noted that Title IV is limited to 
particular pollutants (i.e., SO2 and NOX) and 
particular sources--fossil fuel-fired EGUs--and as a result, lends 
itself to greater specificity about the types of control measures. 
Section 111(d), in contrast, applies to a wide range of source 
types, which, as discussed above, supports reading it to authorize a 
broad range of control measures.
---------------------------------------------------------------------------

    c. Deference to interpret the BSER to include building blocks 2 and 
3.
    To the extent that it is not clear whether the phrase ``system of 
emission reduction'' may include the measures in building blocks 2 and 
3, the EPA's interpretation of CAA section 111(d) and (a) is reasonable 
\511\ in light of our discretion to determine ``whether and how to 
regulate carbon-dioxide emissions from power plants . . . .'' \512\
---------------------------------------------------------------------------

    \511\ EPA v. EME Homer City Generation, L.P., 134 S. Ct. 1584, 
1603 (2014) (``We routinely accord dispositive effect to an agency's 
reasonable interpretation of ambiguous statutory language.'').
    \512\ American Electric Power Co. v. Connecticut, 131 S. Ct. 
2527, 2538 (2011) (``AEP'') (emphasis added).
---------------------------------------------------------------------------

    Our interpretation that a ``system of emission reduction'' for the 
affected EGUs may include building blocks 2 and 3 is a reasonable 
construction of the statute for the reasons described above and in this 
section below.
    (1) Consistency of building blocks 2 and 3 with the structure of 
the utility power sector.
    (a) Integration of the utility power sector.
    Certain characteristics of the utility power sector are of central 
importance for understanding why the measures of building blocks 2 and 
3 qualify as part of the system of emission reduction. As discussed 
above, electricity is highly substitutable and the utility power sector 
is highly integrated, so much so that it has been likened to a 
``complex machine.'' \513\ Specifically, the utility power sector is 
characterized by physical, as well as operational, interconnections 
between electricity generators themselves, and between those generators 
and electricity users. Because of the physical properties of 
electricity and the current low availability of large scale electricity 
storage, generation and load (or use) must be instantaneously balanced 
in real time. As a result, the utility power sector is uniquely 
characterized by extensive planning and highly coordinated operation. 
These features have been present for decades, and in fact, over time, 
the sector has become more highly integrated. Another important 
characteristics of the utility power sector is that although the states 
have developed both regulated and de-regulated markets, the generation 
of electricity reflects a least-cost dispatch approach, under which 
electricity is generated first by the generators with the lowest 
variable cost.
---------------------------------------------------------------------------

    \513\ S. Massoud Amin, ``Securing the Electricity Grid,'' The 
Bridge, Spring 2010, at 13, 14; Phillip F. Schewe, The Grid: A 
Journey Through the Heart of Our Electrified World 1 (2007).
---------------------------------------------------------------------------

    These characteristics of the sector have facilitated the overall 
objective of providing reliable electric service at least cost subject 
to a variety of constraints, including environmental constraints. 
Moreover, in each type of market, the sector has developed mechanisms, 
including the participation of institutional actors, to safeguard 
reliability and to assure least cost service.
    Congress,\514\ the Courts,\515\ the EPA in its regulatory 
actions,\516\ and states in

[[Page 64769]]

their regulatory actions \517\ have recognized the integrated nature of 
the utility power sector.
---------------------------------------------------------------------------

    \514\ See CAA section 404(f)(2)(B)(iii)(I) (conditioning a 
utility's eligibility for certain allowances on implementing an 
energy conservation and electric power plan that evaluates a range 
of resources to meet expected future demand at least cost); see also 
S. Rep. No. 101-228, at 319-20 (Dec. 20, 1989) (recognizing that 
``utilities already engage in power-pooling arrangements to ensure 
maximum flexibility and efficiency in supplying power'' to support 
the establishment of an allowance system under Title IV).
    \515\ New York v. Federal Energy Regulatory Commission, 535 U.S. 
1, at 7 (2002) (citing Brief for Respondent FERC 4-5).
    \516\ ``Stack Heights Emissions Balancing Policy,'' 53 FR 480, 
482 (Jan. 7, 1988).
    \517\ See 79 FR 34830, 34880 (June 18, 2014) (discussing State 
of California Global Warming Solutions Act of 2006, Assembly Bill 
32, http://www.leginfo.ca.gov/pub/05-06/bill/asm/ab_0001-0050/ab_32_bill_20060927_chaptered.pdf, and quoting December 27, 2013 
Letter from Mary D. Nichols, Chairman of California Air Resources 
Board, to EPA Administrator Gina McCarthy).
---------------------------------------------------------------------------

    (b) Significance of integrated utility power sector for the BSER.
    The fungibility of electricity, coupled with the integration of the 
utility power sector, means that, assuming that demand is held 
constant, adding electricity to the grid from one generator will result 
in the instantaneous reduction in generation from other generators. 
Similarly, reductions in generation from one generator lead to the 
instantaneous increase in generation from other generators. Thus, the 
operation of individual EGUs is integrated and coordinated with the 
operations of other EGUs and other sources of generation, as well as 
with electricity users. This allows for locational flexibility across 
the sector in meeting demand for electricity services. The institutions 
that coordinate planning and operations routinely use this flexibility 
to meet demand for electricity services economically while satisfying 
constraints, including environmental constraints. Because of these 
characteristics, EGU owner/operators have long conducted their 
business, including entering into commercial arrangements with third 
parties, based on the premise that the performance and operations of 
any of their facilities is substantially dependent on the performance 
and operation of other facilities, including ones they neither own nor 
operate. For example, when an EGU goes off-line to perform maintenance, 
its customer base is served by other EGUs that increase their 
generation. Similarly, if an EGU needs to assure that it can meet its 
obligations to supply a certain amount of generation, it may enter into 
arrangements to purchase that generation, if it needs to, from other 
EGUs.
    Because of this structure, fossil fuel-fired EGUs can reduce their 
emissions by taking the actions in building blocks 2 and 3. 
Specifically, fossil fuel-fired EGUs may generate or cause the 
generation of increased amounts of lower- or zero-emitting 
electricity--through contractual arrangements, investment, or 
purchase--which will back out higher-emitting generation, and thereby 
lower emissions. In addition, fossil fuel-fired EGUs may reduce their 
generation, which, given the overall emission limits this rule 
requires, will have the effect of stimulating lower- or zero-emitting 
generation.
    It should also be noted that CO2 is particularly well-
suited for building blocks 2 and 3 because it is a global, not local, 
air pollutant, so that the location where it is emitted does not affect 
its environmental impact. The U.S. Supreme Court in the UARG case 
highlighted the importance of taking account of the unique 
characteristics of CO2.\518\
---------------------------------------------------------------------------

    \518\ See Util. Air. Reg. Group v. EPA, 134 S. Ct. 2427, 2441 
(2014).
---------------------------------------------------------------------------

    In light of these characteristics of the utility power sector, as 
well as the characteristics of CO2 pollution, it is 
reasonable for the EPA to reject an interpretation of the term ``system 
of emission reduction'' that would exclude building blocks 2 and 3 from 
consideration in this rule and instead restrict consideration to 
measures integrated into each individual affected source's design or 
operation, especially since the record and other publicly available 
information makes clear that the measures in the two building blocks 
are effective in reducing emissions and are already widely used.
    As discussed above, no such restriction on the measures that can be 
considered part of a ``system of emission reduction'' is required by 
the statutory language, and the legislative history demonstrates that 
Congress intended an interpretation of the phrase broad enough to 
encompass building blocks 2 and 3. The narrow interpretation advocated 
by some commenters would permit consideration only of potential 
CO2 reduction measures that are either more expensive than 
building blocks 2 and 3 (such as the use of natural gas co-firing at 
affected EGUs or the application of CCS technology) or measures capable 
of achieving far less reduction in CO2 emissions (such as 
the heat rate improvement measures included in building block 1). 
Imposing such a restrictive interpretation--one which is not called for 
by the statute--would be inconsistent with CAA section 111's specific 
requirement that standards be based on the ``best'' system of emission 
reduction and, as discussed below, would be inconsistent with 
Congressional design that the CAA be comprehensive and address the 
major environmental issues.\519\
---------------------------------------------------------------------------

    \519\ See King v. Burwell, No. 14-114 (2015) (slip op., at 21) 
(``But in every case we must respect the role of the Legislature, 
and take care not to undo what it has done.'').
---------------------------------------------------------------------------

    The unique characteristics of the sector described above require 
coordinated action in the fundamental, primary function of EGUs--and in 
meeting current pollution control requirements to the extent that EGUs 
operate in dispatch systems that apply variable costs in determining 
dispatch--and affected EGUs necessarily already plan and operate on a 
multi-unit basis. In doing so, they already make use of building blocks 
2 and 3 to meet operational and environmental objectives in a cost-
effective manner, as further described below. CO2 is a 
global pollutant that is exceptionally well-suited to emission 
reduction efforts optimized on a broad geographic scale rather than on 
a unit-by-unit basis. It is also clear from both comments and 
communications received through the Agency's outreach efforts that 
affected EGUs will seek to use building blocks 2 and 3 to achieve 
compliance with the emission standards set in the section 111(d) plans 
following promulgation of this rule. For these reasons--and the 
additional reasons discussed below--interpreting ``system of emission 
reduction'' so as to allow consideration in this rule of only the 
individual pieces of the ``complex machine,'' and to forbid 
consideration of the ways in which the pieces actually fit and work 
together as parts of that machine, such as building blocks 2 and 3, 
cannot be justified. This is particularly so in light of the dilemma 
presented by the types of control options that commenters argue are the 
only ones authorized under section 111(a)(1), which are controls that 
apply to the design or operation of the affected EGUs themselves. On 
the one hand, the control measures in building block 1 yield only a 
small amount of emission reductions. On the other hand, control 
measures such as carbon capture and storage, or co-firing with natural 
gas, could yield much greater emission reductions, but are 
substantially more expensive than building blocks 2 and 3.
    (2) Current implementation of measures in building blocks 2 and 3.
    The requirement that the ``system of emission reduction'' be 
``adequately demonstrated'' suggests that we begin our review under CAA 
section 111(d)(1) and (a)(1) with the systems that sources are already 
implementing to reduce their emissions. As noted above, fossil fuel-
fired EGUs have long implemented, and are continuing to implement, the 
measures in building blocks 2 and 3 for various purposes, including for 
the purpose of reducing CO2 emissions \520\--

[[Page 64770]]

and certainly always with the effect of reducing emissions. This is a 
strong indicator that these measures should be considered part of a 
``system of emission reduction'' for CO2 emissions from 
these sources. The requirement that the ``system of emission 
reduction'' be ``adequately demonstrated'' indicates that the 
implementation of control mechanisms or other actions that the sources 
are already taking to reduce their emissions are of particular 
relevance in establishing the emission reduction requirements of CAA 
section 111(d)(1) and (a)(1). As a result, such measures are a logical 
starting point for consideration as a ``system of emission reduction'' 
under CAA section 111.
---------------------------------------------------------------------------

    \520\ A number of utilities have climate mitigation plans. 
Examples include National Grid, http://www2.nationalgrid.com/responsibility/how-were-doing/grid-data-centre/climate-change/; 
Exelon, http://www.exeloncorp.com/newsroom/pr_20140423_EXC_Exelon2020.aspx; PG&E, http://www.pge.com/about/environment/pge/climate/; and Austin Energy, http://austinenergy.com/wps/portal/ae/about/environment/austin-climate-protection-plan/!ut/p/a0/04_Sj9CPykssy0xPLMnMz0vMAfGjzOINjCyMPJwNjDzdzY0sDBzdnZ28TcP8DAMMDPQLsh0VAU4fG7s!/.
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    (3) Reliance in CAA Title IV on building block measures.
    Some of the building block approaches to reducing emissions in the 
utility power sector were first tested around the time that Congress 
adopted the 1970 CAA Amendments.\521\ Over time, these techniques have 
become more established within the industry, and by the 1990 CAA 
Amendments, Congress based the Title IV acid rain program for existing 
fossil fuel-fired EGUs in part on the same measures that are considered 
here.
---------------------------------------------------------------------------

    \521\ See, e.g., Shepard, Donald S., A Load Shifting Model for 
Air Pollution Control in the Electric Power Industry, Journal of the 
Air Pollution Control Association, Vol. 20:11, pp. 756-761 (November 
1970).
---------------------------------------------------------------------------

    (a) Overview.
    It is logical that in determining whether the ``system of emission 
reduction'' that Congress established in CAA section 111(d)(1) and 
(a)(1) is broad enough to include the measures in building blocks 2 and 
3 as the basis for establishing emission guidelines for fossil fuel-
fired EGUs, an inquiry should be made into the tools that Congress 
relied on in other CAA provisions to reduce emissions from those same 
sources. The most useful CAA provision to examine for this purpose is 
Title IV, which includes a nationwide cap-and-trade program under which 
coal-fired power plants must have allowances for their SO2 
emissions.
    Title IV includes several signals that it is especially relevant 
for interpreting and implementing CAA section 111(d) for purposes of 
this rule. Title IV applies to most of the same sources that this rule 
applies to--existing coal-fired EGUs and other utility boilers, as well 
as NGCC units. In addition, Congress added Title IV in the 1990 CAA 
Amendments at the same time that Congress largely reinstated the 1970-
vintage reading of section 111(a)(1) to adopt the currently applicable 
definition of a ``standard of performance,'' which is based on the 
``best system of emission reduction . . . adequately demonstrated.'' 
Moreover, Congress linked Title IV and CAA section 111 in certain 
respects. Specifically, Congress conditioned the revisions to CAA 
section 111(a)(1), i.e., eliminating the percentage reduction and most 
of the other limitations under the 1977 CAA Amendments, on the 
continued applicability of the Title IV SO2 cap, so that if 
the cap were eliminated, the changes would, by operation of law, also 
be eliminated, and the 1977 version of section 111(a)(1) would be 
reinstated.\522\ Additionally, Congress authorized the EPA to establish 
standards of performance for new and existing industrial (non-EGU) 
sources of SO2 emissions if emissions from these sources 
might exceed 1985 levels and failed to decline at the expected 
rate.\523\ While industrial sources were not required to participate 
under Title IV--they could elect to do so, under CAA section 410(a)--
Congress believed SO2 reductions from these sources were 
``an essential component of the reductions sought under [Title IV]'' 
and intended that Title IV would ``assure[ ] that these projected 
reductions occur and will not be overcome by future growth in 
emissions.'' \524\ As such, Congress viewed federal standards of 
performance as the appropriate backstop to Title IV even for sources 
that could not otherwise be regulated under CAA section 111(d).\525\ 
Together, these signals suggest that it is reasonable for the EPA to 
consider Title IV when interpreting and implementing CAA section 111.
---------------------------------------------------------------------------

    \522\ 1990 CAA Amendments, Sec.  403, 104 Stat. at 2631 
(requiring repeal of amendments to CAA section 111(a)(1) upon any 
cessation of effectiveness of CAA section 403(e), which requires new 
units to hold allowances for each ton of SO2 emitted). 
Congress believed that mandating a technological standard through 
the percentage reduction requirement in section 111(a)(1) would 
ensure the continued availability of low sulfur coal for existing 
sources. In other words, the percentage reduction requirement 
discouraged compliance with new source performance standards based 
solely on fuel shifting because it was much more costly to achieve 
the percentage reduction with lower sulfur coal. This belief was 
expressed during the 1977 CAA Amendments and is discussed above as 
part of the legislative history of section 111.
    \523\ 1990 CAA Amendments, Sec.  406, 104 Stat. at 2632-33; see 
also S. Rep. No. 101-228, at 282 (industrial source emissions 
totaled 5.6 million tons of SO2 in 1985).
    \524\ S. Rep. No. 101-228, at 345 (Dec. 20, 1989).
    \525\ To reiterate, ordinarily, standards of performance cannot 
be used to regulate SO2 emissions from existing sources 
because of the pollutant exclusions in CAA section 111(d).
---------------------------------------------------------------------------

    For present purposes, the essential features of Title IV are that 
it regulates SO2 emissions from coal-fired EGUs by adopting 
a nationwide cap of 8.95 million tons to be achieved through a tradable 
allowance system. As we explain below, the provisions of Title IV and 
its legislative history make clear that Congress based the stringency 
of the emission limitation requirement (8.95 million tons) and the 
overall structure of the approach (a cap-and-trade system) on 
Congress's recognition that the affected EGUs had a set of tools 
available to them to reduce their emissions, including through a shift 
to lower emitting generation and use of RE, along with add-on controls 
and other measures. Thus, Title IV provides a close analogy to CAA 
section 111: Generation shift and RE were part of Congress's basis for 
the Title IV emission requirements, and that is analogous to building 
blocks 2 and 3 serving as part of the ``system of emission reduction'' 
that is the EPA's basis for the section 111(d) emission guidelines. For 
this reason, the fact that in Title IV, Congress relied on generation 
shift and RE as the basis for the SO2 emission limitations 
for affected EGUs strongly supports interpreting CAA section 111(d)(1) 
and (a)(1) to include use of those same measures as part of the 
``system of emission reduction'' as the basis for CO2 
emission limitations for those same sources.
    (b) Title IV provisions.
    Several provisions of Title IV make explicit Congress's reliance on 
some of the same measures as are in building blocks 2 and 3. Title IV 
begins with a statement of congressional ``findings,'' including the 
finding that ``strategies and technologies for the control of 
precursors to acid deposition exist now that are economically feasible, 
and improved methods are expected to become increasingly available over 
the next decade.'' CAA section 401(a)(4) (emphasis added). Title IV 
then identifies as its ``purposes,'' ``to reduce the adverse effects of 
acid deposition through reductions in annual emissions of sulfur 
dioxide . . . and nitrogen oxides,'' as well as ``to encourage energy 
conservation, use of renewable and clean alternative technologies, and 
pollution prevention as a long-range strategy, consistent with the 
provisions of this subchapter, for reducing air pollution and other 
adverse impacts of energy production and use.'' CAA section 401(b) 
(emphasis added).
    By its terms, this statement of Title IV's purposes explicitly 
embraces the

[[Page 64771]]

use of RE. Moreover, the legislative history makes clear that the 
reference in the ``findings'' section quoted above to ``strategies and 
technologies'' includes generation shift to lower-emitting generation. 
Specifically, the Senate Report stated that an ``allowance system'' 
\526\ would encourage such ``technologies and strategies'' as
---------------------------------------------------------------------------

    \526\ See S. Rep. No. 101-228, at 320 (Dec. 20, 1989).

energy efficiency; enhanced emissions reduction or control 
technologies--like sorbent injection, cofiring with natural gas, 
integrated gasification combined cycles; fuel-switching and least-
emissions dispatching in order to maximize emissions reductions. 
\527\
---------------------------------------------------------------------------

    \527\ See S. Rep. No. 101-228, at 316 (Dec. 20, 1989) (emphasis 
added).

Congress's reliance on generation shifting and RE to reduce acid rain 
precursors from affected EGUs in Title IV strongly supports the EPA's 
authority to identify those same measures as part of the CAA section 
111 ``system of emission reduction'' to reduce CO2 emissions 
from those same sources.
    In addition, Title IV includes other provisions expressly 
concerning RE. In CAA section 404(f) and (g), Congress set aside a 
special pool of allowances to encourage use of RE. In order to obtain a 
special allowance (which would authorize emissions from a coal-fired 
utility), an electric utility needed to pay for qualifying RE sources 
``directly or through purchase from another person.'' \528\ These 
measures confirm Congress's recognition that RE was available to the 
industry, was desirable to encourage from a policy perspective, and was 
appropriate to consider in determining the amount of pollution 
reduction the law should require.
---------------------------------------------------------------------------

    \528\ CAA section 404(f)(2)(B)(i).
---------------------------------------------------------------------------

    (c) Title IV legislative history.
    Numerous statements in the legislative history confirm that 
Congress based the Title IV requirements on the fact that affected EGUs 
could reduce their SO2 emissions through a set of measures, 
including shifting to lower-emitting generation as well as reliance on 
RE.
    For example, the Senate Committee Report \529\ and Senator 
Baucus,\530\ a member of the Senate Committee on Environment and Public 
Works and Chairman of the House and Senate Clean Air Conferees, both 
emphasized that affected EGUs could rely on, among other things, 
``least-emissions dispatching in order to maximize emissions 
reductions.'' Similarly, statements supporting the RE reserve were 
included in the legislative history on the House side.
---------------------------------------------------------------------------

    \529\ S. Rep. No. 101-228 (Dec. 20, 1989), 1990 CAA Legis. Hist. 
at 8656.
    \530\ S. Debates on Conf. Rep. to accompany S. 1630, H.R. Rep. 
No. 101-952 (Oct. 27, 1990), 1990 CAA Legis. Hist. at 1033-35 
(statement of Senator Baucus, inserting ``the Clean Air Conference 
Report'' into the record).

    We believe that this provision of the bill will establish a 
balanced and workable approach that will provide certainty for 
utility companies that are considering conservation and renewables, 
while at the same time strengthening the environmental goals of this 
legislation.\531\
---------------------------------------------------------------------------

    \531\ H.R. Rep. No. 101-490, at 368-69; 674-76 (May 17, 1990) 
(additional views of Reps. Markey and Moorhead) (``We believe that 
H.R. 3030, as amended, will create a strong and effective incentive 
for utilities to immediately pursue energy conservation and 
renewable energy sources as key components of their acid rain 
control strategies.''); see also Rep. Collins, H. Debates on H.R. 
Conf. Rep. No. 101-952 (Oct. 26, 1990), 1990 CAA Legis. Hist. at 
1307 (``The bottom line is that our Nation's utilities and 
production facilities must reach beyond coal, oil, and fossil fuels. 
The focus must shift instead toward conservation and renewables such 
as hydropower, solar thermal, photovoltaics, geothermal, and wind. 
These clean sources and energy, available in virtually limitless 
supply, are the way of the future.'').

    (4) Reliance on RE measures to reduce CO2.
    The Title IV legislative history also makes clear that Congress 
viewed RE measures as a means to reduce CO2 for the purpose 
of mitigating climate change. By the time of the 1990 CAA Amendments, 
Congress had long been aware that emissions of CO2 and other 
GHGs put upward pressure on world temperatures and threatened to change 
the climate in destructive ways. In 1967, President Lyndon Johnson sent 
a letter to Congress recognizing that carbon dioxide was changing the 
composition of the atmosphere.\532\ The record for the 1970 CAA 
Amendments include hearings \533\ and a report by the National Academy 
of Sciences noting that carbon dioxide emissions could heat the 
atmosphere.\534\ A 1976 report noting the phenomenon was included in 
the record for the 1977 CAA Amendments.\535\ A 1977 Report by the 
National Academy of Sciences warned that average temperatures would 
rise due to the burning of fossil fuel.\536\ By the time of the 1990 
CAA Amendments, the dangers had become more clearly evident. Senate 
hearings beginning in 1988 had presented testimony from Dr. James E. 
Hansen of the National Aeronautics and Space Administration and other 
scientists that described the dangers of climate change caused by 
anthropogenic carbon dioxide and other GHG emissions and asserted that 
as a result of those emissions, the climate was in fact already 
changing.\537\
---------------------------------------------------------------------------

    \532\ ``Special Message to the Congress on Conservation and 
Restoration of Natural Beauty (Feb. 8, 1965). http://www.presidency.ucsb.edu/ws/?pid=27285 (``This generation has altered 
the composition of the atmosphere on a global scale through 
radioactive materials and a steady increase in carbon dioxide from 
the burning of fossil fuels.'').
    \533\ Testimony of Charles Johnson, Jr., Administrator of the 
Consumer Protection and Environmental Health Service (Administration 
Testimony), Hearing of the House Subcommittee on Public Health and 
Welfare (Mar. 16, 1970), 1970 CAA Legis. Hist. at 1381 (stating that 
``the carbon dioxide balance might result in the heating up of the 
atmosphere whereas the reduction of the radiant energy through 
particulate matter released to the atmosphere might cause reduction 
in radiation that reaches the earth'').
    \534\ 1970 CAA Legis. Hist. at 244, 257 S. Debate on S. 4358 
(Sept. 21, 1970) (statement of Sen. Boggs) (replicating Chapter IV 
of the Council on Environmental Quality's first annual report, which 
states, ``the addition of particulates and carbon dioxide in the 
atmosphere could have dramatic and long-term effects on world 
climate.'').
    \535\ 122 Cong. Rec. S25194 (daily ed. Aug. 3, 1976) (statement 
of Sen. Bumpers) (inserting into the record, ``Summary of Statements 
Received from Professional Societies for the Hearings on Effects of 
Chronic Pollution (in the Subcommittee on the Environment and the 
Atmosphere),'' which stated, ``there is near unanimity that carbon 
dioxide concentrations in the atmosphere are increasing rapidly. 
Though even the direction (warming or cooling) of the climate change 
to be caused by this is unknown, very profound changes in the 
balance of climate factors that determine temperature and rainfall 
on the earth are almost certain within 100 years'').
    \536\ National Academy of Sciences, ``Energy and Climate: 
Studies in Geophysics'' viii (1977), http://www.nap.edu/openbook.php?record_id=12024 (noting that a fourfold to eightfold 
increase in carbon dioxide by the latter part of the twenty-second 
century would increase average world temperature by more than 6 
degrees Celsius).
    \537\ S. Rep. No. 101-228, at 322 (Dec. 20, 1989), at 1990 
Legis. Hist. at 8662 (``In the last several years, the Committee has 
received extensive scientific testimony that increases in the human-
caused emissions of carbon dioxide and other GHGs will lead to 
catastrophic shocks in the global climate system.''); History, 
Jurisdiction, and a Summary of Activities of the Committee on Energy 
and Natural Resources During the 100th Congress, S. Rep. No. 101-
138, at 5 (Sept. 1989); ``Global Warming Has Begun, Expert Tells 
Senate,'' New York Times, June 24, 1988, http://www.nytimes.com/1988/06/24/us/global-warming-has-begun-expert-tells-senate.html.
---------------------------------------------------------------------------

    In enacting the 1990 CAA Amendments, Congress identified reductions 
in carbon dioxide emissions as an important co-benefit of the 
reductions in coal use and stressed that the RE measures would achieve 
those reductions. Senator Fowler, the author of the provision that 
established a RE technology reserve within the allowance system, noted 
that RE technologies, ``can greatly reduce emissions of . . . global 
warming gases. That makes them a potent weapon against catastrophic 
climate change . . . .'' \538\
---------------------------------------------------------------------------

    \538\ Sen. Fowler, S. Debate on S. 1630 (Apr. 3, 1990), 1990 CAA 
Legis. Hist. at 7106.
---------------------------------------------------------------------------

    In addition, the 1990 CAA Amendments required EGUs covered by the 
monitoring requirements of the Title IV acid rain program to report 
their CO2 emissions.\539\
---------------------------------------------------------------------------

    \539\ 1990 CAA Amendments, Sec.  821, 104 Stat. at 2699.

---------------------------------------------------------------------------

[[Page 64772]]

    (5) Other EPA actions that rely on the building block measures.
    Another indication that it is reasonable to interpret the CAA 
section 111(d)(1) and (a)(1) provisions for the BSER to include the 
measures in building blocks 2 and 3 is that the EPA and states have 
relied on these measures to reduce emissions in a number of other CAA 
actions.
    For example, in 2005, the EPA promulgated a rule to control mercury 
emissions from fossil fuel-fired power plants under section 111(d): The 
Clean Air Mercury Rule (CAMR).\540\ The EPA established a nationwide 
cap-and-trade program that took effect in two phases: In 2010, the cap 
was set at 38 tons per year, and in 2018, the cap was lowered to 15 
tons per year. The EPA expected, on the basis of modeling, that sources 
would achieve the second phase, 15-ton per year cap cost-effectively by 
choosing among a set of measures that included shifting generation to 
lower-emitting units.\541\ CAMR was vacated by the D.C. Circuit on 
other grounds,\542\ but it shows that in the only other section 111(d) 
rule that the EPA attempted for affected EGUs, the EPA relied on 
shifting generation as part of the BSER in a CAA section 111(d) 
rulemaking for fossil fuel-fired EGUs.
---------------------------------------------------------------------------

    \540\ 70 FR 28606 (May 18, 2005).
    \541\ 70 FR 28606, 28619 (May 18, 2005) (``Under the CAMR 
scenario modeled by EPA, units [were] projected to meet their 
SO2 and NOX requirements and take additional 
steps to address the remaining [mercury] reduction requirements 
under CAA section 111, including adding [mercury]-specific control 
technologies (model applies [activated carbon injection]), 
additional scrubbers and [selective catalytic reduction], dispatch 
changes, and coal switching.'').
    \542\ New Jersey v. EPA, 517 F.3d 574, 583-84 (D.C. Cir. 2008), 
cert. denied sub nom. Util. Air Reg. Group v. New Jersey, 555 U.S. 
1169 (2009).
---------------------------------------------------------------------------

    In 2011, the EPA promulgated the Cross State Air Pollution Rule 
(CSAPR),\543\ in which it set statewide emission budgets for 
NOX and SO2 emitted by fossil fuel-fired EGUs, 
and based those standards in part on shifts to lower-emitting 
generation. CSAPR established state-wide emissions budgets based on a 
range of cost-effective actions that EGUs could take, and set the 
stringency of the deadlines for some required reductions in part 
because of the availability of ``increased dispatch of lower-emitting 
generation which can be achieved by 2012.'' \544\ The EPA developed a 
federal implementation plan (FIP) that established a trading program to 
meet the state-wide emission budgets set by CSAPR. The EPA projected 
that sources would meet their emission reduction obligations by 
implementing a range of emission control approaches, including the 
operation of add-on controls, switches to lower-emitting coal, and 
``changes in dispatch and generation shifting from higher emitting 
units to lower emitting units.'' \545\ The U.S. Supreme Court upheld 
CSAPR in EPA v. EME Homer City Generation, L.P.\546\
---------------------------------------------------------------------------

    \543\ 76 FR 48208 (Aug. 8, 2011).
    \544\ 76 FR at 48452.
    \545\ 76 FR at 48279-80. The exact mix of controls varied for 
different air pollutants and different time periods, but in all 
cases, shifting generation from higher to lower emitting units was 
one of the expected control strategies for the fossil fuel-fired 
power plants. Prior to CSAPR, the EPA promulgated two other 
transport rules, the NOX SIP Call (1998) and the Clean 
Air Interstate Rule (CAIR) (2005), which similarly established 
standards based on analysis of the availability and cost of emission 
reductions achievable through the use of add-on controls and 
generation shifting, and also authorized and encouraged the 
implementation of RE and demand-side EE measures. CAIR: 70 FR 25162, 
25165, 25256, 25279 (May 12, 2005) (allowing use of allowance set-
asides for renewables and energy efficiency); NOX SIP 
Call: 63 FR 57356, 57362, 57436, 57438, 57449 (Oct. 27, 1998) 
(authorizing and encouraging SIPs to rely on renewables and energy 
efficiency to meet the state budgets).
    \546\ 134 S. Ct. 1584 (2014).
---------------------------------------------------------------------------

    With respect to RE, in 2004, the EPA provided guidance to states 
for adopting attainment SIPs under CAA section 110 that include RE 
measures.\547\ Some states have done so. For example, Connecticut 
included in its SIP reductions from solar photovoltaic 
installations.\548\ In 2012, the EPA provided additional guidance on 
this topic.\549\ In addition, the EPA has partnered with the Northeast 
States for Coordinated Air Use Management (NESCAUM) and three states 
(Maryland, Massachusetts, and New York) to identify opportunities for 
including RE in a SIP and to provide real-world examples and lessons 
learned through those states' case studies.\550\
---------------------------------------------------------------------------

    \547\ See, e.g., Guidance on SIP Credits for Emission Reductions 
from Electric-Sector Energy Efficiency and Renewable Energy Measures 
(Aug. 2004), http://www.epa.gov/ttn/oarpg/t1/memoranda/ereseerem_gd.pdf; Incorporating Emerging and Voluntary Measures in a 
State Implementation Plan (SIP) (Sept. 2004), http://www.epa.gov/ttn/oarpg/t1/memoranda/evm_ievm_g.pdf.
    \548\ CT 1997 8-hour ozone SIP Web site, http://www.ct.gov/deep/cwp/view.asp?a=2684&q=385886&depNav_GID=1619 (see Attainment 
Demonstration TSD, Chapter 8 at 31, http://www.ct.gov/deep/lib/deep/air/regulations/proposed_and_reports/section_8.pdf).
    \549\ ``Roadmap for Incorporating EE/RE Policies and Programs 
into SIPs/TIPs'' (July 2012), http://epa.gov/airquality/eere/manual.html.
    \550\ States' Perspectives on EPA's Roadmap to Incorporate 
Energy Efficiency/Renewable Energy in NAAQS State Implementation 
Plans: Three Case Studies, Final Report to the U.S. Environmental 
Protection Agency (Dec. 2013), http://www.nescaum.org/documents/nescaum-final-rept-to-epa-ee-in-naaqs-sip-roadmap-case-studies-20140522.pdf.
---------------------------------------------------------------------------

    (6) Other rules that relied on actions by other entities.
    The EPA has promulgated numerous actions that establish control 
requirements for affected sources on the basis of actions by other 
entities or actions other than measures integrated into the design or 
operations of the affected sources. This section summarizes some of 
those actions. First, virtually all pollution control requirements 
require the affected sources to depend in one way or another on other 
entities, such as control technology manufacturers. Second, the EPA has 
promulgated numerous regulatory actions that are based on trading of 
mass-based emission allowances or rate-based emission credits, in which 
many sources meet their emission limitation requirements by purchasing 
allowances or credits from other sources that reduce emissions.
    (a) Third-party transactions.
    To reiterate, commenters argue that the ``system of emission 
reduction'' must be limited to measures taken by the affected source 
itself because only those measures are under the control of the 
affected source, as opposed to third parties, and therefore only those 
measures can assure that the affected source will achieve its emission 
limits. But this argument is belied by the fact that for a wide range 
of pollution control measures--including many that are indisputably 
part of a ``system of emission reduction''--affected sources are in 
fact dependent on third parties. For example, to implement any type of 
add-on pollution control equipment that is available only from a third-
party manufacturer, the affected source is dependent upon that third 
party for developing and constructing the necessary controls, and for 
offering them for sale. Indeed, the affected sources may be dependent 
upon third parties to install (and in some cases to operate) the 
controls as well, and in fact, in the CAIR rule, the EPA established 
the compliance date based on the limited availability of the 
specialized workforce needed to install the controls needed by the 
affected EGUs.\551\ In addition, EGU owners and operators may be 
dependent on the actions of third parties to finance the controls and 
third-party regulators to assure the mechanism for repaying that 
financing. However, this dependence does not mean that the emission 
limit based on that equipment is not achievable. Rather, the fact that 
the owner or operator of the affected source can arrange with the 
various third parties to

[[Page 64773]]

acquire, install, and pay for the equipment means that emission limit 
is achievable.
---------------------------------------------------------------------------

    \551\ 70 FR 25162, 25216-25225 (May 12, 2005). The EPA noted 
that its view was ``based on the NOX SIP Call 
experience.'' Id. at 25217.
---------------------------------------------------------------------------

    In this rule, as noted, the affected EGUs may, in many cases, 
implement the measures in building blocks 2 and 3 directly, and, in 
other cases, implement those measures by engaging in market 
transactions with third parties that are as much within the affected 
EGUs' control as engaging in market transactions with the range of 
third parties involved in pollution control equipment. By the same 
token, the market transactions that the affected EGUs engage in with 
third parties to implement the measures in building blocks 2 and 3 are 
comparable to the market transactions that affected EGUs engage in as 
part of their normal course of business, which include, among many 
examples, transactions with RTOs/ISOs or balancing authorities, 
entities in organized markets.
    (b) Emissions trading.
    Additional precedent that the ``system of emission reduction'' may 
include the measures in building blocks 2 and 3 and is not limited to 
measures that a source can integrate into its own design or operations, 
without being dependent on other entities, is found in the many rules 
that Congress has enacted or that the EPA has promulgated that allow 
EGUs and other sources to meet their emission limits by trading with 
other sources. In a trading rule, the EPA authorizes a source to meet 
its emission limit by purchasing mass-based emission allowances or 
rate-based emission credits generated from other sources, typically 
ones that implement controls that reduce their emissions to the point 
where they are able to sell allowances or credits. As a result, the 
availability of trading reduces overall costs to the industry by 
focusing the controls on the particular sources that have the least 
cost to implement controls. For present purposes, what is relevant is 
that in a trading program, some affected sources choose to meet their 
emission limits not by implementing emission controls integrated into 
their own design or operations, but rather by purchasing allowances or 
credits. These affected sources, therefore, are dependent on the 
actions of other entities, which are the ones that choose to meet their 
emission limits by implementing emission controls, which permits them 
to sell allowances or credits. They are dependent, however, in the same 
way that a source acquiring pollution control technology for the 
purposes of meeting a NSPS is dependent on a vendor of that technology 
to fulfill its contractual obligations. That is, the source operator 
purchasing a credit or an allowance is acquiring an equity in the 
technology or action applied to the credit-selling source for purposes 
of achieving a reduction in emissions occurring at the selling source. 
Trading programs have been commonplace under the CAA, particularly for 
EGUs, for decades. They include the acid rain trading program in Title 
IV of the CAA, the trading programs in the transport rules promulgated 
by the EPA under the ``good neighbor provision'' of CAA section 
110(a)(2)(D)(i)(I), the Clean Air Mercury Rule, and the regional haze 
rules. In each of these actions, the Congress or the EPA recognized 
that some of the affected EGUs would implement controls or take other 
actions that would lower their emissions and thereby allow them to sell 
allowances to other EGUs, which were dependent on the purchase of those 
allowances to meet their obligations.\552\ For the reasons just 
described, these trading rules refute commenters' arguments for 
limiting the scope of the ``system of emission reduction.''
---------------------------------------------------------------------------

    \552\ For example, in the enacting the acid rain program under 
CAA Title IV, Congress explicitly recognized that some sources would 
comply by purchasing allowances instead of implementing controls. S. 
Rep. No. 101-228, at 303 (Dec. 20, 1989). Similarly, in promulgating 
the NOX SIP Call in 1998, the EPA stated, ``Since EPA's 
determination for the core group of sources is based on the adoption 
of a broad-based trading program, average cost-effectiveness serves 
as an adequate measure across sources because sources with high 
marginal costs will be able to take advantage of this program to 
lower their costs.'' 63 FR at 57399 (emphasis added). By the same 
token, in promulgating the Cross State Air Pollution Rule, the EPA 
stated, ``the preferred trading remedy will allow source owners to 
choose among several compliance options to achieve required emission 
reductions in the most cost effective manner, such as installing 
controls, changing fuels, reducing utilization, buying allowances, 
or any combination of these actions.'' 76 FR at 48272 (emphasis 
added).
---------------------------------------------------------------------------

    (c) NSPS rules for EGUs that depend on the integrated grid.
    The EPA has promulgated NSPS for EGUs that include requirements 
based on the fact that an EGU may reduce its generation, and therefore 
its emissions, because the integration of the grid allows another EGU 
to increase generation and thereby avoid jeopardizing the supply of 
electricity. For example, in 1979, the EPA finalized new standards of 
performance to limit emissions of SO2 from new, modified, 
and reconstructed EGUs. In evaluating the best system against concerns 
of electric service reliability, the EPA took into account the unique 
features of power transmission along the interconnected grid and the 
unique commercial relationships that rely on those features.\553\
---------------------------------------------------------------------------

    \553\ See 44 FR 33580, 33597-33600 (taking into account ``the 
amount of power that could be purchased from neighboring 
interconnected utility companies'' and noting that ``[a]lmost all 
electric utility generating units in the United States are 
electrically interconnected through power transmission lines and 
switching stations'' and that ``load can usually be shifted to other 
electric generating units'').
---------------------------------------------------------------------------

    Additionally, in 1982, the EPA recognized that utility turbines 
could meet a NOX emission limit without unacceptable 
economic consequences because ``other electric generators on the grid 
can restore lost capacity caused by turbine down time.'' \554\ We 
describe the relevant parts of these rules in greater detail in the 
Legal Memorandum.
---------------------------------------------------------------------------

    \554\ 47 FR 3767, 3768 (Jan. 27, 1982).
---------------------------------------------------------------------------

    (7) Consistency with the purposes of the Clean Air Act.
    Interpreting the term ``system of emission reduction'' broadly to 
include building blocks 2 and 3 (so that the ``best system of emission 
reduction . . . adequately demonstrated'' may include those measures as 
long as they meet all of the applicable requirements) is also 
consistent with the purposes of the CAA. Most importantly, these 
purposes include protecting public health and welfare by 
comprehensively addressing air pollution, and, particularly, protecting 
against urgent and severe threats. In addition, these purposes include 
promoting pollution prevention measures, as well as the advancement of 
technology that reduces air pollution.
    (a) Purpose of protecting public health and welfare.
    The first provisions in the Clean Air Act set out the 
``Congressional findings and declaration of purpose.'' CAA section 101. 
CAA section 101(a)(2) states the finding that ``the growth in the 
amount and complexity of air pollution brought about by urbanization, 
industrial development, and the increasing use of motor vehicles, has 
resulted in mounting dangers to the public health and welfare.'' CAA 
section 101(a)(3) states the finding that ``air pollution prevention 
(that is, the reduction or elimination, through any measures, of the 
amount of pollutants produced or created at the source) and air 
pollution control at its source is the primary responsibility of States 
and local governments.'' CAA section 101(a) states the finding that 
``Federal financial assistance and leadership is essential for the 
development of cooperative Federal, State, regional, and local programs 
to prevent and control air pollution.''
    CAA section 101(b) next states ``[t]he purposes'' of the Clean Air 
Act. The first purpose is ``to protect and enhance the

[[Page 64774]]

quality of the Nation's air resources so as to promote the public 
health and welfare and the productive capacity of its population.'' CAA 
section 101(b)(1). The second is ``to initiate and accelerate a 
national research and development program to achieve the prevention and 
control of air pollution.'' CAA section 101(b)(2). The third is ``to 
provide technical and financial assistance to State and local 
governments in connection with the development and execution of their 
air pollution prevention and control programs.'' CAA section 101(b)(3). 
The fourth is ``to encourage and assist the development and operation 
of regional air pollution prevention and control programs.'' CAA 
section 101(c) adds that ``[a] primary goal of this Act is to encourage 
or otherwise promote reasonable Federal, State, and local governmental 
actions, consistent with the provisions of this Act, for pollution 
prevention.''
    As just quoted, these provisions are explicit that the purpose of 
the CAA is ``to protect and enhance the quality of the Nation's air 
resources so as to promote the public health and welfare and the 
productive capacity of its population.'' Moreover, Congress designed 
the CAA to be ``the comprehensive vehicle for protection of the 
Nation's health from air pollution'' \555\ and, in fact, designed CAA 
section 111(d) to address air pollutants not covered under other 
provisions, specifically so that ``there should be no gaps in control 
activities pertaining to stationary source emissions that pose any 
significant danger to public health or welfare.'' \556\ Furthermore, in 
these purpose provisions, Congress recognized that while pollution 
prevention and control are the primary responsibility of the States, 
``federal leadership'' would be essential.
---------------------------------------------------------------------------

    \555\ H.R. Rep. No. 95-294, at 42 (May 12, 1977), 1977 CAA 
Legis. Hist. at 2509 (discussing a provision in the House Committee 
bill that became CAA section 122, requiring the EPA to study and 
regulate radioactive air pollutants and three other air pollutants).
    \556\ S. Rep. No. 91-1196, at 20 (Sept. 17, 1970), 1970 CAA 
Legis. Hist. at 420 (discussing section 114 of the Senate Committee 
bill, which was the basis for CAA section 111(d)).
---------------------------------------------------------------------------

    At its core, Congress designed the CAA to address urgent and severe 
threats to public health and welfare. This purpose is evident 
throughout 1970 CAA Amendments, which authorized stringent remedies 
that were necessary to address those problems. By 1970, Congress viewed 
the air pollution problem, which had been worsening steadily as the 
nation continued to industrialize and as automobile travel dramatically 
increased after World War II,\557\ as nothing short of a national 
crisis.\558\ With the 1970 CAA Amendments, Congress enacted a stringent 
response, designed to match the severity of the problem. At the same 
time, Congress did not foreclose the EPA's ability to address new 
environmental concerns; in fact, Congress largely deferred to the EPA's 
expertise in identifying pollutants and sources that adversely affect 
public health or welfare. In doing so, Congress authorized the EPA to 
establish national ambient air quality standards for the most pervasive 
air pollutants--including the precursors for the choking smog that 
blanketed urban areas \559\--to protect public health with an ample 
margin of safety. Disappointed that the states had not taken effective 
action to that point to curb air pollution, ``Congress reacted by 
taking a stick to the States'' \560\ and including within the 1970 CAA 
Amendments both the requirement that the states develop plans to assure 
that their air quality areas would meet those standards by no later 
than five years, and the threat of imposition of federal requirements 
if the states did not timely adopt the requisite plans. Congress also 
required the EPA to establish standards for hazardous air pollutants 
that could result in shutting sources down. Congress added stringent 
controls on automobiles, overriding industry objections that the 
standards were not achievable. In addition, Congress added CAA section 
111(b), which required the EPA to list categories based on harm to 
public health and regulate new sources in those categories. Congress 
then designed CAA section 111(d) to assure, as the Senate Committee 
Report for the 1970 CAA Amendments noted, that ``there should be no 
gaps in control activities pertaining to stationary source emissions 
that pose any significant danger to public health or welfare.'' \561\
---------------------------------------------------------------------------

    \557\ See Dewey, Scott Hamilton, Don't Breathe the Air: Air 
Pollution and U.S. Environmental Politics, 1945-1970 (Texas A&M 
University Press 2000).
    \558\ 1970 was a significant year in environmental legislation, 
but it was also marked as ``a year of environmental concern.'' Sen. 
Muskie, S. Debate on S. 4358 (Sept. 21, 1970), 1970 CAA Legis. Hist. 
at 223. By mid-1970, Congress recognized that ``[o]ver 200 million 
tons of contaminants [were] spilled into the air each year in 
America . . . . And each year these 200 million tons of pollutants 
endanger the health of [the American] people.'' Id. at 224. ``Cities 
up and down the east coast were living under clouds of smog and 
daily air pollution alerts.'' Sen. Muskie, S. Consideration of the 
Conference Rep. (Dec. 18, 1970), 1970 CAA Legis. Hist. at 124. Put 
simply, America faced an ``environmental crisis.'' Sen. Muskie, S. 
Debate on S. 4358 (Sept. 21, 1970), 1970 CAA Legis. Hist. at 224. 
The conference agreement, it was reported, ``faces the air pollution 
crisis with urgency and in candor. It makes hard choices, provides 
just remedies, requires stiff penalties.'' Sen. Muskie, S. 
Consideration of the Conference Rep. (Dec. 18, 1970), 1970 CAA 
Legis. Hist. at 123. ``[I]t represents [Congress'] best efforts to 
act with the knowledge available . . . in an affirmative but 
constructive manner.'' Id. at 150.
    \559\ See Dewey, Scott Hamilton, Don't Breathe the Air: Air 
Pollution and U.S. Environmental Politics, 1945-1970 (Texas A&M 
University Press 2000) at 230 (``By the mid-1960s, top federal 
officials showed an increasing sense of alarm regarding the health 
effects of polluted air. In June, 1966, Secretary of Health, 
Education, and Welfare John W. Gardner testified before the Muskie 
subcommittee: ``We believe that air pollution at concentrations 
which are routinely sustained in urban areas of the United States is 
a health hazard to many, if not all, people.'').
    \560\ Train v. NRDC, 421 U.S. 60, 64 (1975).
    \561\ S. Rep. No. 91-1196, at 20 (Sept. 17, 1970), 1970 CAA 
Legis. Hist. at 420 (discussing section 114 of the Senate Committee 
bill, which was the basis for CAA section 111(d)). Note that in the 
1977 CAA Amendments, the House Committee Report made a similar 
statement. H.R. Rep. No. 95-294, at 42 (May 12, 1977), 1977 CAA 
Legis. Hist. at 2509 (discussing a provision in the House Committee 
bill that became CAA section 122, requiring EPA to study and then 
take action to regulate radioactive air pollutants and three other 
air pollutants).
---------------------------------------------------------------------------

    Similarly, the 1977 and 1990 CAA Amendments were also designed to 
respond to new and/or pressing environmental issues. For example, in 
1977 then-EPA Administrator Costle testified before Congress that the 
expected increase in coal use (in response to various energy crises, 
including the 1973-74 Arab Oil Embargo) ``will make vigorous and 
effective control even more urgent.'' \562\ Similarly, by 1990, 
Congress recognized that ``many of the Nation's most important air 
pollution problems [had] failed to improve or [had] grown more 
serious.'' \563\ Indeed, President George H. W. Bush said that `` 
`progress has not come quickly enough and much remains to be done.' '' 
\564\
---------------------------------------------------------------------------

    \562\ Statement of Administrator Costle, Hearings before the 
Subcommittee on Energy Production and Supply of the Senate Committee 
on Energy and Natural Resources (Apr. 5, 7, May 25, June 24 and 30, 
1977), 1977 CAA Legis. Hist. at 3532 (discussing the relationship 
between the National Energy Plan and the Administration's proposed 
CAA amendments). Some of the specific changes to the CAA include the 
addition of the PSD program, visibility protections, requirements 
for nonattainment areas, and stratospheric ozone provisions.
    \563\ H.R. Rep. No. 101-490, at 144 (May 17, 1990).
    \564\ H.R. Rep. No. 101-490, at 144 (May 17, 1990). Some of the 
changes adopted in 1990 include revisions to the NAAQS nonattainment 
program, a more aggressive and substantially revised CAA section 
112, the new acid rain program, an operating permits program, and a 
program for phasing out of certain ozone depleting substances.
---------------------------------------------------------------------------

    Climate change has become the nation's most important environmental 
problem. We are now at a critical juncture to take meaningful action to 
curb the growth in CO2 emissions and forestall the impending 
consequences of prior inaction. CO2 emissions from existing 
fossil fuel-fired power plants

[[Page 64775]]

are by far the largest source of stationary source emissions. They emit 
almost three times as much CO2 as do the next nine 
stationary source categories combined, and approximately the same 
amount of CO2 emissions as all of the nation's mobile 
sources. The only controls available that can reduce CO2 
emissions from existing power plants in amounts commensurate with the 
problems they pose are the measures in building blocks 2 and 3, or far 
more expensive measures such as CCS.
    Thus, interpreting the ``system of emission reduction'' provisions 
in CAA section 111(d)(1) and (a)(1) to allow the nation to meaningfully 
address the urgent and severe public health and welfare threats that 
climate change pose is consistent with what the CAA was designed to 
do.\565\ This interpretation is also consistent with the cooperative 
purpose of section 111(d) to assure that the CAA comprehensively 
address those threats through the mechanism of state plans, where the 
states assume primary responsibility under federal leadership. See King 
v. Burwell, 576 U.S. (2015), No. 14-114 (2015), slip op. at 15 (``We 
cannot interpret federal statutes to negate their own stated purposes'' 
(quoting New York State Dept. of Social Servs. v. Dublino, 413 U.S. 
405, 419-20 (1973)); id. at 21 (``A fair reading of legislation demands 
a fair understanding of the legislative plan.'').\566\
---------------------------------------------------------------------------

    \565\ In addition, as we have noted, in designing the 1970 CAA 
Amendments, Congress was aware that carbon dioxide increased 
atmospheric temperatures. In 1970, when Congress learned that ``the 
carbon dioxide balance might result in the heating up of the 
atmosphere'' and that particulate matter ``might cause reduction in 
radiation,'' the Nixon Administration assured Congress that ``[w]hat 
we are trying to do, however, in terms of our air pollution effort 
should have a very salutary effect on either of these.'' Testimony 
of Charles Johnson, Jr., Administrator of the Consumer Protection 
and Environmental Health Service (Administration Testimony), Hearing 
of the House Subcommittee on Public Health and Welfare (Mar. 16, 
1970), 1970 CAA Legis. Hist. at 1381. Many years later, scientific 
consensus has formed around the particular causes and effects of 
climate change; and the tools put in place in 1970 can be read 
fairly to address these concerns.
    \566\ This final rule is also consistent with the CAA's purpose 
of protecting health and welfare. For example, the CAA authorizes 
the EPA to regulate air pollutants as soon as the EPA can determine 
that those pollutants pose a risk of harm, and not to wait until the 
EPA can prove that those pollutants actually cause harm. See H.R. 
Rep. No. 95-294, at 49 (May 12, 1977), 1977 CAA Legis. Hist. at 2516 
(describing the CAA as being designed . . . to assure that 
regulatory action can effectively prevent harm before it occurs; to 
emphasize the predominant value of protection of public health''). 
The protective spirit of the CAA extends to the present rule, in 
which the EPA regulates on the basis of building blocks 2 and 3 
because the range of available and cost-effective measures in those 
building blocks achieves more pollution reduction than building 
block 1 alone. Indeed, add-on controls that are technically capable 
of reducing CO2 emissions at the scale necessitated by 
the severity of the environmental risk--for example, CCS 
technology--are not as cost-effective as building blocks 2 and 3 on 
an industry-wide basis, and while the costs of the add-on controls 
can be expected to be reduced over time, it is not consonant with 
the protective spirit of the CAA to wait.
---------------------------------------------------------------------------

    (b) Purpose of encouraging pollution prevention.
    Interpreting ``system of emission reduction'' to include building 
blocks 2 and 3 is also consistent with the CAA's purpose to encourage 
pollution prevention. CAA section 101(c) states that ``[a] primary goal 
of [the CAA] is to encourage or otherwise promote reasonable federal, 
state, and local governmental actions, consistent with the provisions 
of this chapter, for pollution prevention.'' Indeed, in the U.S. Code, 
in which the CAA is codified as chapter 85, the CAA is entitled, ``Air 
Pollution Prevention and Control.'' \567\ CAA section 101(a)(3) 
describes ``air pollution prevention'' as ``the reduction or 
elimination, through any measures, of the amount of pollutants produced 
or created at the source''. (Emphasis added.) The reference to ``any 
measures'' highlights the breadth of what Congress considered to be 
pollution prevention, that is, any and all measures that reduce or 
eliminate pollutants at the source.\568\
---------------------------------------------------------------------------

    \567\ See Air Quality Act of 1967, Pub. L. 90-148, Sec.  2, 81 
Stat. 485 (Nov. 21, 1967) (adding ``Title I--Air Pollution 
Prevention and Control'' to the CAA, along with Congress' initial 
findings and purposes under CAA section 101).
    \568\ Section 101 emphasizes the importance of air pollution 
prevention in two other provisions: CAA section 101(b)(4) states 
that one of ``the purposes of [title I of the CAA, which includes 
section 111] are . . . (b) to encourage and assist the development 
and operation of regional air pollution prevention and control 
programs.'' CAA section 101(a)(3) adds: ``The Congress finds--. . . 
(3) that air pollution prevention . . . and air pollution control at 
its source is the primary responsibility of states and local 
governments.'' In fact, section 101 mentions pollution prevention no 
less than 6 times.
---------------------------------------------------------------------------

    The measures in building blocks 2 and 3 qualify as ``pollution 
prevention'' measures because they are ``any measures'' that ``reduc[e] 
or eliminate[e] . . . the amount of pollutants produced or created at 
the [fossil fuel-fired affected] source[s].'' Thus, consistent with the 
CAA's primary goals, it is therefore reasonable to interpret a ``system 
of emission reduction,'' as including the pollution prevention measures 
in building blocks 2 and 3.
    (c) Purpose of advancing technology to control air pollution.
    This final rule is also consistent with CAA section 111's purpose 
of promoting the advancement of pollution control technology based on 
the expectation that American industry will be able to develop 
innovative solutions to the environmental problems.
    The legislative history and case law of CAA section 111 identify 
three different ways that Congress designed CAA section 111 to 
authorize standards of performance that promote technological 
improvement: (i) The development of technology that may be treated as 
the ``best system of emission reduction . . . adequately 
demonstrated;'' under CAA section 111(a)(1); \569\ (ii) the expanded 
use of the best demonstrated technology; \570\ and (iii) the 
development of emerging technology.\571\ This rule is consistent with 
the second of those ways--it expands the use of the measures in 
building blocks 2 and 3, which are already established and provide 
substantial reductions at reasonable cost. As discussed below, the use 
of the measures in these building blocks will be most fully expanded 
when organized markets develop, and our expectation that those markets 
will develop is consistent with the Congress's view, just described, 
that CAA section 111 should promote technological innovation.
---------------------------------------------------------------------------

    \569\ See Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 
391 (D.C. Cir. 1973) (the best system of emission reduction must 
``look[] toward what may fairly be projected for the regulated 
future, rather than the state of the art at present'').
    \570\ See S. Rep. No. 91-1196, at 15 (``The maximum use of 
available means of preventing and controlling air pollution is 
essential to the elimination of new pollution problems'').
    \571\ See Sierra Club v. Costle, 657 F.2d at 351 (upholding a 
standard of performance designed to promote the use of an emerging 
technology).
---------------------------------------------------------------------------

    This final rule is also consistent with Congress's overall view 
that the CAA Amendments as a whole were designed to promote 
technological innovation. In enacting the CAA, Congress articulated its 
expectation that American industry would be creative and come up with 
innovative solutions to the urgent and severe problem of air pollution. 
This is manifest in the well-recognized technology-forcing nature of 
the CAA, and was expressed in numerous, sometimes ringing, statements 
in the legislative history about the belief that American industry will 
be able to develop the needed technology. For example, in the 1970 
floor debates, Congress recalled that the nation had put a man on the 
moon a year before and had won World War II a quarter century earlier, 
and attributed much of the credit for those singular achievements to 
American industry and its ability to be productive and innovative. 
Congress expressed confidence that American industry

[[Page 64776]]

could meet the challenges of developing air pollution controls as 
well.\572\
---------------------------------------------------------------------------

    \572\ Sen. Muskie, S. Debates on S. 4358 (Sept. 21, 1970), 1970 
CAA Legis. Hist. at 227 (``At the beginning of World War II industry 
told President Roosevelt that his goal of 100,000 planes each year 
could not be met. The goal was met, and the war was won. And in 
1960, President Kennedy said that America would land a man on the 
moon by 1970. And American industry did what had to be done. Our 
responsibility in Congress is to say that the requirements of this 
bill are what the health of the Nation requires, and to challenge 
polluters to meet them.''). See Blaime, A.J., The Arsenal of 
Democracy: FDR, Detroit, and an Epic Quest to Arm an America at War 
(Houghton Mifflin Harcourt 2014); Carew, Michael G., Becoming the 
Arsenal: The American Industrial Mobilization for World War II, 
1938-1942 (University Press of America, Inc. 2010).
---------------------------------------------------------------------------

    (d) Response to commenters concerning purpose.
    Commenters have stated that the proposed rule ``would transform CAA 
section 111 into something untethered to its statutory language and 
unrecognizable to the Congress that created it.'' \573\ Commenters with 
this line of comments focused on the ramifications of building block 4, 
which the EPA has decided does not belong in BSER using EPA's 
historical interpretation of BSER. Regardless of whether the comments 
are accurate with respect to building block 4 measures, they are 
certainly not accurate with respect to the three building blocks that 
the EPA is defining as the BSER. This rule would be recognizable to the 
Congresses that created and amended CAA section 111 and is carefully 
fashioned to the statutory text in CAA section 111(d) and (a)(1). This 
final rule would be recognizable to the Congress that adopted CAA 
section 111 in 1970 as part of a bold, far-reaching law designed to 
address comprehensively an air pollution crisis that threatened the 
health of millions of Americans; to have EPA and the States work 
cooperatively to develop state-specific approaches to address a 
national problem; to challenge industry to meet that crisis with 
creative energy; and to give the EPA broad authority--under section 111 
and other provisions--to craft the needed emission limitations. This 
final rule would be recognizable to the Congress that revised CAA 
section 111 in 1977 to explicitly authorize that standards be based on 
actions taken by third parties (fuel cleaners). And this final rule 
would be recognizable to the Congress that revised CAA section 111 in 
1990 to be linked to the Acid Rain Program that Congress adopted at the 
same time, which regulated the same industry (fossil fuel-fired EGUs) 
through some of the same measures (generation shifts and RE), and that 
explicitly acknowledged that those measures (RE) would also reduce 
CO2 and thereby address the dangers of climate change. To 
reiterate, for the reasons explained in this preamble, this rule is 
grounded in our reasonable interpretation of CAA section 111(d) and 
(a)(1).
---------------------------------------------------------------------------

    \573\ UARG comment at 31. See id. at 18, 29, 49. This comment 
appears to be a reference to the Supreme Court's statement in UARG. 
See Util. Air Reg. Group v. EPA, 134 S. Ct. 2427, 2444 (2014).
---------------------------------------------------------------------------

    (8) Constraints on the BSER--treatment of building block 4 and 
response to comments concerning precedents.
    Although the BSER provisions are sufficiently broad to include, for 
affected EGUs, the measures in building blocks 2 and 3, they also 
incorporate significant constraints on the types of measures that may 
be included in the BSER. We discuss those constraints in this section. 
These constaints explain why we are not including building block 4 in 
the BSER. In addition, these constraints explain why our reliance on 
building blocks 2 and 3 will have limited precedential effect for other 
rulemakings, and serve as our basis for responding to commenters who 
expressed concern that reliance on building blocks 2 and 3 would set a 
precedent for the EPA to rely on similar measures in promulgating 
future air pollution controls for other sectors.\574\
---------------------------------------------------------------------------

    \574\ Commenters offered hypothetical examples to illustrate 
their concerns over precedential effects, discussed below. Some 
commenters objected that our proposed interpretation of the BSER 
failed to include limiting principles. In the Legal Memorandum, we 
note that the statutory constraints discussed in this section of the 
preamble constitute limits on the type of the BSER that the EPA is 
authorized to determine.
---------------------------------------------------------------------------

    As discussed above, the emission limits in the CAA section 111(d) 
emission guidelines that this rule promulgates are based on the EPA's 
determination, for the affected EGUs, of the ``system of emission 
reduction'' that is the ``best,'' taking into account ``cost'' and 
other factors, and that is ``adequately demonstrated.'' Those 
components include certain interpretations and applications and provide 
constraints on the types of measures or controls that the EPA may 
determine to include in the BSER.
    (a) Emission reductions from affected sources.
    The first constraint is that the BSER must assure emission 
reductions from the affected sources. Under section 111(d)(1), the 
states must submit state plans that ``establish[] standards of 
performance for any existing source,'' and, under section 111(a)(1) and 
the EPA's implementing regulations, those standards are informed by the 
EPA's determination of the best system of emission reduction adequately 
demonstrated. Because the emission standards must apply to the affected 
sources, actions taken by affected sources that do not result in 
emission reductions from the affected sources--for example, offsets 
(e.g., the planting of forests to sequester CO2)--do not 
qualify for inclusion in the BSER. Building blocks 2 and 3 achieve 
emission reductions from the affected EGUs, and thus are not precluded 
under this constraint.
    (b) Controls or measures that affected EGUs can implement.
    The second constraint is that because the affected EGUs must be 
able to achieve their emission performance rates through the 
application of the BSER, the BSER must be controls or measures that the 
EGUs themselves can implement. Moreover, as noted, the D.C. Circuit has 
established criteria for achievability in the section 111(b) case law; 
e.g., sources must be able to achieve their standards under a range of 
circumstances. If those criteria are applicable in a section 111(d) 
rule, the BSER must be of a type that allows sources to meet those 
achievability criteria. As noted, under this rule, affected EGUs can 
achieve their emission performance rates in the various circumstances 
under which they operate, through the application of the building 
blocks.
    (c) ``Adequately demonstrated.''
    The third constraint is that the system of emission reduction that 
the EPA determines to be the best must be ``adequately demonstrated.'' 
To qualify as the BSER, controls and measures must align with the 
nature of the regulated industry and the nature of the pollutant so 
that implementation of those controls or measures will result in 
emission reductions from the industry and allow the sources to achieve 
their emission performance standards. The history of the effectiveness 
of the controls or other measures, or other indications of their 
effectiveness, are important in determining whether they are adequately 
demonstrated.
    More specifically, the application of building blocks 2 and 3 to 
affected EGUs has a number of unique characteristics. Building blocks 2 
and 3 entail the production of the same amount of the same product--
electricity, a fungible product that can be produced using a variety of 
highly substitutable generation processes--through the cleaner (that 
is, less CO2-intensive) processes of shifting dispatch from 
steam generators to existing NGCC units, and from both steam generators 
and NGCC units to renewable generators.

[[Page 64777]]

    The physical properties of electricity and the highly integrated 
nature of the electricity system allow the use of these cleaner 
processes to generate the same amount of electricity. In addition, the 
electricity sector is primarily domestic--little electricity is 
exported outside the U.S.--and there is low capacity for storage. In 
addition, the electricity sector is highly regulated, planned, and 
coordinated. As a result, holding demand constant, an increase in one 
type of generation will result in a decrease in another type of 
generation. Moreover, the higher-emitting generators, which are fossil 
fuel-fired, have higher variable costs than renewable generators, so 
that increased renewable generation will generally back out fossil 
fuel-fired generation.
    Because of these characteristics, the electricity sector has a long 
and well-established history of substituting one type of generation for 
another. This has occurred for a wide variety of reasons, many of which 
are directly related to the system's primary purposes and functions, as 
well as for environmental reasons. As a result, at present, there is a 
well-established network of business and operational relationships and 
past practices that supports building blocks 2 and 3. As noted 
elsewhere, a large segment of steam generators already have business 
relationships with existing NGCC units, and a large segment of all 
fossil fuel-fired EGUs already own, co-own, or have invested in RE.
    Many of these characteristics are unique to the utility power 
sector. Moreover, this complex of characteristics, ranging from the 
physical properties of electricity and the integrated nature of the 
grid to the institutional mechanisms that assure reliability and the 
existing practices and business relationships in the industry, combine 
to facilitate the implementation of building blocks 2 and 3 in a 
uniquely efficient manner. This supports basing the emission limits on 
the ability of owners and operators of fossil fuel-fired EGUs to 
replace their generation with cleaner generation in other locations, 
sometimes owned by other entities.
    As noted above, commenters offered hypothetical examples to 
illustrate their concerns over precedential effects. Most of their 
concerns focused on building block 4, and most of their hypothetical 
examples concerned reductions in demand for various types of products. 
We address these concerns in the response to comments document, but we 
note here that, in any event, these concerns are mooted because we are 
not finalizing building block 4. Some commenters offered hypothetical 
examples for building blocks 2 and 3 as well. For example, some 
commenters asserted that the EPA could ``develop standards of 
performance for tailpipe emissions from motor vehicles'' by ``requiring 
car owners to shift some of their travel to buses,'' which the 
commenters considered analogous to building block 2; or by ``requiring 
there to be more electric vehicle purchases,'' which the commenters 
considered analogous to building block 3.\575\
---------------------------------------------------------------------------

    \575\ UARG comment at 2-3.
---------------------------------------------------------------------------

    Commenters' concerns over precedential impact cannot be taken to 
mean that the building blocks should not be considered to meet the 
requirements of the BSER or that the affected EGUs cannot be considered 
to meet the emission limits by implementing those measures. Moreover, 
because many of these individual characteristics, and their inherent 
complexity, are unique to the utility power sector, building blocks 2 
and 3 as applied to fossil fuel-fired EGUs will have a limited 
precedent for other industries and other types of rulemakings. For 
example, the commenter's hypothetical examples noted above are 
inapposite for several reasons. The hypotheticals appear to be premised 
on government action mandating actions not implementable by emitting 
sources (e.g., that a government would ``require[e] car owners to shift 
some of their travel to buses, or . . . require[e] there to be more 
electric vehicle purchases''), whereas the measures in building blocks 
2 and 3 can be implemented by the affected EGUs. Nor have commenters 
attempted to address how car owners shifting travel to buses or 
purchasing more electric vehicles could be translated into lower 
tailpipe standards for motor vehicles.\576\
---------------------------------------------------------------------------

    \576\ In any event, it is questionable whether measures such as 
those hypothesized by the commenters would be consistent with the 
provisions of Title II.
---------------------------------------------------------------------------

    (d) ``Best'' in light of ``cost . . . nonair quality health and 
environmental impact and energy requirements'' and EPA's past practice 
and current policy.
    The fourth constraint, or set of constraints, is that the system of 
emission reduction must be the ``best,'' ``taking into account the cost 
of achieving such reduction and any nonair quality health and 
environmental impact and energy requirements.'' As noted, in light of 
the D.C. Circuit case law, the EPA has considered cost and energy 
factors on both an individual source basis and on the basis of the 
nationwide electricity sector. In determining what is ``best,'' the EPA 
has broad discretion to balance the enumerated factors.\577\ In 
interpreting and applying these provisions in this rulemaking to 
regulate CO2 emissions from affected EGUs under section 
111(d), we are acting consistently with our past practice for applying 
these provisions in previous section 111 rulemakings and for regulating 
air pollutants from the electricity sector under other provisions of 
the CAA, as well as current policy.
---------------------------------------------------------------------------

    \577\ See Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. 
Cir. 1999).
---------------------------------------------------------------------------

    The great majority of our regulations under section 111 have been 
111(b) regulations for new sources. As discussed in the Legal 
Memorandum and briefly below, the BSER identified under section 111(b) 
is designed to assure that affected sources are well controlled at the 
time of construction, and that approach is consistent with the design 
expressed in the legislative history for the 1970 CAA Amendments that 
enacted the provision.
    Traditionally, CAA section 111 standards have been rate-based, 
allowing as much overall production of a particular good as is desired, 
provided that it is produced through an appropriately clean (or low-
emitting) process. CAA section 111 performance standards have primarily 
targeted the means of production in an industry and not consumers' 
demand for the product. Thus, the focus for the BSER has been on how to 
most cleanly produce a good, not on limiting how much of the good can 
be produced.
    One example of the focus under section 111 on clean production, not 
limitation of product is provided by the revised new source performance 
standards for electric utility steam generating units that we 
promulgated in 1979 following the 1977 CAA Amendments to limit 
emissions of SO2, PM, and NOX. In relevant part, 
the revised standards limited SO2 emissions to 1.20 lb/
million BTU heat input and imposed a 90 percent reduction in potential 
SO2 emissions. This was based on the application of flue gas 
desulfurization (FGD) together with coal preparation techniques. In the 
preamble, we explain that ``[t]he intent of the final standards is to 
encourage power plant owners and operators to install the best 
available FGD systems and to implement effective operation and 
maintenance procedures but not to create power supply disruptions.'' 
578 579

[[Page 64778]]

EPA has taken the same overall approach in its section 111(d) 
rules,\580\ including the CAMR rule noted below.
---------------------------------------------------------------------------

    \578\ See, e.g., 44 FR 33580, at 33599 (June 11, 1979). In this 
rulemaking, the EPA recognized the ability of the integrated grid to 
minimize power disruptions: ``When electric load is shifted from a 
new steam-electric generating unit to another electric generating 
unit, there would be no net change in reserves within the power 
system. Thus, the emergency condition provisions prevent a failed 
FGD system from impacting upon the utility company's ability to 
generate electric power and prevents an impact upon reserves needed 
by the power system to maintain reliable electric service.'' Id.
    \579\ The EPA's 1982 revised new source performance standards 
for certain stationary gas turbines provide another example of a 
rulemaking that focused controls on reducing emissions, as well as 
reliance on the integrated grid to avoid power disruptions. 44 FR 
33580 (June 11, 1979). In response to comments that requested a 
NOX emission limit exemption for base load utility gas 
turbines, the EPA explained that ``for utility turbines . . . since 
other electric generators on the grid can restore lost capacity 
caused by turbine down time'' the NOX emission limit of 
1150 ppm for such turbines would not be rescinded. 44 FR 33580, at 
33597-98.
    \580\ See ``Phosphate Fertilizer Plants; Final Guideline 
Document Availability,'' 42 FR 12022 (Mar. 1, 1977); ``Standards of 
Performance for New Stationary Sources; Emission Guideline for 
Sulfuric Acid Mist,'' 42 FR 55796 (Oct. 18, 1977); ``Kraft Pulp 
Mills, Notice of Availability of Final Guideline Document,'' 44 FR 
29828 (May 22, 1979); ``Primary Aluminum Plants; Availability of 
Final Guideline Document,'' 45 FR 26294 (Apr. 17, 1980); ``Standards 
of Performance for New Stationary Sources and Guidelines for Control 
of Existing Sources: Municipal Solid Waste Landfills, Final Rule,'' 
61 FR 9905 (Mar. 12, 1996).
---------------------------------------------------------------------------

    Similarly, in a series of rulemakings regulating air pollutants 
from EGUs under several provisions of the CAA, we have focused our 
efforts on assuring that electricity is generated through cleaner or 
lower-emitting processes, and we have not sought to limit the aggregate 
amount of electricity that is generated. We describe those rules in 
section II, elsewhere in this section V.B.3., and in the Legal 
Memorandum.
    For example, as discussed in the Legal Memorandum, in the three 
transport rules promulgated under CAA section 110(a)(2)(D)(i)(I)--the 
NOX SIP Call, CAIR, and CSAPR--which regulated precursors to 
ozone-smog and particulate matter, the EPA based certain aspects of the 
regulatory requirements on the fact that fossil fuel-fired EGUs could 
shift generation to lower-emitting sources. In CAMR, the 2005 
rulemaking under section 111(d) regulating mercury emissions from coal-
fired EGUs, the EPA based the first phase of control requirements on 
the actions the affected EGUs were required to take under CAIR, 
including shifting generation to lower-emitting sources. In addition, 
as also discussed in the Legal Memorandum, in the EPA's 2012 MATS rule 
regulating mercury from coal-fired EGUs under section 112, at 
industry's urging, the EPA allowed compliance deadlines to be extended 
for coal-fired EGUs that desired to substitute replacement power of any 
type, including NGCC units or RE, for compliance purposes.
    While these and other rulemakings for fossil fuel-fired EGUs took 
different approaches towards lower-emitting generation and renewable 
generation, they all were based on control measures that reduced 
emissions without reducing aggregate levels of electricity generation. 
It should be noted that even though some of those rules established 
overall emission limits in the form of budgets implemented through a 
cap-and-trade program, the EPA recognized that the fossil fuel-fired 
EGUs that were subject to the rules could comply by shifting generation 
to lower-emitting EGUs, including relying on RE. In this manner, the 
rules limited emissions but on the basis that the industry could 
implement lower-emitting processes, and not based on reductions in 
overall generation.
    We are applying the same approach to this rulemaking. Our basis for 
this rulemaking is that affected EGUs can implement a system of 
emission reduction that will reduce the amount of their emissions 
without reducing overall electricity generation. This approach takes 
into account costs by minimizing economic disruption as well as the 
nation's energy requirements by avoiding the need for environmental-
based reductions in the aggregate amount of electricity available to 
the consumer, commercial, and industrial sectors.
    This approach is a reasonable exercise of the EPA's discretion 
under section 111, consistent with the U.S. Supreme Court's statements 
in its 2011 decision, American Electric Power Co. v. Connecticut, that 
the CAA and the EPA actions it authorizes displace any federal common 
law right to seek abatement of CO2 emissions from fossil-
fuel fired power plants. There, the Court emphasized that CAA section 
111 authorizes the EPA--which the Court identified as the ``expert 
agency''--to regulate CO2 emissions from fossil fuel-fired 
power plants based an ``informed assessment of competing interests . . 
. . Along with the environmental benefit potentially achievable, our 
Nation's energy needs and the possibility of economic disruption must 
weigh in the balance.'' \581\
---------------------------------------------------------------------------

    \581\ American Electric Power Co. v. Connecticut, 131 S. Ct. 
2527, 2539-40 (2011).
---------------------------------------------------------------------------

    Similarly, the D.C. Circuit, in a 1981 decision upholding the EPA's 
section 111(b) standards for air pollutants from fossil fuel-fired 
EGUs, stated that section 111 regulations concerning the electric power 
sector ``demand a careful weighing of cost, environmental, and energy 
considerations.'' \582\ This exercise of policy discretion is 
consistent with Congress's expectation that the Administrator ``should 
determine the achievable limits'' \583\ and ``would establish 
guidelines as to what the best system for each such category of 
existing sources is.'' \584\ As the D.C. Circuit explained, ``[i]t 
seems likely that if Congress meant . . . to curtail EPA's discretion 
to weigh various policy considerations it would have explicitly said so 
in section 111, as it did in other parts of the statute.'' \585\
---------------------------------------------------------------------------

    \582\ Sierra Club v. EPA, 657 F.2d 298, 406 (D.C. Cir. 1981). 
Id. at 406 n. 526.
    \583\ S. Rep. No. 91-1196, at 15-16 (Sept. 17, 1970), 1970 CAA 
Legis. Hist. at 415-16 (explaining that the ``[Administrator] should 
determine the achievable limits and let the owner or operator 
determine the most economic, acceptable technique to apply.'').
    \584\ H.R. Rep. No. 95-294, at 195 (May 12, 1977).
    \585\ Sierra Club v. Costle, 657 F.2d 298, 330 (D.C. Cir. 1981).
---------------------------------------------------------------------------

    Our interpretation that CAA section 111 targets supply-side 
activities that allow continued production of a product through use of 
a cleaner process, rather than targeting consumer-oriented behavior, 
also furthers Congress' intent of promoting cleaner production measures 
``to protect and enhance the quality of the Nation's air resources so 
as to promote the public health and welfare and the productive capacity 
of its population.'' \586\ This principle is also consistent with 
promoting ``reasonable . . . governmental actions . . . for pollution 
prevention.'' \587\
---------------------------------------------------------------------------

    \586\ CAA section 101(b)(1).
    \587\ CAA section 101(c).
---------------------------------------------------------------------------

    In this rule, we are applying that same approach in interpreting 
the BSER provisions of section 111. That is, we are basing the 
regulatory requirements on measures the affected EGUs can implement to 
assure that electricity is generated with lower emissions, taking into 
account the integrated nature of the industry and current industry 
practices. Building blocks 1, 2 and 3 fall squarely within this 
paradigm; they do not require reductions in the total amount of 
electricity produced.
    We recognize that commenters have raised extensive legal concerns 
about building block 4. We recognize that building block 4 is different 
from building blocks 1, 2, and 3 and the pollution control measures 
that we have considered under CAA section 111. Accordingly, under our 
interpretation of section 111, informed by our past practice and 
current policy, today's final action excludes building block 4 from the 
BSER. Building block 4 is outside our paradigm for section 111 as it 
targets

[[Page 64779]]

consumer-oriented behavior and demand for the good, which would reduce 
the amount of electricity to be produced.
    Although numerous commenters urged us to include demand-side EE 
measures as part of the BSER, as we had proposed to do, we conclude 
that we cannot do so under our historical practice, current policy, and 
current approach to interpreting section 111 as well as our historical 
practice in regulating the electricity sector under other CAA 
provisions. While building blocks 2 and 3 are rooted in our past 
practice and policy, building block 4 is not and would require a change 
(which we are not making) in our interpretation and implementation and 
application of CAA section 111.
    Excluding demand-side EE measures from the BSER has the benefit of 
allaying legal and other concerns raised by commenters, including 
concerns that individuals could be ``swept into'' the regulatory 
process by imposing requirements on ``every household in the land.'' 
\588\ While building block 4 could have been implemented without 
imposing requirements on individual households, this final rule 
resolves any doubt on this matter and is not based on the inclusion of 
demand-side EE as part of the BSER.
---------------------------------------------------------------------------

    \588\ See Util. Air Reg. Group v. EPA, 134 S. Ct. 2427, 2436 
(2014).
---------------------------------------------------------------------------

    By the same token, we are not finalizing reduced generation of 
electricity overall as the BSER. Instead, components of the BSER focus 
on shifting generation to lower- or zero-emitting processes for 
producing electricity.\589\
---------------------------------------------------------------------------

    \589\ As discussed below, however, reduced generation remains 
important to this rule in that it is one of the methods for 
implementing the building blocks.
---------------------------------------------------------------------------

    (e) Constraints for new sources.
    For new sources, practical and policy concerns support the 
interpretation of basing the BSER on controls that new sources can 
install at the time of construction, so that they will be well-
controlled throughout their long useful lives. This approach is 
consistent with the legislative history. We discuss this at greater 
length in the Legal Memorandum.
4. Relationship Between a Source's Implementation of Building Blocks 2 
and 3 and Its Emissions
    In this section, we discuss the relationship between an affected 
EGU's implementation of the measures in building blocks 2 and 3 and 
that affected EGU's own generation and emissions. As discussed above, 
an affected EGU subject to a CAA section 111(d) state plan that imposes 
an emission rate-based standard may achieve that standard in part by 
implementing the measures in building block 2 (for a steam generator) 
and building block 3 (for a steam generator or combustion turbine). 
That is, an affected EGU may invest in low- or zero-emitting generation 
and may apply credits from that generation against its emission rate. 
Those credits reduce the affected EGU's emission rate and thereby help 
it to achieve its emission limit.
    In addition, the additional low- or zero-emitting generation that 
results from the affected EGU's investment will generally displace 
higher-emitting generation. This is because, as described above, 
higher-emitting generation generally has higher variable costs, 
reflecting its fuel costs, than, at least, zero-emitting generation. 
Displacement of higher-emitting generation will lower overall 
CO2 emissions from the source category of affected EGUs.
    If an affected EGU implements building block 2 or 3 by reducing its 
own generation, it will reduce its own emissions. However, the affected 
EGU may also or alternatively choose to implement building block 2 or 3 
by investing in lower- or zero-emitting generation that does not, in 
and of itself, reduce the amount of its own generation or emissions. 
Even so, implementation of building blocks 2 and 3 will reduce 
CO2 from some affected EGUs, and therefore reduce 
CO2 on a source category-wide basis.
    This outcome is, however, consistent with the requirements of CAA 
section 111(d)(1) and (a)(1). To reiterate, CAA section 111(d)(1) 
requires that ``any existing source'' have a ``standard of 
performance,'' defined under CAA section 111(a)(1) as ``a standard for 
emissions of air pollutants which reflects the degree of emission 
limitation achievable through the application of the best system of 
emission reduction . . . adequately demonstrated [BSER] . . . .'' These 
provisions require by their terms that ``any existing source'' must 
have a ``standard of performance,'' but nothing in these provisions 
requires a particular amount--or, for that matter, any amount--of 
emission reductions from each and every existing source. That the 
``standard of performance'' is defined on the basis of the ``degree of 
emission limitation achievable through the application of the [BSER]'' 
does not mean that each affected EGU must achieve some amount of 
emission reduction, for the following reasons.
    The cornerstone of the definition of the term ``standard of 
performance'' is the BSER. In determining the BSER, the EPA must 
consider the amount of emission reduction that the system may achieve, 
and must consider the ability of the affected EGUs to achieve the 
emission limits that result from the application of the BSER. The EPA 
is authorized to include in the BSER, for this source category, the 
measures in building blocks 2 and 3 because, when applied to the source 
category, these measures result in emission standards that may be 
structured to ensure overall emission reductions from the source 
category and remain achievable by the affected EGUs. This remains so 
regardless of whether the ``degree of emission limitation achievable 
through the application of the [BSER]'' by any particular source 
results in actual emission reductions from that source.
    The application of the building blocks has an impact that is 
similar to that of an emissions trading program, under which, overall, 
the affected sources reduce emissions, but any particular source does 
not need to reduce its emissions and, in fact, may increase its 
emissions, as long as it purchases sufficient credits or allowances 
from other sources. In fact, we expect that many states will carry out 
their obligations under this rule by imposing standards of performance 
that incorporate trading or other multi-entity generation-replacement 
strategies. Indeed, any emission rate-based standard may not 
necessarily result in emission reductions from any particular affected 
source (or even all of the affected sources in the category) as a 
result of the ability of the particular source (or even all of them) to 
increase its production and, therefore, its emissions, even while 
maintaining the required emission rate.
5. Reduced Generation and Implementation of the BSER
    In the proposed rulemaking, we described the BSER as the measures 
included in building block 1 as well the set of measures included in 
building blocks 2, 3 and 4 or, in the alternative, reduced generation 
or utilization by the affected EGUs in the amount of building blocks 2, 
3 and 4. In this final rule, based on the comments and further 
evaluation, we are refining our approach to the BSER. Specifically, we 
are determining the BSER as the combination of measures included in 
building blocks 1, 2, and 3.Building blocks 2 and 3 entail substitution 
of lower-emitting generation for higher-emitting generation, which 
ensures that aggregate production levels can continue to meet demand 
even where an individual affected EGU decreases its

[[Page 64780]]

own output to reduce emissions. The amount of generation from the 
increased utilization of existing NGCC units determines a portion of 
the amount of reduced generation that affected fossil fuel-fired steam 
EGUs could undertake to achieve building block 2, and the amount of 
generation from the use of expanded lower- or zero-emitting generating 
capacity that could be provided, determines a portion of the amount of 
reduced generation that affected fossil fuel-fired steam EGUs, as well 
as the entire amount of reduced generation that affected NGCC units 
could undertake to implement building blocks 2 and 3. This section 
discusses the reasons that reduced generation is one of the set of 
reasonable and well-established actions that an affected EGU can 
implement to achieve its emission limits. We are not finalizing our 
proposal that reduced overall generation of electricity may by itself 
be considered the BSER, for the reason that reduced generation by 
itself does not fit within our historical and current interpretation of 
the BSER. Specifically, reduced generation by itself is about changing 
the amount of product produced rather than producing the same product 
with a process that has fewer emissions.
    a. Background. As noted, for both rate-based and mass-based state 
plans, affected EGUs may take a set of actions to comply with their 
emission standards. An affected EGU may comply with an emission rate-
based standard (e.g., a limit on the amount of CO2 per MWh) 
by acquiring, through one means or another, credits from lower- or 
zero-emitting generation (building blocks 2 or 3) to reduce its 
emission rate for compliance purposes. In addition, the affected EGU 
may reduce its generation, and if it does so, it then needs to acquire 
fewer of those credits to meet its emission rate.\590\ Under these 
circumstances, the affected EGU would in effect replace part of its 
higher-emitting generation with lower- or zero-emitting generation. On 
the other hand, an affected EGU that is subject to a mass-based 
standard--for example, a requirement to hold enough allowances to cover 
its emissions (e.g., one allowance for each ton of emissions in any 
year)--may comply at least in part by reducing its generation and, 
thus, its emissions. Therefore, one type of action that an affected EGU 
may take to achieve either of these emission limits is to reduce its 
generation. Further, reduced generation by individual sources offers a 
pathway to compliance in and of itself. That is, a state may adopt a 
mass-based goal, assign mass-based standards to its sources, and those 
sources may comply with their mass-based limits by, in addition to 
implementing building block 1 measures, reducing their generation in 
the appropriate amounts, and without taking any other actions.
---------------------------------------------------------------------------

    \590\ An affected EGU that is subject to an emission rate, e.g., 
pounds of CO2 per MWh generated, cannot achieve that rate 
simply by reducing its generation (unless it shuts down, in which 
case it would achieve a zero emission rate). This is because 
although reducing generation results in fewer emissions, it does 
not, by itself, result in fewer emissions per MWh generated.
---------------------------------------------------------------------------

    b. Well-established use of reduced generation to comply with 
environmental requirements. Reduced generation is a well-established 
method for individual fossil fuel-fired power plants to comply with 
their emission limits.
    Reduced generation in the amounts contemplated in this rule, as 
undertaken by individual sources to achieve their emission limits, 
reduces emissions from the affected sources, but because of the 
integrated and interconnected nature of the power sector, can be 
accommodated without significant cost or disruption. The electric 
transmission grid interconnects the nation's generation resources over 
large regions. Electric system operators coordinate, control, and 
monitor the electric transmission grid to ensure cost-effective and 
reliable delivery of power. These system operators continuously balance 
electricity supply and demand, ensuring that needed generation and/or 
demand resources are available to meet electricity demand. Diverse 
resources generate electricity that is transmitted and distributed 
through a complex system of interconnected components to end-use 
consumers.
    The electricity system was designed to meet these core functions. 
The three components of the electricity supply system--generation, 
transmission and distribution--coordinate to deliver electricity from 
the point of generation to the point of consumption. This 
interconnectedness is a fundamental aspect of the nation's electricity 
system, requiring a complicated integration of all components of the 
system to balance supply and demand and a federal, state and local 
regulatory network to oversee the physically interconnected network. 
Electricity from a diverse set of generation resources such as natural 
gas, nuclear, coal and renewables is distributed over high-voltage 
transmission lines. The system is planned and operated to ensure that 
there are adequate resources to meet electricity demand plus additional 
available capacity over and above the capacity needed to meet normal 
peak demand levels. System operators have a number of resources 
potentially available to meet electricity demand, including electricity 
generated by electric generation units of various types as well as 
demand-side resources. Importantly, if generation is reduced from one 
generator, safeguards are in place to ensure that adequate supply is 
still available to meet demand. We describe these safeguards in the 
background section of this preamble.
    Both Congress and the EPA have recognized reduced generation as one 
of the measures that fossil fuel-fired EGUs may implement to reduce 
their emissions of air pollutants and thereby achieve emission limits. 
Congress, in enacting the allowance requirements in CAA Title IV, under 
which fossil fuel-fired EGUs must hold an allowance for each ton of 
SO2 emitted, explicitly recognized that fossil fuel-fired 
EGUs could meet this requirement by reducing their generation. In fact, 
Congress anticipated that fossil fuel-fired EGUs may choose to comply 
with the SO2 emission limits by reducing utilization, and 
included provisions that specifically addressed reduced utilization. 
For example, CAA section 408(c)(1)(B) includes requirements for an 
owner or operator of an EGU that meets the Phase 1 SO2 
reduction obligations and the NOX reduction obligations ``by 
reducing utilization of the unit as compared with its baseline or by 
shutting down the unit.''
    The EPA has also recognized in several rulemakings limiting 
emissions from fossil fuel-fired EGUs that reduced generation is one of 
the methods of emission reduction that an EGU was expected to rely on 
to achieve its emission limitations. Examples include rulemakings to 
impose requirements that sources implement BART to reduce their 
emissions of air pollutants that cause or contribute to visibility 
impairment. As explained earlier, for certain older stationary sources 
that cause or contribute to visibility impairment, including fossil 
fuel-fired EGUs, states must determine BART on the basis of five 
statutory factors, such as costs and energy and non-air quality 
impacts.\591\ In 1980, the EPA promulgated a regulatory definition of 
BART: ``an emission limitation based on the degree of reduction 
achievable through the best system of continuous emission reduction for 
each pollutant which is emitted by an existing stationary facility.'' 
\592\ Both the statutory factors and the regulatory definition resemble 
the definition of the BSER under CAA section 111(a)(1)

[[Page 64781]]

(although, as noted, the statutory definition of BART is more 
technology focused than the definition of BSER). In its regional haze 
SIP, the State of New York determined that BART for the NOX 
emissions from two coal-fired boilers that served as peaking units was 
caps on baseline emissions rates and annual capacity factors of 5 
percent and 10 percent, respectively.\593\
---------------------------------------------------------------------------

    \591\ CAA section 169A(g)(2).
    \592\ 40 CFR 51.301.
    \593\ 77 FR 24794, 24810 (Apr. 25, 2012).
---------------------------------------------------------------------------

    There have been numerous other instances in which fossil fuel-fired 
EGUs have reduced their individual generation, or placed limits on 
their generation, in order to achieve, or obviate, emission standards. 
In fact, there are numerous examples of EGUs that take restrictions on 
hours of operation in their permits for the purpose of avoiding CAA 
obligations, including avoiding triggering the requirements of the 
Prevention of Significant Deterioration (PSD), Nonattainment New Source 
Review (NNSR), or Title V programs (including Title V fees), and 
avoiding triggering HAP requirements. Such restrictions may also be 
taken to limit emissions of pollutants, such as limiting emissions of 
criteria pollutants for attainment purposes.
    More specifically, EPA's regulations for a number of air programs 
expressly recognize that certain sources may take enforceable limits on 
hours of operation in order to avoid triggering CAA obligations that 
would otherwise apply to the source. Stationary sources that emit or 
have the potential to emit a pollutant at a level that is equal to or 
greater than specified thresholds are subject to major source 
requirements.\594\ A source may voluntarily obtain a synthetic minor 
limitation--that is, a legally and practicably enforceable restriction 
that has the effect of limiting emissions below the relevant level--to 
avoid triggering a major stationary source requirement.\595\ Such 
synthetic minor limits may be based on restrictions on the hours of 
operation, as provided in EPA's regulations defining ``potential to 
emit,'' as well as on air pollution control equipment. ``Potential to 
emit'' is defined, for instance, in the regulations for the PSD program 
for permits issued under federal authority as: ``the maximum capacity 
of a stationary source to emit a pollutant under its physical and 
operational design. Any physical or operational limitation on the 
capacity of the source to emit a pollutant, including air pollution 
control equipment and restrictions on hours of operation . . . shall be 
treated as part of its design if the limitation or the effect it would 
have on emissions is federally enforceable,'' \596\ or ``legally and 
practicably enforceable by a state or local air pollution control 
agency.'' \597\ The regulations for other air programs similarly 
recognize that potential to emit may be limited through restrictions on 
hours of operations in their corresponding definitions of ``potential 
to emit.'' \598\ These regulatory provisions make clear that 
restrictions on potential to emit include both ``air pollution control 
equipment'' and ``restrictions on hours of operation,'' and indicate 
that these are equally cognizable means of restricting emissions to 
comply with, or avoid, CAA requirements.\599\
---------------------------------------------------------------------------

    \594\ See, e.g., CAA sections 112(a)(1), 112(d)(1), 165(a), 
169(1), 172(c)(5), 173(a) & (c), 501(2), 502(a), 302(j).
    \595\ See, e.g., Memorandum from Terrell Hunt, Assoc. 
Enforcement Counsel, U.S. EPA, & John Seitz, Director, Stationary 
Source Compliance Div., U.S. EPA, Guidance on Limiting Potential to 
Emit in New Source Permitting, at 1-2, 6 (June 13, 1989), available 
at http://www.epa.gov/region07/air/nsr/nsrmemos/lmitpotl.pdf 
(``Restrictions on production or operation that will limit potential 
to emit include limitations on quantities of raw materials consumed, 
fuel combusted, hours of operation, or conditions which specify that 
the source must install and maintain controls that reduce emissions 
to a specified emission rate or to a specified efficiency level.'') 
(emphasis added).
    \596\ 40 CFR 52.21(b)(4) (emphasis added).
    \597\ John Seitz, Director, Office of Air Quality Planning and 
Standards, and Robert Van Heuvelen, Director, Office of Regulatory 
Enforcement, Release of Interim Policy on Federal Enforceability of 
Limitations on Potential to Emit, at 3 (Jan. 22, 1996), available at 
http://www.epa.gov/region07/air/nsr/nsrmemos/pottoemi.pdf.
    \598\ See 40 CFR 51.166(b)(4) (addressing SIP approved PSD 
programs), 51.165(a)(1)(iii) (addressing SIP approved NNSR 
programs), 70.2 (addressing Title V operating permit programs), and 
63.2 (addressing hazardous air pollutants).
    \599\ See, e.g., 40 CFR 52.21(b)(4).
---------------------------------------------------------------------------

    As one of many examples of a fossil-fuel fired EGU taking 
restrictions on hours of operation for the purpose of avoiding CAA 
obligations, Manitowoc Public Utilities in Wisconsin obtained a Title V 
renewal permit that limited the operating hours of the single simple-
cycle combustion turbine to not more than 194 hours per month, averaged 
over any consecutive 12 month period, as part of limiting its potential 
to emit for volatile organic compounds below the Title V threshold of 
100 tpy, and carbon monoxide, NOX and SO2 below 
the PSD threshold of 250 tpy.\600\ As another example, Sunbury 
Generation LP in Pennsylvania obtained a minor new source 
preconstruction permit, called a plan approval, for a repowering 
project from the Pennsylvania Department of Environmental Protection in 
2013 that limited the hours of operation of three combined cycle 
combustion turbines that were planned for construction in order to 
remain below the significance threshold for GHGs.\601\ The Legal 
Memorandum includes numerous other examples of power plants accepting 
permit limits that reduce generation to meet, or avoid the need to 
meet, emission limits.
---------------------------------------------------------------------------

    \600\ See Final Operation Permit No. 436123380-P10 for Manitowoc 
Public Utilities--Custer Street (Wis. Dept. Nat. Res., 8/19/2013), 
Condition ZZZ.1.a(1) at p. 9 (Limiting potential to emit) and n. 11 
(``These conditions are established so that the potential emissions 
for volatile organic compounds will not exceed 99 tons per year and 
potential emissions for carbon monoxide, nitrogen oxides and sulfur 
dioxide emissions from the facility will not exceed 249 tons per 
year.''). See also Analysis and Preliminary Determination for the 
Renewal of Operation Permit 436123380-P01 (Wis. Dept. Nat. Res., 5/
21/2013) at p. 5 (noting that the ``existing facility is a major 
source under Part 70 because potential emissions of sulfur dioxide, 
nitrogen oxides and carbon monoxide exceed 100 tons per year. The 
existing facility is a minor source under PSD and an area source of 
federal HAP'' and further noting that after renewal, ``the facility 
will continue to be a major source under Part 70 because potential 
emissions of sulfur dioxide, nitrogen oxides and carbon monoxide 
exceed 100 tons per year. The facility will also continue to be a 
minor source under PSD and an area source of federal HAP.'').
    \601\ See Plan Approval No. 55-00001E for Sunbury Generation LP 
(Pa. Dept. Env. Protection, 4/1/2013), Conditions #016 on pp. 24, 32 
and 40 (limiting turbine units to operating no more than 7955, 6920, 
or 8275 hours in any 12 consecutive month period depending on which 
of three turbine options was selected); Memorandum from J. Piktel to 
M. Zaman, Addendum to Application Review Memo for the Repowering 
Project (Pa. Dept. Env. Protection, 4/1/2013) at p. 2 of 10 (noting 
that source had ``calculated a maximum hours per year (12 
consecutive month period) of operation for the sources proposed for 
each of the turbine options in order to remain below the 
significance threshold for GHGs.'').
---------------------------------------------------------------------------

    There are several ways that an affected EGU may implement reduced 
generation. For example, an EGU may accept a permit requirement that 
specifically limits its operating hours. In addition, an EGU may treat 
the cost of its generation as including an additional amount associated 
with environmental impacts, which requires it to raise its bid price, 
so that the EGU is dispatched less.
    c. Other aspects of reduced generation.
    The amounts of increased existing NGCC generation and new 
renewables, in the amounts reflected in building blocks 2 and 3, can be 
substituted for generation at affected EGUs at reasonable cost. The 
NGCC capacity necessary to accomplish the levels of generation 
reduction proposed for building block 2 is already in operation or 
under construction. Moreover, it is reasonable to expect that the 
incremental resources reflected in building block 3 will develop at the 
levels requisite to ensure an adequate and reliable supply of 
electricity at the same time that affected EGUs may

[[Page 64782]]

choose to reduce their CO2 emissions by means of reducing 
their generation.
    Reduced generation by affected EGUs, in the amounts that affected 
EGUs may rely on to implement the selected building blocks, will not 
have adverse effects on the utility power sector and will not reduce 
overall electricity generation. In light of the emission limits of this 
rule, because of the availability of the measures in building blocks 2 
and 3, and because the grid is interconnected and the electricity 
system is highly planned, reductions in generation by fossil fuel-fired 
EGUs in the amount contemplated if they were to implement the building 
blocks, and occurring over the lengthy time frames provided under this 
rule, will result in replacement generation that generally is lower- or 
zero-emitting. Mechanisms are in place in both regulated and 
deregulated electricity markets to assure that substitute generation 
will become available and/or steps to reduce demand will be taken to 
compensate for reduced generation by affected EGUs. As a result, 
reduced generation will not give rise to reliability concerns or have 
other adverse effects on the utility power sector and are of reasonable 
cost for the affected source category and the nationwide electricity 
system.\602\ All these results come about because the operation of the 
electrical grid through integrated generation, transmission, and 
distribution networks creates substitutability for electricity and 
electricity services, which allows decreases in generation at affected 
fossil fuel-fired steam EGUs to be replaced by increases in generation 
at affected NGCC units (building block 2) and allows decreases in 
generation at all affected EGUs to be replaced by increased generation 
at new lower- and zero-emitting EGUs (building block 3). Further, this 
substitutability increases over longer timeframes with the opportunity 
to invest in infrastructure improvements, and as noted elsewhere, this 
rule provides an extended state plan and source compliance horizon.
---------------------------------------------------------------------------

    \602\ Although, as discussed in the text in this section of the 
preamble, we are not treating reduced overall generation of 
electricity as the BSER (because it does not meet our historical and 
current approach of defining the BSER to include methods that allow 
the same amount of production but with a lower-emitting process) we 
note that reduced generation by individual higher-emitting EGUs to 
implement building blocks 2 and 3 meets the following criteria for 
the BSER: As the examples in the text and in the Legal Memorandum 
make clear, reduced generation is ``adequately demonstrated'' as a 
method of reducing emissions (because Congress and the EPA have 
recognized it and on numerous occasions, power plants have relied on 
it); it is of reasonable cost; it does not have adverse effects on 
energy requirements at the level of the individual affected source 
(because it does not require additional energy usage by the source) 
or the source category or the U.S.; and it does not create adverse 
environmental problems.
---------------------------------------------------------------------------

    d. Comments concerning limiting principles.
    A commenter stated that ``an interpretation of [`system of emission 
reduction'] that relies primarily on reduced utilization has no clear 
limiting principle.'' \603\ We disagree with this concern, for the 
following reasons.
---------------------------------------------------------------------------

    \603\ EEI comment, at 284.
---------------------------------------------------------------------------

    As discussed, in this final rule, we are identifying the BSER as 
the combination of the three building blocks. Building blocks 2 and 3 
entail substitution of lower- or zero-emitting generation for higher-
emitting generation, and one component of that substitution is reduced 
generation, which is limited in several respects discussed below. 
Accordingly, our identification of the BSER in this final rule does not 
``rel[y] primarily'' on reduced utilization in and of itself (and 
therefore reduced generation of the product overall, electricity) as 
the BSER. Rather, the BSER is, in addition to building block 1, the 
substitution of lower- or zero-emitting generation for higher emitting 
generation, and reduced utilization may be a way to implement that 
substitution and is one of numerous methods that affected EGUs may 
employ to achieve or help achieve the emission limits established by 
these emission guidelines.\604\ The commenter's concerns over a 
perceived lack of a limiting principle cannot be taken to mean that 
reduced generation by higher-emitting EGUs cannot be considered to be a 
method for affected EGUs to achieve their emission limits.
---------------------------------------------------------------------------

    \604\ Indeed, load shifting--as substitute generation is 
sometimes called--is an ``easy and fairly inexpensive strategy'' 
that ``may be used in conjunction with other control measures'' for 
``emission reduction.'' Donald S. Shepard, ``A Load Shifting Model 
for Air Pollution Control in the Electric Power Industry,'' Journal 
of the Air Pollution Control Association, Vol. 20, No. 11, p. 760 
(Nov. 1970). In fact, load shifting has been recognized as a 
pollution control technique as early as 1968, when it was included 
in the ``Chicago Air Pollution System Model'' for controlling 
incidents of extremely high pollution. E.J. Croke, et al., ``Chicago 
Air Pollution System Model, Third Quarterly Progress Report,'' 
Chicago Department of Air Pollution Control, p. 186 (1968) 
(discussing the feasibility of ``Control by Load Reduction'' in 
combination with load shifting as applied to the Commonwealth Edison 
Company), available at http://www.osti.gov/scitech/servlets/purl/4827809. The report also considered ``combining fuel switching and 
load reduction'' as a possible air pollution abatement technique. 
See id. at 188. The report recognized, as an initial matter, that 
the Commonwealth Edison Company (CECO) was ``constrained to meet the 
total load demand'' but that ``load reduction at one plant or even a 
number of plants is usually feasible by shifting the power demand to 
other plants in the system.'' Id. As a result, the report noted, 
``load shifting within the physical limits of the CECO system . . . 
may be a highly desirable control mechanism.'' Id. The report also 
predicted that ``[i]n the future, it may be possible to form 
reciprocal agreements to obtain `pollution abatement' power from 
neighbor companies during a pollution incident and return this 
borrowed power at some later date.'' Id. at 187.
---------------------------------------------------------------------------

    Moreover, reduced generation, as applied to affected EGUs in this 
rule, is limited in a number of respects. The amount of reduced 
generation is the amount of replacement generation that is lower- or 
zero-emitting, that is of reasonable cost, that can be generated 
without jeopardizing reliability, and that meets the other requirements 
for the BSER. As discussed, that amount is the amount of generation in 
building blocks 2 and 3.\605\
---------------------------------------------------------------------------

    \605\ The EPA notes that affected EGUs are not actually required 
to collectively reduce generation by the amount represented in the 
BSER, and may collectively reduce generation by more or less than 
that amount. Individual affected EGUs are free to choose reduced 
generation or other means of reducing emissions, as permitted by 
their state plans, in order to achieve the standards of performance 
established for them by their states.
---------------------------------------------------------------------------

    Finally, as discussed, the integrated nature of the electricity 
system, coupled with the high substitutability of electricity, allows 
EGUs to reduce their generation without adversely affecting the 
availability of their product. Those characteristics facilitate 
replacement of generation that has been reduced, and for that reason, 
EGUs have a long history of reducing their generation and either 
replacing it directly or having it replaced through the operation of 
the interconnected electricity system through measures similar to those 
in building blocks 2 and 3. Thus, an EGU can either directly replace 
its generation, or simply reduce its generation, and in the latter 
case, the integrated grid, combined with the high degree of planning 
and various reliability safeguards, will result in entities providing 
replacement generation. This means that consumers receive exactly the 
same amount of the same product, electricity, after the reduced 
generation that they received before it. No other industry is both 
physically interconnected in this manner and manufactures such a highly 
substitutable product; as a result, the use of reduced generation is 
not easily transferrable to another industry.
6. Reasons That This Rule Is Within the EPA's Statutory Authority and 
Does Not Represent Over-Reaching
    In this section, we respond to adverse comments that the EPA is 
overreaching in this rulemaking by attempting to direct the energy 
sector. These commenters construed the proposed rulemaking as the EPA 
proposing to mandate the implementation of the measures in the building 
blocks,

[[Page 64783]]

including investment in RE and implementation of a broad range of state 
and utility demand-side EE programs. Commenters added that in some 
instances, the affected EGUs and states would have no choice but to 
take the actions in the building blocks because they would not 
otherwise be able to achieve their emission standards. Commenters also 
emphasized that with the proposed portfolio approach, the rule would 
impose federally enforceable requirements on a wide range of entities 
that do not emit CO2 and have not previously been subject to 
CAA regulation. Commenters cite the U.S. Supreme Court's statements in 
Utility Air Regulatory Group v. EPA (UARG) \606\ that caution an agency 
against interpreting its statutory authority in a way that ``would 
bring about an enormous and transformative expansion in [its] 
regulatory authority without clear congressional authorization,'' and 
that add, ``When an agency claims to discover in a long-extant statute 
an unheralded power to regulate `a significant portion of the American 
economy,' . . . we typically greet its announcement with a measure of 
skepticism.'' \607\ Commenters assert that in this rule, the EPA is 
taking the actions that the UARG opinion cautioned against. For the 
reasons discussed below, these comments are incorrect and misunderstand 
fundamental aspects of this rule. In addition, to the extent these 
comments address either building block 4 or the portfolio approach they 
are moot, because the EPA is not finalizing those elements of the 
proposal.
---------------------------------------------------------------------------

    \606\ 134 S. Ct. 2427 (2014).
    \607\ Utility Air Regulatory Group v. EPA, 134 S. Ct. 2427, 2444 
(2014) (citations omitted).
---------------------------------------------------------------------------

    In this rule, the EPA is following the same approach that it uses 
in any rulemaking under CAA section 111(d), which is designed to 
regulate the air pollutants from the source category at issue. First, 
the EPA identifies the BSER to reduce harmful air pollution. Second, 
based on the BSER, the EPA promulgates emission guidelines, which 
generally take the form of emission rates applicable to the affected 
sources. In this case, the EPA is promulgating a uniform CO2 
emission performance rate for steam-generating EGUs and a uniform 
CO2 emission performance rate for combustion turbines, and 
the EPA is translating those rates into a combined emission rate and 
equivalent mass limit for each state. These emission guidelines serve 
as the guideposts for state plan requirements. The states, in turn, 
promulgate standards of performance and, in doing so, retain 
significant flexibility either to promulgate rate-based emission 
standards that mirror the emission performance rates in the guidelines, 
promulgate rate-based emission standards that are equivalent to the 
emission performance rates in the guidelines, or promulgate equivalent 
mass-based emission standards. The sources, in turn, are required to 
comply with their emission standards, and may do so through any means 
they choose. Alternatively, the state may adopt the state-measures 
approach, which provides additional flexibility.
    Thus, the EPA is not requiring that the affected EGUs take any 
particular action, such as implementation of the building blocks. 
Rather, as just explained, the EPA is regulating the affected EGUs' 
emissions by requiring that the state submit state plans that achieve 
specified emission performance levels. The states may choose from a 
wide range of emission limits to impose on their sources, and the 
sources may choose from a wide range of compliance options to achieve 
their emission limits. Those options include various means of 
implementing the building blocks as well as numerous other compliance 
options, ranging from--depending in part on whether the state imposes a 
rate-based or mass-based emission limit--implementation of demand-side 
EE measures to natural gas co-firing.\608\
---------------------------------------------------------------------------

    \608\ In fact, the EPA is expressly precluded from mandating 
specific controls except in certain limited circumstances. See 42 
U.S.C. 7411(b)(5). For instance, the EPA is authorized to mandate a 
particular ``design, equipment, work practice, or operational 
standard, or combination thereof,'' when it is ``not feasible to 
prescribe or enforce a standard of performance'' for new sources. 42 
U.S.C. 7411(h)(1). CAA section 111(h) also highlights for us that 
while ``design, equipment, work practice, or operational standards'' 
may be directly mandated by the EPA, CAA section 111(a)(1) 
encompasses a broader suite of measures for consideration as the 
BSER.
---------------------------------------------------------------------------

    As some indication of the diverse set of actions we expect to 
comply with the requirements of this rule, we note that demand-side EE 
programs, in particular, are expected to be a significant compliance 
method, in light of their low costs. In addition, the National 
Association of Clean Air Agencies (NACAA) has issued a report that 
provides a detailed discussion of 25 approaches to CO2 
reduction in the electricity sector.\609\ In addition, we note that the 
nine RGGI states--Connecticut, Delaware, Maine, Maryland, 
Massachusetts, New Hampshire, New York, Rhode Island and Vermont--have 
indicated that they intend to maintain their current state programs, 
which this rule would allow, and there are reports that other states 
may seek to join RGGI.\610\ Similarly, California has indicated that it 
intends to maintain its current state program, which this rule would 
allow. Other states could employ the types of methods used in Oregon, 
Washington, Colorado, or Minnesota, described in the background section 
of this preamble.
---------------------------------------------------------------------------

    \609\ NACAA, ``Implementing EPA's Clean Power Plan: A Menu of 
Options (May 2015), http://www.4cleanair.org/NACAA_Menu_of_Options. 
NACAA describes itself as ``the national, non-partisan, non-profit 
association of air pollution control agencies in 41 states, the 
District of Columbia, four territories and 116 metropolitan areas.'' 
Id.
    \610\ Martinson, Erica, ``Cap and trade lives on through the 
states,'' Politico (May 27, 2014), http://www.politico.com/story/2014/05/cap-and-trade-states-107135.html.
---------------------------------------------------------------------------

    As a practical matter, we expect that for some affected EGUs, 
implementation of the building blocks will be the most attractive 
option for compliance. This does not mean, contrary to the adverse 
comments noted above, that this rule constitutes a redesign of the 
energy sector. As discussed above, the building blocks meet the 
criteria to be part of the best system of emission reduction . . . 
adequately demonstrated. The fact that some sources will implement the 
building blocks and that this may result in changes in the electricity 
sector does not mean that the building blocks cannot be considered the 
BSER under CAA section 111(d).
    In this rule, as with all CAA section 111(d) rules, the EPA is not 
directly regulating any entities. Moreover, the EPA is not finalizing 
the proposed portfolio approach. Accordingly, the EPA is neither 
requiring nor authorizing the states to regulate non-affected EGUs in 
their CAA section 111(d) plans.\611\
---------------------------------------------------------------------------

    \611\ A state may regulate non-EGUs as part of a state measures 
approach, but those measures would not be federally enforceable.
---------------------------------------------------------------------------

    Moreover, contrary to adverse comments, this rule does not require 
the states to adopt a particular type of energy policy or implement 
particulate types of energy measures. Under this rule, a state may 
comply with its obligations by adopting the emission standards approach 
to its state plan and imposing rate-based or mass-based emission 
standards on its affected EGUs. In this manner, this rule is consistent 
with prior section 111(d) rulemaking actions, in which the states have 
complied by promulgating one or both of those types of standards of 
performance. In this rulemaking, as an alternative, the state may adopt 
the state measures approach, under which the state could, if it wishes, 
adopt particular types of energy measures that would lead to reductions 
in emissions from its EGUs. But again, this rule does not require the 
state to implement a

[[Page 64784]]

particular type of energy policy or adopt particular types of energy 
measures.
    It is certainly reasonable to expect that compliance with these air 
pollution controls will have costs, and those costs will affect the 
electricity sector by discouraging generation of fossil fuel-fired 
electricity and encouraging less costly alternative means of generating 
electricity or reducing demand. But for affected EGUs, air pollution 
controls necessarily entail costs that affect the electricity sector 
and, in fact, the entire nation, regardless of what BSER the EPA 
identifies as the basis for the controls. For example, had some type of 
add-on control such as CCS been identified as the BSER for coal-fired 
EGUs, sources that complied by installing that control would incur 
higher costs. As a result, generation from coal-fired EGUs would be 
expected to decrease and be replaced at least in part by generation 
from existing NGCC units and new renewables because those forms of 
generation would see their competitive positions improved.
    This basic fact that EPA regulation of air pollutants from affected 
EGUs invariably affects the utility sector is well-recognized and in no 
way indicates that such regulation exceed the EPA's authority. In 
revising CAA section 111 in the 1977 CAA Amendments, Congress 
explicitly acknowledged that the EPA's rules under CAA section 111 for 
EGUs would significantly impact the energy sector.\612\ The Courts have 
recognized that, too. The U.S. Supreme Court, in its 2011 decision that 
the CAA and the EPA actions it authorizes displace any federal common 
law right to seek abatement of CO2 emissions from fossil 
fuel-fired power plants, emphasized that CAA section 111 authorizes the 
EPA--which the Court identified as the ``expert agency''--to regulate 
CO2 emissions from these sources in a manner that balances 
``our Nation's energy needs and the possibility of economic 
disruption:''
---------------------------------------------------------------------------

    \612\ The D.C. Circuit acknowledged this legislative history in 
Sierra Club v. EPA, 657 F.2d 298, 331 (D.C. Cir. 1981). There, the 
Court stated:
    [T]he Reports from both Houses on the Senate and House bills 
illustrate very clearly that Congress itself was using a long-term 
lens with a broad focus on future costs, environmental and energy 
effects of different technological systems when it discussed section 
111. [Citing S. Rep. No. 95-127, 95th Cong., 1st Sess. (1977), 3 
Legis. Hist. 1371; H.R. Rep. No. 95-294, 95th Cong., 1st Sess. 188 
(1977), 4 Legis. Hist. 2465.]

    The appropriate amount of regulation in any particular 
greenhouse gas-producing sector cannot be prescribed in a vacuum: As 
with other questions of national or international policy, informed 
assessment of competing interests is required. Along with the 
environmental benefit potentially achievable, our Nation's energy 
needs and the possibility of economic disruption must weigh in the 
balance.
    The [CAA] entrusts such complex balancing to EPA in the first 
instance, in combination with state regulators. Each ``standard of 
performance'' EPA sets must ``tak[e] into account the cost of 
achieving [emissions] reduction and any nonair quality health and 
environmental impact and energy requirements.'' Sec.  7411(a)(1), 
(b)(1)(B), (d)(1); see also 40 CFR 60.24(f) (EPA may permit state 
plans to deviate from generally applicable emissions standards upon 
demonstration that costs are ``[u]n-reasonable''). EPA may 
``distinguish among classes, types, and sizes'' of stationary 
sources in apportioning responsibility for emissions reductions. 
Sec.  7411(b)(2), (d); see also 40 CFR 60.22(b)(5). And the agency 
may waive compliance with emission limits to permit a facility to 
test drive an ``innovative technological system'' that has ``not 
[yet] been adequately demonstrated.'' Sec.  7411(j)(1)(A). The Act 
envisions extensive cooperation between federal and state 
authorities, see Sec.  7401(a), (b), generally permitting each state 
to take the first cut at determining how best to achieve EPA 
emissions standards within its domain, see Sec.  7411(c)(1), (d)(1)-
(2).
    It is altogether fitting that Congress designated an expert 
agency, here, EPA, as best suited to serve as primary regulator of 
greenhouse gas emissions. The expert agency is surely better 
equipped to do the job than individual district judges issuing ad 
hoc, case-by-case injunctions.\613\
---------------------------------------------------------------------------

    \613\ American Electric Power Co. v. Connecticut, 131 S. Ct. 
2527, 2539-40 (2011).

    Similarly, the D.C. Circuit, in its 1981 decision upholding the 
EPA's rules to reduce SO2 emissions from new coal-fired EGUs 
under the version of CAA section 111(b) adopted in the 1977 CAA 
---------------------------------------------------------------------------
Amendments, stated:

    [S]ection 111 most reasonably seems to require that EPA identify 
the emission levels that are ``achievable'' with ``adequately 
demonstrated technology.'' After EPA makes this determination, it 
must exercise its discretion to choose an achievable emission level 
which represents the best balance of economic, environmental, and 
energy considerations. It follows that to exercise this discretion 
EPA must examine the effects of technology on the grand scale in 
order to decide which level of control is best. . . . The standard 
is, after all, a national standard with long-term effects.\614\
---------------------------------------------------------------------------

    \614\ Sierra Club v. EPA, 657 F.2d 298, 330 (D.C. Cir. 1981).

    The D.C. Circuit added: ``Regulations such as those involved here 
demand a careful weighing of cost, environmental, and energy 
considerations. They also have broad implications for national economic 
policy.'' \615\ This rule has ``economic, environmental, and energy'' 
impacts, as Congress and the Courts expect in a CAA section 111 rule, 
but those impacts do not mean that the EPA is precluded from 
promulgating the rule.
---------------------------------------------------------------------------

    \615\ Sierra Club v. EPA, 657 F.2d 298, 406 (D.C. Cir. 1981). 
The Court supported this statement with a lengthy quotation from a 
scholarly article, which stated, in part:
    Consider for a moment the chain of collective decisions and 
their effects just in the case of electric utilities. Petroleum 
imports can be conserved by switching from oil-fired to coal-fired 
generation. But barring other measures, burning high-sulfur Eastern 
coal substantially increases pollution. Sulfur can be ``scrubbed'' 
from coal smoke in the stack, but at a heavy cost, with devices that 
turn out huge volumes of sulfur wastes that must be disposed of and 
about whose reliability there is some question. Intermittent control 
techniques (installing high smokestacks and switching off burners 
when meteorological conditions are adverse) can, at lower cost, 
reduce local concentrations of sulfur oxides in the air, but cannot 
cope with the growing problem of sulfates and widespread acid 
rainfall. Use of low-sulfur Western coal would avoid many of these 
problems, but this coal is obtained by strip mining. Strip-mining 
reclamation is possible, but substantially hindered in large areas 
of the West by lack of rainfall. Moreover, in some coal-rich areas 
the coal beds form the underground aquifer and their removal could 
wreck adjacent farming or ranching economies. Large coal-burning 
plants might be located in remote areas far from highly populated 
urban centers in order to minimize the human effects of pollution. 
But such areas are among the few left that are unspoiled by 
pollution and both environmentalists and the residents (relatively 
few in number compared with those in metropolitan localities but 
large among the voting population in the particular states) strongly 
object to this policy. Id. at 406 n. 526.
---------------------------------------------------------------------------

    As noted above, in this rule, to control CO2 emissions 
from affected EGUs, the EPA first considered more traditional air 
pollution control measures, including supply-side efficiency 
improvements, fuel-switching (for CO2 emissions, that 
entails co-firing with natural gas), and add-on controls (for 
CO2 emissions, that entails CCS). However, it became 
apparent that even if the EPA could have finalized those controls as 
the BSER \616\ and established the same uniform CO2 emission 
performance rates, the affected EGUs would rely on less expensive ways 
to achieve their emission limits. Specifically, instead of relying on 
co-firing and CCS, the affected EGUs generally would replace their 
generation with lower- or zero-emitting generation--the measures in 
building blocks 2 and 3--because those measures are significantly less 
expensive and already well-established as pollution control measures. 
Indeed, some affected EGUs have stated that while they oppose including 
in the BSER generation shifts to lower- or zero-emitting sources (or, 
as proposed, demand-side EE), they request that those measures be 
available for compliance, which indicates their

[[Page 64785]]

interest in implementing those measures.\617\
---------------------------------------------------------------------------

    \616\ For the reasons explained, we did not finalize those 
measures because significantly less expensive control measures--
building blocks 2 and 3--are available for these affected EGUs.
    \617\ See the proposal for this rule, 79 FR at 34888 (``during 
the public outreach sessions, stakeholders generally recommended 
that state plans be authorized to rely on, and that affected sources 
be authorized to implement, re-dispatch, renewable energy measures, 
and demand-side energy efficiency measures in order to meet states' 
and sources' emission reduction obligations.'').
---------------------------------------------------------------------------

    We expect that many sources will choose to comply with their 
emission limits through the measures in building blocks 2 and 3, but 
contrary to the assertions of some commenters, this will not result in 
unprecedented and fundamental alterations to the energy sector. As 
discussed above, Congress relied on the same measures as those the EPA 
is including in building blocks 2 and 3 as essential parts of the basis 
for the Title IV emission limits for fossil fuel-fired EGUs, and the 
EPA did the same for the emission limits in various rules for those 
same sources.
    In addition, reliance on the measures in building blocks 2 and 3 is 
fully consistent with the recent changes and current trends in 
electricity generation, and as a result, would by no means entail 
fundamental redirection of the energy sector. As indicated in the RIA 
for this rule, we expect that the main impact of this rule on the 
nation's mix of generation will be to reduce coal-fired generation, but 
in an amount and by a rate that is consistent with recent historical 
declines in coal-fired generation. Specifically, from approximately 
2005 to 2014, coal-fired generation declined at a rate that was greater 
than the rate of reduced coal-fired generation that we expect to result 
from this rulemaking from 2015 to 2030. In addition, under this rule, 
the trends for all other types of generation, including natural gas-
fired generation, nuclear generation, and renewable generation, will 
remain generally consistent with what their trends would be in the 
absence of this rule. In addition, this rule is expected to result in 
increases in demand-side EE.
    In addition, contrary to claims of some commenters, in this rule, 
the EPA is not attempting to expand its authorities by attempting to 
expand the jurisdiction of the CAA to previously unregulated sectors of 
the economy, in contravention of the UARG decision. In UARG, the U.S. 
Supreme Court struck down the EPA's interpretation of the PSD 
provisions of the CAA because the interpretation had the effect of 
applying the PSD requirements to large numbers of small sources that 
previously had not been subject to PSD, and because, according to the 
Court, the EPA acknowledged that Congress did not intend that such 
sources be subject to the PSD requirements.\618\ Commenters appear to 
interpret this decision to preclude the EPA from including at least 
building block 3 in the BSER because it includes measures that involve 
entities (such as RE developers) that do not emit CO2 and 
have not previously been subject to the CAA. However, in this rule, the 
EPA is not attempting to subject any entity other than the affected 
EGUs in the source category to CAA section 111 requirements. As 
discussed below, the EPA is not finalizing the proposed portfolio 
approach, under which states were authorized to include, in their CAA 
section 111(d) state plans, federally enforceable requirements on 
entities other than affected EGUs. Thus, as noted above, this final 
rule does not require or authorize the states to include entities other 
than affected EGUs in their CAA section 111(d) state plans, and as a 
result, those entities will not come under CAA jurisdiction \619\ and 
the parts of the economy that they represent will not be regulated by 
the EPA.
---------------------------------------------------------------------------

    \618\ Util. Air Reg. Group v. EPA, 134 S. Ct. 2427, 2443 (2014).
    \619\ States may regulate non-affected EGUs through a state 
measures approach, but those regulations would not be federally 
enforceable.
---------------------------------------------------------------------------

7. Relative Stringency of Requirements for Existing Sources and New, 
Modified, and Reconstructed Sources
    Commenters also objected that the proposed CAA section 111(d) 
standards are more stringent than the standards for new, modified or 
reconstructed sources, and they assert that setting CAA section 111(d) 
standards that are more stringent than CAA section 111(b) standards 
would be illogical, contrary to precedent, contrary to the intent of 
the remaining useful life exception, and arbitrary and capricious.\620\ 
We disagree with these comments. Comparing the control requirements of 
the two sets of rules, CAA section 111(d) and 111(b), is an ``apples-
to-oranges'' comparison and, as a result, it is not possible--and it is 
overly simplistic--to conclude that the CAA section 111(d) requirements 
are more stringent than the CAA section 111(b) requirements.
---------------------------------------------------------------------------

    \620\ ACC et al. (Associations) comments at 40, Luminant 
comments at 89.
---------------------------------------------------------------------------

    Most importantly, the two sets of rules become applicable at 
different points in time and have significantly different compliance 
periods. The CAA section 111(b) rule becomes applicable for new, 
modified and reconstructed sources immediately upon construction, 
modification, or reconstruction and, in fact, by operation of CAA 
section 111(e) and (a)(2), new, modified, or reconstructed sources that 
commenced construction prior to the effective date of the CAA section 
111(b) rule must also be in compliance upon the effective date of the 
rule. In contrast, the requirements under the CAA section 111(d) rule 
do not become applicable to existing affected EGUs until seven years 
after promulgation of the rule, when the interim compliance period 
begins in 2022, and the final compliance period does not begin until 
2030. Moreover, the compliance period for the interim requirements is 
eight years. This later applicability date and longer compliance period 
for existing sources accommodates a requirement that, on average, those 
sources have a lower nominal emission limit than the standards for new 
or modified sources, which those latter sources must comply with 
immediately.
    In addition, the timetables for compliance with the CAA section 
111(b) and 111(d) rules should be considered in light of the 8-year 
review schedule required for CAA section 111(b) rules under CAA section 
111(b)(1)(B). Under CAA section 111(b)(1)(B), the EPA is required to 
``review and, if appropriate, revise'' the CAA section 111(b) standards 
``at least every 8 years.'' This provision obligates the EPA to review 
the CAA section 111(b) rule for CO2 emissions from new, 
modified, and reconstructed power plants by the year 2023. That 
mandatory review will reassess the BSER to determine the appropriate 
stringency for emission standards for new, modified, and reconstructed 
sources into the future. Therefore, for present purposes of comparing 
the stringency of the CAA section 111(b) and 111(d) rules, the year 
2023 presents an important point of comparison.
    Specifically, as noted above, the CAA section 111(b) standards 
apply to new, modified and reconstructed sources beginning in 2015, 
while the CAA section 111(d) rule does not take effect until 2022, 
which happens to fall on the cusp of the 8-year review for the CAA 
section 111(b) standards.
    Even after the section 111(d) rule takes effect in 2022, the 
flexibility that this rule offers the states has important implications 
for its stringency and for any comparison to the CAA section 111(b) 
rule. Although the requirements for the CAA section 111(d) rule begin 
in 2022, they are phased in, in a flexible manner, over the 2022-2030 
period. That is, states are required to meet interim goals for the 
2022-2029 period by 2029, and the final goals by 2030, but states are 
not required to impose requirements on their sources that take

[[Page 64786]]

effect in 2022. In fact, states may, if they prefer, impose business-
as-usual emission standards on their sources that do not require 
emission reductions in 2022 and apply emission standards on their 
sources that do require emission reductions and that take effect no 
earlier than 2023. Moreover, because emission standards may have an 
annual compliance period, the states may allow their sources to delay 
having to comply with any emission reduction requirements until the end 
of 2023.\621\
---------------------------------------------------------------------------

    \621\ A state that chooses to allow its sources to remain 
uncontrolled through 2023 would still be able to meet its interim 
goal by 2029, although it would need to impose more stringent 
requirements on its sources over the 2024-2029 period than it would 
if it had imposed requirements beginning in 2022. It should also be 
noted that in fact, most states could allow their sources to remain 
uncontrolled for 2022 and 2023, and require controls beginning in 
2024, and still be able to meet their interim goal.
---------------------------------------------------------------------------

    Therefore, while the CAA section 111(b) standards apply to new, 
modified, and reconstructed sources beginning in 2015, the CAA section 
111(d) standards may not apply to existing sources until 2023. As a 
result, by 2023--the year that the CAA section 111(b) standards are 
required to be reviewed for possible revision--affected EGUs subject to 
the CAA section 111(d) standards may remain uncontrolled. Under those 
circumstances, the CAA section 111(d) rule cannot be said to be more 
stringent than the CAA section 111(b) rule.\622\
---------------------------------------------------------------------------

    \622\ In addition, because the section 111(d) requirements are 
phased in, states may choose to apply a gradual phase-in of the 
reductions. This means that the nominal emission rates for section 
111(d) sources would be significantly less stringent for the first 
several years of the compliance period. We estimate that if states 
choose to impose the section 111(d) requirements in a proportional 
amount each year, beginning in 2022, the requirements for steam 
generators by 2022 would result in an average emission performance 
rate of 1,741 lb. CO2/MWh net and by 2023, an average 
emission rate of 1,681 lb. CO2/MWh net (In 2030, the rate 
falls to 1,305 lb. CO2/MWh net.) For existing NGCC units, 
if states choose to implement the section 111(d) requirements 
proportionally, in 2022, the average rate would be 898 lb. 
CO2/MWh net, and in 2023 it would be 877 lb. 
CO2/MWh net. (In 2030, this rate falls to 771 lb. 
CO2/MWh net.)
---------------------------------------------------------------------------

    Another reason why the section 111(d) rule cannot be said to be 
more stringent than the section 111(b) rule is that for any individual 
source, the section 111(d) rule is applied more flexibly and includes 
more flexible means of compliance. Whereas the CAA section 111(b) rule 
entails an emission rate that each affected EGU must meet on a 12-month 
(rolling) basis, the CAA section 111(d) is more flexible. For example, 
states may adopt the state measures approach and refrain from imposing 
any requirements on their affected EGUs. In addition, under the CAA 
section 111(d) rule, sources have more flexible means of compliance. 
For an emission standards approach, depending on the form of the state 
requirements (mass-based or rate-based), the state may be expected to 
authorize trading of mass-based emission allowances or rate-based 
emission credits, and in addition, the purchase of ERCs. These 
flexibilities are not included in the CAA section 111(b) rule, rather, 
as noted, each new, modified, and reconstructed EGU must individually 
meet its emission standard on a 12-month (rolling) basis. The EPA has 
frequently required that sources meet a more stringent nominal limit 
when they are allowed compliance flexibility, particularly, the 
opportunity to trade.\623\ In addition, states have the discretion to 
allow their sources to meet emission standards over a longer time 
period. This distinction between the two rules is another reason why 
the CAA section 111(d) rule cannot be said to be more stringent in fact 
than the CAA section 111(b) rule.
---------------------------------------------------------------------------

    \623\ See, e.g., EPA, ``Improving Air Quality with Economic 
Incentive Programs,'' EPA-452/R-01-001, at 82 (2001) (requiring that 
Economic Incentive Programs show an environmental benefit, such as 
``reducing emission reductions generated by program participants by 
at least 10 percent''), available athttp://www.epa.gov/airquality/advance/pdfs/eipfin.pdf; ``Economic Incentive Program Rules: Final 
Rule,'' 59 FR 16690 (April 7, 1994) (same); ``Certification Programs 
for Banking and Trading of NOX and PM Credits for Heavy-
Duty Engines: Final Rule,'' 55 FR 30584 (July 26, 1990) (requiring 
that for programs for banking and trading of NOX and PM 
credits for gasoline, diesel and methanol powered engines, all 
trading and banking of credits must be subject to a 20 percent 
discount ``as an added assurance that the incentives created by the 
program will not only have no adverse environmental impact but also 
provide an environmental benefit.'').
---------------------------------------------------------------------------

    There are other reasons why the CAA section 111(d) rule cannot be 
said to be more stringent. With respect to the CAA section 111(d) and 
111(b) rules for existing and new NGCC units, we note the following: As 
explained in the CAA section 111(b) preamble, the standard for new NGCC 
units is designed to accommodate a wide range of unit types, including 
small units and rapid-start units, which are a small part of the 
expected new NGCC generation capacity. As such, the CAA section 111(b) 
standard (1,000 lb CO2/MWh gross, which equates to 1,030 lb 
CO2/MWh net) will not constrain the emissions of the great 
majority of expected new NGCC generation capacity, which is expected to 
consist of larger base load units (with a capacity of 100 MW or 
greater) that are not intended to cycle frequently. Their initial 
emissions are expected to be below 800 lb. CO2/MWh gross, 
their emissions over time may be somewhat higher due to equipment 
deterioration, and as a result, their PSD permits are expected to 
include emission limits at approximately the 800 lb. CO2/MWh 
gross level. A very small amount of the new NGCC generation is expected 
to be small units (with a capacity of approximately 25 MW) or rapid-
start units. Their initial emissions are expected to be approximately 
950 lb. CO2/MWh gross, their emissions over time are 
expected to be somewhat higher due to equipment deterioration, and it 
these units that the standard of 1,000 lb. CO2/MWh gross is 
designed to constrain.\624\ As a result, the 1,000 lb. CO2/
MWh gross limit applies to all new NGCC units, including the great 
majority of the expected new capacity consisting of larger, non-rapid 
start units, even though, as just noted, the great majority of the 
units are expected to emit at significantly lower emission rates. The 
CAA section 111(d) standard for existing sources, in contrast, is 
generally expected to constrain existing NGCC units on average. 
Moreover, very little of the existing NGCC generation includes small 
units or, in particular, rapid-start units because the latter are a 
recently developed technology. To some extent, the same is true for the 
111(b) standard for reconstructed NGCC units. The average NGCC rate was 
approximately 850 lb CO2/MWh gross in 2014 and, as a result, 
most sources are emitting below the CAA section 111(b) standard for 
reconstructed sources. For these reasons, too, the CAA section 111(b) 
standards for new and reconstructed NGCC units cannot be compared to 
the 111(d) standards for existing NGCC units.\625\
---------------------------------------------------------------------------

    \624\ As explained in the 111(b) preamble, any attempt to 
subcategorize and assign a lower emission limit to larger, non-rapid 
start NGCC units could cause market distortions.
    \625\ The section 111(b) standards for modified and 
reconstructed steam generation units are generally lower than the 
emission rates of existing stream generation units, but for the 
reasons explained earlier, those standards cannot be compared to the 
section 111(d) standards for existing steam generation units.
---------------------------------------------------------------------------

    Moreover, even if commenters were correct that the CAA section 
111(d) requirements for existing sources are more stringent than the 
CAA section 111(b) requirements for new sources, that would not, by 
itself, call into question the reasonableness of either standard. The 
stringency of the requirements for each source subcategory is, of 
course, a direct function of the BSER identified for that source 
subcategory. In this rulemaking, we explain the basis for the BSER for 
existing sources, and why we do not include certain measures, such as 
CCS; and in the CAA section 111(b) rulemaking, we explain the basis for 
the

[[Page 64787]]

BSER for new sources, and why we do not include certain measures, such 
as the building blocks. As long as the BSER determination is reasonable 
and the resulting emission limits meet other applicable requirements, 
those emission limits are valid, even if the one for new sources is 
less stringent than the one for existing sources. No provision in 
section 111, nor any statement in its legislative history, nor any of 
its case law, indicates that the standards for new sources must be more 
stringent than the standards for existing sources.

C. Building Block 1--Efficiency Improvements at Affected Coal-Fired 
Steam EGUs

    The first category of approaches to reducing CO2 
emissions at affected fossil fuel-fired EGUs consists of measures that 
improve heat rate at coal-fired steam EGUs. Heat rate improvements are 
changes implemented at an EGU that increase the efficiency with which 
the EGU converts fuel energy to electric energy, thereby reducing the 
amount of fuel needed to produce the same amount of electricity and 
consequently lowering the amount of CO2 produced as a 
byproduct of fuel combustion. Heat rate improvements yield important 
economic benefits to affected EGUs by reducing their fuel costs.
    An EGU's heat rate is the amount of fuel energy input needed (Btu, 
higher heating value basis) to produce 1 kWh of net electrical energy 
output.\626\ In 2012, the generation-weighted average annual heat rate 
of the 884 coal-fired EGUs included in EPA's building block 1 analysis 
was approximately 9,732 Btu per gross kWh.\627\ Because an EGU's 
CO2 emissions are driven primarily by the amount of fuel 
consumed, improving (i.e., decreasing) heat rate at a coal-fired EGU 
inherently reduces the carbon-intensity of generation.
---------------------------------------------------------------------------

    \626\ Typically, the units of measure used for heat rate (e.g., 
Btu/kWh-net) indicate whether a given value is based on the gross 
output or net output. Net heat rate is always higher than gross heat 
rate; in coal-steam units, net heat rate can be 5-10% higher than 
gross heat rate.
    \627\ Similarly, within each interconnection, the generation-
weighted average annual heat rates for those coal-fired EGUs in our 
study population were 9,700 Btu per gross kWh (Eastern); 9,888 Btu 
per gross kWh (Western); and 9,789 Btu per gross kWh (Texas).
---------------------------------------------------------------------------

    As discussed above in section V.A and in the June 2014 
proposal,\628\ it is critical to recognize that affected coal-fired 
EGUs operate in the context of the integrated electricity system. 
Because of this reality, applying building block 1 in isolation can 
result in a ``rebound effect'' that undermines the emissions reductions 
otherwise achieved by heat rate improvements. As already noted, the 
building block 1 measures described below cannot by themselves 
constitute the BSER because the quantity of emission reductions 
achieved--which is a factor that the courts have required EPA to 
consider in determining the BSER--would be of insufficient magnitude in 
the context of this pollutant and this industry. The potential rebound 
effect, if it occurred, would exacerbate the insufficiency of the 
emission reductions. However, applying building block 1 in combination 
with other building blocks can address this concern for the reasons 
stated in section V.A.4.
---------------------------------------------------------------------------

    \628\ See, e.g., 79 FR 34830, 34859 (June 18, 2014).
---------------------------------------------------------------------------

    We conducted several analyses to assess the potential for heat rate 
improvements from the coal-fired EGU fleet. As in the proposal, we 
employed a unit-specific approach that compared each EGU's performance 
against its own historical performance in lieu of directly comparing an 
EGU's performance against other EGUs with similar characteristics. 
Accordingly, as described below, our method effectively controls for 
the characteristics and factors of an EGU that typically remain 
constant over time (e.g., a unit is unlikely to dramatically increase 
or decrease in size). Our methodology for determining the amount of 
heat rate improvement appropriately included in the BSER as building 
block 1 is discussed in the next section, below.
1. Summary of Measures Comprising the BSER in Building Block 1
    a. Measures under building block 1--heat rate improvements.
    In finalizing the building block 1 portion of this rule, we 
considered over a thousand individual comments from the public, 
including individual EGUs and state agencies, on heat rate improvement, 
which are discussed below and also in the responses to comments 
document and the GHG Mitigation Measures TSD for the CPP Final Rule. 
Based on these public comments, we have refined the statistical 
analyses used in the proposal to identify the potential heat rate 
improvement that can be achieved on average by affected coal-fired 
EGUs.
    In the proposal, we used two approaches to analyze the variability 
of an EGU's gross heat rate using a robust dataset comprised of 11 
years of hourly gross heat rate data for 884 coal-fired EGUs--over 11 
million hours of data collected between 2002 and 2012. The foundation 
of our first approach was an analysis of the variability of each EGU's 
gross heat rate, which was accomplished in large part by grouping each 
EGU's hourly data by similar ambient temperature and capacity factor 
(i.e., hourly operating level as a percentage of nameplate capacity) 
conditions. The second approach analyzed the difference between an 
EGU's average gross heat rate and its best historical gross heat rate 
performance. We proposed that, on a nationwide basis, affected coal-
fired EGUs should be able to achieve 6-percent heat rate improvement: 
4-percent improvement from best practices, and an additional 2-percent 
improvement from equipment upgrades.
    We received many comments asserting that the 11-year dataset we had 
used to determine the 4-percent best practices figure likely reflected 
some portion of the 2-percent equipment upgrades figure we had 
separately identified. Accordingly, these commenters claim that the EPA 
double-counted equipment upgrades in arriving at the full estimate of 
6-percent heat rate improvement. Commenters also noted the difficulty, 
in some cases, of determining whether a heat rate improvement measure 
is an ``equipment upgrade'' or ``best practice,'' such as optimizing 
soot blowing with intelligent systems, using CO monitors for optimizing 
combustion, or applying air heater and duct leakage controls.
    As noted below in sections V.C.1.b and V.C.3, the EPA acknowledges 
that some equipment upgrades implemented by EGUs during the 11-year 
study period are reflected in the hourly heat rate data. Therefore, we 
made two refinements to our analyses of heat rate improvement 
potential. First, we refined our statistical approaches to use each 
EGU's gross heat rate from 2012--the final year of the 11-year study 
period--as the baseline for calculating heat rate improvement 
potential. By comparing each EGU's best historical gross heat rate with 
its 2012 gross heat rate, our analyses account for the enduring effects 
on heat rate of any equipment upgrades or best practices that an EGU 
implemented during the study period. Heat rate improvement measures 
that an EGU maintains in 2012 are reflected in that baseline, and thus 
are not treated as evidence that the EGU can further improve heat rate. 
Additionally, in part because of limitations on the information 
available to us regarding which equipment upgrades have been or could 
be implemented at individual EGUs, as well concerns about double-
counting, we have conservatively decided not to add a separate 
equipment upgrade component to our estimate of heat rate improvement 
potential. Nonetheless, we remain confident that additional equipment 
upgrades

[[Page 64788]]

(including measures that are unambiguously equipment upgrades, such as 
turbine overhauls) are possible at many coal-fired EGUs, as supported 
by numerous commenters, the Sargent & Lundy study \629\ (S&L) and other 
industry reports and studies. Many of these reports and studies are 
referenced in the TSD developed for the proposed rule, as well as in 
the GHG Mitigation Measures TSD supporting the final CPP.
---------------------------------------------------------------------------

    \629\ Sargent and Lundy 2009, Coal-Fired Power Plant Heat Rate 
Reductions, SL-009597, Final Report, January 2009, available at: 
http://www.epa.gov/airmarkets/documents/ipm/coalfired.pdf.
---------------------------------------------------------------------------

    Several commenters criticized the fact that the proposal assessed 
potential heat rate improvement on a nationwide basis. These commenters 
suggested instead that we narrow the geographic scope of our analysis, 
generally identifying a state-by-state approach as a preferred 
alternative. In light of commenters' concerns about using a single 
nationwide approach, as well as for reasons described in Section V.A 
and elsewhere in this preamble, the final rule assesses potential heat 
rate improvement regionally, within the Eastern, Western and Texas 
Interconnections.\630\
---------------------------------------------------------------------------

    \630\ The geographic area within the Texas Interconnection 
generally corresponds to the portion of the state of Texas covered 
by ERCOT (the Electric Reliability Council of Texas). Additional 
portions of the state of Texas are located within the Eastern and 
Western Interconnections.
---------------------------------------------------------------------------

    For the final rule, we performed several analyses to determine what 
heat rate improvement was achievable in each interconnection from best 
practices and equipment upgrades. As in the proposal, these analyses 
used the 11-year dataset of EGU hourly gross heat rate data from 2002 
to 2012. As discussed further in the GHG Mitigation Measures TSD, our 
reliance on these gross heat rate data was reasonable given that (1) 
these data are the only comprehensive data available to the EPA, and 
(2) heat rate is proportional to CO2 emission rate.
    As in the proposal, we used more than one analytical method to 
evaluate the opportunity for EGUs to reduce their CO2 
emissions through heat rate improvements. Our final methodology uses 
three different analytical approaches based on refinements of the two 
approaches described at the proposal stage. We call these final 
approaches: (1) The ``efficiency and consistency improvements under 
similar conditions'' approach; (2) the ``best historical performance'' 
approach; and (3) the ``best historical performance under similar 
conditions'' approach. As described below and in the GHG Mitigation 
Measures TSD, each approach provides an independently reasonable way to 
estimate the potential for heat rate improvements by EGUs in each 
region. However, rather than select a potential heat rate improvement 
value supported by one or only some of these independently reasonable 
analytical approaches, we conservatively based our final determination 
for each region on the value for that region supported by all three 
approaches.
    The ``efficiency and consistency improvements under similar 
conditions'' approach is a slight refinement of an approach discussed 
at length in the proposal. As in the proposal, we distributed each hour 
of gross heat rate data for each EGU into a matrix comprised of 168 
bins, based on the ambient temperature and hourly capacity factor of 
the EGU at the time that hour of gross heat rate data was generated. 
Each bin represented a 10-degree Fahrenheit ([deg]F) range in ambient 
temperature (from -20 [deg]F to greater than 110 [deg]F), and a 10-
percent range in capacity factor (from 0 percent to greater than 110 
percent \631\). Thus, for example, one bin would contain all of an 
EGU's hourly gross heat rate data generated during the 11-year study 
period while that EGU was operating at 80- to 89-percent capacity while 
ambient temperatures were between 70 [deg]F and 79 [deg]F.
---------------------------------------------------------------------------

    \631\ Because an EGU's rated nameplate capacity is based on a 
maximum continuous rating, EGUs may operate for periods of time 
``over'' 100 percent of their capacity factor. The EPA's dataset of 
hourly operating data reflected some such instances.
---------------------------------------------------------------------------

    As we explained at proposal and as discussed further in the GHG 
Mitigation Measures TSD, ambient temperature and hourly capacity factor 
are important conditions that influence heat rate at individual EGUs. 
By separating the EGU-specific data into bins based on these variables, 
and only directly comparing data within a bin, we were largely able to 
control for the influence of those variables on an EGU's heat rate. 
Accordingly, having controlled for these two external factors, and 
having already controlled for unit-specific factors affecting heat rate 
by analyzing the data for each EGU in isolation, we are confident that 
the remaining variation in each bin's data was primarily driven by 
factors under the EGU operator's control.
    After allocating an individual EGU's data across the bins, we next 
established a benchmark for each bin based on the best hourly gross 
heat rate accounting for outliers (i.e., we set the benchmark at the 
10th percentile hourly gross heat rate value) during any consecutive 
two-year period.\632\ We compared the hourly gross heat rate data 
within each bin to the EGU's benchmark value. Similar to the proposal, 
within each bin we assessed the effect on heat rate of improving the 
consistency of that EGU by reducing hourly gross heat rate values that 
were greater than the benchmark by a percentage of the distance between 
each of those higher hourly values and the benchmark.\633\ We refer to 
this percentage improvement value as the ``consistency factor,'' 
because applying it results in values for heat rate that are more 
consistent with the EGU's benchmark for that bin. In our proposal we 
evaluated the heat rate improvement that would result from applying 
consistency factors of 10, 20, 30, 40 and 50 percent of the distance 
between those less-efficient hourly gross heat rate values and the 
benchmark; using engineering judgment, we selected a consistency factor 
of 30 percent, which produced results comparable to those obtained 
using other approaches for analyzing heat rate. For our final analysis 
under this approach, we refined the consistency factor based on a 
statistical assessment of the overall variability of heat rate in that 
EGU's region, as described in the GHG Mitigation Measures TSD.\634\ As 
in the proposal, we applied the consistency factor to each bin of each 
EGU's hourly gross heat rate data, and averaged the result across all 
bins in that EGU's matrix. The net result was an improved gross heat 
rate reflecting what that EGU would have achieved between 2002 and 2012 
if, under certain ambient temperature and capacity factor conditions, 
the EGU had improved its gross heat rate during less-efficient hours to 
be slightly more consistent with the relevant benchmark value. We then 
compared the improved gross heat rate for each EGU to its actual 2012 
historical average gross heat rate. We

[[Page 64789]]

chose 2012 as the year of comparison because 2012 was the latest year 
for which the EPA had data at the time of the proposal, and because 
using the most recent data reflects the EGU's current operating level 
and accounts for improvements the EGU may have undertaken over the 11-
year study period.
---------------------------------------------------------------------------

    \632\ As described below, we also conducted this regionalized 
approach using a benchmark based on the best hourly gross heat rate 
accounting for outliers during any one-year period. See the GHG 
Mitigation Measures TSD supporting the final CPP for more details.
    \633\ In the proposal, we used heat input values rather than 
gross heat rate values. See the GHG Mitigation Measures TSD 
supporting the final CPP for more details.
    \634\ For the Eastern Interconnection, the consistency factor is 
38.1 percent. For the Western Interconnection, the consistency 
factor is 38.4 percent. For the Texas Interconnection, the 
consistency factor is 37.1 percent. Conducting this analysis on a 
nationwide basis would have resulted in application of a consistency 
factor of 38.2 percent. As described below, we also conducted this 
regionalized approach using consistency factors determined based on 
one-year figures. See the GHG Mitigation Measures TSD supporting the 
final CPP for more details.
---------------------------------------------------------------------------

    Applying this procedure to all units in our database and averaging 
the generation-weighted results, we determined that it would be 
reasonable to conclude that, through application of best practices and 
equipment upgrades, EGUs on average are at least capable of reducing 
their CO2 emissions by improving heat rate 4.3 percent in 
the Eastern Interconnection, 2.1 percent in the Western 
Interconnection, and 2.3 percent in the Texas Interconnection.\635\
---------------------------------------------------------------------------

    \635\ Conducting this analysis on a nationwide basis would have 
resulted in a finding that EGUs nationwide are capable on average of 
reducing their CO2 emissions by improving heat rate 4.0 
percent. See the table in this section and the GHG Mitigation 
Measures TSD for the results of this approach using benchmarks and 
consistency factors based on one-year averages.
---------------------------------------------------------------------------

    In addition to the statistical approach described above, we 
employed a ``best historical performance'' approach refined from the 
proposal, which compared each EGU's best two-year rolling average gross 
heat rate to that EGU's 2012 average annual gross heat rate.\636\ We 
then calculated the differences across all EGUs in a region to 
determine the potential heat rate improvement that would result if, in 
2012, each EGU had performed at the best two-year rolling average gross 
heat rate that the EGU achieved between 2002 and 2012. Under this 
analysis of historical gross heat rate, we determined that it would be 
reasonable to conclude that the average heat rate improvement potential 
from best practices and equipment upgrades is at least 4.9 percent in 
the Eastern Interconnection, 2.6 percent in the Western Interconnection 
and 3.1 percent in the Texas Interconnection.\637\
---------------------------------------------------------------------------

    \636\ As described below, we also conducted this regionalized 
approach using each EGU's best one-year rolling average. See the GHG 
Mitigation Measures TSD supporting the final CPP for more details.
    \637\ Conducting this approach on a nationwide basis would have 
resulted in a finding that EGUs nationwide are capable on average of 
reducing their CO2 emissions by improving heat rate 4.6 
percent. As described below, we also conducted this regionalized 
approach using one-year averages. See the GHG Mitigation Measures 
TSD supporting the final CPP for more details.
---------------------------------------------------------------------------

    Finally, we employed the ``best historical performance under 
similar conditions'' approach, which combines aspects of the other two 
approaches. First, as with the ``efficiency and consistency 
improvements under similar conditions approach,'' we grouped hourly 
data for each EGU by ambient temperature conditions and hourly capacity 
factor. Next, we calculated each EGU's best two-year gross heat rate 
for each of the 168 ambient temperature-capacity factor bins.\638\ 
Similar to the ``best historical performance'' approach, to calculate 
the potential heat rate improvement, the EPA then compared each EGU's 
2012 gross heat rate for each of the ambient temperature-capacity 
factor bins to the EGU's best two-year gross heat rate for the 
corresponding bin. Accounting for differences in ambient temperature 
and capacity factor, we determined that under this analytical approach 
the average heat rate improvement potential from best practices and 
equipment upgrades was at least 5.3 percent in the Eastern 
Interconnection, 3.1 percent in the Western Interconnection and 3.5 
percent in the Texas Interconnection.\639\
---------------------------------------------------------------------------

    \638\ As described below, we also conducted this approach using 
one-year averages for each EGU instead of two-year averages. See the 
GHG Mitigation Measures TSD supporting the final CPP for more 
details.
    \639\ Conducting this approach on a nationwide basis would have 
resulted in a finding that EGUs nationwide are capable on average of 
reducing their CO2 emissions by improving heat rate 5.0 
percent.
---------------------------------------------------------------------------

    As in the proposal, we additionally analyzed the data with our 
analytical approaches using one-year averaging periods in place of the 
two-year averaging periods described above.\640\ However, because our 
conservative overall methodology adopts the lowest value that is 
identified for a region by any of our reasonable analytical approaches, 
the inherently less conservative results obtained with one-year 
averaging periods (reproduced below) could not influence the outcome of 
our methodology as a whole. Overall, applying these three analytical 
approaches resulted in six heat rate improvement values generated for 
each region, each of which represents a reasonable estimate of the 
potential for heat rate improvements by EGUs in that region. Those 
values ranged from 4.3 to 6.9 percent in the Eastern Interconnection, 
from 2.1 to 4.7 percent in the Western Interconnection, and from 2.3 to 
4.9 percent in the Texas Interconnection. In all three regions, the 
most conservative values were generated using the ``efficiency and 
consistency improvements under similar conditions'' approach with two-
year averaging periods and consistency factors. As shown in Table 6, 
the values produced by that approach were the minimum values for each 
region produced by any of the three approaches:
---------------------------------------------------------------------------

    \640\ The GHG Mitigation Measures TSD describes in more detail 
our rationale for using one- and two-year averaging periods in our 
analytical approaches and methodology as a whole.

                     Table 6--Heat Rate Improvement Potential by Region and Averaging Period
----------------------------------------------------------------------------------------------------------------
                                      Heat rate improvement potential (percent)  by region and averaging period
                                   -----------------------------------------------------------------------------
        Analytical approach                  Western                    Texas                    Eastern
                                   -----------------------------------------------------------------------------
                                       1 year       2 year       1 year       2 year       1 year       2 year
----------------------------------------------------------------------------------------------------------------
Efficiency and consistency                  3.5          2.1          3.7          2.3          5.6          4.3
 improvements under similar
 conditions.......................
Best historical performance.......          4.1          2.6          4.2          3.1          6.3          4.9
Best historical performance under           4.7          3.1          4.9          3.5          6.9          5.3
 similar conditions...............
----------------------------------------------------------------------------------------------------------------

    Accordingly, we have concluded that a well-supported and 
conservative estimate of the potential heat rate improvements (and 
accompanying reductions in CO2 emission rates) that EGUs can 
achieve on average through best practices and equipment upgrades is a 
4.3-percent improvement in the Eastern Interconnection, a 2.1-percent 
improvement in the Western Interconnection and a 2.3-percent 
improvement in the Texas Interconnection. The decision to use these 
values as the building block 1 potential in each region is based on the 
weight of evidence that these are conservative values; for each region, 
each of the three analytical approaches in our methodology supports our 
determination that the heat rate improvement value we selected is

[[Page 64790]]

achievable. Taken individually, each approach provides an independently 
reasonable estimate of the potential for heat rate improvement. 
Furthermore, as described in the GHG Mitigation Measures TSD, these 
approaches are conservative on even an individual basis because they do 
not account for the full extent of heat rate improvements available 
through additional equipment upgrades and best practices. Some EGUs may 
have faced difficulties achieving significant heat rate improvement in 
the past and EGU owners may feel they face challenges in the future. 
Nevertheless, our methodology as a whole indicates that, on average, 
coal-fired EGUs can at least achieve the percentage heat rate 
improvement selected for their region through application of best 
practices and some of the available equipment upgrades. A more detailed 
discussion of the EPA's analysis in determining the heat rate 
improvement potential for existing coal-fired EGUs may be found in the 
GHG Mitigation Measures TSD supporting the final CPP.
    No affected coal-fired EGU is specifically required to improve heat 
rate by any amount as a result of this rule. Rather, as described in 
section VI, the potential for heat rate improvement is used to 
determine a CO2 emission performance rate. Those affected 
EGUs that have done the most to reduce their heat rate will tend to be 
closer to that CO2 emission rate. In this sense, our 
approach to determining potential CO2 reductions through 
heat rate improvements is similar to the way EPA ordinarily approaches 
standards of performance.\641\
---------------------------------------------------------------------------

    \641\ To give an illustrative example, imagine a population of 
sources that emit Pollutant X. Half of the sources emit Pollutant X 
at 2500 lbs/hour, while the other half of the sources have scrubbers 
installed that reduce their emission rates to 1500 lbs/hour. Because 
the sources are evenly divided between those with and without 
scrubbers, the average emission rate for the population as a whole 
is 2000 lbs/hour. In this hypothetical, EPA decides to base 
requirements on the emission rate achievable through use of a 
scrubber, meaning that all sources will have to meet an emission 
rate of 1500 lbs/hour. Because the fleet as a whole has an average 
emission rate of 2000 lbs/hour, it would be accurate for EPA to say 
that the fleet as a whole can reduce its emission rate by 25 
percent--from 2000 lbs/hour on average (only half the sources with 
scrubbers), to 1500 lbs/hour on average (all the sources with 
scrubbers). This description of what is possible for the fleet as a 
whole--a 25-percent reduction in emission rate--should not be 
misinterpreted as a statement that every individual source is 
capable of further reducing its emissions by 25 percent. The sources 
that have already installed scrubbers, and which are thus already 
operating at 1500 lbs/hour, would not be required to further improve 
their emission rate.
---------------------------------------------------------------------------

    In this final analysis, we do not delineate what proportion of the 
potential heat rate improvement can be expected from equipment upgrades 
versus best practices; \642\ only that these heat rate improvements are 
achievable in the regions through a combination of these methods. As 
discussed in section V.C.3 below, we believe that a single heat rate 
improvement goal for each region incorporating both best practices and 
upgrades, based on the 11 years of hourly heat rate data for 884 coal-
fired EGUs available to the EPA, is a reasonable approach that is 
supported by our analysis, and is particularly conservative given that 
it does not account for the full range of heat rate improvements 
achievable through additional equipment upgrades and best practices.
---------------------------------------------------------------------------

    \642\ Examples of the many types of best practices and equipment 
upgrades available to coal-fired EGUs include adopting sliding 
pressure operation to reduce turbine throttling losses; installing 
intelligent sootblowing system software; upgrading the combustion 
control/optimization system; installing heat rate optimization 
software; installing a production cost optimization program that 
benchmarks plant thermal performance using historical plant data; 
establishing centralized remote monitoring centers with thermal 
performance software for monitoring heat rates systemwide; repairing 
steam and water leaks; automating steam system drains; performing an 
on-site performance appraisal to identify potential areas for 
improved performance; developing heat rate improvement procedures 
and training O&M staff on their use; aligning the cycle to isolate 
or capture high-energy fluid leakage from the steam cycle; repairing 
utility boiler air in-leakage; performing utility boiler chemical 
cleaning; installing condenser tube cleaning system; retubing 
condenser; repairing/upgrading flue gas desulfurization systems; 
cleaning air preheater coils; adjusting/replacing worn air heater 
seals; replacing corroded air heater baskets; replacing feed pump 
turbine steam seals; overhauling high pressure feedwater pumps; 
installing fan and pump variable speed/frequency drives; upgrading 
turbine steam seals; upgrading all turbine internals; and installing 
coal drying systems. These and additional heat rate improvement 
measures are discussed further in the GHG Mitigation Measures TSD 
for the CPP Final Rule.
---------------------------------------------------------------------------

    The performance rates quantified in section VI, below, reflect the 
region-specific values for heat rate improvement. Although the 
performance rates are based on the least stringent overall performance 
rate determined to be reasonable for any region, and are thus based in 
part on the percentage heat rate improvement identified for the region, 
this rule does not itself require any specific EGU to implement 
measures resulting in a specific percentage heat rate improvement. 
Rather, the percentage heat rate improvement value is merely reflected 
in the CO2 emission performance rates and corresponding 
mass-based and rate-based state goals. Each state has the flexibility 
to develop a plan that achieves those CO2 performance rates 
or emission goals by assigning the emission standards the state 
considers appropriate to its affected coal-fired EGUs. Similarly, 
depending on the content of the applicable plan, affected EGUs may 
achieve their emission standards through use of any of the building 
block measures described in this rule or any other measures permitted 
under the plan.
    b. Changes from the proposal.
    In the proposed rule, we determined that building block 1 measures 
could on average achieve a 6-percent heat rate improvement from coal-
fired EGUs in the U.S. based on a 4-percent heat rate improvement from 
implementation of best practices and a 2-percent heat rate improvement 
from equipment upgrades. Based on comments received and refinements 
made to our methodology for determining potential heat rate improvement 
from the hourly gross heat rate dataset of 884 coal-fired EGUs, we have 
applied this methodology on a regional basis and reduced the overall 
expected percentage heat rate improvement for coal-fired EGUs to 4.3 
percent in the Eastern Interconnection, 2.1 percent in the Western 
Interconnection, and 2.3 percent in the Texas Interconnection.\643\ 
These values reflect improvements achievable through both best 
practices and equipment upgrades because, as described above, we also 
no longer include a separate estimation of the potential heat rate 
improvement achievable solely through equipment upgrades.
---------------------------------------------------------------------------

    \643\ Had the EPA maintained a nationwide approach to analyzing 
the potential reductions under building block 1, the result would 
have been 4.0 percent.
---------------------------------------------------------------------------

    We received comments on our proposed statistical methodology for 
determining the CO2 emission reductions opportunities 
achievable by coal-fired EGUs through heat rate improvements. We have 
closely reviewed those comments and, for the final rule, have made 
refinements to our methodology, as described above and explained in 
more detail in the GHG Mitigation Measures TSD supporting the final 
CPP.
    In the final rule, the EPA extends the implementation deadline from 
2020 to 2022. This additional time will be helpful to the states 
seeking to conduct more targeted analyses of the nature and extent of 
heat rate improvements that specific coal-fired EGUs can make, 
considering specific recent improvements or upgrades, planned 
retirements of older coal-fired EGUs, and other relevant 
considerations. The extended deadline will also provide additional time 
to accommodate

[[Page 64791]]

changes to heat rate monitoring methods at EGUs and for the 
installation of new pollution controls that comply with other rules, as 
discussed below in the summary of key comments.
2. Costs of Heat Rate Improvements
    By definition, any heat rate improvement made by EGUs for the 
purpose of reducing CO2 emissions will also reduce the 
amount of fuel that EGUs consume to produce the same electricity 
output. The cost attributable to CO2 emission reductions, 
therefore, is the net cost of achieving heat rate improvements after 
any savings from reduced fuel expenses. As summarized below, we 
estimate that, on average, the savings in fuel cost associated with the 
percentage heat rate improvements we identified for each region would 
be sufficient to cover much of the associated costs. Accordingly, the 
net costs of heat rate improvements associated with reducing 
CO2 emissions from affected EGUs are relatively low. We 
recognize that this cost analysis will represent the costs for some 
EGUs better than others because of differences in individual 
circumstances. We further recognize that reduced generation from coal-
fired EGUs due to the implementation of other building block measures 
would tend to reduce the fuel savings associated with heat rate 
improvements, thereby raising the effective cost of achieving the 
CO2 emission reductions from the heat rate improvements. 
Nevertheless, we still expect that a significant fraction of the 
investment required to capture the technical potential for 
CO2 emission reductions from heat rate improvements would be 
offset by fuel savings, and that the net costs of implementing heat 
rate improvements as an approach to reducing CO2 emissions 
from affected EGUs are reasonable. Even if we conservatively estimate 
that EGUs will largely rely on equipment upgrades rather than cheaper 
best practices to reduce heat rate, those reductions can generally be 
achieved at $100 or less per kW, or approximately $23 per ton of 
CO2 removed, as described in detail in the GHG Mitigation 
Measures TSD supporting the final CPP.\644\ Depending on the balance 
between equipment upgrades and best practices, improving heat rate 
would even result in a net savings for some EGUs.
---------------------------------------------------------------------------

    \644\ The $100/kW cost figure from the proposal is now 
particularly conservative because it included the cost of 
significant equipment upgrades that improve heat rate, whereas 
building block 1 is now largely quantified based on low- or no-cost 
best practices, with a smaller portion of the remainder comprised of 
equipment upgrades.
---------------------------------------------------------------------------

    Based on the analyses of technical potential and cost summarized 
above and in Chapter 2 of the GHG Mitigation Measures TSD, we find that 
heat rate improvements of 4.3, 2.1 and 2.3 percent are reasonable and 
conservative estimates of what coal-fired EGUs in the Eastern, Western 
and Texas Interconnections, respectively, can achieve at a reasonable 
cost.
3. Response to Key Comments
    Many commenters said that the EPA should have subcategorized by EGU 
design or operating characteristics for purposes of evaluating 
potential heat rate improvements under building block 1.
    Several studies categorize EGUs broadly by capacity, thermodynamic 
cycle, fuel rank or other characteristics. We considered 
subcategorizing the EGUs by their design and fuel characteristics under 
building block 1. Although grouping by categories does not account for 
all of the factors that may affect heat rate, it can provide a useful 
way of understanding the operating profile of classes of coal-fired 
EGUs and the fleet as a whole. However, we have declined to 
subcategorize among affected coal-fired EGUs for both technical and 
practical reasons. First, as discussed above, our assessment of heat 
rate improvement potential uses a unit-specific data methodology that 
compares each EGU's performance against its own historical performance. 
By substantially basing our analysis on these unit-specific 
assessments, we inherently factor in the effect of numerous design 
conditions. We also conducted a regression analysis that evaluated the 
effect of numerous factors on heat rate, and found that subcategorizing 
would generally make little difference in our analysis. Additionally, 
subdividing the EGUs into subcategories would reduce the quantity of 
EGUs used to calculate each average, which would increase the influence 
of random and atypical variations in the data on the overall averages, 
and would thus decrease our confidence in the results. Furthermore, as 
a practical matter, states are free to apportion reductions in a way 
that reflects any subcategories of their choosing when determining the 
emission standards for individual affected EGUs. Additionally, 
commenters assert that because building block 1 is calculated on an 
average basis, some affected EGUs will have greater potential than 
others to reduce CO2 emissions through heat rate 
improvements. If an affected EGU cannot meet its particular emission 
standard because it has below-average potential to reduce emissions 
through heat rate improvements, then in instances where the EGU's state 
plan allows emissions trading, the EGU can acquire credits or 
allowances from affected EGUs that have above-average potential. For a 
further discussion of our reasonable decision not to subcategorize 
among coal-fired EGUs for purposes of determining building block 1, see 
the GHG Mitigation Measures TSD supporting the final CPP.
    Many commenters told the EPA that EGUs already have undertaken 
significant efforts to operate efficiently to provide reliable electric 
service at the lowest reasonable cost; that they believe they cannot 
significantly improve heat rate; that best practice maintenance 
activities are performed on a daily basis, including during maintenance 
outages that allow for the inspection, cleaning and repair of all 
equipment; that extensive capital investments have been made to install 
state-of-the art equipment and replace equipment that is beyond repair; 
and that their employees continuously monitor and control operating 
levels in the combustion process to maintain maximum combustion of fuel 
and to avoid wasting available heat energy. In summary, these 
commenters say they have expended considerable effort and resources to 
maintain peak boiler efficiency at all times and, therefore, the 6-
percent heat rate improvement proposed for building block 1 is 
unreasonable to apply to EGUs across the board; the EPA should develop 
a rule that allows treatment of affected EGUs on a case-by-case basis.
    We commend the efforts of those who strive to operate and maintain 
EGUs in the best possible manner to minimize heat loss and 
CO2 emissions. This rule does allow for treatment of EGUs on 
a case-by-case basis. States may believe that individual considerations 
are appropriate in some cases and, accordingly, we have purposely 
allowed states to make decisions about how to implement specific 
CO2 reductions. Our determinations of 4.3-, 2.1- and 2.3-
percent heat rate improvement for EGUs in the Eastern, Western and 
Texas Interconnection, respectively, are conservatively based on the 
lowest value identified by any of our reasonable statistical analyses. 
If states choose to set limits on individual affected EGUs based in 
part on the availability of heat rate improvements, the states are free 
to assess heat rate improvements on a more targeted, case-by-case basis 
that takes into account an EGU's previous heat rate improvement 
efforts, or lack thereof. The fact that states (or EGUs complying with 
state requirements) can make case-by-case

[[Page 64792]]

decisions about how to achieve goals does not contradict our 
conservative estimates--which are based on millions of hours of 
operating data reported to the EPA by EGUs--of how much EGUs are 
capable of improving their heat rate in each region overall. 
Opportunities to improve heat rate abound for affected EGUs as a whole, 
as evidenced by the fact that the approaches in our statistical 
methodology each included a comparison of an EGU's historical heat rate 
to its 2012 heat rate. Our estimates of the potential heat rate 
improvement are additionally conservative because they are based purely 
on comparisons among historical gross heat rate data, and thus do not 
reflect available, cost-effective opportunities to improve heat rate 
that affected EGUs never implemented during the study period. Finally, 
to the extent that an affected EGU was in 2012 fully implementing every 
possible best practice for improving heat rate, it may still be capable 
of improving heat rate through equipment upgrades.
    Other commenters said that a 6-percent heat rate improvement 
overall is too high; that the heat rate improvement from upgrades are 
double-counted within the data used to determine heat rate improvements 
from best practices; and that the 2-percent heat rate improvement 
specifically for upgrades was inappropriately based on ``conceptual'' 
improvements from only one study.
    We have reduced the 6-percent heat rate improvement from the 
proposed rule to three regionalized figures of 4.3 percent (Eastern), 
2.1 percent (Western) and 2.3 percent (Texas), as discussed above and 
described in detail in the GHG Mitigation Measures TSD supporting the 
final CPP. We expect that, on average, affected coal-fired EGUs can at 
a minimum improve heat rate in these amounts by implementing best 
practices and equipment upgrades identified in the GHG Mitigation 
Measures TSD. These overall heat rate improvement figures do not 
include an estimated percentage heat rate improvement attributable 
specifically to upgrades. Although we are no longer including in our 
calculation of building block 1 a separate 2-percent heat rate 
improvement attributable solely to equipment upgrades, this decision is 
not because we believe that our initial 2-percent assessment of 
equipment upgrades was incorrect. To the contrary, the information 
presented in the S&L study was similar to that in other industry 
reports and studies--many of which were referenced in the proposal 
TSD--describing potential heat rate improvements at EGUs from all types 
of equipment upgrades. However, we recognized that the possibility 
existed that some limited portion of that 2 percent was also reflected 
in our statistical analyses of historical gross heat rate data. In 
order to ensure that our methodology did not double-count an 
indeterminate amount of heat rate improvement available through 
equipment upgrades, we conservatively set aside the entire additional 2 
percent attributable solely to equipment upgrades. Accordingly, we 
determined the amount of potential heat rate improvement in the BSER 
solely from the heat rate analyses described above, which account for 
improvements through best practices and equipment upgrades that were at 
some point achieved by an EGU, but not for the full range of best 
practices and equipment upgrades that are actually available.
    Commenters also said that the EPA did not look at important factors 
that affect heat rate such as coal type, boiler type, cooling water 
temperature, age, nameplate capacity or the use of post-combustion 
pollution controls.
    Our statistical methodology compared each unit to its own 
historical performance and, therefore, largely accounts for the effects 
that a unit's design or fuel characteristics would have on heat rate. 
As discussed above, our methodology used hourly data from 884 units 
over an 11-year period (2002-2012) and compared the variability in the 
heat rate of each individual unit to that unit's own performance. By 
assessing potential heat rate improvement by first looking at unit-
specific data, our methodology inherently factors in the possible 
effects of design and fuel characteristics (e.g., coal type, boiler 
type, nameplate capacity, age, cooling water system, air pollution 
controls) on heat rate and heat rate variability.
    Although cooling water temperature likely plays an important role 
in a coal-fired EGU's heat rate, as stated by commenters, there are no 
consistent quality-assured hourly cooling water temperature data 
available to the EPA. However, in an effort to determine the potential 
effect of cooling water temperature on heat rate, we looked at a sample 
of 45 coal-fired EGUs at 19 facilities for which we had hourly surface 
water temperature data (used as a surrogate for cooling water) from 
monitors located nearby and upstream of cooling water intake points. 
Our analysis found that surface water temperature did explain some of 
the variation in heat rate, but that surface water temperature is 
strongly correlated with ambient air temperature--a variable we did 
control for in our methodology. Because of the strong correlation 
between ambient air temperature and surface water temperature, the 
availability of a comprehensive dataset of nationwide hourly ambient 
air temperature, and the similar explanatory power of surface water 
temperature and ambient air temperature, it is unlikely that separately 
addressing cooling water temperature would significantly change the 
results. Rather, we are confident that our use of hourly ambient air 
temperature in our analyses adequately addressed any significant impact 
of cooling water temperature. See the GHG Mitigation Measures TSD 
supporting the final CPP for further details about this analysis. As 
described further in that TSD, the other potentially relevant variables 
for which we did not directly control are unlikely to significantly 
affect the average heat rate.
    Commenters said that the heat rate improvement attributable to 
upgrades will degrade over time or require repeated and costly further 
upgrades.
    We are aware that some heat rate improvement measures can degrade 
over time. Like most power plant components, some heat rate improvement 
technologies require maintenance in order to sustain their efficacy 
over time. Therefore, to avoid degradation, personnel at EGUs will need 
to diligently apply ``best practices'' on a regular basis, a practice 
that numerous commenters say is standard operating procedure. The S&L 
study includes estimates of associated operations and maintenance (O&M) 
costs for each heat rate improvement method that is discussed. As we 
explained in the proposal, the related O&M costs of diligently applying 
best practices are relatively small compared to the associated capital 
costs and would, therefore, have little effect on the economics of heat 
rate improvements.
    Commenters stated that heat rate improvement should be set on a 
basis that is narrower than nationwide--for example, state-by-state or 
unit-by-unit.
    The EPA did not propose and is not finalizing a rule that sets heat 
rate improvement goals for individual states or for individual coal-
fired EGUs. Instead, in the approved state plans developed under this 
rule, each state will set the emission standards for its various coal-
fired EGUs. In doing so, the state may take into account its own view 
of the amount of heat rate improvement needed (if any) at specific 
EGUs, and may look to the EPA's analysis of heat rate improvement 
potential in the applicable region as a guide, while keeping in mind 
the CO2 emission

[[Page 64793]]

performance rate. This broad-based approach is consistent with the 
traditional rules evaluating the potential for emission reductions on a 
source-category basis, and is consistent with the broader goal-setting 
purpose of this rule. Furthermore, the final rule establishes a uniform 
national performance rate based on the least stringent regional 
performance rate calculated with the building blocks. Accordingly, 
affected EGUs in regions not setting the national level have emission 
reduction opportunities beyond those reflected in the applicable 
performance rate.
    The heat rate improvement measures comprising building block 1 
would ordinarily be evaluated on a nationwide basis. However, in this 
instance there are two good reasons to calculate building block 1 on a 
regionalized basis. First, a regionalized approach is consistent with 
the EPA's approach to determining the other building blocks. For 
building block 1, this means that the heat rate improvement should 
reflect only as much potential for emission reduction from building 
block 1 as our analyses indicate can be achieved on average by the 
affected coal-fired EGUs in that region. This ensures that the BSER for 
each region is representative of the characteristics and opportunities 
available within that region, rather than a less logical combination of 
opportunities in the region and opportunities nationwide. Second, a 
regionalized approach provides a more representative average of the 
potential heat rate improvement that EGUs in a given region are capable 
of achieving. The populations of affected coal-fired EGUs in each 
region differ in some respects, as discussed in the GHG Mitigation 
Measures TSD, and the more nuanced regionalized approach thus 
indirectly accounts for some of those systemic differences. For these 
and other reasons described in Section V.A. of the preamble with 
respect to the BSER as a whole, we have reasonably based building block 
1 on a regionalized approach. Applying this regionalized approach to 
building block 1 strikes an appropriate balance between the proposed 
nationwide analysis and commenters' suggested state-specific analysis, 
which does not fully reflect the interconnected nature of the system 
within which affected coal-fired EGUs operate.
    The practical consequence of calculating building block 1 on a 
regionalized versus nationwide basis is minimal. This is because the 
CO2 emission performance rates are based on the overall 
performance rate determined to be reasonable for EGUs in the Eastern 
Interconnection. Our methodology identifies a 4.3 percent potential 
improvement in the Eastern Interconnection, compared to a 4.0 percent 
figure across all three interconnections.
    We further note, along with some commenters, that site-specific 
engineering studies or unit-by-unit analyses of heat rate improvement 
potential for coal-fired EGUs are not available to the EPA; only a 
small number of site-specific case studies are available in the public 
literature. We considered that for the EPA to develop a comprehensive, 
unit-by-unit heat rate improvement study of nearly 900 coal-fired EGUs 
from scratch, it would likely cost the Agency $50,000 to $100,000 to 
study each EGU (almost $50 to $100 million total) and require three to 
four years to complete. Such a granular analysis would not serve the 
broader goal-setting purpose of this rulemaking. We agree with 
commenters who have pointed out that a heat rate improvement-estimating 
effort of that magnitude and duration would be unnecessarily lengthy 
and expensive. Nor would such a granular analysis be a necessary 
predicate for states to develop emission standards, or for EGUs to 
comply with those emission standards. Rather, our methodology relies on 
individualized, unit-by-unit hourly performance data from 884 EGUs 
provides conservative and reasonable regional estimates of heat rate 
improvement potential. Indeed, given the conservative nature of our 
methodology, a unit-specific approach that evaluates the full range of 
best practices and equipment upgrades available at individual EGUs--
including upgrades not accounted for here--would be more likely to 
result in higher overall heat rate improvement figures than we are 
finalizing for building block 1. Furthermore, site-specific information 
forms the foundation of the EPA's estimated heat rate improvement 
potential, and similar data likely would be used in any site-specific 
heat rate improvement engineering study. Finally, EGU-specific detailed 
design and operation information is not consistently available for all 
the factors that influence heat rate. The EPA has used the 
comprehensive data that are available to reasonably and conservatively 
estimate potential heat rate improvement in each region.
    Commenters also said that shifting electricity generation from 
coal-fired EGUs to other EGUs because of measures implemented under 
other building blocks will lower the capacity factors of coal-fired 
EGUs, and thus increase, not decrease, their heat rates.
    We expect that most states will develop plans that optimize the 
operation of existing coal-fired EGUs while utilizing the other 
building blocks and other measures to reduce emissions from carbon-
intensive generation. From our IPM projections, the average annual 
capacity factor of existing coal-fired EGUs that are expected to remain 
in operation in 2030 will actually increase compared to 2012. This 
projection--which is further described in the GHG Mitigation Measures 
TSD--incorporates expected retirements of inefficient units and 
generation shifts away from using coal-fired EGUs as peaking units.
    Commenters also noted that the EPA used net heat rate in state 
goals, but used gross heat rate in its heat rate improvement analysis--
potentially ignoring the detrimental effect that parasitic load from 
air pollution control devices (APCD) and other equipment can have on 
net heat rate.
    The EPA's variability analysis necessarily and reasonably used 
gross output data for each of the 884 EGUs in the EPA's database 
because they are the only publicly available, unit-specific, hourly 
performance data. By definition, improvement in gross heat rate would 
be reflected in the net heat rate. Gross heat rate is the total heat 
output from the EGU, in units of Btu/gross kWh, and includes the power 
used by auxiliary equipment required to operate the EGU itself. By 
contrast, net heat rate is the remaining Btu/kWh after subtracting the 
power used by the EGU's own auxiliary equipment from the gross heat 
rate value, i.e., what the EGU is able to provide to the grid. 
Improvements in net heat rate alone (e.g., reducing parasitic load of 
on-site equipment) may be possible on many units. Therefore, our use of 
gross heat rate to estimate potential heat rate improvement was 
conservative because of the additional opportunities to achieve the 
uniform performance rate through improvements in net heat rate alone.
    Commenters also raised concerns that the EPA was not taking into 
account net heat rate increases due to additional add-on pollution 
controls that may, for some units, be required by other rules.\645\
---------------------------------------------------------------------------

    \645\ See above for an explanation of gross versus net heat 
rate.
---------------------------------------------------------------------------

    The results of our statistical analyses are based on gross heat 
rates and would not change with installation of emission controls for 
CSAPR, MATS, or other rules because these controls will add parasitic 
load requirements and thereby have an impact on the net heat rates 
only. Furthermore, we conservatively consider region-wide net heat rate

[[Page 64794]]

improvement potential to be the same as that indicated for the region-
wide gross heat rate, when in fact it is not. In order to check our 
assumptions concerning gross versus net heat rate, we used the IPM 
Power Sector Modeling Platform (version 5.14) and National Electric 
Energy Data System (NEEDS) (version 5.14) to analyze the anticipated 
incremental heat input required to operate additional add-on controls 
to comply with various EPA rules, including CSAPR, MATS, effluent 
guidelines for EGUs, and coal combustion residuals. From this analysis, 
we project that between 2012 and 2025, existing coal-fired EGUs are 
expected to install approximately 18.6 GW of wet flue gas 
desulphurization (FGD), 16.6 GW of dry FGD, 24.9 GW of selective 
catalytic reduction (SCR), and 3.9 GW of selective noncatalytic 
reduction (SNCR). The resulting impact from new pollution controls on 
existing coal-fired EGUs' heat rate is expected to be very small, at 
conservatively less than 31 Btu/kWh, or less than 0.3 percent in 
2025.\646\ After 2025, this estimate is particularly conservative 
because the EPA's cost performance models overestimate the parasitic 
load from individual add-on controls for future years. Furthermore, at 
some EGUs these newer pollution control devices will replace existing 
pollution control devices. Accordingly, for these EGUs, the minimal 
increase in net heat rate due to power required to operate new controls 
will be at least partially offset by the decrease in net heat rate 
caused by removal of the control devices currently in place. For more 
information about this analysis, see the GHG Mitigation Measures TSD 
supporting the final CPP.
---------------------------------------------------------------------------

    \646\ When considered on a regional basis, we expect these 
controls to impact heat rate by approximately 0.3 percent in both 
the Eastern and Western Interconnections, and by less than 0.1 
percent in the Texas Interconnection.
---------------------------------------------------------------------------

    Commenters contended that the 11 years of data used to evaluate 
potential heat rate improvement is too broad, and that the population 
of domestic coal-fired EGUs has changed significantly over this time 
period.
    The 11-year span for the hourly gross heat rate data is appropriate 
because it represents a wide variety of economic conditions, market 
conditions and fleet composition, while also capturing the relatively 
recent historical performance of affected coal-fired EGUs. We also 
noted in the proposal TSD that the population of coal-fired EGUs used 
in the analytical approaches to determine potential heat rate 
improvement is made up of coal-fired EGUs that operated in 2012. The 
gross heat rate data of any coal-fired EGUs that retired prior to 2012 
were not included in the dataset.
    Commenters stated that many of the changes in heat rate reflected 
in the 11-year hourly gross heat rate dataset are attributable to 
changes in monitoring methodology, and thus do not represent heat rate 
improvements attributable to best practices or equipment upgrades. In 
addition, commenters are concerned that changes to the monitoring 
methodology in the future could artificially alter the measured heat 
rate.
    Different stack gas flow monitoring methods can yield more or less 
accurate measurements of heat input and CO2 emissions. These 
differences depend on the characteristics of the stack gas flow where 
the monitoring and reference method measurements are taken, and which 
options under the Part 75 emission measurement rules are chosen in the 
application of the various flow rate reference methods. In general, 
more accurate stack gas flow monitoring methodologies yield lower 
values that, when used to calculate emissions or heat input, may lower 
the heat rate values reported to the EPA.
    Some EGUs adopted monitoring methodologies that have the potential 
to affect the exactness of the data we used for assessing heat rate 
improvements. However, as discussed in detail in the GHG Mitigation 
Measures TSD supporting the final CPP, our review of the data shows 
that a relatively small amount of the data are affected by these 
changes; we are confident that the values adopted for building block 1 
are conservative and reasonable estimates of the potential for heat 
rate improvement in each region. Some changes in monitoring methodology 
would have the result of tending to cause us to underestimate the 
potential for heat rate improvement. Furthermore, because our 
methodology analyzes percentage heat rate improvement based on 2012 
gross heat rate data, our results are unaffected by EGUs that used more 
accurate monitoring methodologies in 2012 or used the same monitoring 
methodologies consistently throughout the 11-year study period. For 
these and other reasons discussed in detail in the GHG Mitigation 
Measures TSD, we remain confident in our results despite the marginal 
differences attributable to monitoring methodologies in some of the 
heat rate data for a subset of EGUs.\647\
---------------------------------------------------------------------------

    \647\ Furthermore, on a fundamental level, our methodology 
accounts for a certain amount of any residual inexactness because we 
have conservatively adopted the lowest value identified by any of 
our reasonable approaches--all three of which are themselves 
conservative because they do not account for the full extent of heat 
rate improvements achievable through equipment upgrades.
---------------------------------------------------------------------------

    In terms of concerns with future methodological changes, the 
overwhelming majority of the 884 EGUs in the dataset we used to assess 
heat rate improvement have already changed their stack gas flow 
monitoring methodology in 2012 or earlier. Furthermore, extension of 
the compliance date to 2022 for this rule, as discussed above, more 
than adequately allows enough time for EGUs to determine how to 
actually improve their heat rates and lower CO2 emissions 
while accommodating future changes to monitoring methodologies. For a 
more detailed explanation, see the GHG Mitigation Measures TSD 
supporting the final CPP.
    Commenters said that there is no proof that lowering the heat rate 
will reduce variability or that reduced variability will reduce heat 
rate, i.e., correlation does not prove causation.
    As an initial matter, it is important to note that for the final 
rule the EPA used three types of statistical analyses to evaluate and 
estimate potential heat rate improvements of coal-fired EGUs, and only 
one of these analyses involved any consideration of heat rate 
variability. All three types of statistical analyses are described in 
the GHG Mitigation Measures TSD supporting the final CPP.
    These commenters are correct that, in the abstract, reducing heat 
rate variability only means that heat rate will be more consistent--not 
necessarily lower or higher. However, our analysis is not an abstract 
evaluation of the potential to reduce variability, as commenters 
suggest, but rather is an evaluation of the potential heat rate 
improvement achievable through reducing variability--i.e., reducing 
variability to achieve a more consistently low heat rate. See the more 
detailed discussion of the statistical procedures used for the final 
rule, above. In particular, the application of a ``consistency factor'' 
in the analyses performed for both the proposed and final rule 
demonstrates the potential results if each individual EGU operated 
slightly more consistently with the lower heat rates that the EGU had 
itself previously achieved under similar conditions.
    The consequence of a reduced heat rate is, of course, a lower rate 
of CO2 emissions, which is the purpose of the BSER for 
building block 1. This way of thinking about reduced variability is 
consistent with the utility power sector's own efforts to reduce 
variability, which are aimed at securing

[[Page 64795]]

the economic benefits of a more consistently lower overall heat rate.
    Some commenters expressed concern that heat rate improvements could 
trigger applicability of new source review (NSR) provisions. The 
relationship of this final rule to other regulatory provisions, 
including NSR, is discussed in section X of the preamble.

D. Building Block 2--Generation Shifts Among Affected EGUs

    The second element of the foundation for the EPA's BSER 
determination for reducing CO2 emissions at affected fossil 
fuel-fired EGUs entails an analysis of the extent to which fossil steam 
EGUs can shift generation to existing NGCC EGUs. In this section, we 
define building block 2 as the gradual shifting of generation from 
existing fossil steam to existing NGCC within each region up to a 
maximum NGCC utilization of 75 percent on a net summer basis. In each 
year of the interim period, this 75 percent net summer maximum 
potential is subject to a regional limit informed by historical growth 
rates.
    This section summarizes the EPA's analysis supporting that 
definition. We begin by discussing the sector's ability to reduce 
CO2 emissions by shifting generation, including selected 
background information, data on trends toward greater NGCC generation, 
and various mechanisms for executing or facilitating generation shifts. 
Next, we describe the amount and timing of generation shift we have 
determined to be achievable through the building block. We then discuss 
various elements supporting our quantification of achievable generation 
shift, including the technical feasibility of NGCC units to increase 
generation; historical shifts to NGCC generation; considerations 
related to reliability, natural gas transmission infrastructure, 
natural gas production, and electricity transmission infrastructure; 
and regulatory flexibility. A discussion of costs follows. Finally, we 
respond to certain comments not addressed in the preceding discussions.
1. Demonstration of Ability To Reduce CO2 Emissions Through 
Shifting Generation
    a. Background of utility power sector.
    The ability to shift generation from higher- to lower-emitting 
sources is compatible with the way EGUs are generally dispatched.\648\ 
The standard approach to dispatching generation is through Security 
Constrained Economic Dispatch (SCED), a well-established practice in 
the electric power industry.\649\ As the name indicates, SCED has two 
defining components: Economic operation of generating facilities and 
assurance that the electric system remains reliable and secure.\650\ 
Economic dispatch generally refers to shorter-term planning and 
operations from a day ahead through real time. During this period, 
generating units are committed--a process known as ``unit commitment,'' 
in which units are committed to be ready to provide generation to the 
system when they will be needed--and then dispatched in real time to 
meet the electricity demand of the system. Overall changes in the level 
of generation from different facilities are also planned over time 
periods longer than this 2-day dispatch period. Over a calendar year, 
for example, units are planned and scheduled seasonally or monthly to 
ensure that sufficient capacity and energy will be available to meet 
expected loads in an area. Over a period of a week, units are committed 
to be prepared to start up or shut down to meet forecast loads, and 
dispatch is coordinated within this planning and unit commitment 
framework. This process enables system operators to respond quickly to 
short-term changes in demand, and also to shift generation among 
different generation types to match longer-term requirements and goals.
---------------------------------------------------------------------------

    \648\ See preamble section II.C.1, History of the Power Sector, 
for background to this discussion.
    \649\ ``Economic Dispatch: Concepts, Practices and Issues'', 
FERC Staff Presentation to the Joint Board for the Study of Economic 
Dispatch'', Palm Springs, California, November 13, 2005. A copy of 
this presentation is available in the docket for this rule.
    \650\ ``Security Constrained Economic Dispatch: Definitions, 
Practices, Issues and Recommendations: A Report to Congress'', 
Federal Energy Regulatory Commission, July 31, 2006.
---------------------------------------------------------------------------

    EGUs using technologies with relatively low variable costs, such as 
nuclear units, are for economic reasons generally operated at their 
maximum output whenever they are available. Renewable EGUs such as wind 
and solar units also have low variable costs, but the magnitude and 
timing of their output generally depend on wind and sun conditions 
rather than the operators' discretion. In contrast, fossil fuel-fired 
EGUs have higher variable costs and are also relatively flexible to 
operate. Fossil fuel-fired EGUs are therefore generally the units that 
operators use to respond to intra-day and intra-week changes in demand. 
Because of these typical characteristics of the various EGU types, the 
primary opportunities for switching generation among existing units 
available to EGU owners and grid operators generally consist of 
opportunities to shift generation among various fossil fuel-fired 
units, in particular between coal-fired EGUs (as well as oil- and gas-
fired steam EGUs) and NGCC units. In the short term--that is, over time 
intervals shorter than the time required to build a new electric 
generation unit--fossil fuel-fired units consequently tend to compete 
more with one another than with nuclear and renewable EGUs. The amount 
of generation shifting from coal-fired EGUs to NGCC units that takes 
place as a result of this competition is highly relevant to overall 
power sector GHG emissions, because a typical NGCC unit produces less 
than half as much CO2 per MWh of electricity generated as a 
typical coal-fired EGU.
    b. Trends in generation shifts from coal-fired to natural gas-fired 
sources.
    Since at least 2000, fossil fuel-fired generation has been shifting 
from coal- and oil-fired EGUs to NGCC units, both as a result of 
construction of additional NGCC units, and also as a result of dispatch 
of pre-existing NGCC units at higher capacity factors. As a result, 
generation from NGCC EGUs in 2012 reached over four times the level of 
NGCC generation in 2000, while generation from coal and oil/gas steam 
EGUs decreased by around one third.\651\ As we demonstrate in the GHG 
Mitigation Measures TSD, NGCC units are capable of operating at higher 
annual capacity factors than they have historically, so there remains 
considerable opportunity for increased use of existing NGCC units to 
replace generation currently supplied by higher-emitting coal and oil/
gas steam units. The electric utility industry is thus well-positioned 
to address the requirements of this building block by increasing use of 
existing NGCC units and correspondingly decreasing use of steam units. 
The electric industry has been shifting generation to NGCC units in 
recent years and is expected to continue to retire coal capacity and 
add new NGCC capacity. In the reference case without implementation of 
CO2 emission limitations, EIA forecasts 40 GW of coal 
retirements and 53 GW of NGCC capacity additions from 2014 to 
2030.\652\ An EPA review of state Integrated Resource Plans (IRPs) 
shows a pattern of shifting away from coal steam capacity to NGCC 
capacity and, in some cases, conversion of coal steam capacity to 
natural gas steam capacity. For example, Ameren plans to add 600 MW of 
NGCC capacity and convert two coal units to natural gas steam units, 
and Duke plans to add 680 MW of

[[Page 64796]]

NGCC capacity and convert one coal unit to a natural gas steam 
unit.\653\
---------------------------------------------------------------------------

    \651\ Ventyx Electric Power Database.
    \652\ Energy Information Administration, Annual Energy Outlook 
2015 reference case, ref2015.d021915a.
    \653\ For further examples, see the memo entitled ``Review of 
Electric Utility Integrated Resource Plans'' (May 7, 2015) available 
in the docket.
---------------------------------------------------------------------------

    c. Mechanisms for dispatch shifts from coal-fired to natural gas-
fired generation.
    There are a variety of patterns of ownership and operational 
control of EGUs; these ownership and operational structures influence 
how EGUs will respond to this building block. However, all owners and 
operators have the ability to comply by using this building block. In 
terms of ownership, investor-owned utilities (IOUs) serve about 75 
percent of the US population, while consumer-owned utilities serve the 
remaining 25 percent.\654\ In states that have maintained traditional 
regulation, IOUs are generally vertically integrated (owning generating 
capacity as well as transmission and distribution infrastructure), and 
the wholesale sales of these EGUs are regulated by the state; in states 
that have deregulated their retail service, ownership of the EGU is 
separated from ownership of transmission, and wholesale sales of 
generation are regulated by FERC. Consumer-owned utilities comprise 
municipal utilities, public utility districts of various types owned by 
government agencies, nonprofit cooperative entities (co-ops), and a 
number of other entities such as Native American Tribes.
---------------------------------------------------------------------------

    \654\ Regulatory Assistance Project, Electricity Regulation in 
the US: A Guide, Page 9, March 2011. Available at http://www.raponline.org/docs/RAP_Lazar_ElectricityRegulationInTheUS_Guide_2011_03.pdf.
---------------------------------------------------------------------------

    Operational control of the dispatch of power over the electricity 
grid is superimposed on this pattern of ownership. Prior to electricity 
restructuring, this dispatch was typically operated by major 
vertically-integrated utilities or by public power entities. Over the 
last 15 years, large portions of the power grid are now independently 
operated by ISOs or RTOs. These entities are regulated by FERC and 
dispatch power from multiple owners to meet the loads on the bulk power 
grid.
    The combination of multiple ownership and types of operational 
control adds to the complexity of electricity dispatch, but all 
affected EGUs, regardless of ownership and type of control, can use 
this building block to comply with the final rule. The principal 
difference among the differing entities lies in the types of methods 
that are available for the affected EGU owner to bring about the shift 
in generation that will make use of this building block for compliance. 
There are several alternatives to accomplish this result: The owner of 
the higher-emitting affected EGU may also own, or have affiliates that 
own, lower emitting generation and thus reduce its own generation and 
use its control over these other EGUs to increase their generation; an 
EGU may be able to reduce its generation and buy replacement power from 
the market that is lower emitting; or the EGU may be able to reduce its 
generation and procure generation from a separately-owned lower-
emitting EGU. These alternatives will be available in states with 
either rate or mass-based state plans without any change in their 
general form. Under a rate-based state plan, an EGU owner may also be 
able to purchase ERCs and average the ERCs into its emission rate for 
purposes of demonstrating compliance with its standard of performance. 
Under standards of performance that incorporate emissions trading, an 
EGU owner may be able to purchase rate-based emission credits or mass-
based emission allowances not needed by other EGUs and use those 
credits or allowances to help achieve its standard of performance.
    The potential to shift generation identified for this building 
block is entirely consistent with the existing economic dispatch 
protocols described above. State environmental policies can shift 
generation in two ways. The first is operational restrictions, such as 
permit limits on the number of hours that an EGU can operate in order 
to limit emissions. The second is changes in the relative costs of 
generation among different types of EGUs related to pollution reduction 
measures. For example, a regulation that necessitates the use of a 
control technology that requires the application of a reagent in a 
certain kind of EGU will increase the variable cost of operating that 
plant, which in turn may reduce the amount of generation it is called 
upon to deliver to the grid through security-constrained economic 
dispatch procedures.
    In an organized market, where the system operator dispatches units 
partly based upon costs, an electric power plant that experiences an 
increase in its variable costs will tend to operate less than it 
otherwise would have. For example, market-based pollution control 
programs require units to hold tradable allowances to authorize their 
emissions of a regulated pollutant. Such an allowance-holding 
requirement puts a price on the act of emitting the regulated 
pollutant, which increases the operating costs of units that emit that 
pollutant, and thus such units will be dispatched less than they 
otherwise would without such an allowance-holding requirement. The RGGI 
is an example of a state program that has this effect. In the present 
rule, although shifts in the mix of generation to address the costs of 
pollution control can lead to higher electricity generating costs 
overall, the EPA analysis shows these costs to be modest and well below 
their associated benefits.\655\
---------------------------------------------------------------------------

    \655\ See the Regulatory Impact Analysis.
---------------------------------------------------------------------------

    Many of the NGCC units are owned by the same companies or 
affiliates that also own steam units. In these cases, changes in EGU 
generation can be planned by the company or affiliate without the need 
to engage in separate market transactions with outside parties. Where 
the affected EGU owner is also the dispatch entity, as in most 
traditional market structures, the EGU owner will generally have 
operational control over the unit. Environmental conditions, such as 
compliance costs or limits on generation, can be factored in with fuel 
costs for purposes of determining when the unit is committed to be 
available, how the unit can be most efficiently cycled, and at what 
level the unit is dispatched.
    An analysis of generation data from steam and NGCC units in 2012 
shows that 77 percent of the steam generation occurred from an EGU that 
owned, or that had an affiliate that owned, NGCC generation. Eighty 
percent of the generation shift potential identified in this building 
block (increasing NGCC generation up to a 75 percent capacity factor on 
a net basis to replace steam generation) could occur among these 
entities that own (either directly or through affiliates) both steam 
and NGCC generation.\656\ These data show that most EGU generation 
relevant for this building block is produced by entities that own both 
steam and NGCC generation.
---------------------------------------------------------------------------

    \656\ SNL Energy. Data used with permission. Accessed May 2015.
---------------------------------------------------------------------------

    Another alternative available to an affected EGU owner that does 
not also own NGCC generation is for the higher-emitting affected EGU to 
reduce its generation and purchase replacement power from the market. 
In organized markets such as RTOs, it is available through standard 
practice, because the owner impacts how its EGUs are dispatched based 
upon how it bids into the RTO market. In this case, the owner can 
exercise control over the levels of generation across units by when it 
offers generation to the market operator (the RTO or ISO), and the 
prices it bids for this generation. As in traditional economic dispatch 
by a utility, environmental conditions, compliance

[[Page 64797]]

costs, or limits on generation can be incorporated by the owner into 
the determination of the cost-effective generation pattern of its EGUs.
    In regions with organized electricity markets (including, but not 
limited to, RTOs or ISOs), the various types of EGU owners of higher-
emitting sources can reduce their generation, and any resulting deficit 
in generation on the system can be supplied from other EGUs in the 
region; for example, a coal-fired unit can reduce generation that is 
then replaced through the operation of the market by generation from an 
NGCC unit, subject to dispatch by a regional operator to ensure the 
reliable delivery of the generation to loads within the region. To 
comply with this rule, higher-emitting steam units will need greater 
emission reductions relative to lower-emitting NGCC units which will, 
in turn, tend to raise steam unit costs compared to NGCC units. As a 
result, the bids that a steam unit provides a market operator will rise 
relative to NGCC units. This process of reducing generation from a 
higher-emitting unit will lead to substitution of lower-emitting 
generation.
    EGU owners that do not participate in an organized electricity 
market may nevertheless purchase power from the wholesale power market. 
Purchases in the wholesale power market can be spot purchases, which 
are typically general purchases of system power supplied by the EGUs 
across a region, or contract purchases, which may have more provider-
specific characteristics (such as specifying the type of unit that is 
providing the power). Purchases between EGUs through the wholesale 
power market will have similar emission-lowering properties as 
operation of the organized market discussed above, because dispatch in 
balancing areas outside RTOs and ISOs also follows a similar economic 
dispatch protocol that is informed by each unit's production costs and 
environmental limitations.
    Under this alternative, the steam generators may, in effect, 
realize emission reductions from building block 2 simply by reducing 
their generation. Steam generators do not need to purchase replacement 
electricity as a prerequisite for realizing emission reductions from 
reducing their own generation because other generators already have an 
incentive to provide as much electricity as load-serving entities are 
willing to buy in order to satisfy electricity demand.\657\ As noted 
above, higher-emitting generation sources will have to incorporate 
correspondingly higher costs of pollution reduction into their supply 
bids compared to lower-emitting generation sources, and as a result, 
load-serving entities will seek to buy a greater share of electricity 
from the lower-emitting sources because their supply bids will be more 
economically attractive. Once the steam generators reduce their 
generation (and associated emissions), the other entities in the 
electricity system arrange for the replacement electricity. The outcome 
of this power market process will reduce both the mass and the rate of 
emissions across sources.
---------------------------------------------------------------------------

    \657\ Some owners or operators of steam generators may have 
electricity supply obligations to which they may be applying power 
from those steam generators. However, such parties may fulfil those 
supply obligations using the wholesale power market in the exact 
same way described here that enables any other generator with 
economically attractive electricity to offer such supply. In other 
words, the ability of a steam generator to reduce its generation is 
not contingent on an associated purchase to replace that power, 
notwithstanding the possibility that the owner or operator of that 
steam unit may choose to make such a purchase to meet an electricity 
supply obligation.
---------------------------------------------------------------------------

    An owner of a source can also reduce the generation of an EGU by 
substituting generation from a lower-emitting NGCC directly. For an EGU 
owner without existing NGCC generation, this substitution can take the 
form of a bilateral contract purchase. In RTOs and ISOs, this 
alternative often takes the form of a contract for differences, where 
the replacement source could be an NGCC and the contract specifies a 
delivery location and the price of the power. In bilateral markets, the 
contract vehicle could be a Power Purchase Agreement from a replacement 
source. It is also possible that the owner of a steam unit could 
directly invest in an existing EGU by purchasing the asset or taking a 
partial ownership position, thus acquiring the generation from the unit 
through that means. The acquired generation and its associated 
emissions could be used for compliance by the higher-emitting EGU, in 
accordance with the plan under which it is operating. The amount of 
generation that could be shifted using the approaches described in this 
paragraph will depend on the type and terms of the commercial 
arrangements, as well as the potential need for regulated entities to 
obtain approvals for contracts or for changes in asset positions. The 
wide range of approaches permitted by this rule provides flexibility, 
both within a year and across multiple years, for EGUs to fashion these 
arrangements to fit their circumstances.
    Where permitted under its state plan, an EGU would also be able to 
meet its reduction obligations using ERCs or allowances. The particular 
nature of this alternative will depend on how a state elects to develop 
its plan. If a state chooses a mass-based approach, the EGU would 
simply need to hold allowances to cover its emissions. To realize an 
emission reduction from building block 2 under this approach, a steam 
generator would only need either to reduce its emissions by reducing 
its generation, which would lead to that generator needing fewer 
allowances to cover its emissions under the program, or to purchase 
surplus allowances not needed by another EGU that had reduced its 
emissions. In a rate-based state, the state may choose to provide for 
compliance through the acquisition of tradable ERCs. To realize an 
emission reduction from building block 2 under this approach, a steam 
generator would be able to adjust its effective emission rate by 
purchasing ERCs that are produced by other sources whose emission rates 
are lower than the applicable rate standard. In this fashion, a steam 
generator does not need to purchase lower-emitting replacement power 
per se in order to demonstrate an emission reduction from this building 
block; instead, the steam generator may purchase any ERCs that were 
produced from lower-emitting sources (see section VIII for more detail 
on how state plans can use an ERC approach to facilitate a rate-based 
compliance demonstration of this type of emission reduction).\658\
---------------------------------------------------------------------------

    \658\ Stakeholders have recognized that ERCs and allowances are 
an effective tool for EGUs to implement the building blocks and 
achieve their standards of performance required under this rule. See 
``Clean Power Plan Implementation: Single-State Compliance 
Approaches with Interstate Elements,'' Georgetown Climate Center 
(May 2015), http://www.georgetownclimate.org/sites/www.georgetownclimate.org/files/GCC_ComplianceApproacheswithInterstateElements_May2015.pdf.
---------------------------------------------------------------------------

    The approaches shown here collectively demonstrate that all steam 
generators--regardless of size, location, form of ownership, or type of 
market in which they operate--can implement building block 2 through 
some or all of the mechanisms described.
2. Amount and Timing of Generation Shift
    The EPA has determined that for purposes of quantifying the 
CO2 emission reductions achievable through building block 2, 
a reasonable amount of generation shift is the amount of generation 
shift that would result from existing NGCC units, on average, 
increasing their annual utilization rates to 75 percent of net summer 
capacity. However, the building block does not reflect achievement of 
this average capacity factor at the start of the interim period, but 
instead reflects a glide path of increases in NGCC utilization over

[[Page 64798]]

the interim period. Below, we discuss the glide path, and in the 
following section we discuss the basis for finding the 75 percent 
utilization rate, achieved over the period of time consistent with the 
glide path, to be reasonable.
    The EPA received significant public comments expressing concern 
regarding the proposal's incorporation of the full building block 2 
shift in generation by the first year of the interim period. These 
commenters perceived this approach as requiring states to achieve such 
a significant portion of the required CO2 emission 
reductions early in the interim period that states would lack 
flexibility in when and how they may achieve the required emission 
reductions. Other commenters expressed concern that the full extent of 
building block 2 would be difficult for some states to achieve by the 
first year of the interim period as a result of technical, engineering, 
and infrastructure limitations or other considerations; that such 
timing may crowd out other cost-effective options for emission 
reductions; and that such timing might have negative implications for 
reliability.
    In the proposal, the EPA determined that emission reductions are 
feasible and achievable at fossil fuel-fired steam EGUs by shifting 
from more carbon-intensive EGUs to less carbon-intensive EGUs, as part 
of the BSER. More specifically, the EPA proposed that generation shifts 
from fossil fuel-fired steam units (which are primarily coal-fired) to 
NGCC units, up to a utilization of 70 percent on a nameplate capacity 
basis, could be achieved by 2020. In contrast, the EPA proposed that 
reductions in CO2 emissions from fossil fuel-fired units 
associated with other measures, such as increased utilization of RE 
generating capacity and increased demand-side EE, would be achievable 
on a phased-in basis between 2020 and 2029, reflecting the time needed 
for deployment.\659\ In light of the concerns noted above, in the 
October 2014 NODA, the EPA solicited comment on potential rationales 
for phasing in the potential to shift generation under building block 
2.\660\
---------------------------------------------------------------------------

    \659\ 79 FR 34866.
    \660\ 79 FR 64543.
---------------------------------------------------------------------------

    As already noted, in the final rule the EPA has revised the interim 
period to start in 2022, which itself is a meaningful response 
regarding the concerns expressed by commenters about the timing of 
building block 2's generation shift potential. In addition, the EPA has 
evaluated the feasibility over time of building block 2 within the 
framework of BSER, and is finalizing a change to building block 2 that 
gradually phases in the shift from existing fossil steam to existing 
NGCC over the interim period. This phase-in allows for additional time 
to complete potential infrastructure improvements (e.g., natural gas 
pipeline expansion or transmission improvements) that might be needed 
to support more use of existing natural gas-fired generation, and 
provides states with the increased ability to coordinate actions taken 
under building block 2 with actions taken under building block 3 
(deployment of new renewable capacity).
    The phase-in schedule applies a limit to the maximum building block 
2 potential in each year of the interim period based on two parameters. 
The first parameter defines an amount of generation shift to existing 
NGCC capacity that is feasible by 2022, and the second parameter 
defines how quickly that amount could grow until the full amount of 
NGCC generation could be achieved as part of the BSER. Both of these 
parameters are determined by examining the extent to which gas-fired 
generation has increased over historical time periods. The first 
parameter is based on the single largest annual increase in power 
sector gas-fired generation since 1990, which occurred between 2011 and 
2012 and is equal to 22 percent.\661\ We believe that this amount is a 
conservative estimate of the ability of the sector to increase 
utilization of NGCC capacity by 2022, given that this increase has 
already occurred in a single year. The second parameter is based on the 
average annual growth in gas-fired generation in the power sector 
between 1990 and 2012, which is approximately 5 percent per year.
---------------------------------------------------------------------------

    \661\ US EIA Monthly Energy Review, Table 7.2b Electricity Net 
Generation: Electric Power Sector (2015), available at http://www.eia.gov/totalenergy/data/browser/xls.cfm?tbl=T07.02B&freq=m.
---------------------------------------------------------------------------

    In the performance rate calculation methodology, these two 
parameters constrain the annual rate at which building block 2 shifts 
generation from fossil steam units to NGCC units. The interim 
performance rate is an average of annual rates calculated over the 
2022-2029 period. The two parameters above limit the extent to which 
NGCC generation is able to increase and replace fossil steam generation 
in each year of the interim period. In the first year, NGCC generation 
is limited to a maximum of a 22 percent increase from 2012 levels in 
each region. In each subsequent year, regional NGCC generation is 
limited to a maximum of a 5 percent increase from the previous year. 
This phase-in continues in the performance rate-setting methodology 
until the full building block 2 level of shifting from fossil steam 
generation to NGCC generation is reached. Under this approach, building 
block 2 is completely phased into the source category calculation of 
all regions by the end of the interim period.

                                             Table 7--BSER Maximum NGCC Generation by Region and Year (TWh)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                  NGCC generation (TWh)
                                                                ----------------------------------------------------------------------------------------
                             Region                                Maximum                                          BSER maximum
                                                                  potential       2012    --------------------------------------------------------------
                                                                    at 75%     (adjusted)   2022   2023   2024   2025   2026   2027   2028   2029   2030
--------------------------------------------------------------------------------------------------------------------------------------------------------
Limit..........................................................  ...........  ...........    22%     5%     5%     5%     5%     5%     5%     5%     5%
Eastern Interconnection........................................          988          735    896    941    988    988    988    988    988    988    988
Western Interconnection........................................          306          198    242    254    267    280    294    306    306    306    306
Texas Interconnection..........................................          204          137    167    176    185    194    203    204    204    204    204
--------------------------------------------------------------------------------------------------------------------------------------------------------

This phase-in, in addition to the flexible nature of the goals, ensures 
that the overall framework of this final rule includes sufficient 
flexibility, particularly with respect to timing of and strategies for 
reducing emissions from the affected units, so that states can develop 
cost-effective strategies and allow for infrastructure improvements to 
occur should they prove necessary in some locations.

[[Page 64799]]

3. Basis for Magnitude of Generation Shift
    a. Technical feasibility of NGCC units to generate at 75% of their 
capacity.
    In order to estimate the potential magnitude of the opportunity to 
reduce power sector CO2 emissions through shifting 
generation among existing EGUs, the EPA first examined information on 
the design capabilities and availability of NGCC units. Availability is 
defined as the number of hours that generators are available to 
generate electricity, and it is typically expressed as a percentage of 
the total number of hours in a year. Since the value of NGCC capacity 
is related to how much electricity the owner of that capacity can 
generate and sell, units are typically designed with very high 
availability ratings. Baseload units have annual average availabilities 
of approximately 91%-92%, and peaking units are generally available 96% 
to 98% of peak hours.\662\ The EPA also examined information on the 
historical availability of NGCC units in practice. This examination 
showed that, although most NGCC units have historically been operated 
in intermediate-duty roles for economic reasons, they are technically 
capable of operating in baseload roles at much higher annual 
utilization rates. Average annual availability (that is, the percentage 
of annual hours when an EGU is not in a forced or maintenance outage) 
for NGCC units in the U.S. generally exceeds 85 percent, and can exceed 
90 percent for some groups.\663\
---------------------------------------------------------------------------

    \662\ Negotiating Availability Guarantees for Gas Turbine 
Plants, available at: http://www.power-eng.com/articles/print/volume-105/issue-3/features/negotiating-availability-guarantees-for-gas-turbine-plants.html.
    \663\ See, e.g., North American Electric Reliability Corp., 
2008-2012 Generating Unit Statistical Brochure--All Units Reporting, 
http://www.nerc.com/pa/RAPA/gads/Pages/Reports.aspx; Higher 
Availability of Gas Turbine Combined Cycle, Power Engineering (Feb. 
1, 2011), http://www.power-eng.com/articles/print/volume-115/issue-2/features/higher-availability-of-gas-turbine-combined-cycle.html.
---------------------------------------------------------------------------

    We also researched historical data to determine the utilization 
rates that NGCC units have already demonstrated their capability to 
sustain. Over the last several years, the utilization patterns of 
fossil fuel-fired units have shifted relative to historical dispatch 
patterns, with NGCC units increasing generation and many coal-fired 
EGUs reducing generation. In fact, in April 2012, for the first time 
ever the total quantity of electricity generated nationwide from 
natural gas was approximately equal to the total quantity of 
electricity generated nationwide from coal.\664\ These changes in 
generation patterns have been driven largely by changes over time in 
the relative prices of natural gas and coal. Although the relative fuel 
prices vary by location, as do the recent generation patterns, this 
trend holds across broad regions of the U.S. In the aggregate, the 
historical data provide ample evidence indicating that, on average, 
existing NGCC units can achieve and sustain utilization rates higher 
than their historical average utilization rates.
---------------------------------------------------------------------------

    \664\ http://www.eia.gov/todayinenergy/detail.cfm?id=6990.
---------------------------------------------------------------------------

    Utilization of EGUs is often considered using the metric of a 
capacity factor, which is the percentage of total production potential 
that an electric generating unit achieves in a given time period. A 
capacity factor of 75 percent thus represents a unit producing three-
quarters of the electricity it could have produced in that time had it 
utilized its entire capacity. The EPA received multiple comments 
regarding the proposed use of nameplate capacity in calculating the 
potential utilization level of existing NGCCs under building block 2. 
These comments stated that net summer capacity is a more meaningful and 
reliable metric than nameplate capacity, because net capacity best 
reflects the electric output available to serve load. The EPA agrees 
with these comments. The quantification of building block 2 as well as 
performance rate and state goal calculations in the final rule are all 
based on net summer generating capacity. An annual utilization rate of 
75 percent on a net summer basis is similar to the proposed rule's 
consideration of 70 percent utilization on a nameplate basis.\665\
---------------------------------------------------------------------------

    \665\ For a given amount of net generation, a net summer 
capacity factor appears higher compared to a corresponding nameplate 
capacity factor because net summer capacity reflects a lower amount 
of total generation potential achievable by the unit in practice.
---------------------------------------------------------------------------

    The experience of relatively heavily-used NGCC units provides an 
additional indication of the degree of increase in average NGCC unit 
utilization that is technically feasible.
    The EPA reexamined the historical NGCC plant utilization rate data 
reported to the EIA, and found that in 2012 roughly 15 percent of 
existing NGCC plants operated at annual utilization rates of 75 percent 
or higher on a net summer basis.\666\ In effect, these plants were 
providing baseload power. In addition to the 15 percent of NGCC plants 
that operated approximately at a 75 percent utilization rate on an 
annual basis, some NGCC plants operated at even higher utilization 
rates for shorter, but still sustained, periods of time in response to 
high cyclical demand. For example, on a seasonal basis, a significant 
number of NGCC plants have achieved utilization rates greater than 90 
percent on a net summer basis; during the summer of 2012 (June through 
August), about 30 percent of NGCC plants operated at utilization rates 
of 75 percent or more across the entire season. During the spring and 
fall periods when electricity demand levels are typically lower, these 
plants were sometimes idled or operated at much lower capacity factors. 
Nonetheless, the data clearly demonstrate that a substantial number of 
existing NGCC plants have proven the ability to sustain 75 percent 
utilization rates for extended periods of time. We view this as strong 
evidence that increasing the annual average utilization rates of 
existing NGCC units to 75 percent on a net summer basis would be 
technically feasible.
---------------------------------------------------------------------------

    \666\ Net summer capacity is defined as: ``The maximum output, 
commonly expressed in megawatts (MW), that generating equipment can 
supply to system load, as demonstrated by a multi-hour test, at the 
time of summer peak demand (period of June 1 through September 30.) 
This output reflects a reduction in capacity due to electricity use 
for station service or auxiliaries.'' (EIA, http://www.eia.gov/tools/glossary).
---------------------------------------------------------------------------

    The EPA believes that an annual average utilization rate of 75 
percent on a net summer basis is a conservative assessment of what 
existing NGCC plants are capable of sustaining for extended periods of 
time. In 2012, roughly 10 percent of existing NGCC plants operated at 
annual utilization rates of 80 percent or higher on a net summer basis. 
While the EPA believes this level is also technically feasible on 
average for the existing NGCC fleet, the EPA is quantifying building 
block 2 assuming an NGCC utilization level of 75% on a net summer basis 
in order to offer sources additional compliance flexibility, given that 
the extent to which they realize a utilization level beyond 75 percent 
will reduce their need to rely on other emission reduction measures or 
building blocks.
    b. Historical generation shifts to NGCC generation.
    In 2012, total electric generation from existing NGCC units was 966 
TWh.\667\ After the application of the building block 2 potential 
(increasing NGCC utilization up to a 75 percent capacity factor on a 
net summer basis, including generation from NGCC units that were under 
construction), the total generation

[[Page 64800]]

from these existing sources is assumed to be 1,498 TWh.\668\
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    \667\ Appendix 1, CO2 Emission Performance Rate and 
Goal Computation Technical Support Document for CPP Final Rule.
    \668\ Appendix 1, CO2 Emission Performance Rate and 
Goal Computation Technical Support Document for CPP Final Rule.
---------------------------------------------------------------------------

    The EPA believes that producing this quantity of generation from 
this set of NGCC units is feasible. To put this level of generation 
into context, NGCC generation increased by approximately 439 TWh (an 83 
percent increase) between 2005 and 2012. The EPA calculates that 
assumed NGCC generation in 2022 through the quantification of building 
block 2 potential is approximately 44 percent higher than 2014 levels. 
This reflects a smaller growth rate in potential NGCC generation 
between 2015 and 2022 than has been observed in practice from 2005 to 
2012, a time period of the same duration.
    c. Reliability.
    We also expect that an increase in NGCC generation of this amount 
would not impair power system reliability. Sources can achieve 
increases in utilization of existing NGCCs that displace generation 
from steam sources without impacting reliability because this shift in 
average annual utilization across existing EGUs does not inhibit the 
power sector's ability to maintain adequate dispatchable resources to 
continue to meet reserve margins and maintain reliability. Furthermore, 
sources are not required to achieve the exact or even the full extent 
of the building block 2 generation shift itself, which means that 
sources will have ample flexibility to maintain reliability-relevant 
operations while achieving emission reductions through a variety of 
measures.\669\
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    \669\ See section VIII for further discussion of electric 
reliability planning.
---------------------------------------------------------------------------

    d. Natural gas infrastructure.
    The EPA also examined the technical capability of the natural gas 
supply and delivery system to provide increased quantities of natural 
gas and the capability of the electricity transmission system to 
accommodate shifting generation patterns. For several reasons, we 
conclude that these systems would be capable of supporting the degree 
of increased NGCC utilization potential in building block 2. First, the 
natural gas pipeline system is already supporting national average NGCC 
utilization rates of 60 percent or higher during peak hours, which are 
the hours when constraints on pipelines or electricity transmission 
networks are most likely to arise. NGCC unit utilization rates during 
the range of peak daytime hours from 10 a.m. to 9 p.m. are typically 15 
to 20 percentage points above their average utilization rates (which 
have recently been in the range of 40 to 50 percent).\670\ Fleet-wide 
combined-cycle average monthly utilization rates have reached 65 
percent,\671\ showing that the pipeline system can currently support 
these rates for an extended period. If the current pipeline and 
transmission systems allow these utilization rates to be achieved in 
peak hours and for extended periods, it is reasonable to expect that 
similar utilization rates should also be possible in other hours when 
constraints are typically less severe, and be reliably sustained for 
other months of the year. Furthermore, the NGCC utilization increase 
assumed in building block 2 could occur without a significant impact on 
peak demand for natural gas, including winter demand (when the power 
sector's demand for natural gas competes with other sectors' demands 
for natural gas), since increasing annual utilization of NGCCs could 
focus on non-peak periods when NGCC capacity factors are currently low.
---------------------------------------------------------------------------

    \670\ EIA, Average utilization of the nation's natural gas 
combined-cycle power plant fleet is rising, Today in Energy, July 
9,2011, http://www.eia.gov/todayinenergy/detail.cfm?id=1730#; EIA, 
Today in Energy, Jan. 15, 2014, http://www.eia.gov/todayinenergy/detail.cfm?id=14611 (for recent data).
    \671\ EIA, Electric Power Monthly, February, 2014. Table 6.7.A.
---------------------------------------------------------------------------

    The second consideration supporting a conclusion regarding the 
adequacy of the gas supply infrastructure is that pipeline and 
transmission planners have repeatedly demonstrated the ability to 
methodically relieve bottlenecks and expand capacity.\672\ Natural gas 
pipeline capacity has regularly been added in response to increased gas 
demand and supply, such as the addition of large amounts of new NGCC 
capacity from 2001 to 2003, or the delivery to market of unconventional 
gas supplies since 2008. These pipeline capacity increases have added 
significant deliverability to the natural gas pipeline network to meet 
the potential demands from increased use of existing NGCC units. Over a 
longer time period, much more significant pipeline expansion is 
possible. In previous studies, when the pipeline system was expected to 
face very large demands for natural gas use by electric utilities, the 
pipeline industry projected that increases of up to 30 percent in total 
deliverability out of the pipeline system would be possible.\673\ There 
have been notable pipeline capacity expansions over the past five 
years, and substantial additional pipeline expansions are currently 
under construction.\674\ Further, the phasing in of building block 2's 
potential in the determination of the BSER; the flexible nature of 
multi-year compliance with the ultimate emission reduction requirements 
of the rule; and the seven years between finalization of this rule and 
the first year of compliance provide time for infrastructure 
improvements to occur should they prove necessary in some locations. 
Combining these factors of currently observed average monthly NGCC 
utilization rates of up to 65 percent, the flexibility of the emission 
guidelines, the rates of historical growth, and the availability of 
time to address any existing pipeline infrastructure limitations, it is 
reasonable to conclude that the natural gas pipeline system can 
reliably deliver sufficient natural gas supplies to allow NGCC 
utilization to increase up to an average annual capacity factor of 75 
percent on a net summer basis.
---------------------------------------------------------------------------

    \672\ See, e.g., EIA, Natural Gas Pipeline Additions in 2011, 
Today in Energy, available at http://www.eia.gov/todayinenergy/detail.cfm?id=5050; INGAA Foundation, Pipeline and Storage 
Infrastructure Requirements for a 30 Tcf Market (2004 update), 
available at http://www.ingaa.org/Foundation/Foundation-Reports/Studies/FoundationReports/45.aspx; INGAA Foundation, North American 
Midstream Infrastructure Through 2035--A Secure Energy Future Report 
(2011), available at http://www.ingaa.org/File.aspx?id=14911.
    \673\ Pipeline and Storage Infrastructure Requirements for a 30 
Tcf Market, INGAA Foundation, 1999 (Updated July, 2004); U.S. gas 
groups confident of 30-tcf market, Oil and Gas Journal, 1999.
    \674\ For example, between 2010 and April 2014, 118 pipeline 
projects with 44,107 MMcf/day of capacity (4,699 miles of pipe) were 
placed in service, and between April 2014 and 2016 an additional 47 
pipeline projects with 20,505 MMcf/day of capacity (1,567 miles of 
pipe) are scheduled for completion. Energy Information 
Administration, http://www.eia.gov/naturalgas/data.cfm.
---------------------------------------------------------------------------

    e. Natural gas production.
    We recognize that an increase in NGCC utilization rates at existing 
units corresponds with an associated increase in natural gas 
production, consistent with the current trends in the natural gas 
industry. The EPA expects the growth in NGCC generation assumed for 
building block 2 to be feasible and consistent with the production 
potential of domestic natural gas supplies. Increases in the natural 
gas resource base have led to fundamental changes in the outlook for 
natural gas. There is general agreement that recoverable natural gas 
resources will be substantially higher for the foreseeable future than 
previously anticipated, exerting downward pressure on natural gas 
prices. According to EIA, proven natural gas reserves have doubled 
between 2000 and 2012. Domestic dry gas production has increased by 25 
percent over that same timeframe (from 19.2 TCF in 2000 to 24.0 TCF in 
2012).

[[Page 64801]]

EIA's Annual Energy Outlook Reference Case for 2015 projects that 
production will further increase to 29.5 TCF by 2022 and 33 TCF by 
2030, as a result of increased supplies and favorable market 
conditions. In the AEO 2015 high oil and gas resource case, production 
is projected to increase to 42.7 TCF in 2030. For comparison, building 
block 2 assumes NGCC generation growth of 235 TWh from 2012 to reach 
the level assumed for 2022, and that NGCC generation growth would 
result in increased gas consumption of less than 2 TCF for the 
electricity sector, which is less than EIA's projected increase in 
natural gas production of 5.5 TCF from 2012 to 2022.
    The EPA has also assessed the ability of the electricity and 
natural gas industries to achieve the potential quantified for building 
block 2 using the Integrated Planning Model (IPM). IPM is a multi-
regional, dynamic, deterministic linear programming model of the U.S. 
electric power sector that the EPA has used for over two decades to 
evaluate the economic and emission impacts of prospective environmental 
policies. To inform its projections of least-cost capacity expansion 
and electricity dispatch, IPM incorporates representations of 
constraints related to fuel supply, bulk power transmission capacity, 
and unit availability. The model includes a detailed representation of 
the natural gas pipeline network and the capability to project economic 
expansion of that network based on pipeline load factors. At the EGU 
level, IPM includes detailed representations of key operational 
limitations such as turn-down constraints, which are designed to 
account for the cycling capabilities of EGUs to ensure that the model 
properly reflects the distinct operating characteristics of peaking, 
cycling, and base load units.
    As described in more detail below, the EPA used IPM to assess the 
costs of increasing generation from existing NGCC capacity. IPM was 
able to meet average NGCC utilization rates of 75 percent on a net 
summer basis, while observing the market, technical, and regulatory 
constraints represented in the model. This modeling also demonstrates 
the ability of domestic natural gas supplies to increase their 
production levels, and deliver that supply through the pipeline 
network, to support the level of NGCC generation quantified in building 
block 2. Such a result is consistent with the EPA's determination that 
increasing the average utilization rate of existing NGCC units to 75 
percent would be technically feasible.
    f. Transmission planning and construction.
    Achieving the generation shift quantified in building block 2 would 
not impose significant additional burden on the transmission planning 
process and does not necessitate major construction projects. Two 
considerations are important for this conclusion:
    First, building block 2 applies only to increases in generation at 
existing NGCC facilities and does not contemplate any connection of new 
capacity to the bulk power grid. Second, regional grids are already 
supporting operation of the NGCC units for sustained periods of time at 
the capacity factors quantified in building block 2.\675\ Although some 
upgrades to the grid (including potential, but modest, expansions of 
transmission capacity) may be necessary to support the extension of the 
time that these capacity factors are sustained over the course of the 
annual time period on which building block 2 is based, such upgrades 
are part of the normal planning process around the increased use of 
existing facilities. In fact, the electric transmission system is 
currently undergoing substantial expansion.\676\ Consequently, EPA does 
not believe that achieving the generation shift potential in building 
block 2 would necessitate any significant additional requirements for 
transmission planning and construction beyond those already being 
addressed at routine intervals by the power sector. Furthermore, the 
phasing in of building block 2's potential in the determination of the 
BSER; the flexible nature of multi-year compliance with the ultimate 
emission reduction requirements of the rule; and the seven years 
between finalization of this rule and the first year of compliance all 
provide time for infrastructure improvements to occur should they prove 
necessary in some locations.
---------------------------------------------------------------------------

    \675\ See Greenhouse Gas Mitigation Measures TSD for a 
discussion of regional NGCC capacity factors.
    \676\ According to the Edison Electric Institute, member 
companies are planning over 170 projects through 2024, with costs 
totaling approximately $60.6 billion (this is only a portion of the 
total transmission investment anticipated). Approximately 75 percent 
of the reported projects (over 13,000 line miles) are high voltage 
(345 kV and higher). Construction of transmission lines of 345KV and 
above are generally major projects that are particularly effective 
at carrying power of large distances. http://www.eei.org/issuesandpolicy/transmission/Documents/Trans_Project_lowres_bookmarked.pdf.
---------------------------------------------------------------------------

    g. Regulatory flexibility.
    The final consideration supporting our view that natural gas and 
electricity system infrastructure would be capable of supporting 
increased NGCC unit utilization rates at a maximum of 75% on a net 
summer basis is the substantial unit-level compliance flexibility of 
the emission guidelines. The final rule does not require any particular 
NGCC unit to achieve any particular utilization rate in any specific 
hour or year. Thus, even if isolated natural gas or electricity system 
constraints were to limit NGCC unit utilization rates in certain 
locations in certain hours, this would not prevent an increase in NGCC 
generation overall across a state or broader region and across all 
hours on the order assumed in the generation shift potential quantified 
for building block 2.
4. Cost
    Having established the technical feasibility and quantification of 
the potential to replace incremental generation at higher-emitting EGUs 
with generation at NGCC facilities as a CO2 emissions 
reduction strategy, we next turn to the question of cost. The cost of 
the power sector CO2 emission reductions that can be 
achieved through shifting generation among existing fossil fuel-fired 
EGUs depends on the relative variable costs of electricity production 
at EGUs with different degrees of carbon intensity. These variable 
costs are driven by the EGUs' respective fuel costs and by the 
efficiencies with which they can convert fuel to electricity (i.e., 
their heat rates). Historically, natural gas has had a higher cost per 
unit of energy content (e.g., MMBtu) than coal in most locations, but 
for NGCC units this disadvantage in fuel cost per MMBtu relative to 
coal-fired EGUs is typically offset in significant part, and sometimes 
completely, by a technological heat rate advantage.
    To consider the cost implications of building block 2, the EPA 
expanded upon the proposal's extensive analysis of the magnitude and 
cost of CO2 emission reductions through generation shifting 
within defined areas (consistent with the application of building 
blocks for performance rate- and state goal-setting), without 
consideration of the availability of other emission reduction methods 
ultimately available to units for compliance.
    To evaluate how EGU owners and grid operators could respond to a 
state plan's possible requirements, signals, or incentives to shift 
generation from more carbon-intensive to less carbon-intensive EGUs, 
the EPA analyzed a series of scenarios in which the fleet of NGCC units 
within each of the regions considered for quantifying BSER (i.e., the 
three interconnections) was directed to achieve a specified average 
annual utilization rate across that region on a net basis while 
maintaining a fixed level of aggregate generation in that region

[[Page 64802]]

across all existing fossil fuel-fired sources. The EPA conducted such 
scenarios to address average utilization rates of 70 percent, 75 
percent and 80 percent on a net basis, allowing for shifting of fossil 
generation between existing units within the regions described above. 
This scenario identifies a generation pattern that would meet 
electricity demand at the lowest total cost, subject to all other 
specified operating and bulk power transfer constraints for the 
scenario, including the specified average NGCC unit utilization rate.
    The costs of the various scenarios were evaluated by comparing the 
total costs and emissions from each scenario to the costs and emissions 
from a base case scenario. For the scenario reflecting a 75 percent 
NGCC utilization rate on a net basis with regional fossil generation 
shifting, comparison to the base case indicates that the average cost 
of the CO2 reductions achieved over the 2022-2030 period was 
$24 per short ton of CO2. We view these estimated costs as 
reasonable and therefore as supporting the use of a 75 percent net 
utilization rate target for purposes of quantifying the emission 
reductions achievable at a reasonable cost through the application of 
building block 2 in the BSER.
    We also conclude from these analyses that potential impacts to fuel 
prices and electricity prices from achieving the extent of fossil 
generation shifting quantified for this building block are reasonably 
within the bounds of power sector experience. For example, in the 75 
percent NGCC unit utilization rate scenario where generation shifting 
is limited to regional boundaries, the delivered natural gas price was 
projected to increase by an average of 7 percent over the 2022-2030 
period, which is well within the range of historical natural gas price 
variability.\677\ Projected wholesale electricity price increases over 
the same period were less than 4 percent, which similarly is well 
within the range of historical electric price variability. These 
projected impacts on prices were captured in the emission reduction 
costs of these scenarios already described above, which are reasonable 
and support use of a 75 percent NGCC utilization rate target for 
purposes of quantifying the emission reductions achievable through 
application of the BSER.
---------------------------------------------------------------------------

    \677\ According to EIA data, year-to-year changes in natural gas 
prices at Henry Hub averaged 29.9 percent over the period from 2000 
to 2013. http://www.eia.gov/dnav/ng/hist/rngwhhdA.htm.
---------------------------------------------------------------------------

    However, we also note that the costs (and their incorporated price 
impacts) just described are higher than we would expect to actually 
occur in real-world compliance with the final rule's compliance 
requirements for the following reasons. First, this analysis does not 
capture the building block 2 phase-in, which assumes an average 
utilization rate over the interim period of less than 75 percent in all 
three interconnections. Second, the analysis overstates the extent to 
which building block 2 is ultimately reflected in the source category 
performance rates. While the performance rate computation procedure 
assumes a maximum NGCC utilization rate of 75 percent on a net summer 
basis, the Eastern Interconnection's realization of this level of NGCC 
utilization yields higher source category performance rates for steam 
than what would have been calculated for units in the Western 
Interconnection and Texas Interconnection if they realized that maximum 
NGCC utilization rate in conjunction with the other building blocks. In 
other words, there is substantial building block 2 potential in the 
Western Interconnection and Texas Interconnection that is not actually 
captured in the source category performance rates that are ultimately 
assigned to steam through this rate- and goal-setting approach (where 
the performance rates are ultimately determined by the BSER region with 
the highest rate outcome in the calculation). Therefore, the building 
block 2 analysis overstates the cost of this component of BSER to the 
extent that it assumes achievement of this generation shift potential 
that is not reflected in the source category performance rates 
ultimately determined. Third, as a practical matter, sources will be 
able to achieve additional emission reductions through other measures 
that may prove to be less costly than generation shifting and could 
substitute for the reductions and costs considered here. These building 
block 2 analyses were focused on evaluating the potential impacts of 
fossil generation shifting in isolation, and as a result, they do not 
consider states' and sources' flexibility to choose among alternative 
CO2 reduction strategies that could offer lower-cost 
reductions, instead of relying on fossil generation shifting to the 
extent analyzed here.
    Based on the analyses summarized above, the EPA concludes that an 
average annual utilization rate for each region's NGCC units of up to 
75 percent is a technically feasible, cost-effective, and adequately 
demonstrated building block for BSER.
    For further information on the analysis discussed in this section, 
see Chapter 3 of the GHG Mitigation Measures TSD for the CPP Final 
Rule.
5. Major Comments and Responses
    The EPA received numerous comments regarding building block 2. Many 
of these comments provided helpful information and insights and have 
resulted in improvements to the rule. This section summarizes some of 
these comments, and the remainder of the comments are responded to in 
the Response to Comment document, available in the docket.
    The EPA received comment regarding the potential for an increase in 
upstream methane emissions from increased utilization of natural gas. 
Our analysis found that the net upstream methane emissions from natural 
gas systems and coal mines and CO2 emissions from flaring of 
methane will likely decrease under the Clean Power Plan. Furthermore, 
the changes in upstream methane emissions are small relative to the 
changes in direct emissions from power plants. The technical details 
supporting this analysis can be found in the Regulatory Impact 
Analysis.
    Commenters also expressed concern that neither a utility nor any 
state agency controls dispatch in most states. The EPA believes these 
comments fail to adequately appreciate that the utilities do control 
the dispatch of units that they own and/or operate, either by being the 
actual dispatch agent in many cases where there is no RTO or ISO that 
schedules the dispatch, or by the choice of units and bids they offer 
into an organized electricity market operated by an RTO or ISO. These 
entities currently control the dispatch of their units while respecting 
all existing requirements from environmental rules. This final rule 
does not change these current circumstances and makes clear that it is 
the EGU that is responsible for meeting the requirements in the state 
plan; the state is responsible for the development of that plan, but 
the state does not need to control the dispatch.
    Other comments object to the use of a single capacity factor for 
all existing NGCCs to quantify building block 2 potential on the 
grounds that not all units may be able to achieve this utilization 
level, and that some units may be designed for cycling and so may need 
upgrades to sustain such utilization. The EPA disagrees with these 
comments. The 75 percent capacity factor establishes a regional 
potential for generation from existing NGCC capacity, and it does not 
establish any individual unit requirements.
    Some comments argue that generation limits in permits for some 
existing NGCC units will limit the amount by

[[Page 64803]]

which these units can increase their generation and thereby limit the 
feasibility of building block 2. The EPA disagrees with these comments. 
Although permit limits can constrain the ability of individual units to 
operate above certain levels, building block 2 was developed 
conservatively, with units operating on average at a level below the 
maximum levels at which some units have demonstrated the capability to 
operate. No individual unit is required to achieve the average 
generation levels used to quantify building block 2. Further, permit 
limits at individual units can be considered when state plans are 
developed. There are many flexibilities in the final rule, including 
the opportunity to establish standards of performance that incorporate 
emissions trading or develop plans that will respect any existing 
permit limits at individual units.
    The EPA also received comments asserting that increasing generation 
from new renewables would require increased use of natural gas capacity 
for back-up and ramping, and therefore it is not possible for NGCC 
units to run at BSER utilization rates and also be available to support 
the additional variable renewable generation resulting from building 
block 3. The EPA disagrees with this comment. The 75% net summer 
utilization rates defined by building block 2 is a conservative 
assessment and applied on an annual average basis. It is therefore 
possible for these existing units to both operate at higher annual 
utilization rates, and also to operate at higher rates during limited 
periods and still maintain a 75% net summer average annual utilization 
rate. While variable renewable generation does require additional load 
following and ramping resources and unit cycling, these requirements 
are generally a small part of the overall ramping costs of the system 
(see NREL, Relevant Studies for NERC's Analysis of EPA's Clean Power 
Plan 111(d) Compliance). Additionally, while existing NGCC units are an 
efficient source of ramping to support variable renewables, other units 
running in an intermediate mode can also provide load following and 
ramping.

E. Building Block 3--New Zero-Emitting Renewable Generating Capacity

    The third element of the foundation for the EPA's BSER 
determination for reducing CO2 emissions at affected fossil 
fuel-fired EGUs entails an analysis of the extent to which generation 
at the affected EGUs can be replaced by using an expanded amount of 
zero-emitting renewable electricity (RE) generating capacity to produce 
replacement generation.
    In this section we address first the history of and then trends in 
RE development, as well as the importance of expanding the use of RE. 
Next we discuss the ability of affected EGUs to access generation from 
new RE generating capacity, followed by a discussion of renewable 
energy certificate (REC) markets. We then describe the quantification 
of the amount of generation from new RE generating capacity achievable 
through building block 3, including key comments, changes made from the 
proposal, the method by which RE target generation levels are 
quantified, and the magnitude and timing of increases in RE generation 
associated with this building block. Next, we discuss the feasibility 
of implementing the identified incremental amounts of RE generation. 
Finally, we address the costs associated with those increases in RE 
generation.
1. History of RE Development
    RE generating technologies are a well-established part of the 
utility power sector. These technologies generate electricity from 
renewable resources, such as wind, sun and water. While RE has been 
used to generate electricity for over a century, the push to 
commercialize RE more broadly began in the 1970s.\678\ Following a 
series of energy crises, new federal organizations and initiatives were 
established to coordinate energy policy and promote energy self-
sufficiency and security, including solar energy legislation, the 
Public Utility Regulatory Policies Act of 1978 (PURPA) and the 1980 
Energy Security Act.\679\
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    \678\ Nearly all U.S. hydroelectric capacity was built before 
the mid-1970s. U.S. DOE. History of Hydropower. Accessed March 2015. 
Available at: http://energy.gov/eere/water/history-hydropower.
    \679\ U.S. DOE Office of Management, Timeline of Events: 1971-
1980. Accessed March 2015. Available at: http://energy.gov/management/office-management/operational-management/history/doe-history-timeline/timeline-events-1.
---------------------------------------------------------------------------

    PURPA was a key step in stimulating RE development. By requiring 
utilities to purchase generation from qualifying facilities (i.e., 
certain CHP and RE generators) at avoided costs, PURPA opened 
electricity markets to more RE generation and gave rise to non-utility 
generators that were willing to try new RE technologies.\680\ In 
addition, since 1992, federal tax policy has provided important 
financial support via tax credits for the production of RE and 
investments in RE.
---------------------------------------------------------------------------

    \680\ ``Restructuring or Deregulation?'' Smithsonian Museum of 
American History. Accessed March 2015. Available at: http://americanhistory.si.edu/powering/dereg/dereg1.htm.
---------------------------------------------------------------------------

    States have also taken a significant lead in requiring the 
development of RE resources. In particular, a number of states have 
adopted renewable portfolio standards (RPS), which are regulatory 
mandates to increase production of RE. As of 2013, 29 states and the 
District of Columbia had enforceable RPS or similar laws.\681\ These 
RPS requirements continue to drive robust near-term growth of non-
hydropower RE.
---------------------------------------------------------------------------

    \681\ Energy Information Administration, Annual Energy Outlook 
2014 with Projections to 2040, at LR-5 (2014).
---------------------------------------------------------------------------

2. Trends in RE Development
    Today, RE is tightly integrated with the utility power sector in 
multiple ways: States have set RE targets for electrical load serving 
entities; utilities themselves are diversifying their portfolios by 
contracting with RE generators; and new RE generators are being 
developed to provide more electrical power grid support services beyond 
just energy (e.g., modern electronics allow wind turbines to provide 
voltage and reactive power control at all times).682 683
---------------------------------------------------------------------------

    \682\ IPCC, Renewable Energy Sources and Climate Change 
Mitigation, 2012. Accessed March 2015. Available at: http://www.ipcc.ch/pdf/special-reports/srren/SRREN_Full_Report.pdf.
    \683\ American Wind Energy Association. AWEA Comments on EPA's 
Proposed Carbon Pollution Emission Guidelines for Existing 
Stationary Sources and Supplemental Proposed Rule. p. 107.
---------------------------------------------------------------------------

    Use of RE continues to grow rapidly in the U.S. In 2013, 
electricity generated from RE technologies, including conventional 
hydropower, represented 12 percent of total U.S. electricity, up from 8 
percent in 2005.\684\ In 2013, U.S. non-hydro RE capacity for the total 
electric power industry exceeded 80,000 megawatts, reflecting a 
fivefold increase in just 15 years.\685\ In particular, there has been 
substantial growth in the wind and solar photovoltaic (PV) markets in 
the past decade. Since 2009, U.S. wind generation has tripled and solar 
generation has grown twentyfold.\686\
---------------------------------------------------------------------------

    \684\ Energy Information Administration, Monthly Energy Review, 
May 2015, Table 7.2b. Available at: http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf.
    \685\ Non-hydro RE capacity for the total electric power 
industry was more than 16,000 megawatts in 1998. Energy Information 
Administration, 1990-2013 Existing Nameplate and Net Summer Capacity 
by Energy Source Producer Type and State (EIA-860). Available at: 
http://www.eia.gov/electricity/data/state/.
    \686\ Energy Information Administration, Monthly Energy Review, 
May 2015, Table 7.2b. Available at: http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf.
---------------------------------------------------------------------------

    The global market for RE is projected to grow to $460 billion per 
year by

[[Page 64804]]

2030.\687\ RE growth is further spurred by the significant amount of 
existing natural resources that can support RE production in the 
U.S.\688\ In the Energy Information Administration's Annual Energy 
Outlook 2015, RE generation grows substantially from 2013 to 2040 in 
the reference case and all alternative cases.\689\ In the reference 
case, RE generation increases by more than 70 percent from 2013 to 2040 
and accounts for over one-third of new generation capacity.\690\
---------------------------------------------------------------------------

    \687\ ``Global Renewable Energy Market Outlook.'' Bloomberg New 
Energy Finance, November 16, 2011. Available at http://bnef.com/WhitePapers/download/53.
    \688\ Lopez et al., NREL, ``U.S. Renewable Energy Technical 
Potentials: A GIS-Based Analysis,'' (July 2012). Available at http://www.nrel.gov/docs/fy12osti/51946.pdf.
    \689\ Energy Information Administration, Annual Energy Outlook 
2015 with Projections to 2040 (2015), p. 25. Available at http://www.eia.gov/forecasts/aeo/pdf/0382(2015).pdf.
    \690\ Energy Information Administration, Annual Energy Outlook 
2015 with Projections to 2040 (2015), p. ES-6-7. Available at http://www.eia.gov/forecasts/aeo/pdf/0382(2015).pdf.
---------------------------------------------------------------------------

    The recent and projected growth of RE is in part a reflection of 
its increasing economic competitiveness. Numerous studies have tracked 
capital cost reductions and performance improvements for RE, 
particularly for solar and wind. For instance, Lazard's analysis of 
wind and utility-scale solar PV levelized costs of energy (LCOE), on an 
unsubsidized basis, over the last five years found the average 
percentage decrease of high and low of LCOE ranges were 58 percent and 
78 percent, respectively.\691\ Analyses of wind's competitiveness found 
falling wind turbine LCOE while the wind industry developed projects at 
lower wind speed sites using new turbine designs (e.g., increased 
turbine hub heights and rotor diameters). Performance improvements have 
come from novel deployments of new turbines designed for lower quality 
wind sites that are deployed at higher quality wind sites, which have 
resulted in capacity factor increases for these 
locations.692 693 For utility-scale solar, cost and 
performance have also improved significantly. Analysis has shown that 
the installed price of solar photovoltaics (PV) systems, prior to any 
incentives, has declined substantially since 1998. Capacity-weighted 
average prices of solar PV in utility-scale deployments were 40 percent 
lower in 2013 than five years earlier.694 695 Initially, 
price declines were partially driven by oversupply and manufacturers' 
thin margins, but, in 2014, prices have remained low due to reductions 
in manufacturing costs.\696\ The capacity factors of new utility-scale 
installations have increased as systems are optimized to maximize 
energy production. For example, a growing number of utility-scale PV 
systems are increasing the direct current capacity of the solar array 
relative to the alternating current rating of the array's inverter to 
increase energy production and improve project economics.\697\ The cost 
and performance improvements for wind and solar are driven by increased 
scale of production, improved technologies, and advancements in system 
deployments.
---------------------------------------------------------------------------

    \691\ Lazard, Levelized Cost of Energy Analysis-Version 8.0, 
September 2014, p. 9, Available at: http://www.lazard.com/media/1777/levelized_cost_of_energy_-_version_80.pdf.
    \692\ ``2013 Wind Technologies Market Report,'' LBNL, August 
2014. Available at http://emp.lbl.gov/sites/all/files/2013_Wind_Technologies_Market_Report_Final3.pdf.
    \693\ ``2013 Cost of Wind Energy Review,'' NREL, Feb 2015. 
Available at: http://www.nrel.gov/docs/fy15osti/63267.pdf.
    \694\ ``Tracking the Sun VII'' LBNL, Sept 2014. Available at: 
http://emp.lbl.gov/publications/tracking-sun-vii-historical-summary-installed-price-photovoltaics-united-states-1998-20.
    \695\ ``Photovoltaic System Pricing Trends,'' NREL, 22 Sept 
2014. Available at: http://www.nrel.gov/docs/fy14osti/62558.pdf.
    \696\ ``Revolution Now--The Future Arrives for Four Clean Energy 
Technologies--2014 Update,'' DOE, Oct 2014. Available at: http://energy.gov/sites/prod/files/2014/10/f18/revolution_now_updated_charts_and_text_october_2014_1.pdf.
    \697\ ``Utility-Scale Solar 2013,'' LBNL, Sept 2014. Available 
at: http://emp.lbl.gov/publications/utility-scale-solar-2013-empirical-analysis-project-cost-performance-and-pricing-trends.
---------------------------------------------------------------------------

3. Importance of Increasing Use of RE
    Currently, the utility power sector accounts for 40 percent of 
total annual energy consumption in the U.S.\698\ Introducing more zero-
emitting RE generation over the long term could significantly reduce 
CO2 emissions, as production of RE predominantly replaces 
fossil fuel-fired generation and thereby avoids the emissions from that 
replaced generation.
---------------------------------------------------------------------------

    \698\ U.S. Energy Information Administration Annual Energy 
Review, 2011. Accessed March 2015. Available at: http://www.eia.gov/totalenergy/data/monthly/pdf/flow/primary_energy.pdf.
---------------------------------------------------------------------------

    A number of studies and recent policy developments have 
acknowledged RE as an important means of achieving CO2 
reductions. California cited the reduction of CO2 emissions 
from electrical generations as one of the reasons for increasing its RE 
target from 20 percent to 33 percent by 2020 (and potentially 50 
percent by 2030).\699\ A recent IPCC report also concluded that RE has 
large potential to mitigate CO2 emissions.\700\
---------------------------------------------------------------------------

    \699\ California S.B. 2 (1X), 2011. Accessed March 2015. 
Available at: http://www.leginfo.ca.gov/pub/11-12/bill/sen/sb_0001-0050/sbx1_2_bill_20110412_chaptered.pdf.
    \700\ IPCC, Renewable Energy Sources and Climate Change 
Mitigation, 2012. Accessed March 2015. Available at: http://www.ipcc.ch/pdf/special-reports/srren/SRREN_Full_Report.pdf.
---------------------------------------------------------------------------

    Increased use of RE provides numerous benefits in addition to lower 
CO2 emissions. RE typically consumes less water than fossil 
fuel-fired EGUs. Wind power and solar PV systems do not require the use 
of any water to generate electricity; water is only needed for cleaning 
to ensure efficient operation. In contrast, utility boilers, in 
particular, require large quantities of water for steam generation and 
cooling.\701\
---------------------------------------------------------------------------

    \701\ EPA, Water Resource Use. Accessed on March 2015. Available 
at: http://www.epa.gov/cleanenergy/energy-and-you/affect/water-resource.html.
---------------------------------------------------------------------------

    Increasing RE use will also continue to lower other air pollutants 
(e.g., fine particles, ground-level ozone, etc.). In addition, the RIA 
notes that increasing RE will diversify energy supply, hedge against 
fossil fuel price increases and create economic development and jobs in 
manufacturing, installation, and other sectors of the economy.
4. Access to RE by Owners of Affected EGUs
    The ability of affected EGUs to co-locate or obtain incremental RE 
to reduce CO2 emissions is well-demonstrated, whether it is 
through direct ownership, bilateral contracts, or procurement of the 
environmental attributes associated with RE generation.\702\ 
Consequently, the EPA believes that an increase in RE is a proven way 
to reduce CO2 emissions at affected EGUs of all types at a 
reasonable cost.
---------------------------------------------------------------------------

    \702\ Refer to the GHG Mitigation Measures TSD for additional 
information on RE ownership and co-location.
---------------------------------------------------------------------------

    Owners and operators of affected EGUs across the U.S. already have 
substantial opportunities to procure RE regardless of their 
organizational structure and/or business model. In many parts of the 
country, EGUs are owned and operated by vertically integrated 
utilities. These utilities can be investor-owned utilities that operate 
under traditional electricity regulation, municipal utilities (munis), 
or electric cooperatives (co-ops). These utilities have significant 
control over the types of generating capacity they develop or acquire, 
and over the electricity mix used to meet demand within their service 
territories.
    Even when EGU owners participating in organized markets do not 
directly determine dispatch among energy sources, such EGU owners make

[[Page 64805]]

decisions about what types of capacity they choose to develop and thus 
what generation mix they can ultimately supply into that market's 
dispatch choices. Because zero-emitting RE technologies have relatively 
low variable costs, an EGU owner's decision to install (or to finance 
the installation of) RE capacity will yield lower-cost electricity 
generation that, when available, a system dispatcher will prefer over 
higher-variable-cost generation from fossil fuel-fired capacity. 
Therefore, all owners of affected EGUs have a direct path for replacing 
higher-emitting generation with RE regardless of their organizational 
type and regardless of whether they operate in a cost-of-service 
framework or in a competitive, organized market.
    Many affected EGUs have already directly invested in RE. Of the 404 
entities that owned part of at least one affected EGU under this rule, 
178 also owned RE (biomass, geothermal, solar, water or wind). These 
178 owners owned 82 percent of affected EGU capacity. As a whole, these 
entities' share of RE capacity was equal to 25 percent of the total of 
their affected EGU capacity.\703\
---------------------------------------------------------------------------

    \703\ SNL Energy. Data used with permission. Accessed on June 9, 
2015.
---------------------------------------------------------------------------

    Some of the largest owners of affected EGUs also owned RE (see 
Table 8). For example, NRG Energy, Inc. owns more than 3,000 megawatts 
of RE capacity, over 20 percent of which (nearly 800 megawatts) is 
solar, and almost 80 percent of which (over 2,500 megawatts) is wind. 
Duke Energy Corporation owns 175 megawatts of solar and over 1,500 
megawatts of wind. NextEra Energy, Inc.'s share of RE capacity 
approaches 40 percent of their total affected EGU capacity.\704\ Table 
8 lists a sampling of affected EGUs that have large amounts of fossil 
fuel-fired capacity and RE capacity:
---------------------------------------------------------------------------

    \704\ Ibid.

   Table 8--Sample of Owners of Affected EGUs and RE Capacity 705 706
------------------------------------------------------------------------
                                           Affected EGU      Renewable
             Ultimate parent               capacity (MW)   capacity (MW)
------------------------------------------------------------------------
NRG Energy, Inc.........................          48,787           3,149
Duke Energy Corporation.................          39,028           5,526
Southern Company........................          37,168           3,245
American Electric Power Company, Inc....          34,940           1,142
NextEra Energy, Inc.....................          29,471          11,626
Calpine Corporation.....................          23,878           1,509
Tennessee Valley Authority..............          21,717           5,427
Berkshire Hathaway Inc..................          18,899           6,650
FirstEnergy Corp........................          16,175           1,371
Exelon Corporation......................          10,283           3,361
Nebraska Public Power District..........           2,003              90
Basin Electric Power Cooperative........           1,526             275
American Municipal Power, Inc...........           1,112              53
Sacramento Municipal Utility District...             925             834
Golden Spread Electric Cooperative, Inc.             521              78
------------------------------------------------------------------------

    Large vertically integrated utilities generally have multiple 
options for investing in RE, including building their own RE capacity 
or procuring RE under a long-term power purchase agreement. Municipal 
utilities and rural cooperatives that own generating asset portfolios, 
particularly generation and transmission cooperatives and larger 
municipal utilities, have also used RE to reduce carbon emissions. 
Large generation and transmission cooperatives also purchase 
significant quantities of RE for their members. Federal power 
authorities own or contract for significant amounts of 
RE.707 708
---------------------------------------------------------------------------

    \705\ SNL Energy. Data used with permission. Accessed on June 9, 
2015.
    \706\ eGRID, EPA. 2012 Unit-Level Data Using the eGRID 
Methodology.
    \707\ American Wind Energy Association. AWEA Comments on EPA's 
Proposed Carbon Pollution Emission Guidelines for Existing 
Stationary Sources and Supplemental Proposed Rule. pp. 88-91.
    \708\ Solar Energy Industries Association. Comments to the EPA 
and States on the Proposed Clean Power Plan Regulating Existing 
Power Plants Under Section 111(d) of the Clean Air Act. pp. 98-147.
---------------------------------------------------------------------------

    The list of ten electric utilities with the largest amounts of wind 
power capacity on the system (owned or under contract) includes a 
variety of affected EGU organizational structures, including vertically 
integrated investor-owned utilities, municipal utilities, and federal 
power authorities. Xcel Energy and Berkshire Hathaway Energy rank first 
and second with 5,736 megawatts and 4,992 megawatts of wind capacity, 
respectively. Tennessee Valley Authority, a federal power authority, 
had 1,572 megawatts and CPS Energy, a public utility, had 1,059 
megawatts of wind power capacity.\709\ Basin Electric Power Cooperative 
had 716 megawatts and was the top ranked cooperative utility, but is 
not on the top ten utilities with wind power capacity list.
---------------------------------------------------------------------------

    \709\ American Wind Energy Association. U.S. Wind Industry 
Annual Market Report (2014 data). Accessed July 2015. Available at 
http://www.awea.org/AnnualMarketReport.aspx?ItemNumber=7422&RDtoken=64560&userID=. The 
ten largest electric utilities with wind power capacity on the 
system (owner or under contract) includes: Xcel Energy; Berkshire 
Hathaway Energy; Southern California Edison; American Electric 
Power; Pacific Gas & Electric; Tennessee Valley Authority; San Diego 
Gas & Electric; CPS Energy; Los Angeles Department of Water & Power; 
and Alliant Energy.
---------------------------------------------------------------------------

    Many affected EGUs are already planning on deploying significant 
amounts of RE according to their integrated resource plans (IRPs). 
Electric utilities use IRPs to plan operations and investments over 
long time horizons. These plans typically cover 10 to 20 years and are 
mandated by public utility commissions (PUCs). A recent study of IRPs, 
included in the docket for this rulemaking, shows this trend.\710\ For 
instance, Dominion plans for over 800 megawatts of wind and solar in 
their 2015 to 2029 planning period.\711\ Duke Energy Carolinas' IRP has 
no plans for new coal, but describes plans for roughly 1,250 megawatts 
of additional RE by 2021, and approximately 2,150 megawatts by 2029. A 
significant

[[Page 64806]]

portion (1,670 megawatts) of the planned RE is solar.\712\ Ameren is 
planning to retire one-third of the coal generating capacity, as well 
as installing an additional 400 megawatts of wind, 445 megawatts of 
solar, and 28 megawatts of hydroelectric generating capacity.\713\
---------------------------------------------------------------------------

    \710\ See memo entitled ``Review of Electric Utility Integrated 
Resource Plans'' (May 7, 2015).
    \711\ Dominion North Carolina Power's and Dominion Virginia 
Power's Report of Its Integrated Resource Plan, August 2014. 
Available at: https://www.dom.com/library/domcom/pdfs/corporate/integrated-resource-planning/nc-irp-2014.pdf.
    \712\ Duke Energy Carolinas' 2014 Integrated Resource Plan, 
September 2014. Available at: http://starw1.ncuc.net/NCUC/ViewFile.aspx?Id=c3c5cbb5-51f2-423a-9dfc-a43ec559d307.
    \713\ Integrated Resource Plan Update, October 2014. Available 
at: https://www.ameren.com/missouri/environment/renewables/ameren-missouri-irp.
---------------------------------------------------------------------------

    Independent power producers (IPPs) also can and do own both RE and 
fossil generation. For example, NRG is a diversified IPP that operates 
substantial coal, natural gas, wind, solar, and nuclear capacity. NRG 
demonstrates the ability of IPPs to reduce utilization of fossil fuel-
fired EGUs and replace that generation with RE. NRG announced a goal to 
cut CO2 emissions from its fleet by 50 percent by 2030 (from 
a 2014 baseline).\714\ NRG has already reduced CO2 emissions 
from its fleet by 40 percent since 2005. This achievement demonstrates 
that when an IPP commits to shifting its generation portfolio, it can 
do so at reasonable cost and without reliability impacts. The NRG 
example shows that reduced utilization of fossil fuel-fired EGUs that 
is replaced by RE also owned by the EGU owner is adequately 
demonstrated.
---------------------------------------------------------------------------

    \714\ NRG, ``NRG Energy Sets Long-Term Sustainability Goals at 
Groundbreaking of `Ultra-Green' New Headquarters'' (Nov. 20, 2014). 
Available at http://investors.nrg.com/phoenix.zhtml?c=121544&p=irolnewsArticle&ID=1991552.
---------------------------------------------------------------------------

    EGU owners can also replace fossil fuel-fired generation with RE 
through bilateral contracts and REC purchases, as described below. Both 
the bilateral market for RE contracts and REC markets are well-
developed. There are no legal or technical obstacles to a fossil fuel-
fired EGU owner acting as the counterparty of a bilateral contract for 
purchase of energy from a RE facility. Any type of EGU owner (utility 
or otherwise) can purchase and retire RECs. The fact that RECs are 
purchased by a diverse set of market participants--including 
residential consumers, commercial businesses, and industrial 
facilities--demonstrates that such a purchase for all EGU owners is 
adequately demonstrated.
5. REC Markets
    Affected EGU owners do not need to directly invest in, or own, 
renewable generating capacity in order to replace fossil fuel-fired 
generation with RE as an emission reduction measure. RECs are used to 
demonstrate compliance with state RE targets, such as state RPS, and 
also to substantiate claims stemming from RE use. RECs are tradable 
instruments that are associated with the generation of one megawatt-
hour of RE and represent certain information or characteristics of the 
generation, called attributes.\715\ RECs may be traded and transferred 
regardless of the actual energy flow.
---------------------------------------------------------------------------

    \715\ EPA Green Power Partnership, Renewable Energy Certificates 
July 2008). Available at http://www.epa.gov/greenpower/documents/gpp_basics-recs.pdf.
---------------------------------------------------------------------------

    The legal basis for RECs is established by state statutes and 
administrative rules. Nearly all states with a mandatory RPS have 
established RECs as a means of compliance. The Federal Energy 
Regulatory Commission (FERC) has observed that states created RECs to 
facilitate programs designed to promote increased use of RE, and that 
``attributes associated with the [RE] facilities are separate from, and 
may be sold separately from, the capacity and energy.'' \716\
---------------------------------------------------------------------------

    \716\ FERC Docket No. EL03-133-000, Petition for Declaratory 
Order and Request for Expedited Consideration, American Ref-Fuel 
Company, Covanta Energy Group, Montenay Power Corporation, and 
Wheelabrator Technologies, Inc. June 16, 2003, Order Granting 
Petition for Declaratory Ruling, October 1, 2003. American Ref-Fuel 
Co. et al., 105 FERC ] 61,004 (2003); and Order Denying Rehearing. 
April 15, 2004. 107 FERC ] 61,016 (2004). Available online at: 
http://www.ferc.gov/whats-new/comm-meet/041404/E-28.pdf (accessed 
11/7/2014).
---------------------------------------------------------------------------

    In complying with states' RPS requirements, utilities have 
contracted for RECs from in-state and out-of-state resources in 
accordance with RPS requirements. Utilities may have sourced RECs from 
out-of-state to reduce the cost of compliance, to source RECs from 
specific generation types, or for other reasons.\717\
---------------------------------------------------------------------------

    \717\ Heeter, J. Quantifying the Level of Cross-State Renewable 
Energy Transactions. NREL 2015. Available at http://www.nrel.gov/docs/fy15osti/63458.pdf.
---------------------------------------------------------------------------

    The development of REC markets to facilitate RPS compliance 
provides evidence that markets can develop to facilitate compliance 
with rate-based state plans. These markets will afford affected EGU 
owners an alternative to directly invest in, or own, renewable 
generating capacity in order to replace fossil fuel-fired generation 
with RE as an emission reduction measure.
6. Quantification of RE Generation Potential for BSER and Major 
Comments
    The methodology for quantifying RE generation levels under building 
block 3 is a modified version of the alternative RE approach from 
proposal, with adjustments that reflect the data and information the 
EPA collected through stakeholder comments and the EPA's additional 
analysis and information collection. In evaluating the proposed and 
alternative RE approaches commenters observed that RPS, as the basis 
for quantifying RE generation levels under the proposed approach, are 
policy instruments that states may choose to implement for a variety of 
reasons not related to CO2 emission reductions. 
Additionally, differences across RPS policies in eligible resources, 
crediting mechanisms, deliverability requirements, alternative 
compliance payments, and other policy elements made the regional 
averaging of state-level RPS requirements challenging. Finally, 
commenters provided data demonstrating that RE resource potential can 
vary significantly within the regions identified under the proposed 
approach, producing state-level RE generation levels that may not be 
aligned with the opportunity to deploy incremental RE resources at 
reasonable cost. In contrast, commenters argued that a methodology 
similar to the alternative RE approach, which is based on economic 
potential, represents a more technically sound basis for quantifying 
building block 3 target generation levels that accounts for regional 
differences in RE resources and power market conditions, such as 
projected fuel prices, load growth and wholesale power prices. The EPA 
agrees with these comments.
    Within the framework of the alternative RE approach, the EPA 
received significant comments on a number of issues, including the use 
of historical deployment rates, the interstate nature of RE and the 
power system, merits of total versus incremental RE generation as the 
metric by which building block 3 generation levels are quantified, 
types of RE technologies that contribute to those generation levels, 
cost and performance estimates associated with those RE technologies, 
magnitude of the reduced cost applied to new RE capacity as an 
incentive to deploy, and application of a nationally uniform benchmark 
development rate to modeled projections of economic deployment. Based 
on commenter data and information, as well as further analysis and 
information collection, the primary adjustments the EPA made to the 
alternative RE approach are:

     The basis for quantifying building block 3 generation 
has been modified to incorporate historical deployment patterns for 
RE technologies as well as the economic potential identified through 
modeling projections. The introduction of historical capacity 
additions to the final methodology further grounds building block 3 
generation

[[Page 64807]]

in demonstrated levels of RE deployment that have been successfully 
incorporated into the power system. This adjustment also serves to 
harmonize the approach across all three building blocks in which 
historical data is the primary basis for identifying emission 
reduction opportunities under the BSER.
     The RE technologies used to quantify building block 3 
generation levels are onshore wind, utility-scale solar PV, 
concentrating solar power (CSP), geothermal and hydropower. Each of 
these technologies is a utility-scale, zero-emitting resource that 
was included under the alternative RE approach at proposal. 
Additionally, the EPA received significant comments on the 
opportunities and challenges associated with distributed RE 
technologies. Distributed technologies, as a demand-side resource, 
present unique data and technical challenges (such as the role of 
evaluation, measurement and verification (EM&V) procedures in 
verifying their production, the diverse economic incentives of 
different parties involved in their deployment, and the variety of 
grid integration policies and conditions across potential deployment 
sites) that complicate identifying a technically feasible and cost-
effective level of generation. Consequently, the EPA is, at this 
time, choosing not to include distributed technologies as part of 
the BSER (although, as explained in section VIII.K of this preamble, 
distributed RE technologies that meets eligibility criteria may be 
used for compliance). Finally, any RE technology that has not been 
deployed in the U.S., including demonstrated RE technologies for 
which there is clear evidence of technical feasibility and cost-
effectiveness (e.g., offshore wind), contributes no generation to 
building block 3 under this historically-based methodology. These RE 
technologies are consequently reserved for compliance, which offers 
affected EGUs additional flexibility and will reduce their need to 
rely on other emission reduction measures or building blocks.
     Building block 3 generation levels are expressed in 
terms of incremental, rather than total, RE generation. As a metric, 
incremental generation is better aligned with quantifying an amount 
of expanded RE to replace generation at affected EGUs.\718\ 
Specifically, the generation levels under building block 3 include 
generation from capacity that commenced operation subsequent to 2012 
(the data year on which the BSER is evaluated). Commenters remarked 
that it is unnecessary to include generation from RE capacity that 
was already in operation by 2012 in building block 3 because the 
impact of that generation on fossil fuel-fired EGUs is already 
reflected in the observed 2012 emissions and generation data of 
those EGUs.
---------------------------------------------------------------------------

    \718\ Consistent with the October 2014 NODA, the final goal-
setting methodology assumes replacement of affected EGU generation 
by incremental building block 3 generation in calculating source-
specific CO2 emission performance rates. For additional 
information on the goal-setting methodology, refer to Section VI.
---------------------------------------------------------------------------

     Due to the interstate nature of RE and the power 
system, and consistent with the rationale provided in the October 
2014 Notice of Data Availability (NODA), building block 3 generation 
levels are quantified for each of the three BSER regions--the 
Eastern Interconnection, Western Interconnection, and Texas 
Interconnection--rather than at the state-level. This regionalized 
approach, as described in the NODA, takes into account the 
opportunity to develop regional RE resources and thus better aligns 
building block 3 generation levels with the rule's approach to 
allowing the use of qualifying out-of-state renewable generation for 
compliance.
     Commenters observed that the cost and performance 
estimates the EPA relied on at proposal from the Energy Information 
Administration's Annual Energy Outlook 2013 do not reflect the 
decline in cost and increase in performance that have been 
demonstrated by current projects, particularly in regards to wind 
and solar technologies. Commenters provided data from a variety of 
sources to support these claims, including Lawrence Berkeley 
National Laboratory (LBNL), the Department of Energy (DOE) and 
Lazard. Each of these sources supported the contention that RE 
technologies, particularly wind and solar, have realized gains in 
cost and efficiency at a scale that has altered the competitive 
dynamic between RE and conventional resources. As a result, it has 
become increasingly necessary for any long-term outlook of the 
utility power sector to continually assess the development of RE 
technology cost and performance trends. In performing this task, the 
EPA revised its data for onshore wind and solar technologies to 
reflect the mid-case estimates from the National Renewable Energy 
Laboratory's (NREL's) 2015 Annual Technology Baseline. The EPA 
selected the NREL 2015 Annual Technology Baseline (ATB) estimates 
based on the quality of its data as well as NREL's demonstrated 
success in both reflecting and anticipating RE cost and performance 
trends. In addition to wind and solar technologies, the EPA 
evaluated hydropower deployment potential based on the latest cost 
and performance data from NREL's Renewable Energy Economic Potential 
study.\719\
---------------------------------------------------------------------------

    \719\ For additional information on the updated RE cost and 
performance assumptions used to quantify building block 3 
generation, refer to the GHG Mitigation Measures TSD.
---------------------------------------------------------------------------

     The benchmark development rate that constrained cost-
effective RE deployment under the alternative RE approach in the 
proposal has been removed from the final methodology.\720\ 
Commenters detailed several issues with applying the benchmark 
development rate, including that it does not factor in the total 
size of the RE resource in a given state and is inconsistent with a 
regional approach to quantifying target generation levels. EPA 
agrees with these comments and the benchmark development rate has 
been eliminated.
---------------------------------------------------------------------------

    \720\ The technical potential limiter was a nationally uniform, 
technology-specific limit on cost-effective RE deployment based on 
the amount of 2012 generation in a state as a share of that state's 
total technical potential.

    In addition to the comments described above, the EPA received 
significant comments on a wide variety of topics related to building 
block 3. Many of these comments provided helpful information and 
insights, and have resulted in improvements to the final rule. These 
comments, as well as the EPA responses, are available in the Response 
to Comment document.
    The final methodology for quantifying incremental RE target 
generation levels contains seven steps. Each step is described 
below.\721\
---------------------------------------------------------------------------

    \721\ For supporting data, documentation, and examples for each 
step of the quantification methodology, refer to the GHG Mitigation 
Measures TSD.
---------------------------------------------------------------------------

    First, the EPA collected data for each RE technology (onshore wind, 
utility-scale solar PV, CSP, geothermal and hydropower) to determine 
the annual change in capacity over the most recent five-year period. 
From these data, the EPA calculated the five-year annual average change 
in capacity and the five-year maximum annual change in capacity for 
each technology.
    Second, the EPA determined an appropriate capacity factor to apply 
to each RE technology that would be representative of expected future 
performance from 2022 through 2030. For this purpose the EPA relied on 
NREL's ATB.
    Third, the EPA calculated two generation levels for each RE 
technology. The first generation level is the product of each 
technology's five-year average capacity change and the assumed future 
capacity factor. The second generation level is the product of each 
technology's five-year maximum annual capacity deployment and the 
assumed future capacity factor. Table 9 below shows the data and 
assumptions used for these calculations.

[[Page 64808]]



                      Table 9--Historical Capacity Changes and Associated Generation Levels
----------------------------------------------------------------------------------------------------------------
                                                                    Generation                      Generation
                                  Assumed future     Five-Year      associated                      associated
                                     capacity         average     with five year- Maximum annual   with maximum
                                      factor         capacity         average        capacity         annual
                                     (percent)      change (MW)      capacity       change (MW)      capacity
                                                                   change (MWh)                    change (MWh)
----------------------------------------------------------------------------------------------------------------
Utility-Scale Solar PV \722\....            20.7           1,927       3,494,268           3,934       7,133,601
CSP.............................            34.3             251         754,175             767       2,304,590
Onshore Wind....................            41.8           6,200      22,702,416          13,131      48,081,520
Geothermal......................            85.0             142       1,057,332             407       3,030,522
Hydropower......................            63.8             141         788,032             294       1,643,131
                                 -------------------------------------------------------------------------------
    Total Generation............             N/A             N/A      28,796,222             N/A      62,193,363
----------------------------------------------------------------------------------------------------------------

    Fourth, the EPA quantified the RE generation from capacity 
commencing operation after 2012 that can be expected in 2021 (the year 
before this rule's first compliance period) without the imposition of 
this rule. Because building block 3 is focused on the ability of fossil 
fuel-fired EGUs to reduce their emissions by deploying incremental RE, 
it is reasonable to take into account the considerable amount of RE 
deployment that is already taking place and is projected to continue 
doing so before considering the additional deployment that would be 
motivated by this rule's mandate to reduce emissions from affected 
EGUs. The EPA considered its base case power sector modeling 
projections using IPM to quantify this component of future-year RE 
generation, which the EPA assumes to be 213,084,125 megawatt-hours in 
2021.
---------------------------------------------------------------------------

    \722\ Capacity values for utility-scale solar PV are expressed 
in terms of MWDC. The assumed future capacity factor for 
this utility-scale solar PV includes a DC-to-AC conversion, enabling 
the generation totals to be combined across all RE technologies.
---------------------------------------------------------------------------

    Fifth, the EPA applied the generation associated with the five-year 
average capacity change to the first two years of the interim period. 
Combining the projected 2021 RE generation from capacity starting 
operation after 2012 with the generation increment associated with the 
five-year average change in capacity produces 241,880,347 megawatt-
hours in 2022 and 270,676,570 megawatt-hours in 2023. The EPA believes 
it is appropriate to apply the generation associated with the five-year 
average capacity change for the first two years of the interim period 
to ensure adequate opportunity to plan for and implement any necessary 
RE integration strategies and investments in advance of the higher RE 
deployment levels assumed for later years.
    Sixth, for all years subsequent to 2023 the EPA applied the 
generation associated with the maximum annual capacity change from the 
historical data analysis. In 2024, this produces a building block 3 
generation level of 332,869,933 megawatt-hours (aggregated across all 
three BSER regions); by 2030, that generation level is 706,030,112 
megawatt-hours.
    Seventh, to further evaluate the technical feasibility and cost-
effectiveness of the building block 3 generation levels (aggregated 
across all three BSER regions), as well as to produce interconnection-
specific levels of building block 3 generation from the national totals 
described in steps 5 and 6, the EPA conducted analysis using IPM of a 
scenario directing the power sector to achieve those RE generation 
levels. IPM modeling projections assess opportunities for RE deployment 
in an integrated framework across power, fuel, and emission markets. 
The modeling framework incorporates a host of constraints on the 
deployment of RE resources, including resource constraints such as 
resource quality, land use exclusions, terrain variability, distance to 
existing transmission, and population density; system constraints such 
as interregional transmission limits, partial reserve margin credit for 
intermittent RE installations, minimum turndown constraints for fossil 
fuel-fired EGUs, and short-term capital cost adders to reflect the 
potential added cost due to competition for scarce labor and materials; 
and technology constraints such as construction lead times and hourly 
generation profiles for non-dispatchable resources by season.\723\ 
Additionally, the EPA assumes in this analysis that deployment of 
variable, non-dispatchable RE resources is limited to 20 percent of net 
energy for load by technology type and 30 percent of net energy for 
load in total at each of IPM's 64 U.S. sub-regions.\724\ The 30 percent 
constraint applied to variable, non-dispatchable RE resources reflects 
levels commonly modeled in grid integration studies at the level of the 
interconnection. These studies have demonstrated that impacts to the 
grid in reaching levels as high as 30 percent of net energy for load 
are relatively minor.\725\ For example, the Western Wind and Solar 
Study Phase 2 found cycling costs ranged from $0.14 to $0.67 per 
megawatt-hour of added wind and solar generation. These integration 
cost levels are not impactful in determining cost-effectiveness. As 
such, applying the 30 percent constraints at the IPM sub-region level 
is very conservative and provides a high degree of assurance that the 
RE capacity deployment pattern projected by the model would not incur 
significant grid integration costs.\726\
---------------------------------------------------------------------------

    \723\ Refer to GHG Mitigation Measures TSD for more detail on 
modeling methodology.
    \724\ Regions that have already exceeded these limits are held 
at historical percent of net energy for load.
    \725\ 2013 Wind Technologies Market Report. LBNL. August 2014. 
Available at http://emp.lbl.gov/sites/all/files/2013_Wind_Technologies_Market_Report_Final3.pdf.
    Grid Integration and the Carrying Capacity of the U.S. Grid to 
Incorporate Variable Renewable Energy. NREL. Cochran et al., April 
2015. http://energy.gov/sites/prod/files/2015/04/f22/QER%20Analysis%20%20Grid%20Integration%20and%20the%20Carrying%20Capacity%20of%20the%20US%20Grid%20to%20Incorporate%20Variable%20Renewable%20Energy_1.pdf.
    The Western Wind and Solar Integration Study Phase 2. NREL. Lew 
et al., 2013. Available at http://www.nrel.gov/docs/fy13osti/55588.pdf. Refer to GHG Mitigation Measures TSD for further 
analysis.
    \726\ Refer to the GHG Mitigation Measures TSD for additional 
information on constraints related to deployment of non-dispatchable 
RE.
---------------------------------------------------------------------------

    In addition to facilitating the EPA's assessment of the feasibility 
and cost of reaching the aggregate building block 3 generation levels 
across all three BSER regions, the IPM projections also provide the EPA 
with a basis for apportioning those generation levels to each 
interconnection. The EPA considered the projected regional location of 
the evaluated RE deployment in this analysis, which shows the

[[Page 64809]]

majority of such deployment occurring in the Eastern Interconnection. 
The GHG Mitigation Measures TSD describes in greater detail the process 
by which the EPA calculated the apportionment of building block 3 
generation levels to each of the BSER regions, taking these modeling 
projections into account. Table 10 describes the annual building block 
3 generation levels for each interconnection from 2022 through 2030.

                               Table 10--Building Block 3 Generation Levels (MWh).
----------------------------------------------------------------------------------------------------------------
                                                            Eastern             Western              Texas
                        Year                            interconnection     interconnection     interconnection
----------------------------------------------------------------------------------------------------------------
2022................................................         166,253,134          56,663,541          18,963,672
2023................................................         181,542,775          60,956,363          28,177,431
2024................................................         218,243,050          75,244,721          39,382,162
2025................................................         254,943,325          89,533,078          50,586,893
2026................................................         291,643,600         103,821,436          61,791,623
2027................................................         328,343,875         118,109,793          72,996,354
2028................................................         365,044,150         132,398,151          84,201,085
2029................................................         401,744,425         146,686,508          95,405,816
2030................................................         438,444,700         160,974,866         106,610,547
----------------------------------------------------------------------------------------------------------------

    Through the quantification methodology detailed above, the EPA has 
identified amounts of incremental RE generation that are reasonable, 
rather than the maximum amounts that could be achieved while preserving 
the cost-effectiveness of the building block. For example, assuming 
gradual improvement in RE technology capacity factors consistent with 
historical trends, expanding the portfolio of RE technologies that 
contribute to the building block 3 generation level, and applying the 
five-year maximum capacity change values to all years of the interim 
period are adjustments that would produce higher building block 3 
generation levels and maintain the primacy of historical data in 
quantifying RE generation potential. External analysis and studies of 
RE penetration levels strongly support the technical feasibility and 
cost-reasonableness of RE deployment well in excess of the levels 
established by building block 3, as detailed in section V.E.7. By 
identifying reasonable rather than maximum achievable amounts, we are 
increasing the assurance that the identified amounts are achievable by 
the source category and providing greater flexibility to individual 
affected EGUs to choose among alternative measures for achieving 
compliance with the standards of performance established for them in 
their states' section 111(d) plans.
7. Feasibility of RE Deployment
    The 2030 level of RE deployment and the rate of progress during the 
interim period in getting to that level are well supported by comments 
received, DOE and NREL analysis, and external studies evaluating the 
costs of and potential for RE penetration. The EPA has assessed the 
feasibility of RE in terms of deployment potential, system integration, 
reliability, backup capacity, transmission investments, and RE supply 
chains.
    Historical RE deployment rates are a strong indication of the 
feasibility of the 2030 level of deployment and interim period pathway. 
The use of RE continues to grow rapidly in the U.S. In 2013, 
electricity generated from RE, including conventional hydropower, 
represented 12 percent of total U.S. electricity, up from 8 percent in 
2005. In particular, there has been substantial growth in the wind and 
solar markets in the past decade. Since 2009, wind energy has tripled 
and solar has grown tenfold.
    The expected future capacity installations in 2022-2030 needed to 
reach the 2030 level of incremental RE generation are consistent with 
historical deployment patterns. Forecasts by Cambridge Energy Research 
Associates (CERA) of 17 gigawatts in 2015 and historical deployment of 
16 gigawatts in 2012 are significant. The average deployment of wind 
over the past five years was 6,200 megawatts per year; 2014 deployment 
of solar PV, both distributed and utility-scale, was 6,201 megawatts. 
This contribution from solar PV is consistent with the rapid reduction 
in costs that is currently being observed and is expected to continue.
    Grid operators are reliably integrating large amounts of RE, 
including variable, non-dispatchable RE today. For example, Iowa and 
South Dakota produced more than 25 percent of their electricity from 
wind in 2013, with a total of nine states above 12 percent and 17 
states at more than 5 percent. California served nearly 19 percent of 
total load in 2013 with RE resources, not including behind-the-meter 
distributed solar resources, and approximately 25 percent of total load 
with RE in 2014. On an instantaneous basis, California is regularly 
serving above 25 percent of load with RE resources, recently began 
seeing over 5,000 megawatt-hours of solar energy, and is on track for 
33 percent of load with no serious reliability or grid integration 
issues. Germany exceeded 28 percent non-hydro RE as a percentage of 
total energy in first half of 2014. Other recent examples include: 
ERCOT met 40 percent of demand on March 31, 2014 with wind power; SPP 
met 33 percent of demand on April 6, 2013 with wind power; and, Xcel 
Energy Colorado met 60 percent of demand on May 2, 2013 with wind 
power. Operational and technical upgrades to the power system may be 
required to accommodate high levels of variable, non-dispatchable RE 
like wind and solar over longer time periods; however, the penetration 
levels cited above have been achieved without negative impacts to 
reliability due in large part to low-cost measures such as expanded 
operational flexibility and effective coordination with other regional 
markets.
    RE can contribute to reliable system operation. The abundance and 
diversity of RE resources in the U.S. can support multiple combinations 
of RE in much higher penetrations. When California, the Midwest, PJM, 
New York, and New England experienced record winter demand and prices 
during the polar vortex, wind generation played a key role in 
maintaining system reliability.
    Wind and solar PV are increasingly productive and capable of being 
accurately forecast, which improves grid reliability. Increasing 
capacity factors mean less variability and more generation. While the 
wind industry develops more projects at lower wind speed sites, wind 
turbine design changes are driving capacity factors higher among 
projects located in a given

[[Page 64810]]

wind resource regime.\727\ Average capacity factors have risen from the 
low 30 percent range to high 30 percent range and continue to improve. 
One key recent advancement is the increasing use of turbines designed 
for low to medium wind speed sites (with higher hub-heights and larger 
rotors, relative to nameplate capacity) at higher wind-speed sites with 
low turbulence.
---------------------------------------------------------------------------

    \727\ LBNL, Wind Technologies Market Report 2013, August 2014, 
p. 43, Available at: http://emp.lbl.gov/sites/all/files/2013_Wind_Technologies_Market_Report_Final3.pdf.
---------------------------------------------------------------------------

    New variable RE generators can provide more electrical power grid 
support services beyond just energy. Modern wind turbine power 
electronics allow turbines to provide voltage and reactive power 
control at all times. Wind plants meet a higher standard and far exceed 
the ability of conventional power plants to ``ride-through'' power 
system disturbances, which is essential for maintaining reliability 
when large conventional power plants break down. Xcel Energy sometimes 
uses its wind plants' exceedingly fast response to meet system need for 
frequency response and dispatchable resources. Utility-scale PV can 
incorporate control systems that enable solar PV to contribute to grid 
reliability and stability, such as voltage regulation, active power 
controls, ramp-rate controls, fault ride through, and frequency 
control. Solar generation is capable of providing many ancillary 
services that the grid needs but, like other generators, needs the 
proper market signals to trade energy generation for ancillary service 
provision.
    The transmission network can connect distant high-quality RE to 
load centers and improve reliability by increasing system flexibility. 
Investments in transmission and distribution upgrades also enable 
improvements in system-wide environmental performance at lower cost.
    The potential range of new transmission construction is within 
historical investment magnitudes. Under nearly all scenarios analyzed 
for the DOE's Quadrennial Energy Review, circuit-miles of transmission 
added through 2030 are roughly equal to those needed under the base 
case, and while those base case transmission needs are significant, 
they do not appear to exceed historical annual build rates. DOE's Wind 
Vision findings project 11.5 gigawatts of wind per year from 2021-2030. 
This deployment level would require 890 circuit miles per year of new 
transmission; 870 miles per year have been added on average between 
1991 and 2013. 11.5 gigawatts per year is consistent with building 
block 3 deployment levels for wind capacity over the compliance period. 
DOE's SunShot scenario, which increases utility-scale PV to 180 
gigawatts by 2030, required spending of $60 billion on transmission 
through 2050. On an average annual basis, this expenditure is within 
the historical range of annual transmission investments made by IOUs in 
recent decades.
    Incremental grid infrastructure needs can be minimized by 
repurposing existing transmission resources. Transmission formerly used 
to deliver fossil-fired power to distant loads can--and is--being used 
to deliver REwithout new infrastructure. First Solar's Moapa project 
uses transmission built to deliver coal-fired power from Navajo to Los 
Angeles. NV Energy's retirement of Reid-Gardner will free up additional 
transmission capacity. The Milford wind projects in Utah already 
utilize transmission that was built to deliver coal power to Los 
Angeles.
    Storage can be helpful but is not essential for the feasibility of 
RE deployment because there are many sources of flexibility on the 
grid. DOE's Wind Vision and many other studies have found an array of 
integration options (e.g., large balancing areas, geographically 
dispersed RE, weather forecasting used in system operations, sub-hourly 
energy markets, access to neighboring markets) for RE beyond storage. 
Storage is a system resource, as its value for renewables is a small 
share of its total value.
    Increasing regional coordination between balancing areas will 
increase operational flexibility. The Energy Imbalance Market (EIM) 
recently implemented by the California ISO and Pacificorp is a good 
example of the increased coordination that will be helpful in ensuring 
that resources across the West are being utilized in an efficient way.
    Significant wind and solar supply chains have developed in the past 
decade to serve the fast-growing US RE market. For wind, domestic 
production capability would likely have to increase to accommodate 
projected builds under the CPP in the 2022-2030 time period; however, 
the global supply chain has expanded significantly to serve multiple 
markets and can augment production from the domestic supply chain, if 
necessary. At the start of 2014, the U.S. domestic supply chain could 
produce 10,000 blades (6.2 gigawatts) and 4300 towers (8 gigawatts) 
annually. It is not anticipated that expanded domestic manufacturing 
will be constrained by raw materials availability or manufacturing 
capability. For solar technologies, the global supply chain has a 
capacity that has significantly expanded over the past few years from 
1.4 gigawatts per year in 2004 to 22.5 gigawatts per year in 2011. 
Current capacity exceeds these levels and is expected to grow. For PV 
systems, raw materials like tellurium and indium are at highest risk of 
supply shortage, but these materials are not used in the PV 
technologies currently being deployed at large-scale.
8. Cost of CO2 Emission Reductions From RE Generation
    The EPA believes that RE generation at the levels represented in 
building block 3 can be achieved at reasonable costs. In the EPA's 
modeling of the building block 3 generation level, the projected cost 
of achieving CO2 reductions through this expansion of RE 
generation is $37 per ton on average from 2022 through 2030.\728\ There 
are a number of reasons why the EPA believes that the cost of 
CO2 emission reductions from RE generation will be lower 
than this analysis suggests. First, modeling constraints that restrict 
variable, non-dispatchable RE technologies to 30 percent of net energy 
for load at each of the 64 U.S. IPM regions is a conservative limit 
intended to eliminate significant grid integration costs at increased 
levels of RE penetration. In fact, many regions have already 
demonstrated levels of RE penetration that exceed the constraints, and 
in practice intermittency can be managed across larger regions than the 
64. Consequently, the extent to which these regions could, in practice, 
achieve higher levels of RE deployment without facing substantial grid 
integration costs would lead to a lower-cost RE outcome than is 
estimated by this analysis. Second, there are multiple RE technologies 
not quantified under building block 3 that affected EGUs may use to 
demonstrate compliance (distributed generation technologies, offshore 
wind, etc.). Based on preliminary analysis from DOE and NREL, cost-
effective opportunities for distributed generation alone could satisfy 
one-third to over one-half of the stringency associated with building 
block 3.\729\ Third, as discussed in section V and VI of the preamble, 
the BSER reflects the degree of emission limitation achieved through 
the application of the building blocks in the

[[Page 64811]]

least stringent region. By definition, in the other two regions the 
BSER is less stringent than the simple combination of the three 
building blocks, rendering a portion of the emission reduction 
potential quantified by the building blocks unnecessary to achieving 
the interim and final CO2 emission performance rates. For 
example, the EPA has calculated that in excess of 160,000,000 megawatt-
hours of building block 3 potential is not required to achieve the 
final CO2 emission performance rates in 2030--and would be 
accessible to affected EGUs for compliance.\730\ Therefore, it is 
reasonable to expect that it would cost less to achieve the component 
of building block 3 potential that is reflected in the calculation of 
the final CO2 emission performance rates, as compared to the 
results of this analysis which assumed achievement of the entire 
quantified building block 3 potential. The EPA believes that these 
factors provide significant opportunities for achievement of the 
building block 3 generation levels at lower costs than estimated in 
this analysis.
---------------------------------------------------------------------------

    \728\ Refer to the GHG Mitigation Measures TSD for further 
analysis and IPM run results.
    \729\ See Section VIII.K. for a description of qualifying RE 
technologies for compliance.
    \730\ For additional discussion on how this concept impacts 
building block 3 generation levels, refer to the GHG Mitigation 
Measures TSD and the CO2 Emission Performance Rate and 
Goal Computation TSD for Final CPP.
---------------------------------------------------------------------------

VI. Subcategory-Specific CO2 Emission Performance Rates

A. Overview

    In this section, the EPA sets out subcategory-specific 
CO2 emission performance rates to guide states in 
development of their state plans. The emission performance rates 
reflect the emission rates for two generating subcategories affected by 
the rule (fossil steam generation and gas-fired combustion 
turbines).\731\ These final emission performance rates reflect the 
EPA's quantification of the BSER based on the three building blocks 
described in section V above. This procedure follows a similar logic to 
BSER quantification at proposal, but it keeps the emission performance 
rates separate for fossil steam and NGCC subcategories instead of 
immediately blending them together into a single value for all affected 
EGUs. Commenters noted that the proposed rule established guidelines 
that were based on the aggregation of units, and their reduction 
potential, in a state rather than providing technology-specific 
guidelines. While many commenters appreciated the flexibility this 
state-focused structure provided, some noted two concerns with this 
approach: (1) It would potentially create different incentives for the 
same generating technology class depending on the state in which that 
generator was located, and (2) it deviated from the EPA's previous 
interpretation of the 111(d) regulatory guidelines by not providing 
technology-specific standards of performance. In response to these 
comments and our further consideration, the final rule establishes 
subcategory-specific emission performance rates that are identical 
across units within a subcategory regardless of where a unit is located 
within the contiguous U.S. These subcategory-specific emission 
performance rates are then translated into state-specific goals which, 
as in the proposal, reflect the particular energy mix present in each 
state. That translation is presented in section VII.
---------------------------------------------------------------------------

    \731\ The only natural gas fired EGUs currently considered 
affected units under the 111(d) applicability criteria are NGCC 
units capable of supplying more than 25 MW of electrical output to 
the grid. The data and rates for these units represent all emissions 
and MWh output associated with both the combustion turbines as well 
as all associated heat recovery steam generating units. The 
remainder of the section will use the term ``NGCC'' to collectively 
refer to these natural gas fired EGUs.
---------------------------------------------------------------------------

    These performance rates reflect the average emission rate 
requirement for each subcategory. Similar to the proposal, they are 
presented as adjusted average emission rates that reflect other 
generation components of BSER (e.g., renewable) in addition to the 
fossil component. These performance rates must be achieved by 2030 and 
sustained thereafter. The interim performance rates apply over a 2022-
2029 interim period and would be achieved on average through reasonable 
implementation of the best system of emission reduction (based on all 
three building blocks) described above. In other words, the interim 
performance rates are consistent with a reasonable deployment schedule 
of BSER technologies as they scale up to their full BSER potential by 
2030. The performance rates are meant to reflect emission performance 
required across all affected EGUs when averaged together and inclusive 
of lower-emitting BSER components.
    The performance rates are expressed in the form of adjusted \732\ 
output-weighted-average CO2 emission rates for affected 
EGUs. However, states are authorized to use a converted statewide rate-
based or mass-based goal as discussed in the next section. The EPA has 
determined that the statewide rate-based and mass-based CO2 
goals are expressions of the emission performance rates equivalent to 
application of the emission performance rates to affected EGUs within a 
state.
---------------------------------------------------------------------------

    \732\ As described below, the emission performance rates include 
adjustments to incorporate the potential effects of emission 
reduction measures that address power sector CO2 
emissions primarily by reducing the amount of electricity produced 
at a state's affected EGUs (associated with, for example, increasing 
the amount of new low- or zero-carbon generation rather than by 
reducing their CO2 emission rates per unit of energy 
output produced).
---------------------------------------------------------------------------

    The EPA is finalizing the performance rates in a manner consistent 
with the proposal, with appropriate adjustments based on comments. 
Stakeholders had the opportunity to demonstrate during the comment 
period that application of one or more of the building blocks would not 
be expected to produce the level of emission reduction quantified by 
the EPA because implementation of the building block at the levels 
envisioned by the EPA was technically infeasible, or because the costs 
of doing so were significantly higher than projected by the EPA. The 
EPA has considered all of this input in setting final performance 
rates.
    The remainder of this section addresses two sets of topics. First, 
we discuss several issues related to the form of the performance rates. 
Second, we describe the performance rates, computation procedure, and 
adjustments made between proposal and final based on stakeholder 
feedback in the comment period.
    Some of the topics addressed in this section are addressed in 
greater detail in supplemental documents available in the docket for 
this rulemaking, including the CO2 Emission Performance Rate 
and Goal Computation TSD for CPP Final Rule and the Greenhouse Gas 
Mitigation Measures TSD. Specific topics addressed in the various TSDs 
are noted throughout the discussion below.

B. Emission Performance Rate Requirements

    The EPA has developed a single performance rate requirement for 
existing fossil steam units in the contiguous U.S., and a single rate 
for existing gas turbines in the contiguous U.S., reflecting 
application of the BSER, based on all three building blocks described 
earlier, to pertinent data. The rates are intended to represent 
CO2 emission rates achievable by 2030 after a 2022-2029 
interim period on an output-weighted-average basis by all affected 
EGUs, with certain computation adjustments described below to reflect 
the potential to achieve mass emission reductions by avoiding fossil 
fuel-fired generation.
1. Final Emission Performance Rate Requirements
    The emission performance rates are set forth in Table 11 below, 
followed by

[[Page 64812]]

a description of the computation methodology.

                  Table 11--Emission Performance Rates
  [Adjusted output-weighted-average pounds of CO2 per net MWh from all
                    affected fossil fuel-fired EGUs]
------------------------------------------------------------------------
                                                     Interim     Final
                    Subcategory                        rate       rate
------------------------------------------------------------------------
Fossil Fuel-Fired Electric Steam Generating Units.      1,534      1,305
Stationary Combustion Turbines....................        832        771
------------------------------------------------------------------------

    The emission performance rates are expressed as adjusted output-
weighted-average emission rates for each subcategory. As discussed 
later in this section, the emission rate computation includes an 
adjustment designed to reflect mass emission reductions associated with 
lower-emitting BSER components. The adjustment is made by estimating 
the annual net generation associated with an achievable amount of 
qualifying incremental lower-carbon and zero-carbon generation and 
substituting those MWhs for the baseline electricity generation and 
CO2 emissions from the higher-emitting affected EGUs. Under 
the final rule approach, regionally identified building block 3 
potential generation replaces fossil steam and NGCC generation on a 
pro-rata basis corresponding to the baseline mix of fossil generation 
in each region.
2. Interim Emission Performance Rates
    Some commenters suggested that the interim period starting in 2020 
provided too little time for implementation of measures required to 
demonstrate compliance during the interim period. As discussed in 
section V.A.3.g of this preamble, the EPA has determined that an 
interim period beginning in 2022 provides sufficient time for states to 
undertake necessary planning exercises and for the implementation of 
measures towards achieving the performance rates. The EPA determined 
the interim rates in a manner similar to proposal, with an adaptation 
to address the revised timing of the interim compliance period 
(beginning in 2022 rather than in 2020 as proposed). They reflect the 
averaging of estimated emission performance rates for each year in the 
interim period (i.e., 2022-2029).
    The interim performance rates are less stringent than the final 
2030 emission performance rates because the amount of emission 
reduction potential identified for the BSER increases over time, as 
explained in section V.

C. Form of the Emission Performance Rates

1. Rate-Based Guidelines
    The interim and final emission performance rates for fossil steam 
and NGCC units are presented in the form of adjusted output-weighted-
average CO2 emission rates that the affected fossil fuel-
fired units could achieve, through application of the measures 
comprising the BSER (or alternative control methods). Several aspects 
of this form of emission rate are worth noting at the outset: The use 
of emission rates expressed in terms of net rather than gross energy 
output; the use of output-weighted-average emission rates for all 
affected EGUs; the use of adjustments to accommodate incremental NGCC 
generation and RE measures that reduce CO2 emissions by 
reducing the quantity of fossil fuel-fired generation and associated 
emissions; and the adjustability of the goals based on the severability 
of the underlying building blocks.
    a. Rationale for rate-based guidelines.
    First, the EPA sets an emission rate requirement for each 
subcategory by identifying the technology-specific reductions available 
under the building blocks. We then give each state the choice to apply 
the emission performance rates directly to the affected EGUs within the 
state or provides the opportunity to use the statewide rate-based goal 
or the equivalent mass-based form translated from the emission 
performance rates for state plan purposes. The emission performance 
rates reflect the BSER, and the statewide rate-based goal and statewide 
mass-based goal are alternative metrics for realizing the emission 
performance rates at the aggregate affected fleet level for a state.
    Stakeholders have expressed support for having the flexibility to 
choose from among the multiple options for crafting an implementation 
plan to realize the BSER. The EPA is providing emission performance 
rate-based guidelines that apply uniformly to technology subcategories 
nationwide, and the EPA is providing corresponding state emission rate 
goals and state mass goals to further enhance compliance flexibility 
for each state. This approach allows each state to adopt a plan that it 
considers optimal and is consistent with the state flexibility 
principle that is central to the EPA's development of this program.
    b. Net vs. gross MWh.
    The second aspect noted above concerns the expression of the goals 
in terms of net energy output \733\--that is, energy output 
encompassing net MWh of generation measured at the point of delivery to 
the transmission grid rather than gross MWh of generation measured at 
the EGU's generator. The difference between net and gross generation is 
the electricity used at a plant to operate auxiliary equipment such as 
fans, pumps, motors, and pollution control devices. Because 
improvements in the efficiency of these devices represent opportunities 
to reduce carbon intensity at existing affected EGUs that would not be 
captured in measurements of emissions per gross MWh, goals are 
expressed in terms of net generation. As noted by commenters, EGUs have 
familiarity and in some places already have in place equipment 
necessary to collect and report hourly net generation.\734\
---------------------------------------------------------------------------

    \733\ As discussed below in Section VIII on state plans, we are 
similarly determining that states choosing a rate-based form of 
emission performance level for their plans should establish a 
requirement for affected EGUs to report hourly net energy output.
    \734\ Specifically, commenters noted that while net generation 
is not reported to the EPA under 40 CFR part 75, affected EGUs are 
generally required to report gross and net generation on a monthly 
basis to EIA through form 923 submittal.
---------------------------------------------------------------------------

    c. Output-weighted performance rates for all affected EGUs.
    This final rule provides an expression of the BSER as subcategory-
specific emission performance rates rather than the state goals 
provided at proposal. Whereas the proposal also estimated the BSER 
impact on fossil steam and NGCC emissions and generation, it went one 
step further by averaging these two technology rates into a single rate 
for each state. Under this final rule, the EPA is identifying the 
fossil steam rate and the NGCC rate separately instead of only 
presenting them in a blended fashion at the state level.\735\ These two 
emission performance rates are the expression of the BSER for the final 
rule for affected EGUs located within the contiguous U.S.
---------------------------------------------------------------------------

    \735\ However, as discussed in the next section, in order to 
provide maximum flexibility to states, the EPA averages these two 
emission rates together for each state using their adjusted 2012 
baseline generation share to arrive at a single statewide emission 
performance goal. The state has the option to comply with this 
statewide goal through a compliance pathway of its choice. This 
compliance pathway may or may not involve requiring its affected 
units to meet the emission performance rates.
---------------------------------------------------------------------------

    The modification from a blended emission rate in the proposed rule 
to a subcategory-specific emission performance rate for affected EGU 
categories in the final rule was made in response to comments that 
technology

[[Page 64813]]

subcategory-specific emission rates were more analogous to prior 111(d) 
efforts and more consistent with the statute. The EPA received 
significant comments suggesting a technology subcategory-specific rate 
is consistent with past section 111(d) regulations. However, many 
commenters also supported the flexibility provided to states through a 
state goal metric provided at proposal. Therefore, the EPA does provide 
alternative statewide rate-based and mass-based goals in the next 
section.
    The EPA's main consideration has been to ensure that the expression 
of the BSER reflects opportunities to manage CO2 emissions 
by shifting generation among different types of affected EGUs. Both the 
performance rates in this final rule and the state goals at proposal 
rely on the adjusted emission rate metric to reflect that potential 
shifting. Specifically, because CO2 emission rates differ 
widely across the fleet of affected EGUs, and because transmission 
interconnections typically provide system operators with choices as to 
which EGU should be called upon to produce the next MWh of generation 
needed to meet demand, opportunities exist to manage utilization of 
high carbon-intensity EGUs based on the availability of less carbon-
intensive generating capacity. For states and generators, this means 
that CO2 emission reductions can be achieved by shifting 
generation from EGUs with higher CO2 emission rates, such as 
coal-fired EGUs, to EGUs with lower CO2 emission rates, such 
as NGCC units. Our analysis indicates that shifting generation among 
EGUs offers opportunities to achieve large amounts of CO2 
emission reductions at reasonable costs. The realization of these 
opportunities can be reflected in an emission rate established in the 
form of an output-weighted-average emission rate where the weighting 
reflects the varying levels of replacement generation technologies.
    d. Severability of building blocks.
    Section V above discusses the severability of the three building 
blocks upon which the CO2 emission performance rates are 
based. Because the building blocks can be implemented independently of 
one another and the emission performance rates reflect the sum of the 
emission reductions from all of the building blocks, if any of the 
building blocks is found to be an invalid basis for the ``best system 
of emission reduction . . . adequately demonstrated,'' the rates would 
be adjusted to reflect the emissions reductions from the remaining 
building blocks. The sole exception, as described above, is the 
application of building block 1 in isolation, which would not be 
implemented independently. The performance rates and statewide goals 
that would result from any combination of the building blocks could be 
computed using the formulas and data included in the CO2 
Emission Performance Rate and Goal Computation TSD for CPP Final Rule 
and its appendices using the methodology described below and elaborated 
on in that TSD.

D. Emission Performance Rate-Setting Equation and Computation Procedure

    The methodology used to compute the performance rates is summarized 
on a step-by-step basis below in section 3. The methodology is 
described in more detail in the CO2 Emission Performance 
Rate and Goal Computation TSD for CPP Final Rule, which includes a 
numerical example illustrating the full procedure. The quantification 
of the building blocks used in the computation procedure is discussed 
in Section V above and in the Greenhouse Gas Mitigation Measures TSD.
1. Inventory of Likely Affected EGUs
    In order to calculate the subcategory-specific emission performance 
rates reflecting the BSER, the EPA first needed to develop a baseline 
inventory of likely affected EGUs in order to estimate the impact of 
the BSER. The EPA developed an inventory of likely affected units that 
were operating in 2012 or that began construction prior to January 8, 
2014 and that appeared to meet the final rule's applicability 
criteria.\736\ This inventory does not constitute a final applicability 
determination, but best reflects the EPA's estimate of units subject to 
the 111(d) applicability criteria as laid out in Section IV. The EPA 
identified a list of likely affected units at proposal comprised of 
approximately 3,000 EGUs. The agency took comment on this list and has 
made a number of updates to the inventory in response to those comments 
and in regards to applicability criteria changes resulting from 
comments. However, the inventory does not reflect a final applicability 
determination, and where a unit's status was unclear, the EPA generally 
treated the unit's status in a manner consistent with the proposal and 
publically available reported data.\737\
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    \736\ The EPA's responsibility is to determine the BSER for all 
affected EGUs. Some of these under construction units may not enter 
operation until 2015 or later, but they are likely affected units 
and therefore appropriate to reflect in the baseline and 
corresponding subcategory-specific emission performance rates and 
state goals.
    \737\ The EPA notes that in some cases, it may not yet be 
possible to determine the status of an EGU as affected or unaffected 
without additional data. There are potentially some units excluded 
or included in the baseline that will ultimately have a different 
status following an applicability determination. However, these 
cases are limited, and the effect of any collective changes to the 
affected fleet inventory will not yield a bias in the BSER 
computation at the regional level.
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    Since the final rule's applicability includes under construction 
units, the EPA also identified units that had not yet commenced 
operation by the 2012 baseline period, but that commenced construction 
before January 8, 2014. The EPA received significant comment on the 
proposal's sole use of the National Electric Energy Data System (NEEDS) 
to identify these under construction units. Commenters suggested that 
the EPA also utilize EIA and 2012 proposed unit-level files to help 
better identify under construction units. In some cases, NEEDS did not 
reflect units that had commenced construction. Therefore, the EPA 
updated its approach to identifying units that had commenced 
construction prior to January 8, 2014, but that had not commenced 
operation in 2012. In the final rule, the EPA uses EIA data, comments, 
as well as NEEDS data to identify these under construction 
units.738 739 740
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    \738\ The NEEDS database was also updated to reflect the latest 
data and commenter input on under construction units.
    \739\ For purposes of determining emission performance rates, 
the EPA classifies any unit that had begun construction prior to 
Jan. 8, 2014, but had not commenced operation by Dec. 31, 2011 as 
``under construction''. Many of these ``under construction'' units 
have commenced operation at some point during 2012 or prior to 
signature of this final rule.
    \740\ ``Commence'' and ``construction'' are defined in 40 CFR 
60.2.
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    These units that were operating by 2012 along with those that had 
not commenced operation by 2012 but had commenced construction by 
January 8, 2014, reflect the EPA baseline inventory of likely affected 
EGUs. The CO2 Emission Performance Rate and Goal Computation 
TSD for CPP Final Rule explains the prime mover, capacity, and fuel 
criteria used to identify the likely affected EGUs.\741\
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    \741\ The baseline inventory relies on historical data and does 
not incorporate anticipated future retirements. Most commenters 
supported this treatment as they viewed those scheduled retirements 
(and corresponding emission reductions) as an alternative compliance 
flexibility.
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    The EPA received significant comment that units that came online 
during the baseline year (e.g., 2012) should be treated as under 
construction rather than operating units in 2012 for purposes of 
estimating baseline values, because their 2012 operation may be

[[Page 64814]]

misrepresentative of anticipated future-year operation due to partial 
year operation in 2012. The EPA has made an adjustment to flag these 
units as having commenced operation during 2012 and treat them as under 
construction units, consistent with commenters' suggestion; for BSER 
computational purposes, generation and emissions for these units are 
estimated based on a representative first full year of operation for 
that technology class.
2. Data Year
    In the proposed rule, the EPA considered using a historical-year 
data set or a projected-year data set as a starting point for applying 
the technology assumptions identified under BSER. The EPA proposed 
using 2012 data as it was the most recent data year for which complete 
data were available when the EPA undertook analysis for the proposed 
rule and it reflected actual performance at the state level. The EPA 
took comment on alternative data sets. In particular, the EPA issued a 
NODA on October 30, 2014 (79 FR 64543) in which we provided 2010 and 
2011 historic data for consideration.
    The EPA received a significant number of comments supporting the 
use of historical data as the basis from which to quantify performance 
rates reflecting BSER. Some commenters supported the 2012 data year as 
the best reflection of the power fleet, and some suggested that the EPA 
use a different year or a historical average to control for data 
anomalies in 2012. Moreover, some commenters pointed out that using 
2010, 2011, 2012 data, or an average of the three would not address 
their concerns about recent year anomalies in hydro generation due to 
high snow pack. Some commenters also suggested the EPA use a baseline 
including years prior to 2012, not to increase representativeness of 
the power sector, but as a means of recognizing early action.
    In this final rule, the EPA is taking an approach to the baseline 
year where we still largely rely on reported 2012 data as the best and 
most recent available data representing the power sector from which to 
apply the BSER, but also including targeted baseline adjustments to 
address commenter concerns with 2012 data.\742\ Below, we explain why--
at the nationwide level--2012 data are preferable, more objective, and 
more accurate than a prior year, or an average of years, for informing 
the baseline. Then, we explain the adjustments that we are making to 
the 2012 data along with our rationale for such adjustments, in 
response to comments we received.
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    \742\ The EPA recognizes that more recent emissions and 
generation data have become available since 2012, but 2012 data 
constituted the most recent year for which full data was available 
at the time the EPA began its analysis for proposal.
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    Some commenters supported the EPA's use of 2012 data to inform 
performance rates, and the EPA agrees that 2012 data with targeted 
adjustments, relative to other historical years, best reflects the 
power sector and best informs the performance rates that pertain to the 
BSER. The EPA believes that starting with 2012 data is more accurate 
and better informs the BSER than an earlier historical year or 
historical multi-year average for the following reasons:

    (1) Of the historical data fully available at the time the 
proposal analysis began, 2012 was the most recent and best reflects 
the power fleet. Approximately 43 GW of new capacity came online in 
2010 and 2011. In other words, there was 43 GW of capacity online as 
of 2012 that had not been in service at some point during the 2010-
2011 period. Likewise, approximately 17 GW of capacity that were 
operable in 2010 and/or 2011 were retired prior to 2012.\743\ Using 
state-level, prior year data, either on its own, or as part of a 
multi-year baseline, is not as representative of the current power 
fleet as the 2012 data, which better reflects significant changes in 
power sector infrastructure.
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    \743\ EIA Form 860, 2012.
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    (2) A three-year baseline would not address some of the 
substantive concerns raised by commenters. Many commenters pointed 
out that using a three-year baseline would not address their 
critical concern about variation in the hydrological cycle due to 
snow pack (particularly in the Northwest), because the snow pack was 
significantly above average in both 2011 and 2012. The EPA agrees 
with commenters that we can better address their baseline data 
concerns regarding an average hydro year by identifying those states 
with a significant share of hydro generation and variation in that 
hydro generation, and making targeted adjustments to those states' 
affected fossil generation levels in order to reflect a more typical 
snow-pack year. This procedure is described in more detail below and 
in theTSDs.
    (3) In addition to being, in the EPA's view, a less 
representative baseline of the existing power fleet, a multi-year 
baseline would also likely entail complexity when determining how to 
average together yearly fleet data while appropriately accounting 
for fleet changes occurring during those years. The 2012 baseline 
starting point maximizes the EPA's reliance on latest reported 
operating data and minimizes the need for fleet capacity 
adjustments. For instance, because of year-to-year fleet turnover, 
the averaging of multiple baseline years would require additional 
assumptions in regards to which generation to consider from a fleet 
that is changing in a given state or region (or even where units are 
switching fuel sources such as a coal-to-gas conversion).
    (4) Due to the region-based approach to quantify building blocks 
and the BSER as subcategory-specific emission performance rates, 
variations in unit-level data do not significantly impact the 
calculation of emission performance rates. For instance, if one 
fossil unit is operating less in a given year due to an outage, 
another fossil unit in the same region is generally operating more. 
Therefore, at the regional level, fossil generation and emissions do 
not vary to the same degree that unit-level data varies. Moreover, 
the variation at the regional level that does exist in 2012 relative 
to previous years is not necessarily unrepresentative variation, but 
illustrates trends in the power sector infrastructure that are 
desirable to capture for purposes of determining a representative 
year from which further improvements in CO2 emissions 
performance can be made. Because the EPA is moving from a state 
approach at proposal to a regional approach for calculating the 
expression of the BSER in this final rule, unit-level operational 
variation from year to year becomes even less relevant to the 
calculation of regional emission performance rates.
    (5) Some commenters suggested the EPA use an earlier baseline 
year as a means of recognizing early action. They noted that an 
earlier baseline would reflect a higher-emitting fleet and therefore 
when the same level of building block MWhs are applied, they would 
result in a higher (i.e., less stringent) state goal. The EPA 
disagrees with this view for several reasons. First, the objective 
of selecting a baseline to inform BSER is to have one that best 
reflects the power sector and consequently the best system of 
emission reductions of which the power fleet is capable. Using an 
earlier baseline that ``inflates'' the starting point would 
undermine this objective, not serve it. Second, the EPA disagrees 
with the premise of this comment--that the baseline would change and 
building block potentials would stay the same. For instance, 
building block 2 functions based on incremental generation potential 
(incremental generation = potential generation-baseline generation). 
This incremental value would increase if an earlier baseline period 
was used that had less existing NGCC generation.
    (6) Some commenters pointed out that the EPA relied on multi-
year historical data in allowance allocation in previous rulemakings 
(e.g., CAIR and/or CSAPR allocations). However, that comparison is 
not relevant to the quantification of emission reduction potential 
under 111(d). In those previous instances, the EPA was considering 
typical unit-level behavior for allowance allocation purposes--not 
for determining the emission reduction requirements of the program. 
Those allowance allocation determinations were independent of and 
subsequent to the determination of emission reduction requirements 
in those rulemakings.
    (7) The EPA received significant comment that 2012 was not a 
representative year for natural gas prices, and thus the EPA should 
use another year. The EPA disagrees with this comment, and does not 
view it as grounds for a change to the baseline period. While the 
EPA does recognize that Henry

[[Page 64815]]

Hub natural gas prices were lower in 2012 relative to previous 
years, this does not invalidate the suitability of the data year 
selection. The EPA's objective in selecting a baseline is to 
identify potential reductions when BSER technologies are applied; 
year-to-year variation in market prices for natural gas does not 
frustrate this effort. For instance, a region may have generated 
only 5 MWh of NGCC generation in 2011 when gas prices were higher, 
and 10 MWh of NGCC generation in 2012 when gas prices dropped. 
However, this does not change the outcome of the quantification of 
the BSER, because the building block is based on the emission 
reduction potential of the fleet. That potential (e.g., a fuller 
realization of the existing NGCC generation potential equivalent to 
15 MWh) does not change regardless of the year used for baseline 
NGCC generation. Therefore, a different data year may change a 
baseline data point, but it would not change the total potential 
NGCC generation for quantifying the emission performance rates in 
these circumstances.

    In summary, the EPA believes that continuing to rely on 2012 data 
while incorporating select data adjustments as detailed below is not 
only a reasonable choice and adequately supported, but a more reliable 
and preferable starting point for determining the BSER requirements.
3. Adjustments That the EPA Made to the 2012 Data
    The EPA made corrections to unit-level 2012 data based on commenter 
feedback. In addition, we also made some adjustments to 2012 data, not 
to address a correction, but to address a concern about the 
representativeness of the data. Although the EPA determined that the 
2012 data year better informed its BSER determination than a preceding 
year or a multi-year average, commenters did identify some limitations 
that we are addressing through targeted adjustments. These are 
discussed below:

    (1) Adjustments to state-level data to account for annual 
variation in the hydrologic cycle as it relates to fossil 
generation.
    Hydropower plays a unique role in a handful of states in that 
(1) it is a significant portion of their generation portfolio, (2) 
it varies on an annual basis, and (3) 2012 was an outlier year for 
snow-pack (meaning hydropower was above and fossil generation was 
below its historical average).The EPA notes that these three 
conditions are not present in other weather-based RE technologies 
like solar or wind.\744\ Therefore, no similar adjustment was needed 
to account for weather patterns with these technologies.
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    \744\ While solar and wind generation may vary on an hourly or 
daily basis, their annual generation profiles are subject to notably 
less variation compared to hydropower. The EPA's calculation of the 
BSER relies on annual generation data, not on hourly or daily 
generation data.
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    Unlike market conditions (e.g., changes in natural gas prices) 
that may produce different generation profiles year-to-year but that 
do not change the overall generating potential of the state's power 
fleet, variation in the hydrologic cycle does fundamentally change 
the generating potential of the state's power fleet in hydro-
intensive states as they no longer have the same generating 
potential in an average year as they had in a ``high hydro'' year. 
The CO2 Emission Performance Rate and Goal Computation 
TSD for CPP Final Rule provides analysis and explains the adjustment 
that the EPA made to the state-level 2012 data for Idaho, Maine, 
Montana, Oregon, South Dakota, and Washington to better reflect 
fossil generation levels when hydro generation performed at its 
average level as observed over a 1990-2012 timeframe. The EPA agrees 
with commenters that using a 2010-2012 baseline would not address 
the concern as 2011 was also an outlier year relative to historical 
snow-pack and hydro generation.
    (2) Extended unit outages due to maintenance.
    Generally, because of the regional-level approach to calculate 
performance rates, the EPA does not believe that unit-level 
variations in operation influence the subcategory-specific 
performance rates reflecting BSER. For instance, as some units ramp 
down, and others ramp up to replace their load at the regional 
level, total fossil generation changes little due to these fossil-
for-fossil substitutions. Unit-level variation does not inherently 
entail region-wide variation.
    However, the EPA did receive comment that in limited cases, this 
could have a substantial impact on an individual state if it chooses 
to use a rate-based or mass-based statewide goal. Even though the 
EPA is calculating subcategory-specific performance rates that it 
believes are not affected by this type of unit-level variation, it 
still evaluated the possible impacts it may have when converting to 
state goals in the next section. The EPA examined units nationwide 
with 2012 outages to determine where an individual unit-level outage 
might yield a significant difference in state goal computation. When 
applying this test to all of the units informing the computation of 
the BSER, emission performance rates, and statewide goals, the EPA 
determined that the only unit with a 2012 outage that (1) decreased 
its output relative to preceding and subsequent years by 75 percent 
or more (signifying an outage), and (2) could potentially impact the 
state's goal as it constituted more than 10 percent of the state's 
generation was the Sherburne County Unit 3 in Minnesota. The EPA 
therefore adjusted this state's baseline coal steam generation 
upwards to reflect a more representative year for the state in which 
this 900 MW unit operates.
    (3) Many commenters also noted that because the EPA uses annual 
data, 2012 was not representative for units coming online part way 
through the year. The EPA relies on annual data, so if a unit is 
underrepresented in a certain part of the year because it is not yet 
online, then another unit is likely over-represented as it is 
operating more than it otherwise would when the second unit 
commences operation. Therefore, the resulting state-level and 
regional-level aggregate annual generation level used in determining 
the BSER may be considered to be representative and there is not 
necessarily a need for any adjustment.
    However, the EPA recognizes that the over-represented and under-
represented units do not necessarily fall within the same state, and 
therefore this potential difference in the state location of the 
affected units could have an impact when estimating appropriate 
statewide goals. To address this comment, the EPA adjusted the 2012 
generation data for fossil units coming online during 2012 to a more 
representative annual operating level for that type of unit 
reflecting its incremental impact on generation and emissions. This 
effectively resulted in increased baseline emissions and generation 
assumed for those units beyond their reported partial-year 
operations in 2012. Conceptually, the assumption of full-year 
operation at units that came online partway through 2012 could pair 
with an assumed reduction in the operation of other units somewhere 
in the same region. However, the EPA made no corresponding deduction 
to represent this likely decreased utilization at other affected 
units because it was impossible to project the state location of 
such units with certainty and the assumed utilization level was 
meant to reflect the incremental impact on the baseline. As a 
result, this data adjustment increases the total generation and 
emissions for units reporting in the 2012 baseline beyond the 2012 
reported levels.
    Additionally, as done in proposal, the EPA continued to identify 
under construction units that did not begin operation in 2012, but 
had commenced construction prior to January 8, 2014 and would 
commence operation sometime after 2012. As described in the next 
section, the EPA estimated baseline generation and emissions for 
these units as they had no 2012 reported data.

    In summary, this final rule continues to rely on the latest 
reported 2012 data as the foundation for quantifying the BSER. However, 
the EPA has made limited adjustments, in addition to corrections 
identified by commenters, to the 2012 data to address some of the 
relevant concerns raised by commenters. Therefore, the baseline is 
informed by 2012 data, but not limited to 2012 data.\745\
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    \745\ Updated unit-level data reflecting corrections identified 
by commenters to the underlying 2012 file are provided in Appendix 1 
of the CO2 Emission Performance Rate and Goal Computation 
TSD for CPP Final Rule. The adjustments made to the aggregate data 
to address representativeness concerns are provided in Appendix 3.
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4. Equations
    In this section we describe how we develop the equations used to 
determine the emission performance rates for fossil steam and NGCC 
units that express and implement BSER. More detailed

[[Page 64816]]

information regarding rate computation, including example calculations, 
can be found in the CO2 Emission Performance Rate and Goal 
Computation TSD for CPP Final Rule, which is available in the docket 
for this action. Here we first present the general principles we follow 
when developing equations to express the BSER; then, we summarize the 
steps taken to assemble baseline data to reflect 2012 baseline 
emissions and generation, and apply the building blocks that constitute 
the BSER to derive performance rates that will be used by states to 
implement BSER. Section VII then explains how these nationwide 
performance rates are reconstituted into a statewide goal metric 
similar to the proposal in order to allow a state (at its discretion) 
to use a statewide goal as a mechanism for demonstrating compliance at 
the aggregate state level in a state plan, as an alternative to 
applying the emission performance rates to its affected EGUs directly.
    When developing equations to implement BSER, we adhere to a number 
of basic principles. First, we ensure that the equations are consistent 
with the BSER itself, and in particular, reflect the redistribution of 
generation among fossil steam, NGCC and renewables embodied in building 
blocks 2 and 3. In doing this, we account for the interactions between 
building blocks in a way that is consistent with the assessment of 
incremental building block generation potential and the compliance 
framework for Emission Reduction Credits (ERCs). In particular, we must 
ensure that each increment of building block 3 emission reduction 
potential is applied to either fossil steam or NGCC units but not both. 
The equations we develop must also take account of the dual status of 
existing NGCC units, which are simultaneously affected units and 
provide generation that is an element of the BSER itself.
    In addition, we are applying the BSER, as we have done in 
calculating other section 111(d) standards, to a defined population of 
existing affected sources, represented in this case by the generation 
of the source category in the 2012 adjusted baseline. This provides an 
empirical historical baseline against which we define the performance 
rates and their state goal equivalents. In doing so, we must account 
for any offsetting increases in emissions that result from applying the 
BSER control measures, as we have done in setting other standards. For 
example, when determining BSER for particulate matter control, a number 
of pollution control devices (such as sorbent injection technologies) 
themselves create particulate matter. If the particulate matter created 
by these control devices were not appropriately accounted for when 
developing the standard intended to address the primary emissions of 
particulate, this could create an unreasonably stringent PM standard. 
In the current context, this means recognizing that increasing NGCC 
capacity utilization in accordance with building block 2 both offsets 
higher emitting steam generation and increases emissions at the NGCC 
units themselves, which are also affected entities that must 
demonstrate compliance with the BSER. Thus, it is essential that we 
apply the building blocks in a way that avoids creating a level of 
stringency in the performance standards for affected EGUs that goes 
beyond what we have determined to be the BSER--while at the same time 
ensuring that equations apply the building blocks to generate 
performance standards that represent the full application of the BSER 
to the affected EGUs.
    Under section 111, the EPA adopts emission performance standards 
that are based on the BSER. The emission performance rates reflect our 
recognition of the value of giving sources the flexibility to adopt 
equivalent emissions reduction strategies and measures that for them 
may be preferable (in a specific circumstance) to the technologies and 
measures that we define as the BSER. An important function of the 
emission performance rates representing the BSER is to provide the 
flexibility needed to allow alternative compliance options, including 
the development of new technologies or the deployment of effective 
technologies outside of the BSER technologies. In the guidelines we 
issued under section 111(d) for landfill gas, for example, we adopted 
the primary standard based on flaring of any captured landfill gas, but 
we also developed equations that led to an expression of the BSER that 
allowed for the alternative of capturing the gas and combusting it in 
an electrical generating unit.
    Finally, in deriving the emission performance rates, there are a 
number of considerations we took into account. First, it is important 
that the baseline from which the rates are derived be transparent and 
based on observable, historical data. Second, the emission performance 
rates must reflect the emission reductions achievable through the best 
system of emission reduction. Because the BSER includes shifting of 
emissions from higher-emitting to lower-emitting sources, state 
compliance frameworks will likely involve a combination of physical 
measures at the plant (where either rate or generation may be reduced) 
and some form of credit for lower-emitting generation (or demand side 
measures) outside of the plant. In this context, the emission 
performance rates must provide appropriate incentives for affected 
entities to achieve the emission reductions encompassed in the BSER, 
including through state plans that provide crediting for lower-emitting 
generation. Third, and as set forth below, we must account for the 
EPA's determination that pro rata implementation of building block 3 is 
the best reflection of the potential for RE to displace both fossil 
steam and NGCC, and the dual role of NGCC units as both affected 
sources and a BSER compliance technology.
    This set of considerations was central to the development of the 
BSER equations that the EPA describes next. They were particularly 
important for steps five through seven below which address building 
blocks 2 and 3, building blocks that have both significant overlap with 
each other and which impact steam and NGCC units in an integrated way.
Step-by-Step Discussion of Equations
    Step one (compilation of baseline data). On a unit-level basis, the 
EPA obtained total annual quantities of CO2 emissions, net 
generation (MWh), and capacity (MW) from reported 2012 data for likely 
affected EGUs that had commenced operation prior to 2012.\746\ The EPA 
made changes to the historical unit-level data based on comments 
received at proposal. For each state and region, the agency aggregated 
the 2012 operating data for all coal-fired steam EGUs as one group, all 
oil- and gas-fired steam EGUs as a second group, and all NGCC units as 
a third group. The EPA adjusted these state values upwards in

[[Page 64817]]

a limited number of instances to reflect the hydropower and unit outage 
concerns raised in comments and described above. As discussed above, 
the EPA first only aggregated the reported data for units that 
commenced operation prior to 2012. For those likely affected units that 
commenced operation during 2012, the EPA treated that capacity 
consistent with its framework for under construction affected units, 
which were added next. This was done in response to comments 
recognizing the fact that the year during which a unit commences 
operation may not have been representative of its potential generation 
and emissions.
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    \746\ EGUs whose capacity or fossil fuel combustion were 
insufficient to qualify them as likely affected EGUs were not 
included in the subcategory-specific rate and goal computations. 
Most simple cycle combustion turbines (CTs) were excluded on this 
basis at proposal, and all simple cycle CTs were excluded at final 
reflecting changes to the applicability language. IGCC's were 
designated as ``other'' generation at proposal, but they are grouped 
with coal units for purposes the final rule category-specific rates. 
Useful thermal output (UTO) was also translated to a MWh equivalent 
and included in state goals at proposal, resulting in more stringent 
rates for states with more cogeneration sources, but UTO is not 
included in this final rule emission performance rate or state goal 
calculations as a result of comments regarding potentially adverse 
impacts on cogeneration units and uncertainty of thermal load 
outputs. As described in the state plan section of the preamble, 
units may still quantify and convert UTO (i.e., taking credit for 
waste heat capture) when demonstrating compliance. See the 
applicability criteria described in Section IV.D above.
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    For the under construction units (i.e., those under construction 
prior to January 8, 2014 but which had not commenced operation by 
December 31, 2011), the EPA estimated their incremental impact on the 
baseline generation and emissions using their capacity. The EPA assumed 
a 55 percent capacity factor for under construction NGCC units and a 60 
percent capacity factor for under construction fossil steam units, 
which are consistent with the values and methodology the EPA proposed 
for under construction units.\747\ These values are informed by the 
2012 capacity factors for other units in these technology classes that 
recently commenced operation.\748\ Using these capacity factors along 
with the capacity for the units, the EPA estimated an annual baseline 
generation value for these units. The agency then estimated annual 
baseline CO2 emissions for these under construction units 
using the average emission rate of generating units of the same 
technology in the state where the under construction unit is located. 
Where no generators of the same technology existed in a given state, 
the EPA used the national baseline average for that technology. This is 
similar to the adjustment made at proposal for under construction 
units, with the main difference being units that commenced operation in 
2012 are now also treated as under construction for baseline data 
purposes in the final rule.
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    \747\ The EPA notes that we did not identify any under 
construction coal units at proposal, but we are using a methodology 
in this final rule for newly categorized under construction coal 
units similar to our under construction assessment of NGCC at 
proposal.
    \748\ The EPA received comment on the assumed 55 percent 
capacity factor for under construction NGCC EGUs. Some comments 
suggested the value was too large of an estimation for incremental 
generation as some of that 55 percent utilization would have a 
replacement impact on 2012 operating generation. Others suggested it 
should be larger as a particular planned under construction unit was 
anticipated to have a higher utilization rate. The EPA reviewed 
operating patterns of EGUs that came online, and determined a 55 
percent and 60 percent capacity factor assumption for under 
construction NGCC and coal EGUs respectively are a reasonable 
estimate for informing the incremental emissions and generation from 
under construction units. It recognizes that some of these units may 
indeed operate at a higher utilization level, but also recognizes 
that some of the generation may have a replacement effect instead of 
an incremental one.
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    The estimated emissions and generation for under construction units 
were added to the 2012 reported emissions and generation data for the 
affected units that had already commenced operation prior to 2012 to 
derive an adjusted historical baseline total for each state that was 
reflective of all likely affected 111(d) sources.\749\
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    \749\ The EPA received some comments suggesting that under 
construction units should not be included in the quantification of 
BSER and/or rate calculations, and other comments supporting their 
inclusion. The EPA determined that including it was consistent with 
our responsibility under the 111(d) statute to define a Best System 
of Emission Reduction for existing units.
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    Step two (aggregation to the regional level). The EPA took comment 
on applying building blocks at the regional level, and received 
significant comment supporting such an approach. Therefore, whereas the 
proposal aggregated the baseline data to the state level, the final 
rule further aggregated it to the regional level prior to building 
block application. The regions reflect the Eastern, Western, and Texas 
Interconnections. The shift to a regional framework was based on 
comments suggesting that the EPA would better capture the interstate 
impacts of the building blocks and reflect the interconnected nature of 
the electric grid under a regional structure. The basis for the regions 
is defined and discussed in Section V.A.3.
    Step three (identification of source category baseline emission 
rates). As discussed in the beginning of this section, the EPA took a 
technology-specific approach to quantifying guidelines. Therefore, 
whereas the proposal first averaged the fossil steam rate and NGCC rate 
together before applying the building blocks and defining state goals, 
the final rule applied the building blocks at the regional level to 
give a separate fossil steam rate and NGCC rate for each region. The 
starting point for calculating the subcategory-specific emission 
performance rates was the baseline regional emission rates for both 
fossil steam and NGCC in the year 2012 with the modifications discussed 
above.
    Step four (application of building block 1). The baseline 
CO2 emissions amount for the coal-fired steam EGU fleet in 
each region was reduced by 2.1, 2.3, and 4.3 percent in the Western, 
Texas, and Eastern Interconnections respectively, while the coal 
generation level was held constant, reflecting the EPA's assessment of 
the average opportunities in each region to reduce CO2 
emission rates across the existing fleet of coal-fired steam EGUs 
through heat rate improvements that are technically achievable at a 
reasonable cost. The EPA then averaged together the region's baseline 
oil- and natural gas-fired steam rate with its building block 1 
adjusted coal steam rate to get a fossil steam rate post-building block 
1.750 751
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    \750\ Building block 1 analysis acknowledges some variation in 
heat rate improvement potential at different units. The 
implementation of this building block reflects a heat rate 
improvement on average across a region's coal fleet, not necessarily 
a heat rate improvement at every unit.
    \751\ Baseline OG steam emissions are added to adjusted coal 
emissions and divided by baseline OG steam generation and baseline 
coal generation.
---------------------------------------------------------------------------

    Step five (application of building block 3). At proposal, the EPA 
incorporated incremental RE MWhs (where incremental means the amount 
above the adjusted 2012 baseline) by adding them to the denominator of 
the emission rate goal. In response to comments on this approach, the 
EPA issued a NODA discussing an alternative methodology of 
incorporating building block 3 in a manner more analogous to building 
block 2 treatment, where the incremental MWhs identified for the 
building block replace baseline fossil MWhs on a one-to-one basis. The 
EPA is adopting this replacement methodology for building block 3 in 
the final rule consistent with comments noting that such a 
computational procedure better reflects the reduction potential of that 
building block.
    Under this methodology, all of building block 2 incremental NGCC 
potential and part of building block 3 incremental RE potential were 
ultimately applied to replace higher-emitting fossil steam generation 
and emissions, while the remaining building block 3 potential was 
applied to replace NGCC generation and emissions. Commenters noted that 
under this approach building block 3 should be applied first, or the 
EPA would understate the potential of building block 2 by subtracting 
out some NGCC generation after the 75 percent utilization level of NGCC 
had been applied to replace fossil steam. The EPA agrees and calculated 
the building block 3 impacts first in developing the emission 
performance rates.
    To implement this, first, building block 3 replacement potential 
was identified for each region to arrive at a total amount of 
incremental zero-

[[Page 64818]]

emitting generation hours available to replace fossil generation in the 
region. Because renewable generation can replace both fossil steam and 
NGCC on the grid, the EPA determined that it was appropriate to apply 
these incremental zero-emitting generation hours to replace generation 
and associated emissions from each of the fossil steam and NGCC fleets 
in the region on a pro-rata basis in the following manner.\752\ The EPA 
determined the percent of fossil steam generation and the percent of 
NGCC generation of total affected fossil generation in each region's 
baseline. We then assigned those percentages of the incremental zero-
emitting MWhs to each of those technology source categories.\753\ The 
incremental zero-emitting generation assigned to each technology 
replaced the same amount of fossil generation from that technology's 
baseline value.
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    \752\ The EPA took comment on a pro-rata or an intensity-based 
replacement approach. In this final rule, the EPA agrees with 
commenters that a pro-rata approach is a better reflection of the 
BSER. Incremental RE generation has, and is likely to continue, to 
replace both steam and gas turbine generation and the BSER captures 
this through a pro-rata distribution of identified building block 3 
potential.
    \753\ For example, if 100 MWh of incremental zero emitting 
generation is available in a given region and that region had 70 
percent of its affected fossil generation coming from fossil steam 
units in the baseline and 30 percent from NGCC units--then 70 MWhs 
of the incremental zero-emitting generation are applied to baseline 
fossil steam generation and 30 MWhs are applied to baseline NGCC 
generation.
---------------------------------------------------------------------------

    Step six (application of building block 2). If the remaining 
generation level for the NGCC fleet in a region, taking into account 
the previous step's replacement of NGCC generation, was less than 75 
percent of the fleet's potential summertime generating capacity (the 
potential capacity factor the EPA determined to represent the BSER), 
then the NGCC generation in the region was assumed to increase to 
levels equal to the lesser of (1) its potential at a 75 percent 
capacity factor \754\ or (2) a generation level above which there is no 
longer fossil steam generation remaining within the same region to 
replace. In other words, the regional NGCC capacity factor was only 
assumed to reach 75 percent if there was sufficient higher-emitting 
fossil steam generation that it could replace after step five. The 
increase in NGCC generation at this step compared to the post-building 
block 3 level was matched by an equal decrease in fossil steam 
generation reflecting the 1 for 1 MWh hour replacement. At this point, 
the generation for both steam and NGCC reflect the final distribution 
of generation between the subcategories after application of the 
building blocks. But the emission performance rates must account for 
CO2 emissions and generation from incremental gas and 
renewable generation that comprise building blocks 2 and 3, to reflect 
and enable the emission reductions achievable under the best system of 
emission reduction, and ensure that the shared implementation of the 
BSER by steam and NGCC generation is reflected in the rates.
---------------------------------------------------------------------------

    \754\ In early years, will be less than 75 percent due to 
building block 2 gradual deployment.
---------------------------------------------------------------------------

    Step seven (accounting for and facilitating the emission reductions 
achievable through the implementation of the best system of emission 
reduction).
    This step quantifies the aggregate emission changes associated with 
the emission rate improvement and generation replacement patterns 
described in steps four, five, and six to arrive at an adjusted fossil 
steam emission rate and an adjusted NGCC emission rate for each region 
that will, as discussed above, (1) enable the implementation of all 
three building blocks, (2) be based on observable, concrete baselines, 
and (3) reflect the BSER.
    First, in developing the emission performance rates, the EPA had to 
answer the question of how to reflect the building blocks in the 
equations defining the rates in a manner that would enable the 
generation shifts that are essential components of the BSER. In the 
case of building block 3, the EPA accomplished this by incorporating 
the pro rata share of incremental (above baseline) zero emitting 
generation into the emission rates for each group of affected EGUs, 
thus ensuring that these EGUs would have to include a corresponding 
amount of zero-emitting generation in their compliance calculations, 
either through the acquisition of credits or through some other 
mechanism as determined by their state in its implementation plan.
    For building block 2, a similar mechanism is needed. Accordingly, a 
portion of the NGCC generation and emissions used to replace fossil 
steam must be averaged into the steam rate, analogous to what was done 
with building block 3. The EPA considered two approaches to define the 
quantity of NGCC generation and emissions to be averaged into the steam 
rate: (1) Incremental NGCC generation after the implementation of 
building block 3 and (2) incremental NGCC generation from baseline 
levels. For the reasons below, the EPA has determined that the second 
approach better reflects the considerations discussed above.
    As discussed above, it is beneficial that the baseline from which 
emission performance rates are derived be transparent and based on 
observable historical data. The first approach, however, depends on the 
level of incremental NGCC generation relative to what is available 
after the implementation of building block 3. This level of NGCC 
generation (obtained after replacing baseline levels of generation with 
NGCC's pro rata share of incremental RE generation) only exists as an 
intermediate step in the BSER calculation. It is not based on an 
observable or concrete level of generation.
    In Section VIII we discuss methods for creating ERCs for 
implementing shifting of generation from steam to NGCC, and this 
discussion illustrates the value of relying on an observable and 
concrete baseline. In that section we suggest that incentivizing and 
facilitating the purchase of ERCs as a compliance option for steam 
units could be implemented through the use of a factor that creates a 
fraction of an allowable credit for each hour that an NGCC operates. 
This factor is derived from the incremental generation of NGCC post-
building block 2, relative to the baseline. While a different factor 
could be derived from the hypothetical intermediate level resulting 
from the pro rata application of zero emitting generation to NGCC in 
building block 3 (by transferring the full amount of NGCC emissions and 
generation replacing steam generation in building block 2), the EPA 
believes that grounding baselines in historical data (such as those 
used to derive the 2012 baseline) is both more transparent and easier 
to understand in a way that is more useful to states and utilities, in 
contrast to the practical challenges of relying on a calculated level 
that corresponds to an interim step within the emission performance 
rate calculation. As long as the crediting framework for creating ERCs 
is consistent with the amount of gas emissions and generation that is 
transferred to the coal rate, either the chosen option or the option of 
transferring the entire quantity of gas emissions and generation that 
occurred in step six to the coal rate would provide an incentive for 
the power market to implement the shift in generation from coal to 
gas.\755\
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    \755\ The EPA recognizes that real world market dynamics will 
necessarily differ from the BSER assumptions, and has designed the 
emission guidelines to provide flexibility beyond the emission 
reduction opportunities identified in the BSER. The essential 
criteria, however, are that the emission rates and crediting 
framework are consistent with the BSER and provide the incentives 
needed to facilitate the emission reduction measures reflected in 
the BSER and together produce an achievable compliance framework for 
sources.

---------------------------------------------------------------------------

[[Page 64819]]

    Also as discussed above, it is important that the compliance 
equations reflect the BSER pro rata allocation of RE to fossil steam 
and NGCC generation. The first approach to define the quantity of NGCC 
generation and emission to be averaged into the steam rate would 
require the steam rate to take into account the total additional NGCC 
generation that results from the application of building block 3 before 
building block 2 has been applied. This approach would reflect in the 
compliance rate for steam units a greater share of the implementation 
of building block 3. Ensuring that emission performance rates for both 
steam and gas units reflect the emission reduction potential of 
building block 3 is integral to the building block 3 methodology and 
also recognizes that application of building block 3 on a pro-rata 
basis was intended to achieve emission reductions from both NGCC and 
fossil steam commensurate with their emissions reduction opportunities.
    If the EPA were to use the increment of NGCC emissions and 
generation derived at the intermediary step after the application of 
building block 3, rather than the increment relative to the 2012 
baseline, the effect would be to largely assign to fossil steam the 
building block 3 generation shift apportioned to NGCC. That, in turn, 
would have undermined the fact that building block 3 was determined to 
be a BSER measure applicable to the entire source category, comprising 
NGCC as well as fossil steam, and would have conflicted with the 
preceding steps we are taking to develop the equations. Instead, by 
using only the incremental NGCC generation relative to the baseline, 
the EPA has ensured that the logic behind the pro rata displacement of 
fossil generation by RE generation is reflected in the emission rates. 
Having established the appropriate way to measure the amount of 
incremental gas generation placed in the fossil steam rate, the EPA is 
able to calculate the subcategory-specific emission performance rates. 
For the numerator of the fossil steam rate, the EPA multiplied the 
remaining fossil steam generation (post-step six) by the fossil steam 
rate reflecting the heat rate improvement from building block 1 (step 
four). We then added in the emissions associated with the incremental 
NGCC generation from step six by multiplying the incremental NGCC 
generation as discussed above (difference between the baseline NGCC 
generation level and post-step six NGCC generation) by the baseline 
NGCC rate for that region.\756\ This constitutes the numerator of the 
fossil steam emission rate.
---------------------------------------------------------------------------

    \756\ See CO2 Emission Performance Rate and Goal 
Computation TSD for CPP Final Rule for an illustration of this step. 
The EPA defined the ``incremental NGCC generation'' in this step in 
a manner consistent with its measurement and use described in 
section VIII of this preamble.
---------------------------------------------------------------------------

    For the fossil steam denominator, the EPA added the remaining 
fossil steam generation (post-step six), the incremental NGCC 
generation defined above, and the amount of zero emitting building 
block 3 MWhs apportioned to fossil steam generation in the region (step 
five). Dividing the fossil steam numerator described above by this 
fossil steam denominator resulted in a regional adjusted fossil steam 
rate reflecting the three building blocks.
    For the NGCC performance rate, the EPA calculated a numerator in a 
similar manner. First, we took the remaining NGCC generation (post step 
six) and multiplied it by the regional baseline NGCC rate to calculate 
the total emissions in the numerator. For the denominator, the EPA 
added the remaining NGCC generation (post step six) to the amount of 
zero-emitting building block 3 generation assigned to that technology 
in step five. Dividing the emissions by this total generation value 
(inclusive of the RE generation apportioned to NGCC) provided a 
regional adjusted NGCC rate.\757\
---------------------------------------------------------------------------

    \757\ See CO2 Emission Performance Rate and Goal 
Computation TSD for CPP Final Rule for an illustration of this step. 
We note that the entire NGCC generation level (inclusive of the 
amount assigned to the fossil steam rate) expected post building 
block application is included in the NGCC rate calculation. 
Including the entire NGCC generation in the NGCC rate recognizes the 
simultaneous compliance responsibility of affected NGCC units while 
the fossil steam rate recognizes its mitigation potential through 
incorporation of the incremental NGCC generation component. Failing 
to do so would result in a NGCC rate lower than that expected after 
full implementation of the building blocks and create a compliance 
inconsistency when reporting all generation.
---------------------------------------------------------------------------

    Step eight (determining the nationwide subcategory-specific 
emission performance rate).
    Following step seven, we evaluated the resulting adjusted fossil 
steam rates and NGCC rates for each region and identified the highest 
(least stringent) emission rate among the three regions for each 
technology category. This becomes the nationwide emission performance 
rate for that technology class. This ensures that the same rates are 
applied to facilities in each region and that these rates are 
achievable by facilities in all three regions.
    Finally, the EPA repeated steps four through eight for each year 
2022-2030.\758\ The resulting annual rates vary because the amount of 
building block 2 and 3 potential in each year varies. The rates for 
years 2022-2029 were averaged together to calculate an interim rate, 
and the 2030 value becomes the final emission performance rate for that 
year forward. As described in the corresponding TSD, the EPA rounded 
the interim and final subcategory-specific emission performance rates 
up to the nearest integer to ensure that they did not slightly 
overstate BSER potential through use of conventional rounding. Unless 
otherwise stated, conventional rounding is used elsewhere during the 
calculation process.
---------------------------------------------------------------------------

    \758\ At proposal, the EPA repeated this step over a 10 year 
period. The building blocks and corresponding BSER emission rates 
increased for ten consecutive years (2020-2029) in the EPA's rate 
calculation. In this final rule, the EPA has maintained the same 
2030 compliance period for final rates but adjusted the start date 
to 2022 based on comments. Therefore, the deployment of building 
blocks is spread over a nine year period (2022-2030) instead of the 
proposed 10 year period.
---------------------------------------------------------------------------

    It bears emphasis that the procedure described above was used only 
to determine emission performance rates, and the particular data inputs 
used in the procedure are not intended to represent specific 
requirements that would apply to any individual EGU or to the 
collection of EGUs in any state. The specific requirements applicable 
to individual EGUs, to the EGUs in a given state collectively, or to 
other affected entities in the state, would be based on the emission 
standards established through that state's plan. The details of how 
states could demonstrate compliance with the emission performance rates 
or statewide goals through different state plan approaches that 
recognize emission reductions achieved through all the building blocks 
are discussed further in section VIII on state plans.
    Finally, the procedures and assumptions in the equation to 
calculate emission performance rates are not intended to reflect a 
compliance scenario in a future year, but rather reflect a 
representative year in which the building blocks are applied. The power 
sector fleet will continue to turn over, and in some cases has already 
experienced turnover beyond the baseline period. However, while the 
system's fleet may change, the EPA believes this turnover will only 
further promote the feasibility of the emission performance rates. 
Fleet turnover has trended towards, and is expected to continue to 
trend towards, lower-emitting generation sources that will make 
reductions more readily available.

[[Page 64820]]

VII. State-Specific CO2 Goals

A. Overview

    In section VI of this preamble, the EPA provides the methodology 
for computing subcategory-specific CO2 emission performance 
rates, based on the BSER. The subcategory-specific CO2 
emission performance rates are the quantitative expression of the BSER 
as determined by the EPA. In this section, we provide state rate-based 
goals and mass-based goals that can be used in the alternative, by 
states, as an equivalent quantitative expression of the BSER in 
establishing standards of performance for affected EGUs in state plans. 
In this section, the EPA also describes reasons for providing state-
specific rate-based goals and mass-based goals equivalent to the 
emission performance rates, supported by the many requests from 
commenters for the provision of these alternative expressions of the 
BSER established by the EPA. We further ensure this equivalence, and 
therefore reflection of the BSER, by requiring that rate-based state 
goals and mass-based state goals fully implement the BSER, including by 
ensuring that affected EGUs operating under mass-based emission 
standards are not incented by dint of the mass-emissions constraint to 
shift generation to unaffected fossil fuel-fired sources to an extent 
that deviates from, or negates, the implementation of the BSER.
    The EPA is reconstituting the emission performance rates discussed 
in section VI into statewide CO2 emission performance goals 
for each state for the purpose of facilitating states' development of 
state plans encompassing maximum flexibilities in implementing the 
BSER. This state-specific goal is not a compliance requirement, but 
rather an alternative yet equivalent expression of the BSER that the 
state may choose to use to establish emission standards for its 
affected EGUs. The state goal is the equivalent of the technology-
specific CO2 emission performance rates and represents the 
equivalent of the state's applying the emission performance rates 
directly to its affected EGUs in the form of standards of performance. 
As discussed further in section VIII on state plans, the states are 
charged with setting emission standards for the affected EGUs in their 
respective jurisdictions such that the affected EGUs operating under 
those standards together satisfy the requirements of the final emission 
guidelines and statute by meeting the emission performance rates or 
equivalent statewide emission performance goals, and thereby meet 
emission standards that reflect the BSER.
    In the June 2014 proposal, the EPA proposed a set of state-specific 
emission rate-based CO2 goals (in lbs of CO2 per 
MWh of electricity generated). In addition, the EPA proposed emission 
rate-based CO2 goals for areas of Indian country and U.S. 
territories with affected EGUs in a supplemental proposal on November 
4, 2014. To provide flexibility to states, territories, tribes and 
implementing authorities, the proposals authorized each implementing 
authority to translate the form of the goal to a mass-based form (i.e., 
goals expressed in terms of total tons of CO2 per year from 
affected EGUs), as long as the translated goal was equivalent to the 
rate-based goal. Upon issuance of the proposed rule, the EPA continued 
the extensive outreach effort to stakeholders and members of the public 
that the EPA had engaged in for many months preceding the proposal. We 
also issued a notice of data availability (79 FR 67406, November 13, 
2014) and technical support document (Docket ID: EPA-HQ-OAR-2013-0602-
22187) to further clarify potential methods for the translation to a 
mass-based equivalent. The outreach provided additional opportunities 
for all jurisdictions with affected EGUs--both individually and in 
regional groups--as well as numerous industry groups and non-
governmental organizations, to meet with the EPA and ask clarifying 
questions about, and give initial reactions to, the proposed 
components, requirements and timing of the rulemaking. As a result of 
the outreach and notice of data availability, the EPA received informed 
substantive comments for the EPA to consider for the final rule.
    Numerous commenters encouraged and supported the EPA's efforts to 
allow states the maximum possible degree of flexibility in developing 
plans for their affected EGUs, either as a mass-based or rate-based 
CO2 goal. States and other stakeholders supported the option 
to translate rate-based goals to mass-based goals for state plans and 
requested a simple and transparent method for determining mass-based 
statewide CO2 goals that are equivalent to statewide rate-
based CO2 goals and thus reflective of the BSER. We received 
substantial comments on the potential methodologies for the translation 
of rate-based goals to mass-based goals. Several commenters requested 
that the EPA provide the translation to a statewide mass-based goals 
directly while others requested flexibility to translate to mass using 
a variety of methodologies and tools. In the context of these comments, 
the EPA has considered the appropriateness of rate-based and mass-based 
goals as an expression of BSER and their equivalence to the 
quantitative expression of BSER through the two CO2 emission 
performance rates.
    Based on the comments received, the EPA is providing a 
straightforward translation methodology from the CO2 
emission performance rates to yield statewide rate-based and mass-based 
CO2 emission performance goals described in this section. 
The EPA is providing state mass-based goals in this final rule in place 
of having states determine the mass themselves. The mass-based goals 
are the result of a mathematical derivation that provides goals that 
are an equivalent expression of the BSER. Section VIII below discusses 
mechanisms for states to plan for and demonstrate achievement of the 
statewide CO2 emission performance goals.
    CAA section 111(d) requires states to submit a plan that 
establishes standards of performance for affected EGUs that implement 
the BSER. States meet the statutory requirements of CAA section 111(d) 
and the requirements of the final emission guidelines by submitting 
emission standards for affected EGUs that meet the performance rates, 
which reflect the application of the BSER as determined by the EPA. 
Therefore, as a first step for states that choose to submit plans that 
meet the rate-based or mass-based goals, the goals must be determined 
to have equivalence as an application of the BSER. For the rate-based 
and mass-based state goals provided here, this equivalence is evident 
in the mathematical derivation of the goals, as is described in 
sections VII.B and VII.C below.
    Further (as described in section VIII.J), the state plan must 
demonstrate that it has measures in place to ensure that any 
alternative to the performance rates (i.e., rate-based or mass-based 
state goals that it uses to establish standards of performance) does 
not result in affected EGUs' failing to implement either the BSER 
measure themselves or alternative methods of compliance with emission 
standards that achieve equivalent reductions in emissions or carbon 
intensity. The EPA has identified one way in which affected EGUs could 
fail to meet, at a minimum, of the emission performance levels that 
would result from implementing the BSER, which state plans must do.
    Specifically, the EPA has determined that the three building blocks 
are the BSER, including shifting generation from an affected EGU to a 
lower-emitting affected EGU or to a non-

[[Page 64821]]

emitting EGU and that states are required to establish standards of 
performance that require affected EGUs to achieve, at a minimum, the 
emission performance levels that reflect the BSER (recognizing that 
affected sources may choose from a range of equivalent actions (e.g., 
undertaking the measures included in the building blocks, shifting 
generation to low-emitting or zero-emitting resources not included in 
the building blocks or achieving demand-side EE or transmission 
efficiency--either through operational undertakings, direct investment 
or emissions trading). Substantial shifting of generation from affected 
EGUs to new fossil fuel-fired EGUs, such as new NGCC units, represents 
a deviation from implementing the BSER or its compliance equivalent.
    Since the two subcategory-specific emission performance rates 
represent the BSER, states that established standards of performance at 
or below those rates, by definition, would be implementing state plans 
that created no risk that affected EGUs would shift generation to new 
fossil-fired EGUs to an extent that would deviate from the BSER. 
Similarly, the EPA has determined that states using rate-based goals as 
the foundation for plans implementing the BSER are unlikely to foster 
generation shifts to new fossil fuel-fired sources to an extent that 
would deviate from the BSER. In contrast, however, EPA analysis has 
identified a concern that a mass-based state plan that failed to 
include appropriate measures to address leakage could result in failure 
to achieve emission performance levels consistent with the BSER.\759\ 
Section VII.B describes how the form of the rate-based state goals 
minimizes the risk of generation shifts to new fossil fuel-fired 
sources, or ``leakage,'' by providing affected EGUs with a sufficient 
incentive to run, similar to the performance rates. Section VII.D. 
discusses how there is a potential for leakage under mass-based state 
goals because affected EGUs are incented to operate in a manner--in 
particular, by shifting generation to new NGCC units (as opposed to 
shifting generation as contemplated by the BSER or undertaking 
equivalent alternative compliance actions)--that would result in 
negating the equivalence with the emission performance rates and thus 
the BSER, and specifies that requirements are needed in mass-based 
implementation to assure those incentives are realigned.\760\
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    \759\ See Chapter 3 of the Regulatory Impact Analysis for more 
information on this analysis, which is available in the docket.
    \760\ The specific mass-based plan requirements are explained in 
detail in section VIII.J.
---------------------------------------------------------------------------

B. Reconstituting Statewide Rate-Based CO2 Emission Performance Goals 
From the Subcategory-Specific Emission Performance Rates

    In order to provide states flexibility for planning purposes, the 
EPA is providing a state-specific averaging of the subcategory-specific 
emission performance rates to determine a statewide goal. While the 
emission performance rates reflect the quantification of performance 
based on the BSER and embody the reductions estimated under building 
blocks 1, 2, and 3, the state goals reflect an equivalent approach 
through which states may choose to adopt and implement those 
subcategory-specific performance rates.
    The EPA quantified the potential reductions of the BSER in the 
subcategory-specific emission performance rates established in section 
VI. These rates themselves reflect the reduction potential expected in 
emission rates under the BSER for each year from 2022 to 2030. To 
establish state goals, the EPA applied these rates to the baseline 
generation levels to estimate the affected fleet emission rate that 
would occur if all affected EGUs in the fleet met the subcategory-
specific rates. This step respects the flexibility of sources to meet 
the rates in any manner that they see fit (e.g., on-site abatement 
technology, fuel switching, co-firing, credit purchase, etc.), and does 
not limit them to their building block assumptions. For example, the 
EPA derived the statewide rate-based CO2 emission 
performance goals for 2030 by multiplying the fossil steam emission 
performance rate for 2030 by the baseline fossil steam generation in a 
state and multiplying the NGCC emission performance rate for 2030 by 
the baseline NGCC generation in a state. The resulting emissions for 
fossil steam and NGCC are then added together for each state. This 
emission total is divided by that state's baseline generation values 
from the likely affected EGUs in order to develop a state's rate-based 
CO2 emission performance goal for 2030. This blended rate 
reflects the collective emission rate a state may expect to achieve 
when its baseline fleet of likely affected EGUs continues to operate at 
baseline levels while meeting its subcategory-specific emission 
performance rates reflecting the BSER. The EPA believes that using the 
adjusted 2012 baseline is the most appropriate way to combine the 
rates. First, as explained in Section VI, the EPA believes there are 
significant advantages to using real world data to set a baseline 
rather than using projected data. The adjusted 2012 data is the logical 
starting point because it is the data that all of the emission 
performance rates (discussed in Section VI) are based upon. 
Furthermore, it is clear that generation shifts as projected under the 
BSER are not the appropriate baseline. The emission performance rates 
already factor in the BSER assumptions about changes in generation 
(e.g., implementation of building block 2 significantly lowers the 
emission performance rate for fossil-steam units). If, on top of that, 
changes in generation were factored into the calculation of a combined 
rate, those changes in generation would be factored into the combined 
rate twice (once when calculating the individual emission performance 
rates and a second time, when incorporating those rates into a combined 
state rate).
    This step is repeated for each year from 2022-2029 using the 
emission performance rates calculated for each of those years in the 
previous section. The EPA also repeats this step for the interim state 
goal using the interim subcategory rates. The EPA then averages 
together the annual amounts in increments of 3 years, 3 years, and 2 
years for 2022-2024, 2025-2027, and 2028-2029 to estimate emission rate 
averages for those periods that can provide one illustrative pathway 
for states to consider in meeting their interim goals. These 3- and 2-
year increment are not regulatory guidelines or equivalents for interim 
goals, but rather benchmarks for demonstrating plan performance as 
discussed in Section VIII.F illustrative of a potential gradual 
reduction compliance strategy that states may use to reach their 
interim and final state goals.
    As described in the steps above, the statewide goals represent an 
equivalent arithmetic combination of the subcategory-specific emission 
performance rates, weighted by the historical baseline generation 
levels upon which the BSER is premised. In particular, as discussed 
above, the method for deriving these goals assures equivalent 
flexibility by applying the CO2 emission performance rates 
to the baseline levels, which respects the flexibility of affected EGUs 
to meet the rates in whatever way they wish. This corresponding 
treatment of affected EGUs based on the adjusted 2012 baseline ensures 
sufficient incentive to affected existing EGUs to generate and thus 
avoid leakage, similar to the CO2

[[Page 64822]]

emission performance rates (this is further discussed in section VII.D 
below). Consequently, the statewide goals are equivalent to the 
CO2 emission performance rates and are thus an equivalent 
expression of the BSER. The rate-based statewide goals are provided 
below in Table 12.

C. Quantifying Mass-Based CO2 Emission Performance Goals From the 
Statewide Rate-Based CO2 Emission Performance Goals

    The EPA is also establishing mass-based statewide CO2 
emission performance goals for each state, which are provided below in 
Table 13. For state plans choosing to meet a mass-based goal, such a 
goal must be equivalent to the CO2 emission performance 
rates in their application of the BSER, as required by the statute and 
the final emission guidelines. In the following discussion we describe 
the mathematical calculations that provide an equivalent expression of 
the BSER. In evaluating the equivalence of the form of mass goals, the 
EPA must also recognize the impact that the form of the standard has on 
the relative incentives that the implementation of these goals provides 
to affected and unaffected EGUs. This section specifies how we have 
established a quantitative basis for mass goals that is equivalent to 
CO2 emission performance rates. The next section (section 
VII.D) specifies how we require state plans to ensure equivalence to 
the CO2 emission performance rates through certain 
requirements that realign the potential difference in incentives 
provided to affected and unaffected EGUs to generate under a mass-based 
implementation compared to a rate-based implementation that could 
result in leakage.
    The starting place for quantifying mass-based statewide 
CO2 emission performance goals is the emission amounts 
directly represented in the numerator of the statewide rate-based 
CO2 emission performance goals. Each state-specific emission 
amount is the product of the fossil steam emission performance rate and 
historical fossil steam generation, added to the product of the NGCC 
emission performance rate and historical NGCC generation. The resulting 
emission amounts for each state represent the emissions associated with 
rate-based compliance at historical generation levels.
    However, under a rate-based state plan, all affected EGUs have the 
opportunity to increase utilization, provided that sufficient emission 
reduction measures are available to maintain the necessary ratio of 
emissions to generation as quantified by the subcategory-specific 
emission performance rates. Due to the nature of the emission 
performance rate methodology, which selects the highest of the three 
interconnection-based values for each source category as the 
CO2 emission performance rate, there are cost-effective 
lower-emitting generation opportunities quantified under the building 
blocks that are not necessary for affected EGUs in the Western and 
Texas interconnections to demonstrate compliance at historical 
generation levels. The EPA recognizes that these lower-emitting 
generation opportunities are available to affected EGUs at a national 
level as a means to increase their own output (and, as a result, their 
own emissions) while maintaining the relevant emission performance 
rate. To afford affected EGUs subject to a mass-based goal similar 
compliance flexibility as EGUs subject to a rate-based goal, the EPA 
has quantified the emissions associated with the potential realization 
of these lower-emitting generation opportunities and incorporated those 
additional tons into each state's mass-based goal.\761\ Because the 
derivation of these mass-based goals respects the arithmetic of the 
subcategory-specific emission performance rates and the flexibility of 
affected EGUs to achieve those rates while utilizing up to the full 
potential quantified in the building blocks, the derivation of these 
mass-based state goals offers an equivalent expression of BSER in mass 
form.
---------------------------------------------------------------------------

    \761\ For more detail on this methodology, please refer to the 
CO2 Emission Performance Rate and Goal Computation TSD 
for CPP Final Rule, which is available in the docket.
---------------------------------------------------------------------------

    The mass goals for existing sources are presented in Table 13. 
Although their derivation is equivalent to the subcategory-specific 
emission performance rates, in order to maintain this equivalence in 
the establishment of emission standards in state plans mass goals must 
be implemented in combination with requirements that align the 
incentives provided to affected and unaffected EGUs, specifically in 
order to prevent leakage.

D. Addressing Potential Leakage in Determining the Equivalence of 
State-Specific CO2 Emission Performance Goals

    As described in section VI, the subcategory-specific emission 
performance rates reflect the BSER as determined by the EPA. This final 
rule allows states to establish emission standards that meet either 
rate-based or mass-based state goals. As stated above, rate-based state 
goals were published in the proposed rule, and commenters not only 
supported having the flexibility to use rate-based goals or mass-based 
goals as part of state plans, but also requested that the EPA include 
mass-based goals in this final rule. But to ensure the equivalence of 
mass-based state goals, we must consider how the form of the goal 
affects its implementation and how the incentives it provides to 
affected EGUs on the interstate grid affect whether or not the BSER is 
fully implemented.
    Because of the integrated nature of the utility power sector, the 
form of the emission performance requirements for existing sources may 
ultimately impact the relative incentives to generate and emit at 
affected EGUs as opposed to shifting generation to new sources, with 
potential implications for whether a given set of standards of 
performance is, at a minimum, consistent with the BSER, in the context 
of overall emissions from the sector. In this context, we, again, 
define as ``leakage'' the potential of an alternative form of 
implementation of the BSER (e.g., the rate-based and mass-based state 
goals) to create a larger incentive for affected EGUs to shift 
generation to new fossil fuel-fired EGUs relative to what would occur 
when the implementation of the BSER took the form of standards of 
performance incorporating the subcategory-specific emission performance 
rates representing the BSER. In the proposal, the EPA recognized that 
the statutory construction regarding the BSER is to reduce emissions, 
which can be achieved through shifts of generation. Movement of 
generation between and among sources is needed to produce overall 
reductions, particularly movement from higher-emitting affected EGUs to 
lower-emitting affected EGUs, and from all affected EGUs to zero-
emitting RE. In all of these cases, the fossil sources involved in 
these generation shifts are subject to obligations under this final 
rule.\762\
---------------------------------------------------------------------------

    \762\ The final rule includes state plan conditions to prevent 
perverse incentives that could otherwise result in greater overall 
emissions when generation shifts across affected EGUs. For example, 
states that wish to engage in rate-based trading through an emission 
standards plan type must adopt plans designed to achieve either a 
common rate-based state goal or the subcategory-specific emission 
performance rates (see section VIII.L). Such a state plan condition 
avoids encouraging generation to shift from a state with a 
relatively lower state goal to a state with a relatively higher 
state goal solely as a response to the form of CPP implementation.
---------------------------------------------------------------------------

    However, leakage, where shifts in generation to unaffected fossil 
fuel-fired sources result in increased emissions, relative to what 
would have happened

[[Page 64823]]

had generation shifts consistent with the BSER occurred, is contrary to 
this construction. Therefore, if the form of the standard does not 
address leakage or incents the kinds of generation shifts that we 
identify as leakage, the states must otherwise address leakage in order 
to ensure that the standards of performance applied to the affected 
EGUs are, in the aggregate, at least equivalent with the emission 
performance rates, and therefore appropriately reflect the BSER as 
required by the statute. Commenters noted that shifting generation and 
emissions from existing sources to new sources undermined the intent of 
this rule and the overall emission reduction goals, and that requiring 
states to address leakage is consistent with the obligation that states 
establish standards of performance that, in the aggregate, at a 
minimum, reflect the BSER for affected EGUs operating in the 
interconnected electricity sector.
    This section specifically addresses the need for state plans 
designed to achieve either rate- or mass-based state goals to ensure 
that their plans succeed in implementing standards of performance that 
reflect the BSER by minimizing the difference in incentives provided to 
affected EGUs and new sources to generate in order to maintain 
equivalent emission performance with the CO2 emission 
performance rates.
    Rate-based goals do not in our view implicate leakage to an extent 
that would negate or limit the implementation of the BSER because under 
a rate-based state goal, similar to the subcategory-specific emission 
performance rates, existing lower-emitting affected EGUs, primarily 
NGCC units, are incentivized to increase their utilization in order to 
improve the average emission rates of affected EGUs overall. New units 
that are not subject to the rate-based state goal, and that are not an 
allowable measure for adjusting an EGU's CO2 emission rate, 
will not have this incentive to increase utilization, and as a result, 
the imposition of a rate-based goal on affected EGUs is unlikely to 
encourage increased generation and emissions from unaffected new EGUs. 
The form of the rate-based state goals provides an equivalent or 
greater incentive to affected existing EGUs as they are provided in the 
CO2 emission performance rates, and similarly avoid the 
potential for leakage. Under both approaches, existing NGCC units can 
generate ERCs. These ERCs provide an economic incentive to utilize 
existing NGCC units rather than new NGCC units. Further, ERCs from 
incremental RE incentivize new renewable generation over new NGCC 
generation. Both of these features, which exist in the context of 
implementation with a state rate-based goal or CO2 emission 
performance rates, provide significant incentives to ensure that, 
consistent with the BSER, shifting of generation does not occur between 
existing fossil fuel-fired units and new NGCC units.
    Mass-based goals for existing sources, however, incur a leakage 
risk to the extent that they incent generation shifts from affected 
EGUs to unaffected fossil fuel-fired sources in a way that negates the 
reliance on the BSER. In contrast to various forms of rate-based 
implementation, mass-based implementation in a state plan can 
unintentionally incentivize increased generation from unaffected new 
EGUs as a substitute action for reducing emissions at units subject to 
the existing source mass goal in ways that would negate the 
implementation of the BSER and would result in increased emissions. 
This occurs because, unlike in a rate-based system where rate-based 
averaging lowers the cost of generation from existing NGCC units 
relative to generation from new NGCC units, in a mass-based system the 
allowance price increases the cost of generation from existing NGCC 
units relative to generation from new NGCC units. The extent to which 
electricity providers opt to rely on this increase in unaffected new 
source utilization as a substitute for improving the emissions 
performance across existing sources would be fundamentally inconsistent 
with relying on the BSER to reduce emissions as the basis of the 
subcategory-specific emission performance rates.
    As a result, notwithstanding the fact that mass goals for existing 
sources are quantified in a way that is an equivalent expression of the 
BSER, the form of mass goals is only equivalent if leakage is 
satisfactorily addressed in the state plan's establishment of emission 
standards and implementation measures. The EPA is therefore requiring 
that states adopting a mass-based state plan include requirements that 
address leakage, or otherwise provide additional justification that 
leakage would not occur under the state's implementation of mass-based 
emission standards. This requirement enables states to establish 
standards of performance that meet a mass-based goal equivalent to the 
performance rates and therefore reflect the BSER, as required by 
section 111(d). The required demonstration and options for state plans 
to minimize leakage are discussed in detail in section VIII.J of this 
preamble.
    Further supporting the need for this requirement, the EPA has 
evaluated the mass goals in concert with some of the options to 
minimize leakage described in that section. As mentioned above, the EPA 
analysis identified a concern regarding leakage in a mass-based 
approach, namely that the mass-based implementation without measures to 
address leakage produced higher generation from new NGCC units and 
lower emission performance when compared to a rate-based 
implementation. Further analysis where implementation of the mass-based 
goals was coupled with measures to address leakage produce utility 
power sector emissions performance that is similar to emissions 
performance under the rate goals.\763\
---------------------------------------------------------------------------

    \763\ See Chapter 3 of the Regulatory Impact Analysis for more 
information on this analysis, which is available in the docket.
---------------------------------------------------------------------------

E. State Plan Adjustments of State Goals

    The EPA notes that it is the emission performance rates in section 
VI that constitute the application of the BSER to the affected EGUs and 
serve as the chief regulatory requirement of this rulemaking. The 
statewide CO2 rate-based and mass-based emission performance 
goals provided here are metrics that states may choose to adopt when 
demonstrating compliance at the state level, and states may consider 
these goals when determining how to set unit-level compliance 
requirements. The EPA believes that the regional nature of determining 
the emission performance rates encompasses a large population size and 
makes it robust against unit-level variation and unit-level inventory 
discrepancies. The EPA does acknowledge that state-level rate-based 
goals or mass-based goals may be sensitive to applicability changes 
within a state's affected population. In the proposal, the EPA used a 
baseline that aggregated data for what it believed to be affected units 
and asked states, companies and other stakeholders to provide 
corrections in their comments. We received input from many commenters 
and have corrected information as appropriate. Therefore, we believe 
the baseline to be accurate. However, if subsequent applicability 
review or formal applicability determinations change the status of 
units in regards to being affected or unaffected by this rulemaking, 
states can, via state plan submittal or revision, adjust their 
statewide rate or mass goal to reflect this change of status.
    This adjustment flexibility provision is based on comments received 
at proposal. For example, some

[[Page 64824]]

stakeholders noted that the affected status of particular units was 
unclear. The EPA recognizes that all the necessary data to determine 
the affected status of some units may not be available at this time. As 
stated above, the EPA does not believe unit-level variation or 
inclusion/exclusion disparities between baseline inventory and affected 
units will impact the regionally determined emission performance rates 
discussed in the previous section. However, variations in baseline data 
or inventory may have an impact on the state-level rate-based or mass-
based goals provided in this section. Therefore, the EPA is allowing 
the flexibility for states to demonstrate the need for this type of 
adjustment under the justifications above and utilize an adjusted value 
for compliance purposes when submitting or revising its state plan. The 
EPA will evaluate the appropriateness of such an adjusted value based 
on the state's demonstration and evaluate the approvability of a plan 
or plan revision accordingly.
    Rate-based statewide CO2 emission performance goals are 
listed below in Table 12. Mass-based statewide CO2 emission 
performance goals are found in Table 13.
---------------------------------------------------------------------------

    \764\ The EPA has not developed statewide rate-based or mass-
based CO2 emission performance goals for Vermont and the 
District of Columbia because current information indicates those 
jurisdictions have no affected EGUs.

                                           Table 12--Statewide \764\ Rate-Based CO2 Emission Performance Goals
                          [Adjusted output-weighted-average pounds of CO2 per net MWh from all affected fossil fuel-fired EGUs]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                             Interim goal--     Interim goal--     Interim goal--
                        State name                               Step 1             Step 2             Step 3          Interim goal        Final goal
--------------------------------------------------------------------------------------------------------------------------------------------------------
Alabama..................................................              1,244              1,133              1,060              1,157              1,018
Arizona *................................................              1,263              1,149              1,074              1,173              1,031
Arkansas.................................................              1,411              1,276              1,185              1,304              1,130
California...............................................                961                890                848                907                828
Colorado.................................................              1,476              1,332              1,233              1,362              1,174
Connecticut..............................................                899                836                801                852                786
Delaware.................................................              1,093              1,003                946              1,023                916
Florida..................................................              1,097              1,006                949              1,026                919
Georgia..................................................              1,290              1,173              1,094              1,198              1,049
Idaho....................................................                877                817                784                832                771
Illinois.................................................              1,582              1,423              1,313              1,456              1,245
Indiana..................................................              1,578              1,419              1,309              1,451              1,242
Iowa.....................................................              1,638              1,472              1,355              1,505              1,283
Kansas...................................................              1,654              1,485              1,366              1,519              1,293
Kentucky.................................................              1,643              1,476              1,358              1,509              1,286
Lands of the Fort Mojave Tribe...........................                877                817                784                832                771
Lands of the Navajo Nation...............................              1,671              1,500              1,380              1,534              1,305
Lands of the Uintah and Ouray Reservation................              1,671              1,500              1,380              1,534              1,305
Louisiana................................................              1,398              1,265              1,175              1,293              1,121
Maine....................................................                888                827                793                842                779
Maryland.................................................              1,644              1,476              1,359              1,510              1,287
Massachusetts............................................                956                885                844                902                824
Michigan.................................................              1,468              1,325              1,228              1,355              1,169
Minnesota................................................              1,535              1,383              1,277              1,414              1,213
Mississippi..............................................              1,136              1,040                978              1,061                945
Missouri.................................................              1,621              1,457              1,342              1,490              1,272
Montana..................................................              1,671              1,500              1,380              1,534              1,305
Nebraska.................................................              1,658              1,488              1,369              1,522              1,296
Nevada...................................................              1,001                924                877                942                855
New Hampshire............................................              1,006                929                881                947                858
New Jersey...............................................                937                869                829                885                812
New Mexico *.............................................              1,435              1,297              1,203              1,325              1,146
New York.................................................              1,095              1,005                948              1,025                918
North Carolina...........................................              1,419              1,283              1,191              1,311              1,136
North Dakota.............................................              1,671              1,500              1,380              1,534              1,305
Ohio.....................................................              1,501              1,353              1,252              1,383              1,190
Oklahoma.................................................              1,319              1,197              1,116              1,223              1,068
Oregon...................................................              1,026                945                896                964                871
Pennsylvania.............................................              1,359              1,232              1,146              1,258              1,095
Rhode Island.............................................                877                817                784                832                771
South Carolina...........................................              1,449              1,309              1,213              1,338              1,156
South Dakota.............................................              1,465              1,323              1,225              1,352              1,167
Tennessee................................................              1,531              1,380              1,275              1,411              1,211
Texas....................................................              1,279              1,163              1,086              1,188              1,042
Utah *...................................................              1,483              1,339              1,239              1,368              1,179
Virginia.................................................              1,120              1,026                966              1,047                934
Washington...............................................              1,192              1,088              1,021              1,111                983
West Virginia............................................              1,671              1,500              1,380              1,534              1,305
Wisconsin................................................              1,479              1,335              1,236              1,364              1,176
Wyoming..................................................              1,662              1,492              1,373              1,526              1,299
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Excludes EGUs located in Indian country within the state.


[[Page 64825]]


                                              Table 13--Statewide Mass-Based CO2 Emission Performance Goals
                                 [Adjusted output-weighted-average tons of CO2 from all affected fossil fuel-fired EGUs]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                             Interim goal--     Interim goal--     Interim goal--
                          State                                  Step 1             Step 2             Step 3          Interim goal        Final goal
--------------------------------------------------------------------------------------------------------------------------------------------------------
Alabama..................................................         66,164,470         60,918,973         58,215,989         62,210,288         56,880,474
Arizona*.................................................         35,189,232         32,371,942         30,906,226         33,061,997         30,170,750
Arkansas.................................................         36,032,671         32,953,521         31,253,744         33,683,258         30,322,632
California...............................................         53,500,107         50,080,840         48,736,877         51,027,075         48,410,120
Colorado.................................................         35,785,322         32,654,483         30,891,824         33,387,883         29,900,397
Connecticut..............................................          7,555,787          7,108,466          6,955,080          7,237,865          6,941,523
Delaware.................................................          5,348,363          4,963,102          4,784,280          5,062,869          4,711,825
Florida..................................................        119,380,477        110,754,683        106,736,177        112,984,729        105,094,704
Georgia..................................................         54,257,931         49,855,082         47,534,817         50,926,084         46,346,846
Idaho....................................................          1,615,518          1,522,826          1,493,052          1,550,142          1,492,856
Illinois.................................................         80,396,108         73,124,936         68,921,937         74,800,876         66,477,157
Indiana..................................................         92,010,787         83,700,336         78,901,574         85,617,065         76,113,835
Iowa.....................................................         30,408,352         27,615,429         25,981,975         28,254,411         25,018,136
Kansas...................................................         26,763,719         24,295,773         22,848,095         24,859,333         21,990,826
Kentucky.................................................         76,757,356         69,698,851         65,566,898         71,312,802         63,126,121
Lands of the Fort Mojave Tribe...........................            636,876            600,334            588,596            611,103            588,519
Lands of the Navajo Nation...............................         26,449,393         23,999,556         22,557,749         24,557,793         21,700,587
Lands of the Ute Tribe of the Uintah and Ouray                     2,758,744          2,503,220          2,352,835          2,561,445          2,263,431
 Reservation.............................................
Louisiana................................................         42,035,202         38,461,163         36,496,707         39,310,314         35,427,023
Maine....................................................          2,251,173          2,119,865          2,076,179          2,158,184          2,073,942
Maryland.................................................         17,447,354         15,842,485         14,902,826         16,209,396         14,347,628
Massachusetts............................................         13,360,735         12,511,985         12,181,628         12,747,677         12,104,747
Michigan.................................................         56,854,256         51,893,556         49,106,884         53,057,150         47,544,064
Minnesota................................................         27,303,150         24,868,570         23,476,788         25,433,592         22,678,368
Mississippi..............................................         28,940,675         26,790,683         25,756,215         27,338,313         25,304,337
Missouri.................................................         67,312,915         61,158,279         57,570,942         62,569,433         55,462,884
Montana..................................................         13,776,601         12,500,563         11,749,574         12,791,330         11,303,107
Nebraska.................................................         22,246,365         20,192,820         18,987,285         20,661,516         18,272,739
Nevada...................................................         15,076,534         14,072,636         13,652,612         14,344,092         13,523,584
New Hampshire............................................          4,461,569          4,162,981          4,037,142          4,243,492          3,997,579
New Jersey...............................................         18,241,502         17,107,548         16,681,949         17,426,381         16,599,745
New Mexico*..............................................         14,789,981         13,514,670         12,805,266         13,815,561         12,412,602
New York.................................................         35,493,488         32,932,763         31,741,940         33,595,329         31,257,429
North Carolina...........................................         60,975,831         55,749,239         52,856,495         56,986,025         51,266,234
North Dakota.............................................         25,453,173         23,095,610         21,708,108         23,632,821         20,883,232
Ohio.....................................................         88,512,313         80,704,944         76,280,168         82,526,513         73,769,806
Oklahoma.................................................         47,577,611         43,665,021         41,577,379         44,610,332         40,488,199
Oregon...................................................          9,097,720          8,477,658          8,209,589          8,643,164          8,118,654
Pennsylvania.............................................        106,082,757         97,204,723         92,392,088         99,330,827         89,822,308
Rhode Island.............................................          3,811,632          3,592,937          3,522,686          3,657,385          3,522,225
South Carolina...........................................         31,025,518         28,336,836         26,834,962         28,969,623         25,998,968
South Dakota.............................................          4,231,184          3,862,401          3,655,422          3,948,950          3,539,481
Tennessee................................................         34,118,301         31,079,178         29,343,221         31,784,860         28,348,396
Texas....................................................        221,613,296        203,728,060        194,351,330        208,090,841        189,588,842
Utah*....................................................         28,479,805         25,981,970         24,572,858         26,566,380         23,778,193
Virginia.................................................         31,290,209         28,990,999         27,898,475         29,580,072         27,433,111
Washington...............................................         12,395,697         11,441,137         10,963,576         11,679,707         10,739,172
West Virginia............................................         62,557,024         56,762,771         53,352,666         58,083,089         51,325,342
Wisconsin................................................         33,505,657         30,571,326         28,917,949         31,258,356         27,986,988
Wyoming..................................................         38,528,498         34,967,826         32,875,725         35,780,052         31,634,412
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Excludes EGUs located in Indian country within the state.

F. Geographically Isolated States and Territories With Affected EGUs

    Alaska, Hawaii, Guam, and Puerto Rico constitute a small set of 
states and U.S. territories representing about one percent of total 
U.S. EGU GHG emissions. Based on the current record, the EPA does not 
possess all of the information or the analytic tools needed to quantify 
the application of the BSER for these states and territories, 
particularly data regarding RE costs and performance characteristics 
needed for building block 3 of the BSER. The NREL data for RE that the 
EPA is relying upon for building block 3 does not cover the non-
contiguous states and territories.
    The EPA acknowledges that NREL has collaborated with the state of 
Hawaii to provide technical expertise in support of the state's 
aggressive goals for clean energy, including analyses of the grid 
integration and transmission of solar and wind resources.\765\ The EPA 
also recognizes that there are studies and data for some renewable 
resources in some of the other non-contiguous jurisdictions. However, 
taken as a whole, the data we currently possess do not allow us to 
quantify the emissions reductions available from building block 3 using 
the same methodology used for

[[Page 64826]]

the contiguous states encompassed by the three interconnections. 
Lastly, the IPM model used to support the EPA's analysis is 
geographically limited to the contiguous U.S. As a result of these 
factors, the EPA currently lacks the necessary analytic resources to 
set emission performance goals for these areas.
---------------------------------------------------------------------------

    \765\ Hawaii Solar Integration Study, NREL Technical Report 
NREL/TP-5500-57215, June 2013. Available at http://www.nrel.gov/docs/fy13osti/57215.pdf.
---------------------------------------------------------------------------

    Because of the lack of suitable data and analytic tools needed to 
develop area-appropriate building block targets as defined in section 
V, the EPA is not setting CO2 emission performance goals for 
Alaska, Hawaii, Guam, or Puerto Rico in this final rule at this time. 
The EPA believes it is within its authority to address performance 
goals only for the contiguous U.S. states in this final rule. Under 
section 111(d), the EPA is not required, at the time that the EPA 
promulgates section 111(b) requirements for new sources, to promulgate 
emission guidelines for all of the sources that, if they were new 
sources, would be subject to the section 111(b) requirements if there 
is a reasonable basis for deferring certain groups of sources. As 
discussed, in this rule, the EPA has a reasonable basis for deferring 
setting goals for these four jurisdictions. In addition, the Courts 
have recognized the authority of agencies to develop regulatory 
programs in step-by-step fashion. As the U.S. Supreme Court noted in 
Massachusetts v. EPA, 549 U.S. 497, 524 (2007): ``Agencies, like 
legislatures, do not generally resolve massive problems in one fell 
regulatory swoop;'' and instead they may permissibly implement such 
regulatory programs over time, ``refining their preferred approach as 
circumstances change and as they develop a more nuanced understanding 
of how best to proceed.'' \766\
---------------------------------------------------------------------------

    \766\ See, e.g., Grand Canyon Air Tour Coalition v. F.A.A., 154 
F.3d 455, 471 (D.C. Cir. 1998) (ordinarily, agencies have wide 
latitude to attack a regulatory problem in phases and that a phased 
attack often has substantial benefits); National Association of 
Broadcasters v. FCC, 740 F.2d 1190, 121-11 (D.C. Cir. 1984) (``We 
have therefore recognized the reasonableness of [an agency's] 
decision to engage in incremental rulemaking and to defer resolution 
of issues raised in a rulemaking. . . .'').
---------------------------------------------------------------------------

    The EPA recognizes, however, that EGUs in Alaska, Hawaii, Puerto 
Rico, and Guam emit CO2 and that there are opportunities to 
reduce the carbon intensity of generation in those areas over time. We 
recognize further that there are efforts underway to increase the use 
of RE in these jurisdictions. In particular, we recognize that Hawaii 
has tremendous opportunities for RE and has adopted very ambitious 
goals: 40 percent clean energy by 2030 and 100 percent by 2045. Since 
2008, Alaska has apportioned in excess of $1.34 billion pursuing its 
aspirational goal of 50 percent of the state's total yearly electric 
load from renewable and alternative energy sources by 2025. Puerto 
Rico's goal is to achieve 20 percent RE sales by 2035, and the 
territory is working hard to meet the requirements of the Mercury and 
Air Toxics Standards, which will reduce emissions from its power plants 
substantially. Guam's RPS is to achieve 25 percent REsales by 2035.
    The agency intends to continue to consider these issues and 
determine what the appropriate BSER is for these areas. As part of that 
effort, the agency will investigate sources of information and types of 
analysis appropriate to devise the appropriate levels for building 
block 3 and BSER performance levels. Because we recognize that these 
areas face some of the most urgent climate change challenges, severe 
public health problems from air pollution and some of the highest 
electricity rates in the U.S., the EPA is committed to obtaining the 
right information to quantify the emission reductions that are 
achievable in these four areas and putting goals in place soon.

VIII. State Plans

A. Overview

    After the EPA establishes the emission guidelines that set forth 
the BSER, each state with one or more affected EGUs \767\ shall then 
develop, adopt and submit a state plan under CAA section 111(d) that 
establishes standards of performance for the affected EGUs in its 
jurisdiction in order to implement the BSER. Starting from the 
foundation of CAA section 111(d) and the EPA's implementing regulations 
(40 CFR part 60 subpart B), the EPA's proposal laid out a number of 
options, variations and flexibilities that were intended to provide 
states and affected EGUs the ability to design state plans that 
accorded with states' specific situations and policies (now and in the 
future), and to ensure reliability and affordability of electricity 
across the system and for all ratepayers. The proposal has prompted 
numerous discussions between and among stakeholders, especially states 
and groups of states, including state environmental and energy 
regulators and policy officials. The EPA has received many comments 
from a wide range of stakeholders seeking a final rule that afforded 
freedom and flexibility to consider a wide range of standards of 
performance to implement the BSER, but also providing significant 
feedback on the elements and options in the proposal and constructive 
suggestions for alternative approaches. The EPA has carefully 
considered all of this input, and is finalizing emission guidelines 
that continue to provide a variety of options for states to fashion 
their plans in ways legally supportable by the CAA, while also making 
certain adjustments to address key comments.
---------------------------------------------------------------------------

    \767\ As stated previously, states with one or more affected 
EGUs will be required to develop and implement plans that set 
emission standards for affected EGUs. The CAA section 111(d) 
emission guidelines that the EPA is promulgating in this action 
apply to only the 48 contiguous states and any Indian tribe that has 
been approved by the EPA pursuant to 40 CFR 49.9 as eligible to 
develop and implement a CAA section 111(d) plan. Because Vermont and 
the District of Columbia do not have affected EGUs, they will not be 
required to submit a state plan.
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    The next few paragraphs present an overview of the main features of 
the final emission guidelines, highlighting key changes from proposal. 
In the rest of this section, we describe in detail the various elements 
of the final emission guidelines' requirements for state plans.
    The proposal contained rate-based goals for each state, reflecting 
a blended reduction target for that state's fossil fired EGUs, and 
provided that states could either meet that rate-based goal or convert 
it to a mass-based equivalent goal. Reflecting the final BSER described 
in section V and in response to many comments desirous that the EPA 
establish mass-based goals in the final rule, these final guidelines 
include three approaches that states may adopt for purposes of 
implementing the BSER, any one of which a state may use in its plan. 
These are: (1) Establishing standards of performance that apply the 
subcategory-specific CO2 emission performance rates to their 
affected EGUs, (2) adopting a combination of standards and/or other 
measures that achieve state-specific rate-based goals that represent 
the weighted aggregate of the CO2 emission performance rates 
applied to the affected EGUs in each state, and (3) adopting a program 
to meet mass-based CO2 emission goals that represent the 
equivalent of the rate-based goal for each state. These alternatives, 
as well as the other options we are finalizing, ensure that both states 
and affected EGUs enjoy the maximum flexibility and latitude in meeting 
the requirements of the emission guidelines and that the BSER is fully 
implemented by each state.
    In the proposal, we provided two designs for state plans: One where 
all the reduction obligations are placed directly on the affected EGUs 
and one, which we called the ``portfolio approach,'' that could include 
measures to be implemented, in whole or in part, by parties other than 
the affected EGUs. In the final guidelines, we retain that

[[Page 64827]]

basic choice, but with some modifications to respond to comments we 
received, especially on the portfolio approach. In their plans, states 
will be able to choose either to impose federally enforceable emission 
standards that fully meet the emission guidelines directly on affected 
EGUs (the ``emission standards'' approach) or to use a ``state 
measures'' approach, which would be composed, at least in part, of 
measures implemented by the state that are not included as federally 
enforceable components of the plan but result in the affected EGUs 
meeting the requirements of the emission guidelines. A state measures 
type plan must include a backstop of federally enforceable standards on 
affected EGUs that fully meet the emission guidelines and that would be 
triggered if the state measures fail to result in the affected EGUs 
achieving on schedule the required emission reductions.
    States that choose an emission standards plan may establish as 
standards of performance for their affected EGUs the subcategory-
specific CO2 emission performance rates, which express the 
BSER.\768\ This would satisfy the requirement described in section 
VIII.D.2.a.3 that a state demonstrate its plan would achieve the 
CO2 emission performance rates; in this case, no further 
demonstration would be necessary. Alternatively, a state may establish 
emission standards for affected EGUs at different levels from the 
uniform subcategory-specific emission performance rates, provided that 
when implemented, the emission standards achieve the CO2 
emission performance rates or state rate- or mass-based CO2 
emission goal set forth by the EPA for the state. States that adopt 
differential standards of performance among their affected EGUs must 
demonstrate that, in the aggregate, the differential standards of 
performance will result in their affected EGUs meeting the 
CO2 emission performance rates, the state's rate-based 
CO2 emission goal or its mass-based CO2 emission 
goal.
---------------------------------------------------------------------------

    \768\ Rate-based and mass-based emission standards may 
incorporate the use of emission trading.
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    In the proposal, we proposed that states could use the portfolio 
approach to meet either a rate- or mass-based goal. In these final 
emission guidelines, the state measures approach is available only for 
a state choosing a mass-based CO2 emission goal, to provide 
certainty that the state measures are achieving the required emission 
reductions. Similar to emission standards plans with differential 
standards of performance, states that adopt state measures plans must 
demonstrate that the state measures, alone or in conjunction with any 
federally enforceable emission standards on affected EGUs also included 
in the state plan, will result in the affected EGUs in the state 
meeting the state's mass-based CO2 emission goal. A ``state 
measures'' type plan must also include a backstop provision--triggered 
if, during the interim period, the state plan fails to achieve the 
emission reduction trajectory identified in the plan or if, during the 
final phase, the state plan fails to meet the final state mass-based 
CO2 emission goal--that would impose federally enforceable 
emission standards on the affected EGUs adequate to meet the emission 
guidelines when fully implemented.
    The final guidelines reflect the changes to the timing of the 
reductions within the interim period, which is laid out in section V as 
part of the determination of the BSER. States may adopt in their plans 
emission reduction trajectories different from the illustrative three-
step trajectory included in these guidelines for purposes of creating a 
``glide path'' between 2022 and 2029, provided that the interim and 
final CO2 emission performance rates or state CO2 
emission goals are met.
    We recognize that while we are establishing 2022 as the date by 
which the period for mandatory reductions must start as part of our 
BSER determination, utilities and other parties are moving forward with 
projects that reduce emissions of CO2 from affected EGUs. We 
received numerous comments urging us to allow credit for these early 
actions. The final guidelines encourage those early reductions, by 
making clear that states may, in their plans, allow EGUs to use 
allowances or ERCs generated through the CEIP. The final guidelines 
also require that states include in their final plans a schedule of the 
actions they will be taking to ensure that the period for mandatory 
reductions will begin as required starting in 2022, and submit a 
progress report on those actions.
    For all types of plans, the final guidelines make clear that states 
may adopt programs that allow trading among affected EGUs. The final 
guidelines retain the flexibility for states to do individual plans, or 
to join with other states in a multi-state plan. In addition, and in 
response to comments from many states and other stakeholders, the 
guidelines provide that states may design their programs so that they 
are ``ready for interstate trading,'' that is, that they contain 
features necessary and suitable for their affected EGUs to engage in 
trading with affected EGUs in other ``trading ready'' states without 
the need for formal arrangements between individual states.
    We have been mindful of the concerns raised by stakeholders about 
reliability. The final BSER, especially the changes in the timing of 
the interim period, substantially address these concerns. The 
flexibilities provided for the design of state plans, including the 
ability to use trading programs, further enhance system reliability. We 
have included, as an additional assurance, a reliability safety valve 
for use where the built-in flexibilities are not sufficient to address 
an immediate, unexpected reliability situation.
    The EPA believes that all the flexibilities provided in the final 
rule are not only appropriate, but will enhance the success of the 
program. CO2 is a global pollutant, and where and when the 
reductions occur is not as significant to the environmental outcome as 
compared to many other pollutants. The flexibilities provided in the 
final guidelines will better reflect the unique interconnectedness of 
the electricity system, and will allow states and EGUs to reduce 
CO2 emissions while maintaining reliability and 
affordability for all consumers.
    In developing the plan, the state rulemaking process must meet the 
minimum public participation requirements of the implementing 
regulations as applicable to these guidelines, including a public 
hearing and meaningful engagement with all members of the public, 
including vulnerable communities. In the community and environmental 
justice considerations section, section IX of this preamble, the EPA 
addresses the actions that the agency is taking to help ensure that 
vulnerable communities are not disproportionately impacted by this 
rule. These actions include conducting a proximity analysis, setting 
expectations for states to engage meaningfully with vulnerable 
communities and requiring that they describe their plans for doing so 
as they develop their state plans, providing communities with access to 
additional resources, providing communities with information on federal 
programs and resources available to them, recommending that states take 
a multi-pollutant planning approach that examines the potential impacts 
of co-pollutants on overburdened communities, and conducting an 
assessment to determine if any localized air quality impacts need to be 
further addressed. Additionally, the EPA outlines the continued 
engagement that it will be conducting with states and communities 
throughout the state plan development process.

[[Page 64828]]

    As discussed in more detail in section VIII.E, commenters, 
particularly states, provided compelling information establishing that 
for some, and perhaps many, states it will take longer than the agency 
initially anticipated to develop and submit their required plans. In 
response to those comments, we are finalizing a plan submittal process 
that provides additional time for states that need it to submit a final 
plan submittal to the EPA after September 6, 2016. Within the time 
period specified in the emission guidelines (from as early as September 
6, 2016, to as late as September 6, 2018, depending on whether the 
state receives an extension), the state must submit its final state 
plan to the EPA. The EPA then must determine whether to approve or 
disapprove the plan. If a state does not submit a plan, or if the EPA 
disapproves a state's plan, then the EPA has the express authority 
under CAA section 111(d) to establish a federal plan for the 
state.\769\ During and following implementation of its approved state 
plan, each state must demonstrate to the EPA that its affected EGUs are 
meeting the interim and final performance requirements included in this 
final rule through monitoring and reporting requirements.
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    \769\ A federal plan may be withdrawn if the state submits, and 
the EPA approves, a state plan that meets the requirements of this 
final rule and section 111(d) of the CAA. More details regarding the 
federal plan are addressed in the EPA's proposed federal plan 
rulemaking.
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    This section is organized as follows. First, we discuss the 
timeline for state plan performance and provisions to encourage early 
action. Second, we describe the types of plans that states can submit. 
Third, we summarize the components of an approvable state plan 
submittal. Fourth, we address the process and timing for submittal of 
state plans and plan revisions. Fifth, we address plan implementation 
and achievement of CO2 emission performance rates or state 
CO2 emission goals for affected EGUs, and the consequences 
if they are not met. Sixth, we discuss general considerations for 
states in developing and implementing plans, including consideration of 
a facility's ``remaining useful life'' and ``other factors'' and 
electric reliability. Seventh, we note certain resources that are 
available to facilitate state plan development and implementation. 
Finally, we discuss additional considerations for inclusion of 
CO2 emission reduction measures in state plans, including: 
Accounting for emission reduction measures in state plans; requirements 
for mass-based and rate-based emission trading approaches; EM&V 
requirements for RE and demand-side EE resources and other measures 
used to adjust a CO2 rate; and treatment of interstate 
effects.

B. Timeline for State Plan Performance and Provisions To Encourage 
Early Action

    This section describes state plan requirements related to the 
timing of achieving the emission reductions required in the guidelines 
and the state plan performance periods. This section also describes the 
CEIP the EPA is establishing to encourage early investment in certain 
types of RE projects, as well as in demand-side EE projects implemented 
in low-income communities.
1. Timeline for State Plan Performance
    The final guidelines establish three types of performance periods: 
(1) A final deadline by which and after which affected EGUs must be in 
compliance with the final reduction requirements, (2) an interim 
period, and (3) within that interim period, three multi-year interim 
step periods. As discussed below and in section V, these performance 
periods are consistent with our determination of the BSER and are also 
responsive to the key comments we received on this aspect of the state 
plans.
    A performance period is a period for which the final plan submittal 
must demonstrate that the required CO2 emission performance 
rates or state CO2 emission goal will be met. The final 
guidelines establish 2030 as the deadline for compliance by affected 
EGUs with the final CO2 emission performance rates or 
CO2 rate or mass emission goal; 2030 is the beginning of the 
final performance period. The interim performance period is 2022 to 
2029, and there are three interim step periods--2022-2024, 2025-2027, 
and 2028-2029--where increasingly stringent emission performance rates 
or state emission goals must be met. The state may submit a plan that 
incorporates alternative interim step emission performance rates or 
state emission goals to those provided by EPA, as long as on average or 
cumulatively, as appropriate, they result in the equivalent of the 
interim emission performance rates or state emission goals in the 
emission guidelines. These timelines are based on careful consideration 
of the substantial comments we received on both the timing of the 
interim period and the trajectory of compliance by affected EGUs over 
the interim period and our determination of the BSER, discussed in 
section V above. The modifications we have made to the timelines 
included in the proposal respond to these comments and to concerns 
about, among other things, reliability, feasibility, and cost.
    As previously discussed, the EPA has determined that the BSER 
includes implementation of reduction measures over the period of 2022 
through 2029, with final compliance by affected EGUs in 2030. 
Therefore, the final rule requires that interim CO2 emission 
performance rates or state CO2 emission goals be met for the 
interim period of 2022-2029. Many commenters expressed a desire that 
the EPA designate steps during the interim period to create an interim 
goal that offered states and utilities greater flexibility and choice 
in determining their own emission reduction trajectories over the 
course of the interim period. Since our intent at proposal was to 
provide such flexibility and choice, and since it remains our intent to 
do so in this final rule, we are addressing these comments by including 
in the 2022-2029 interim period three interim step periods (2022-2024, 
2025-2027, 2028-2029), which correspond roughly to the phasing in of 
the BSER. We note, however, that the final rule also allows states the 
flexibility to define an alternate trajectory of emission performance 
between 2022 and 2029, provided that (1) the state plan specifies its 
own interim step CO2 emission performance rates or state 
CO2 emission goals, (2) meeting the alternative interim step 
CO2 emission performance rates or state CO2 
emission goals will result in the interim emission performance rates or 
state CO2 emission goal being met on an 8-year average or 
cumulative basis, and, (3) the final CO2 emission 
performance rates or state CO2 emission goal is achieved. To 
be approvable, a state plan submittal must demonstrate that the 
emission performance of affected EGUs will meet the interim step 
CO2 emission performance rates or interim step state 
CO2 emission goals over the 2022-2024, 2025-2027, and 2028-
2029 periods and the final CO2 emission performance rates or 
state CO2 emission goal no later than 2030.\770\
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    \770\ States are free to establish different interim step 
performance rates or interim step state goals than those the EPA has 
specified in this final rule. If states choose to determine their 
own interim step performance rates or state goals, the state must 
demonstrate that the plan will still meet the interim performance 
rates or state goal for 2022-2029 finalized in this action.
---------------------------------------------------------------------------

    This relatively long period--first for planning, then for 
implementation and achievement of the interim and final CO2 
emission performance rates or state CO2 emission goals--
provides states and

[[Page 64829]]

utilities with substantial flexibility regarding methods and timing of 
achieving emission reductions from affected EGUs. The EPA believes that 
timing flexibility in implementing measures provides significant 
benefits that allow states to develop plans that will help achieve a 
number of goals, including, but not limited to: Reducing cost, 
addressing reliability concerns, addressing concerns about stranded 
assets, and facilitating the integration of meeting the emission 
guidelines and compliance by affected EGUs with other air quality and 
pollution control obligations on the part of both states and affected 
EGUs. Moreover, we note that over the course of time between submittal 
of final plans and 2030, circumstances may change such that states may 
need or wish to modify their plans. The relatively lengthy performance 
periods provided in the final rule should help keep those situations to 
a minimum but will also accommodate them if necessary.\771\ The EPA 
envisions that the agency, states and affected EGUs will have an 
ongoing relationship in the course of implementing this program. Since 
the record also indicates a high degree of interest on the part of 
states and stakeholders in pursuing banking and trading programs, the 
timing and level of stringency of the interim CO2 
performance rates or state CO2 emission goals we are 
finalizing should provide states and affected EGUs with ample capacity 
to accommodate such changes without necessitating changes in state 
plans in many instances.
---------------------------------------------------------------------------

    \771\ Modifications to state plans are addressed more 
specifically in section VIII.E.7 below.
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    The timelines established in the final rule respond to the issues 
raised in numerous comments regarding the concept of the interim 
period, including comments supporting the flexibility afforded states 
in developing their plans and the timing necessary to meet the 2030 
emission requirements. Some commenters supported beginning the interim 
goal plan period at 2020. Others stated that the investments necessary 
to meet the proposed interim emission performance goals beginning in 
2020 are unachievable in that timeframe or would place too great a 
burden on affected EGUs, states, and ratepayers. Some suggested that 
the 2020 interim goal step should be eliminated in favor of later start 
dates, including 2022, 2025, or other years. Some commenters urged the 
EPA to establish phased interim steps creating a steady downward 
trajectory that allowed several years for each step, compatible with 
the ``chunkiness'' of utility planning processes. Yet other commenters 
provided input suggesting that states be allowed to establish their own 
set of emission performance steps during the interim plan performance 
period and thereby control their own emission reduction trajectory or 
``glide path'' for achievement of the interim goal and the 2030 goal, 
or that the EPA not establish any interim standards at all. Commenters 
also noted that for some states, there was not a significant difference 
between the interim and final goal, and, therefore, no glide path for 
those states. As discussed in previous sections, based on this input 
and our final determination of the BSER, the EPA has adjusted the 
interim period to include 2022-2029, is establishing three interim 
performance periods creating a reasonable trajectory from 2022 to 2030, 
and is also retaining the flexibility for states to establish their own 
emission reduction trajectory during the interim period.
    As noted, the EPA has determined that the period for mandated 
reductions should begin in 2022, instead of 2020 as we proposed, 
because of the substantial amount of comment and data we received 
indicating that states and utilities reasonably needed that additional 
time to take the steps necessary to start achieving reductions. In 
order to assure the EPA and the public that states are making progress 
in implementing the plan between the time of the state plan submittal 
and the beginning of the interim period, and as discussed in further 
detail in section VIII.D, the final rule requires that the state plan 
submittal include a timeline with all the programmatic plan milestone 
steps the state will take between the time of the state plan submittal 
and 2022 to ensure the plan is effective as of 2022.
2. Provisions To Encourage Early Action
    Many commenters supported providing incentives for states and 
utilities to deploy CO2-reducing investments, such as RE and 
demand-side EE measures, as early as possible. In the proposal, the EPA 
requested comment on an approach that would recognize emission 
reductions that existing programs provide prior to the initial plan 
performance period starting from a specified date. We also requested 
comment on options for that specified date and on conditions that 
should apply to counting those pre-compliance emission reductions 
toward a state goal. The EPA received many comments requesting that the 
agency recognize early actions for the emission reductions they provide 
prior to the performance period, that the EPA allow those pre-
compliance impacts to be counted toward meeting requirements under the 
rule, and that certain conditions should be applied to recognition of 
early reductions so as to ensure the emission reductions required in 
the rule. We also received comments from stakeholders regarding the 
disproportionate burdens that some communities already bear, and 
stating that all communities should have equal access to the benefits 
of clean and affordable energy. The EPA recognizes the validity and 
importance of these perspectives, and as a result has determined to 
provide a program--called the Clean Energy Incentive Program (CEIP)--in 
which states may choose to participate. This section describes this 
program.
    The CEIP is designed to incentivize investment in certain RE and 
demand-side EE projects that commence construction in the case of RE, 
or commence operation in the case of EE, following the submission of a 
final state plan to the EPA, or after September 6, 2018, for states 
that choose not to submit a final state plan by that date, and that 
generate MWh (RE) or reduce end-use energy demand (EE) during 2020 and/
or 2021. State participation in the program is optional; the EPA is 
establishing this program as an additional flexibility to facilitate 
achievement of the CO2 emission reductions required by this 
final rule, regardless of the type of state plan a state chooses to 
implement.
    Under the CEIP, a state may set aside allowances from the 
CO2 emission budget it establishes for the interim plan 
performance period or may generate early action ERCs (ERCs are 
discussed in more detail in section VIII.K.2), and allocate these 
allowances or ERCs to eligible projects for the MWh those projects 
generate or the end-use energy savings they achieve in 2020 and/or 
2021. A state implementing a mass-based plan approach, as described in 
section VIII.C, may issue early action allowances; a state implementing 
a rate-based plan approach, also described in section VIII.C, may issue 
early action ERCs. For each early action allowance or ERC a state 
allocates to such projects, the EPA will provide the state with an 
appropriate number of matching allowances or ERCs, as outlined below, 
for the state to allocate to the project. The EPA will match state-
issued early action ERCs and allowances up to an amount that represents 
the equivalent of 300 million short tons of CO2 emissions. 
The EPA intends that a portion of this pool will be reserved for 
eligible wind and solar projects, and a portion will be reserved for 
low-income EE projects. In the proposed federal plan, the EPA is

[[Page 64830]]

taking comment on the size of each reserve, and is proposing provisions 
to provide that any unallocated amounts would be redistributed among 
participating states.
    The EPA has determined that the size of this 300 million short ton 
CO2-equivalent matching pool is an appropriate reflection of 
the CO2 emission reductions that could be achieved by the 
additional early investment in RE and demand-side EE the agency expects 
will be incentivized by the CEIP. For example, in 2012, 13 GW of 
utility scale wind were deployed,\772\ and, in 2014, 3.4 GW of utility-
scale solar \773\ plus 2-3 GW of distributed solar were deployed,\774\ 
according to industry estimates. Assuming 19 GW per year of RE from 
2017-2020 based on these historic maximums yields an installed base of 
76 GW of RE potentially eligible for CEIP incentives in 2020 and/or 
2021. Assuming an average capacity factor of 30 percent, this would 
translate into approximately 200 TWh/year of generation, which would be 
eligible for approximately 300 million short tons of matching 
allowances over the 2-year period, if the RE MWh were converted to 
allowances based on the 2012 carbon intensity of 0.8 short tons per 
MWh. This would leave the remaining half of the pool of matching 
federal allowances available for EE projects implemented in low-income 
communities, and additional growth in RE deployment beyond these 
historic maximums as potentially enabled by reductions in cost and 
improvements in performance.
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    \772\ U.S. Energy Information Administration Electric Power 
Annual 2013. http://www.eia.gov/electricity/annual. Table 4.6: 
Capacity additions, retirements and changes by energy source. March 
2015.
    \773\ U.S. Energy Information Administration Electric Power 
Monthly. http://www.eia.gov/electricity/monthly. Table 6.3: New 
Utility Scale Generating Units by Operating Company, Plant, Month, 
and Year.
    \774\ GTM Research/Solar Energy Industries Association: U.S. 
Solar Market Insight Q1 2015.
---------------------------------------------------------------------------

    For a state to be eligible for a matching award of allowances or 
ERCs from the EPA, it must demonstrate that it will award allowances or 
ERCs only to eligible projects. These are projects that:
     Are located in or benefit a state that has submitted a 
final state plan that includes requirements establishing its 
participation in the CEIP;
     Are implemented following the submission of a final state 
plan to the EPA, or after September 6, 2018, for a state that chooses 
not to submit a complete state plan by that date;
     For RE: Generate metered MWh from any type of wind or 
solar resources;
     For EE: Result in quantified and verified electricity 
savings (MWh) through demand-side EE implemented in low-income 
communities; and
     Generate or save MWh in 2020 and/or 2021.
    The following provisions outline how a state may award early action 
ERCs or allowances to eligible projects, and how the EPA will provide 
matching ERCs or allowances to states.
     For RE projects that generate metered MWh from any type of 
wind or solar resources: For every two MWh generated, the project will 
receive one early action ERC (or the equivalent number of allowances) 
from the state, and the EPA will provide one matching ERC (or the 
equivalent number of allowances) to the state to award to the project.
     For EE projects implemented in low-income communities: For 
every two MWh in end-use demand savings achieved, the project will 
receive two early action ERCs (or the equivalent number of allowances) 
from the state, and the EPA will provide two matching ERCs (or the 
equivalent number of allowances) to the state to award to the project.
    Early action allowances or ERCs awarded by the state, and matching 
allowances or ERCs awarded by the EPA pursuant to the CEIP, may be used 
for compliance by an affected EGU with its emission standards and are 
fully transferrable prior to such use.
    The EPA discusses the CEIP in the proposed federal plan rule, and 
will address design and implementation details of the CEIP, including 
the appropriate factor for determining equivalence between allowances 
and MWh and the definition of a low-income community for project 
eligibility purposes, in a subsequent action. Before doing so, the EPA 
will engage states and stakeholders to gather additional information 
concerning implementation topics, and to solicit information about the 
concerns, interests and priorities of states, stakeholders and the 
public.
    In order for a state that chooses to participate in the CEIP to be 
eligible for a future award of allowances or ERCs from the EPA, a state 
must include in its initial submittal a non-binding statement of intent 
to participate in the program. In the case of a state submitting a 
final plan by September 6, 2016, the state plan would either include 
requirements establishing the necessary infrastructure to implement 
such a program and authorizing its affected EGUs to use early action 
allowances or ERCs as appropriate, or would include a non-binding 
statement of intent as part of its supporting documentation and revise 
its plan to include those requirements at a later date.
    Following approval of a final state plan that includes requirements 
for implementing the CEIP, the agency will create an account of 
matching allowances or ERCs for the state that reflects the pro rata 
share--based on the amount of the reductions from 2012 levels the 
affected EGUs in the state are required to achieve relative to those in 
the other participating states--of the 300 million short ton 
CO2 emissions-equivalent matching pool that the state is 
eligible to receive. Thus, states whose EGUs have greater reduction 
obligations will be eligible to secure a larger proportion of the 
federal matching pool upon demonstration of quantified and verified MWh 
of RE generation or demand side-EE savings from eligible projects 
realized in 2020 and/or 2021.
    Any matching allowances or ERCs that remain undistributed after 
September 6, 2018,\775\ will be distributed to those states with 
approved state plans that include requirements for CEIP participation. 
These ERCs and allowances will be distributed according to the pro rata 
method outlined above. Unused matching allowances or ERCs that remain 
in the accounts of states participating in the CEIP on January 1, 2023, 
will be retired by the EPA.
---------------------------------------------------------------------------

    \775\ This may occur because not all states may elect to include 
requirements for CEIP participation in their state plans.
---------------------------------------------------------------------------

    For purposes of establishing a state plan program eligible for an 
award of matching allowances or ERCs from the EPA, such a program must 
include a mechanism for awarding early action emission allowances or 
ERCs for eligible actions that reduce or avoid CO2 emissions 
in 2020 and/or 2021, and that is implemented in a way such that the 
early action allowances or ERCs allocated by the state would maintain 
the stringency of the state's goal for emission performance from 
affected EGUs in the performance periods established in this rule. 
Specifically, the state must demonstrate in its plan that it has a 
mechanism in place that enables issuance of ERCs or allowances from the 
state to parties effectuating reductions in 2020 and/or 2021 in a 
manner that would have no impact on the aggregate emission performance 
of affected EGUs required to meet rate-based or mass-based 
CO2 emission standards during

[[Page 64831]]

the compliance periods.\776\ This demonstration is not required to 
account for matching ERCs or allowances that may be issued to the state 
by the EPA. Participation in this program is entirely voluntary, and 
nothing in these provisions would have the effect of requiring any 
particular affected EGU to achieve reductions prior to 2022, or 
requiring states to offer incentives for emission reductions achieved 
prior to 2022.\777\ These and other details will be developed in the 
subsequent action.
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    \776\ For example, under a mass-based implementation, the state 
plan could include a set-aside of early action allowances from an 
emissions budget that itself reflects the state goals. Allocation of 
those early action allowances to parties effectuating reductions in 
2020 and 2021 would have no impact on the total emissions budget, 
which sets the total allowable emissions in the compliance periods. 
Alternatively, under a rate-based implementation, the state plan 
could require that early action ERCs issued to parties effectuating 
reductions in 2020 and 2021 would be ``borrowed'' from a pool of 
ERCs created by the state during the interim plan performance 
period. States could limit the size of the ``borrowed'' pool of ERCs 
to be equivalent to the size of the federal matching pool, or could 
take into consideration the potential for each state's federal 
matching pool to expand after a redistribution of unused credits. 
For every early action ERC awarded for actions in 2020 and 2021, the 
state would retire one ERC from the pool of ERCs created as a result 
of reductions achieved from 2022 onward.
    \777\ In addition to the CEIP, states may also offer credit for 
early investments in RE and demand-side EE according to the 
provisions of section VIII.K.1 of this final rule: A state may award 
ERCs to qualified providers that implement projects from 2013 onward 
that realize quantified and verified MWh results in 2022 and 
subsequent years.
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    The EPA is providing the CEIP as an option for states implementing 
plans--and is including a similar program for the federal plan proposal 
being issued concurrently--for several reasons. Chief among them is 
that offered by commenters to the effect that the overall cost of 
achievement of the emission performance rates or state goals could be 
reduced by an approach that granted some form of beneficial recognition 
to emissions reduction investments that both occur and yield reductions 
prior to the first date on which the program of the interim plan 
performance period. Other commenters pointed out that to the extent 
that states and utilities would benefit from the availability of low-
cost RE and other zero-emitting generation options during the interim 
and final plan performance periods, the EPA should include in the final 
emission guidelines provisions that accelerate deployment of RE 
resources, since in so doing the final emission guidelines would speed 
achievement of expected reductions in the cost of those technologies 
commensurate with their accelerated deployment. In addition, the 
incentives and market signal generated by the CEIP can help sustain the 
momentum toward greater RE investment in the period between now and 
2022 so as to offset any dampening effects that might be created by 
setting the start date 2 years later than at proposal.
    The specific criteria the EPA is establishing for eligible RE 
projects reflect a variety of considerations. First, the EPA seeks to 
preserve the incentive for project developers to execute on planned 
investments in all types of solar and wind technologies. Commenters 
raised concerns that the fast pace of reductions underlying the 
emission targets in the proposed rule could potentially shift 
investment from RE to natural gas, thus dampening the incentive to 
develop wind and solar projects, in particular. Second, the EPA, 
consistent with the CAA's design that incentivizes technology and 
accelerates the decline in the costs of technology, seeks to drive the 
widespread development and deployment of wind and solar, as these broad 
categories of renewable technology are essential to longer term climate 
strategies. Finally, in contrast to other CO2-reducing 
technologies--including other zero-emitting or RE technologies--solar 
and wind projects often require lead times of shorter duration, which 
would allow them to generate MWh beginning in 2020.
    The specific criterion the EPA is establishing for eligible EE 
projects--namely that these projects be implemented in low-income 
communities--is also consistent with the technology-forcing and 
development design of CAA section 111. The EPA believes it is 
appropriate to offer an additional incentive to remove current barriers 
to implementing demand-side EE programs in low-income communities. 
While the EPA acknowledges that a number of states have demand-side EE 
programs focused on these communities,\778\ the agency also recognizes 
that there have been historic economic, logistical, and information 
barriers to implementing programs in these communities. As a result, 
the costs of implementing demand-side EE programs in these communities 
are typically higher than in other communities and stand as barrier to 
harvesting potentially cost effective reductions and advancing these 
technologies. The EPA intends for the CEIP to help incentivize 
increased deployment of projects that will deliver demand-side EE 
benefits to these communities, which will in turn lower the costs of 
these approaches. These lower costs will help new technologies and 
delivery mechanisms penetrate in the future, thus improving the cost of 
implementation of the emission guidelines overall, consistent with 
Congress' design in the New Source Performance Standard provisions of 
the CAA. Further, reducing barriers to demand-side EE in low-income 
communities will help ensure that the benefits of the final rule are 
shared broadly across society and that potential adverse impacts on 
low-income ratepayers are avoided. It complements other steps the 
federal government is taking to bring clean energy technologies to 
these communities, as we discuss in section IX of this preamble.
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    \778\ Several of these programs are discussed in section IX of 
this preamble, including, for example, Maryland's EmPOWER Low Income 
Energy Efficiency Program (LIEEP) and New York's EmPower New York 
program.
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    More broadly, the CEIP responds to the urgency of meeting the 
challenge of climate change in two key ways. First, of course, it 
fosters reductions before 2022. Second, in targeting investments in 
wind, solar and low-income EE, it focuses on the kinds of measures and 
technologies that are the essential foundation of longer-term climate 
strategies, strategies that inevitably depend on the further 
development and widespread deployment of highly adaptable zero-emitting 
technologies.
    We are not requiring that projects demonstrate to states that they 
are ``additional'' or surplus relative to a business-as-usual or state 
goal-related baseline in order to be eligible. At the same time, we 
believe that including an incentive to develop projects that benefit 
low-income communities will increase the likelihood of investments 
being made that would not have been made otherwise.
    In order to be awarded matching ERCs or allowances by the EPA for 
projects that meet the eligibility criteria, a final state plan must 
have requirements establishing the appropriate infrastructure to issue 
early action ERCs or allowances to eligible project providers by 2020. 
The state must require that the state or its agent will, in accordance 
with state plan requirements approved as meeting the ERC issuance and 
EM&V requirements included in section VIII.K: (1) Evaluate project 
proposals from eligible RE and demand-side EE project providers, 
including the EM&V plans that must accompany such proposals; (2) 
evaluate monitoring and verification reports submitted by eligible 
providers following project implementation, which contain the 
quantified and verified MWh of RE generation or energy savings achieved

[[Page 64832]]

by the project in 2020 and/or 2021; (3) issue ERCs or allowances to 
eligible providers for these MWh results; (4) ensure that no MWh of 
renewable generation or energy savings receives early action or 
matching ERCs or allowances more than once.\779\
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    \779\ For a state plan incorporating the use of ERCs or 
allowances to be approvable by the EPA, such a plan must use an EPA-
approved or EPA-administered tracking system for ERCs or allowances. 
The EPA received a number of comments from states and stakeholders 
about the value of the EPA's support in developing and/or 
administering tracking systems to support state administration of 
rate-based emission trading programs. The EPA is exploring options 
for providing such support and is conducting an initial scoping 
assessment of tracking system support needs and functionality.
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    The CEIP will provide a number of benefits. First, the program will 
provide incentives designed to reduce energy bills early in the 
implementation of the guidelines through earlier and broader 
application of energy saving technologies, and help ensure that these 
benefits are fully shared by low-income communities. Second, the EPA 
believes that stimulating or supporting early investment in RE 
generation technologies could accelerate the rate at which the costs of 
these technologies fall over the course of the interim performance 
period. Third, the CEIP will provide affected EGUs and states with 
additional emission reduction resources to help them achieve their 
state plan obligations. Finally, the program will improve the 
liquidity, in the early years of the program, of the ERC and allowance 
markets we expect to emerge for compliance with the requirements of 
these guidelines.\780\
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    \780\ The CEIP is expected to provide states and affected EGUs 
additional flexibility in meeting the guidelines, and bears 
similarity in both design and purpose to the Compliance Supplement 
Pool, which the agency established as a part of the NOX 
SIP Call. See 63 FR 57356, 57428-30 (Oct. 27, 1998). Certain aspects 
of the Compliance Supplement Pool were challenged in litigation and 
upheld by the D.C. Circuit Court of Appeals. See Michigan v. EPA, 
213 F.3d 663, 694 (D.C. Cir. 2000).
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    The EPA is establishing this program as an option for states that 
wish to drive investments in RE and low-income EE that will result in 
actual, early reductions in CO2 emissions from affected 
EGUs. States are also authorized to set their own glide path, or 
interim step performance rates or goals, so long as the interim and 
final performance rates or goals are met, and could do so in a way that 
takes into account the availability of the CEIP to assist affected EGUs 
in meeting the applicable glide path and performance rates or goals. 
While the EPA is not requiring states to take advantage of this 
program, its availability simply enhances these already-existing 
implementation and compliance flexibilities while at the same time 
delivering meaningful benefits, particularly for low-income 
communities. The EPA looks forward to an upcoming public dialogue about 
the implementation details of the CEIP.

C. State Plan Approaches

1. Overview
    Under the final emission guidelines, states may adopt and submit 
either of two different types of state plans. The first would apply all 
requirements for meeting the emission guidelines to affected EGUs in 
the form of federally enforceable emission standards.\781\ We refer to 
this as an ``emission standards'' state plan type. The second, which we 
refer to as a ``state measures'' plan type, would allow the state mass 
CO2 emission goals to be achieved by affected EGUs in part, 
or entirely, through state measures \782\ that apply to affected EGUs, 
other entities, or some combination thereof. The state measures plan 
type also includes a mandatory contingent backstop of federally 
enforceable emission standards for affected EGUs that would apply in 
the event the plan does not achieve its anticipated level of emission 
performance as specified in the state plan during the period that the 
state is relying on state measures. The inclusion of a backstop of 
federally enforceable emission standards in a state measures plan type 
is legally necessary for a state plan to meet the terms of 111(d), 
which specifically require a state to submit standards of performance.
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    \781\ 40 CFR 60.21(f) defines ``emission standard'' as ``a 
legally enforceable regulation setting forth an allowable rate of 
emissions into the atmosphere, establishing an allowance system, or 
prescribing equipment specifications for control of air pollution 
emissions.'' This definition is promulgated and effective, and we 
note that it authorizes the use of allowance systems as a form of 
emission standard. To resolve any doubt that allowance systems are 
an acceptable form of emission standard in the final rule, we are 
including regulatory text in the final subpart UUUU regulations 
authorizing the use of allowance systems as a form of emission 
standard under section 111(d). Section 60.21(f) was originally 
amended in 2005 to include recognition of allowance systems as a 
form of emission standard in the Clean Air Mercury Rule (CAMR) (70 
FR 28606, 28649; May 18, 2005). CAMR was vacated in its entirety in 
New Jersey v. EPA, 517 F.3d 574 (D.C. Cir. 2008). However, the 
reason for vacatur was wholly unrelated to the question of whether 
an allowance system could be a form of emission standard. In 
response to the New Jersey decision, the agency removed CAMR 
provisions from the Code of Federal Regulations. The agency chose to 
retain the language of 60.21(f) and 60.24(b)(1) generally 
recognizing allowance systems. This language is broader than CAMR 
and unrelated to the reasons for its vacatur. The EPA re-promulgated 
these provisions in February of 2012 (77 FR 9304, 9447; Feb. 16, 
2012). Even if this were not the case, the agency would not concede 
that simply because ``allowance systems'' were not provided for in 
the framework regulations of subpart B, they could not be relied 
upon in specific emission guidelines, such as these for 
CO2. The implementing regulations generally serve a gap-
filling role where there are not more specific provisions laid out 
in the relevant emission guidelines. In order to resolve any 
question whether allowance systems are authorized under the final 
rule, we are including regulatory text in subpart UUUU to make this 
authorization explicit.
    \782\ ``State measures'' refer to measures that are adopted, 
implemented, and enforced as a matter of state law. Such measures 
are enforceable only per state law, and are not included in and 
codified as part of the federally enforceable state plan.
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    These two types of state plans and their respective approaches, 
either of which could be implemented on a single-state or multi-state 
basis, allow states to meet the statutory requirements of CAA section 
111(d) while accommodating the wide range of regulatory requirements 
and other programs that states have deployed or will deploy in the 
electricity sector that reduce CO2 emissions from affected 
EGUs. Further, as described in detail below, both types of plans are 
responsive to comments we received from states and other stakeholders. 
In addition to providing states the option of developing an emission 
standards or state measures type plan, the final rule makes clear that 
states that choose an emission standards plan can adopt a plan that 
meets either the CO2 emission performance rates, a rate-
based CO2 emission goal, or a mass-based CO2 
emission goal.
    Under these two basic plan types, the final emission guidelines 
provide states with a number of potential plan pathways for meeting the 
emission guidelines. A plan pathway represents a specific plan design 
approach used to meet the emission guidelines. These plan pathways are 
discussed in section VIII.C.2 through C.5 below, and further elaborated 
in sections VIII.J (for mass-based emission standards) and VIII.K (for 
rate-based emission standards).
    The final emission guidelines provide four streamlined plan 
pathways. These streamlined plan pathways represent straightforward 
plan approaches for meeting the emission guidelines, and avoid the need 
to meet additional plan requirements and include additional elements in 
a plan submittal. The streamlined plan pathways include the following:

     Establishing federally enforceable, mass-based 
CO2 emission standards for affected EGUs, complemented by 
state-enforceable mass-based CO2 emission standards for 
new fossil fuel-fired EGUs.\783\ This approach could involve an 
emission budget trading program that includes affected EGUs as well

[[Page 64833]]

as new fossil fuel-fired EGUs. This approach facilitates interstate 
emission trading, through either a single-state ``ready-for-
interstate-trading'' plan approach or through a multi-state plan. 
Under a ``ready-for-interstate-trading'' plan, interstate emission 
trading may occur without the need for a multi-state plan.\784\
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    \783\ New source CO2 emission complements are 
discussed in section VIII.J.2.b, which also provides EPA-derived new 
source CO2 emission complements for states.
    \784\ Mass-based trading-ready plans are addressed in section 
VIII.J.3. Multi-state plans, where a group of states are meeting a 
joint CO2 goal for affected EGUs, are addressed in 
section VIII.C.5.
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     Establishing federally enforceable, mass-based 
CO2 emission standards for affected EGUs.\785\ This 
approach facilitates interstate emission trading, through either a 
single-state ``ready-for-interstate-trading'' plan approach or 
through a multi-state plan. In a separate concurrent action, the EPA 
is proposing a model rule for states that could be used in a plan 
implementing this approach.\786\
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    \785\ This plan approach would meet a state mass-based 
CO2 goal for affected EGUs, or a joint multi-state mass-
based CO2 goal for affected EGUs. These plan approaches 
are discussed in sections VIII.J.2 and VIII.C.5, respectively.
    \786\ Submission of a state plan based on the EPA's finalized 
model rule for a mass-based emission trading program could be 
considered presumptively approvable. The EPA would evaluate the 
approvability of such submission through an independent notice and 
comment rulemaking.
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     Establishing federally enforceable, subcategory-
specific rate-based CO2 emission standards for affected 
EGUs, consistent with the CO2 emission performance rates 
in the emission guidelines. This approach provides for interstate 
emission trading, through either a single-state ``ready-for-
interstate-trading'' plan approach or through a multi-state 
plan.\787\ In a separate concurrent action, the EPA is proposing a 
model rule for states that could be used in a plan implementing this 
approach.
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    \787\ Rate-based trading-ready plans are addressed in section 
VIII.K.4.
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     Establishing federally enforceable rate-based 
CO2 emission standards at a single level that applies for 
all affected EGUs, consistent with the state rate-based 
CO2 goal for affected EGUs in the emission 
guidelines.\788\ This approach provides for interstate emission 
trading, through a multi-state plan that meets a single weighted 
average multi-state rate-based CO2 goal.\789\
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    \788\ This plan approach is addressed in section VIII.C.2.a.
    \789\ This multi-state plan approach is addressed in section 
VIII.C.5.

    The final emission guidelines also provide for a range of 
additional custom plan approaches that a state may pursue, if it 
chooses, to address specific circumstances or policy objectives in a 
state. The custom plan pathways, while viable options for meeting the 
emission guidelines, come with additional plan requirements and plan 
submittal elements. These additional plan requirements and plan 
submittal elements are necessary to ensure that the emission guidelines 
are met and that the necessary level of CO2 emission 
performance is achieved by affected EGUs.
    Based on this overall approach, the final emission guidelines 
provide for a range of state options--both easily implementable 
approaches that can be used to meet the emission guidelines, and more 
customizable approaches that can be used, if a state chooses, to 
address special circumstances or state policy objectives.
2. ``Emission Standards'' State Plan Type
    The emission standards type of state plan imposes requirements 
solely on affected EGUs in the form of federally enforceable emission 
standards. This type of state plan, as described below, may consist of 
rate-based emission standards for affected EGUs or mass-based emission 
standards for affected EGUs.
    The state plan submittal for an emission standards type plan must 
demonstrate that these federally enforceable emission standards for 
affected EGUs will achieve the CO2 emission performance 
rates or the applicable state rate-based or mass-based CO2 
emission goal for affected EGUs.
    Both rate-based and mass-based emission standards included in a 
state plan must be quantifiable, verifiable, enforceable, non-
duplicative and permanent. These requirements are described in more 
detail at section VIII.D.2.
    Rate-based and mass-based emission standards may incorporate the 
use of emission trading, as described below. The EPA anticipates the 
use of emission trading in state plans, given the advantages of this 
approach and comments suggesting a high degree of interest on the part 
of states, utilities, and independent power producers in the inclusion 
of emission trading in state plans.\790\
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    \790\ The legal basis for authorizing trading in emission 
standards is discussed in section VIII.C.6.
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    The EPA notes it is proposing model rules for both mass-based and 
rate-based emission trading programs. States could adopt and submit the 
finalized model rules for either emission trading program to meet the 
requirements of CAA section 111(d) and these emission guidelines. The 
EPA will evaluate the approvability of such submission, as with any 
state plan submission, through independent notice-and-comment 
rulemaking. The EPA notes that state plan submittals that adopt the 
finalized model rule may be administratively and technically more 
straightforward for the EPA in evaluating approvability, as the EPA 
will have determined that the model rule meets the applicable 
requirements of the emission guidelines through the process of 
finalization of such rule.
    a. Rate-based approach. The first type of ``emission standards'' 
plan approach a state may choose is one that uses rate-based emission 
standards. Under this plan approach, the plan would include federally 
enforceable emission standards for affected EGUs, in the form of lb 
CO2/MWh emission standards.
    A rate-based ``emission standards'' plan may be designed to either 
meet the CO2 emission performance rates for affected EGUs or 
achieve the state's rate-based CO2 emission goal for 
affected EGUs. A plan could be designed such that compliance by 
affected EGUs would assure achievement of either the CO2 
emission performance rates for affected EGUs or the state rate-based 
CO2 emission goal. To meet the CO2 emission 
performance rates for affected EGUs, a plan would establish separate 
rate-based emission standards for affected fossil fuel-fired electric 
utility steam generating units and stationary combustion turbines (in 
lb CO2/MWh) that are equal to or lower than the 
CO2 emission performance rates in the emission guidelines. 
To meet a state rate-based CO2 goal, a plan would establish 
a uniform rate-based emission standard (in lb CO2/MWh) that 
applies to all affected EGUs in the state. This uniform emission rate 
would be equal to or lower than the applicable state rate-based 
CO2 goal specified in the final emission guidelines.
    Under these two approaches, compliance by affected EGUs with the 
rate-based emission standards in a plan would ensure that affected EGUs 
meet the CO2 emission performance rates in the emission 
guidelines or the state rate-based CO2 goal for affected 
EGUs. No further demonstration would be necessary by the state to 
demonstrate that its plan would achieve the CO2 emission 
performance rates or the state's rate-based CO2 goal.
    Alternatively, if a state chooses, it could apply rate-based 
emission standards to individual affected EGUs, or to categories of 
affected EGUs, at a lb CO2/MWh rate that differs from the 
CO2 emission performance rates or the state's rate-based 
CO2 goal. In this case, compliance by affected EGUs with 
their emission standards would not necessarily ensure that the 
collective, weighted average CO2 emission rate for these 
affected EGUs meets the CO2 emission performance rates or 
the state's rate-based CO2 goal.\791\
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    \791\ The weighted average CO2 emission rate that 
will be achieved by the fleet of affected EGUs in a state that 
applies different rate-based emission standards to individual 
affected EGUs or groups of affected EGUs will depend upon the mix of 
electric generation from affected EGUs subject to different emission 
standards. For example, if a state applies higher emission standards 
for affected steam generating units and lower emission standards for 
affected NGCC units, the greater the projected amount of electric 
generation from steam generating units, the higher the projected 
weighted average emission rate that will be achieved for all 
affected EGUs.

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[[Page 64834]]

    Under this type of approach, therefore, the state would be required 
to include a demonstration,\792\ in the state plan submittal, that its 
plan would achieve the CO2 emission performance rates or 
applicable state rate-based CO2 goal. This demonstration 
would include a projection of the collective, weighted average 
CO2 emission rate the fleet of affected EGUs would achieve 
as a result of compliance with the emission standards in the plan. Once 
the plan is implemented, if the CO2 emission performance 
rates or applicable state rate-based CO2 goal are not 
achieved, corrective measures would need to be implemented, as 
described in section VIII.F.3.
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    \792\ A demonstration of how a plan will achieve a state's rate-
based or mass-based CO2 emission goal is one of the 
required plan components, as described in section VIII.D.2.
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    Under a rate-based approach, a state may include in its plan a 
number of provisions to facilitate affected EGU compliance with the 
emission standards. First, a state may encourage (or require) EGUs to 
undertake actions to reduce CO2 emissions at the affected 
EGU level, such as heat rate improvements or fuel switching. These 
measures are discussed in section VIII.I. Second, a state may implement 
a market-based emission trading program, which enables EGUs to generate 
and procure ERCs, a tradable compliance unit representing one MWh of 
electric generation (or reduced electricity use) with zero associated 
CO2 emissions. Considerations and requirements for rate-
based trading programs are discussed in section VIII.K.
    ERCs would be issued by the administering state regulatory body. 
The state may issue ERCs to affected EGUs that emit below a specified 
CO2 emission rate, as well as for measures that provide 
substitute generation for affected EGUs or avoid the need for 
generation from affected EGUs. These ERCs may then be used to adjust 
the reported CO2 emission rate of an affected EGU when 
demonstrating compliance with a rate-based emission standard. For each 
submitted ERC, one MWh is added to the denominator of the reported 
CO2 emission rate, resulting in a lower adjusted 
CO2 emission rate.
    Eligible measures that may generate ERCs, as well as the accounting 
method for adjusting a CO2 emission rate, are discussed in 
section VIII.K.1. Requirements for rate-based emission trading 
approaches are discussed in section VIII.K.2. Quantification and 
verification requirements for measures eligible to generate ERCs are 
discussed in section VIII.K.3.
    (1) Rate-based emission standards based on operational or other 
standards.
    As discussed in further detail in section VIII.D.2.d.3, regarding 
the legal considerations and statutory language of CAA section 111(h), 
the EPA is finalizing that design, equipment, work practice, and 
operational standards cannot be considered to be ``standards of 
performance'' for this final rule. However, a state may elect to use 
emission standards for affected EGUs that result in a reduced 
CO2 lb/MWh emission rate for affected EGUs because of 
operational or other standards. The state would include in its state 
plan an emission standard that is the rate standard that results from 
the applicable operational or other standard. For example, a state 
might choose to recognize that an individual affected EGU has plans to 
retire, and those plans could be codified in the state plan by adopting 
an emission standard of 0 CO2 lb/MWh as of a certain date. 
The state would thus include in the state plan an emission standard of 
0 CO2 lb/MWh for that affected EGU that applies after a 
specified date.
    An approvable plan could apply such emission standards to a subset 
of affected EGUs or all affected EGUs. As with any rate-based plan, the 
state would need to demonstrate that the plan would achieve the 
required level of emission performance for affected EGUs, in 
CO2 lb/MWh. A plan could also apply such emission standards 
to a subset of affected EGUs in the state while applying other rate-
based emission standards to the remainder of affected EGUs in the 
state. For example, a plan might include an emission standard of 0 
CO2 lb/MWh reflecting a retirement mandate for one or more 
affected EGUs in a state and apply a rate-based emission standard equal 
to the CO2 emission performance rates or a state's rate-
based CO2 emission goal to the remainder of affected EGUs.
    As with all emission standards, emission standards based on design, 
equipment, work practice, and operational standards must be 
quantifiable, verifiable, enforceable, non-duplicative and permanent. 
These requirements are described in more detail at section VIII.D.2.
    (2) Additional considerations for rate-based approach.
    Additional considerations and requirements for rate-based emission 
standards state plans are addressed in section VIII.K. This includes 
the basic accounting method for adjusting the reported CO2 
emission rate of an affected EGU, as well as requirements for the use 
of measures to adjust a CO2 emission rate, both of which are 
discussed in sections VIII.K.1 through 3. Such requirements include 
eligibility, accounting, and quantification and verification 
requirements (EM&V) for the use of CO2 emission reduction 
measures that provide substitute generation for affected EGUs or avoid 
the need for generation from affected EGUs in rate-based state plans. 
Section VIII.K.4 addresses multi-state coordination among rate-based 
emission trading programs.
    b. Mass-based approach.
    The second ``emission standards'' approach a state may elect to use 
is mass-based emission standards applied to affected EGUs. Under this 
approach, the plan would include federally enforceable emission 
standards for mass CO2 emissions from affected EGUs. The 
plan would be designed to achieve the mass-based CO2 goal 
for a state's affected EGUs (see section VII) or a level of 
CO2 emissions equal to or less than the mass-based 
CO2 goal plus the new source complement CO2 
emissions (see section VIII.J.2.b, Table 14).\793\
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    \793\ For example, a state plan designed to meet a state mass-
based CO2 goal for affected EGUs plus a new source 
complement could involve a mass-based emission budget trading 
program that, under state law, applies to both affected EGUs, as 
well as new fossil fuel-fired EGUs. The program requirements for 
affected EGUs would be federally enforceable, while the program 
requirements for other fossil fuel-fired EGUs would be state-
enforceable. This approach is described further in section VIII.J.2.
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    Under a mass-based approach, a state could require that individual 
affected EGUs meet a specified mass emission standard. Alternatively, a 
state could choose to implement a market-based emission budget trading 
program. The EPA envisions that the latter option is most likely to be 
exercised by states seeking to implement a mass-based emission standard 
approach, as it would maximize compliance flexibility for affected EGUs 
and enable the state to meet its mass goal in the most economically 
efficient manner possible.
    (1) Mass-based emission standard applied to individual affected 
EGUs.
    One pathway a state could take to achieve its mass-based 
CO2 goal would be to apply mass-based emission standards to 
individual affected EGUs, in the form of a limit on total allowable

[[Page 64835]]

CO2 emissions. These emission standards would be designed 
such that total allowable CO2 emissions from all affected 
EGUs in a state are equal to or less than the state's mass-based 
CO2 goal, or a state's mass-based CO2 goal plus 
the new source complement CO2 emissions specified in section 
VIII.J.2.b, Table 14. The individual affected EGUs would be required to 
emit at or below their mass-based standard to demonstrate compliance. 
Under this approach, individual affected EGUs would be required to 
undertake source-specific measures to assure their CO2 
emissions do not exceed their assigned emission standard. Affected EGU 
compliance with the emission standards prescribed under this type of 
mass-based approach would ensure that the affected EGUs in a state 
achieve the state's mass-based CO2 goal, or mass-based 
CO2 goal plus new source complement.
    (2) Mass-based emission standard with a market-based emission 
budget trading program.
    A second pathway a state could take to achieve its mass-based 
CO2 goal would be to implement a market-based emission 
budget trading program. This type of program provides maximum 
compliance flexibility to affected EGUs, and as a result, may be 
attractive to states that choose to implement a mass-based approach in 
their state plan.
    An emission budget trading program establishes a combined emission 
standard for a group of emission sources in the form of an emission 
budget. Emission allowances are issued in an amount up to the 
established emission budget.\794\ Allowances may be distributed to 
affected emission sources (as well as to other parties) through a 
number of different methods, including direct allocation to affected 
sources or auction. These allowances can be traded among affected 
sources and other parties. The emission standard applied to individual 
emission sources is a requirement to surrender emission allowances 
equal to reported emissions, with each allowance representing one ton 
of CO2.
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    \794\ An emission allowance represents a limited authorization 
to emit, typically denominated in one short ton or metric ton of 
emissions.
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    The EPA views an emission budget trading program as a highly 
efficient, market-based approach for reducing CO2 emissions 
from affected EGUs. Such programs include a limit on mass 
CO2 emissions while providing both short-term and long-term 
price signals that encourage the owners or operators of affected EGUs, 
as well as other entities, to determine the most efficient means of 
achieving the mass emission standard. Notably, such an approach 
incentivizes actions taken at affected EGUs to reduce CO2 
emissions, as well as the use of strategies such as RE and demand-side 
EE as complementary measures that reduce CO2 emissions. 
However, unlike under a rate-based approach, for this latter set of 
measures there is no need to address and describe these state measures 
in a state plan submission or quantify and verify the RE and EE MWh of 
generation and savings. As a result, a mass-based emission budget 
trading program incentivizes and recognizes a wide range of emission 
reduction actions while being relatively simple for a state to 
implement and administer. Furthermore, the EPA notes that such an 
approach still allows for a state to address electricity load growth, 
as load growth can be met through low- and zero-emitting generating 
resources, as well as avoided through demand-side EE and demand-side 
management (DSM) measures.
    Additional considerations and requirements for mass-based emission 
standards state plans are addressed in section VIII.J. This includes 
use of emission budget trading programs in a state plan, including 
provisions required for such programs (section VIII.J.2.a) and the 
design of such programs in the context of a state plan. Section VIII.J 
addresses program design approaches that ensure achievement of a state 
mass-based CO2 emission goal (section VIII.J.2.c), as well 
as how states can use emission budget trading programs with broader 
source coverage and other flexibility features in a state plan, such as 
the programs currently implemented by California and the RGGI 
participating states (section VIII.J.2.d). Section VIII.J.2.e addresses 
other considerations for the design of emission budget trading programs 
that states may want to consider, such as allowance allocation 
approaches. Section VIII.J.3 addresses multi-state coordination among 
emission budget trading programs used in states that retain their 
individual state mass-based CO2 goals.
    (3) Mass-based emission standards based on operational or other 
standards.
    As discussed in section VIII.C.2.a.(1) above, a state may elect to 
use mass-based emission standards for affected EGUs that result in a 
reduced total tonnage of CO2 emissions from affected EGUs 
because of operational or other standards. The state would include in 
its state plan an emission standard that is the mass standard that 
results from the applicable operational or other standard. For example, 
a state might choose to recognize that an individual affected EGU has 
plans to retire, and those plans could be codified in the state plan by 
adopting an emission standard of 0 total tons of CO2, as of 
a certain date. The state would thus include in the state plan an 
emission standard of 0 total tons of CO2 for that affected 
EGU that applies after a specified date. Under a mass-based approach, 
the state could also include an emission standard (e.g., a mass limit) 
that reflects the result of a limit on an affected EGU's total 
operating hours over a specified period. Such an emission standard 
would be based on an affected EGU's potential to emit given a specified 
number of operating hours.
    An approvable plan could apply such emission standards to a subset 
of affected EGUs or all affected EGUs. As with any mass-based plan, the 
state would need to demonstrate that the plan would achieve the 
required level of emission performance for affected EGUs, in total tons 
of CO2. A plan could also apply such emission standards to a 
subset of affected EGUs in the state while applying other emission 
standards to the remainder of affected EGUs in the state. For example, 
a plan might include an emission standard of 0 tons of CO2 
for one or more affected EGUs, reflecting a retirement mandate for one 
or more affected EGUs in a state, and include the remainder of affected 
EGUs in an emission budget trading program.
3. ``State Measures'' State Plan Type
    The second type of state plan is what we refer to as a ``state 
measures'' plan. As previously discussed, the EPA believes states will 
be able to submit state plans under the emission standards plan type, 
and its respective approaches, and achieve the CO2 emission 
performance rates or state rate-based or mass-based CO2 
goals by imposing federally enforceable requirements on affected EGUs. 
Upon further consideration of the requirements of CAA section 111(d), 
in consideration of the comments we received on the proposed portfolio 
approach and the state commitments approach, and in order to provide 
flexibility and choice to states that may wish to adopt a plan that 
does not place all the obligations on affected EGUs, the EPA is 
finalizing the state measures plan type in addition to the emission 
standards plan type. The EPA believes the state measures plan type will 
provide states with additional latitude in accommodating existing or 
planned programs that involve measures implemented by the state, or by 
entities other than affected EGUs, that result in avoided generation 
and CO2 emission

[[Page 64836]]

reductions at affected EGUs. This includes market-based emission budget 
trading programs that apply, in part, to affected EGUs, such as the 
programs implemented by California and the RGGI participating states in 
the Northeast and Mid-Atlantic, as well as RE and demand-side EE 
requirements and programs, such as renewable portfolio standards (RPS), 
EERS, and utility- and state-administered incentive programs for the 
deployment of RE and demand-side EE technologies and practices. The EPA 
believes this second state plan type will afford states with 
appropriate flexibility while meeting the statutory requirements of CAA 
section 111(d).
    Measures implemented under the state measures plan type could 
include RE and demand-side EE requirements and deployment programs. 
This type of plan could align with existing state resource planning in 
the electricity sector, including RE and demand-side EE investments by 
state-regulated electric utilities. The state measures plan type also 
can accommodate emission budget trading programs that address a broader 
set of emission sources than just affected EGUs subject to CAA section 
111(d), such as the programs currently implemented by California and 
the RGGI participating states. The EPA also notes that the state 
measures plan type could accommodate imposition by a state of a fee for 
CO2 emissions from affected EGUs, an approach suggested by a 
number of commenters.
    This plan type would allow the state to implement a suite of state 
measures that are adopted, implemented, and enforceable only under 
state law, and rely upon such measures in achieving the required level 
of CO2 emission performance from affected EGUs. The state 
measures under this plan type could be measures involving entities 
other than affected EGUs, or a combination of such measures with 
emission standards for affected EGUs, so long as the state demonstrates 
that such measures will result in achievement of a state's mass-based 
CO2 goal (or mass-based CO2 goal plus new source 
complement), as discussed below. The EPA notes that under this plan 
type, a state could also choose to include any emission standards for 
affected EGUs, which are required to be included in the plan as 
federally enforceable measures, to be implemented alongside or in 
conjunction with state measures the state would implement and enforce.
    For a state measures plan to be approvable, it must include a 
demonstration of how the measures, whether state measures alone or 
state measures in conjunction with any federally enforceable emission 
standards for affected EGUs, will achieve the state mass-based 
CO2 emission goal for affected EGUs (or mass-based 
CO2 goal plus new source complement). However, because the 
state measures would not be federally enforceable emission standards, 
the plan must also include a backstop of federally enforceable emission 
standards for all affected EGUs, in order for the state measures plan 
type to satisfy the requirement of CAA section 111(d) that a state 
establish standards of performance for affected EGUs. This backstop 
would impose federally enforceable emission standards on the state's 
affected EGUs in the case that the state measures fail to achieve the 
state mass-based CO2 goal. The backstop, discussed further 
below, would assure that the state CO2 emission goal or 
CO2 emission performance rates are fully achieved by 
affected EGUs in the form of federally enforceable emission standards.
    a. Requirements for state measures under a state measures type 
plan.
    Under the state measures plan type, state measures must be 
satisfactorily described in the supporting material for a state plan 
submittal. The supporting material would need to demonstrate that the 
state measures meet the same integrity elements that would apply to 
federally enforceable emission standards. Specifically, the state plan 
submittal must demonstrate that the state measures are quantifiable, 
verifiable, enforceable, non-duplicative and permanent. These 
requirements are described in more detail at section VIII.D.2. Under 
the state measures plan, if a state chooses to impose emission 
standards on affected EGUs, such emission standards must be included in 
the federally enforceable plan as they would be under an emission 
standards plan.
    The EPA would assess the overall approvability of a state measures 
plan based, in part, on the state's satisfactory demonstration that the 
state measures, in conjunction with any federally enforceable emission 
standards on the affected EGUs that might be included in the plan, 
would result in the state plan's achievement of the mass-based 
CO2 goal for the state's affected EGUs (or mass-based 
CO2 goal plus new source complement). This includes a 
demonstration of adequate legal authority and funding to implement the 
state plan and any associated measures. The EPA's determination that 
such a plan is satisfactory would be based in part on whether the state 
measures are adequately described in the supporting documentation and 
the plan submittal demonstrates that the state measures are 
quantifiable, verifiable, enforceable, non-duplicative and permanent as 
described above. This is necessary for the EPA to ensure that the 
results achieved through the plan are quantifiable and verifiable, and 
to assess whether the state measures are anticipated to achieve the 
state mass-based CO2 goal for affected EGUs (or mass-based 
CO2 goal plus new source complement).
    The EPA's evaluation of the approvability of a state measures plan 
would also include an assessment of whether the backstop consisting of 
federally enforceable emission standards for the state's affected EGUs 
would ensure that the required emission performance level is fully 
achieved by affected EGUs, in the case that the state measures fail to 
achieve the state mass-based CO2 goal (or mass-based 
CO2 goal plus new source complement), or the state does not 
meet programmatic state measures milestones during the interim period. 
The trigger for the backstop must also satisfactorily provide for the 
implementation of the backstop emission standards.
    b. Considerations for the backstop included in a state measures 
type plan.
    As further discussed in section VIII.C.6.c, the EPA believes a 
backstop, composed of federally enforceable emission standards for the 
affected EGUs that are sufficient to achieve the state CO2 
emission goal or the CO2 emission performance rates in the 
event that state measures do not result in the required CO2 
emission performance, is necessary for the state measures plan type to 
meet the requirements of CAA section 111(d). The state plan must 
specify the backstop that would apply federally enforceable emission 
standards to the affected EGUs if the state measures plan does not 
achieve the anticipated level of CO2 emission performance by 
affected EGUs, or a state does not meet programmatic state measures 
milestones during the interim period. The state plan must include 
promulgated regulations (or other requirements) that fully specify 
these emission standard requirements, which must be quantifiable, 
verifiable, enforceable, non-duplicative and permanent. These 
requirements are described in more detail at section VIII.D.2.
    These federally enforceable emission standards must be designed 
such that compliance by affected EGUs with the emission standards would 
achieve the CO2 emission performance rates or state's rate- 
or mass-based interim and final goals for affected EGUs. The

[[Page 64837]]

backstop emission standards must specify CO2 emission 
performance levels that would apply for the interim plan performance 
period (including specifying levels for each of the interim step 1 
through step 3 periods) and the final two-year plan performance 
periods.\795\ If a state chose, these backstop emission standards could 
be based on a model rule or federal plan promulgated by the EPA.
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    \795\ This includes the level of emission performance during the 
interim plan periods 2022-2024, 2025-2027 and 2028-2029, as well as 
the performance level that would be achieved during every subsequent 
2-year final plan performance period (2030-2031, and subsequent 2-
year periods).
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    The state measures plan must specify the trigger and conditions 
under which the backstop federally enforceable emission standards would 
apply that is consistent with the requirements in the emission 
guidelines. The trigger and attendant conditions for deployment of the 
backstop would address the CAA section 111(d) requirement that states 
submit a program that provides for the implementation of standards of 
performance. The state measures plan must specify the level of emission 
performance that will be achieved by affected EGUs as a result of 
implementation of the state measures plan during the interim and final 
plan performance periods. This includes the level of emission 
performance during the interim plan periods 2022-2024, 2025-2027 and 
2028-2029, as well as the performance level that would be achieved 
during every subsequent 2-year final plan performance period (2030-
2031, and subsequent 2-year periods). If actual CO2 emission 
performance by affected EGUs fails to meet the level of emission 
performance specified in the plan over the 8-year interim performance 
period (2022-2029) or for any 2-year final goal performance period, the 
state measures plan must require that the backstop federally 
enforceable emission standards would take effect and be applied to 
affected EGUs. Similarly, the plan must require that the backstop 
standards take effect if actual emission performance is deficient by 10 
percent or more relative to the performance levels that the state has 
chosen to specify in the plan for the interim step 1 period (2022-2024) 
or the interim step 2 period (2025-2027). The backstop standards are 
also triggered if, at the time of the state's annual reports to the EPA 
during the interim period, the state has not met the programmatic state 
measures milestones for the reporting period. The state measures plan 
must provide that, in the event the backstop is triggered, such 
emission standards would be effective within 18 months of the deadline 
for the state's submission of its periodic report to the EPA on state 
plan implementation and performance, as described in section 
VIII.D.2.c.796 797
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    \796\ States may choose to establish an effective date for 
backstop emission standards that is sooner than 18 months.
    \797\ In the event a state does not implement the backstop as 
required if actual emission performance triggers the backstop, the 
EPA will take appropriate action. The EPA notes that as part of the 
proposed federal plan rulemaking, it is proposing a regulatory 
mechanism to call plans in the instances of substantial inadequacy 
to meet applicable requirements or failure to implement an approved 
plan.
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    The backstop emission standards must make up for the shortfall in 
CO2 emission performance. The shortfall must be made up as 
expeditiously as practicable. The state may address the requirement to 
make up for the shortfall in CO2 emission performance by 
submitting, as part of the final plan, backstop emission standards that 
assure affected EGUs would achieve the state's interim and final 
CO2 emission goals or the CO2 emission 
performance rates for affected EGUs, and then later submit appropriate 
revisions to the backstop emission standards adjusting for the 
shortfall through the state plan revision process. The state may 
alternately effectuate this by submitting, along with the backstop 
emission standards, provisions to adjust the emission standards to 
account for any prior emission performance shortfall, such that no 
modification of the emission standards is necessary in order to address 
the emission performance shortfall.
    For example, assume a state measures plan identified a mass-based 
CO2 standard for affected EGUs of 100 million tons during 
the interim step 1 performance period (2022-2024), 90 million tons 
during the interim step 2 performance period (2025-2027), and 80 
million tons during the interim step 3 performance period (2028-2029). 
Over the entire interim plan performance period (2022-2029), the 
interim mass-based CO2 goal is cumulative emissions of 270 
million tons. Assume that CO2 emissions from affected EGUs 
in the interim step 1 period were actually 115 million tons, triggering 
implementation of the backstop. In this instance, the mass-based 
standard for affected EGUs implemented as part of the backstop during 
subsequent plan performance periods would need to ensure that 
cumulative CO2 emissions during the 2022-2029 interim period 
do not exceed 270 million tons. This could be achieved, for example, by 
implementing a mass standard of 75 million tons during the interim step 
2 performance period (rather than the 90 million tons originally 
specified in the plan), or some other combination during the remaining 
interim step 2 and 3 performance periods.\798\ The emission standards 
included as the backstop in the plan must specify calculations for how 
such adjustments will be made.
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    \798\ In this example, states could elect to implement different 
combinations of mass-based standards during the remaining interim 
step 2 and 3 plan performance periods, provided that cumulative 
CO2 emissions during the full interim plan performance 
period (2022-2029) do not exceed 270 million tons.
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4. Summary of Comments on State Plan Approaches
    The EPA received a wide range of comments on the basic plan 
approaches in the proposal. Numerous commenters supported providing 
states with the option of implementing a rate-based or mass-based 
approach. Some commenters expressed concern that a rate-based approach 
would not reduce overall emissions, and could actually lead to 
increased emissions. The EPA does not agree with this latter comment, 
because both approaches would result in adequate and appropriate 
constraints on CO2 emissions. As documented in the RIA, a 
rate-based approach would result in a substantial reduction in 
CO2 emissions relative to emissions under a business-as-
usual case.
    Numerous commenters supported allowing states to implement a rate-
based emission standard approach applied to affected EGUs. There was 
also broad support in comments for allowing states to pursue a mass-
based approach in the form of mass emission standards on affected EGUs. 
The EPA is finalizing both of these approaches.
    The EPA received a mix of comments for and against the proposed 
portfolio approach, in which state requirements and other measures that 
apply to non-EGU entities would be part of a state's federally 
enforceable state plan. Multiple commenters supported the portfolio 
approach because it would align with existing state and utility 
planning processes in the electric power sector, and would maximize 
state discretion and flexibility in developing plans. Commenters 
mentioned the range of state requirements and utility programs overseen 
by states that could be used under a portfolio approach and result in 
achieving the CO2 emission goal for affected EGUs, including 
state RPS, EERS and utility-administered EE programs. Commenters noted 
that the portfolio approach would provide states maximum flexibility to 
take local circumstances, economics and state

[[Page 64838]]

policy into account when developing their plans.
    By contrast, multiple commenters opposed the portfolio approach. 
Some commenters questioned how a portfolio approach would work, and 
whether the EPA had provided sufficient detail explaining how such a 
plan approach could be implemented by a state. In particular, multiple 
commenters questioned how different state programs, such as utility-
administered EE programs, could be made federally enforceable in 
practice under CAA section 111(d).\799\ Multiple commenters expressed 
concern about making state requirements and utility programs for RE and 
demand-side EE enforceable under the CAA. Some of these commenters 
supported the state commitments plan approach that the EPA took comment 
on in the proposal, which was a variant of the portfolio approach. 
Under the state commitment variant, measures that applied to entities 
other than affected EGUs would not be federally enforceable under the 
CAA, but state commitments to implement those measures would be 
federally enforceable elements of a state plan under the CAA.
---------------------------------------------------------------------------

    \799\ Legal considerations with the proposed portfolio approach 
are explored in section VIII.C.6.d.
---------------------------------------------------------------------------

    After considering these comments, the EPA is not finalizing the 
portfolio approach or the state commitment variant. However, the EPA is 
finalizing the state measures plan type, as described above, which 
would accommodate state choices and allow states to rely upon a variety 
of measures, as was envisioned under the portfolio approach, in a way 
that meets the statutory requirements of CAA section 111(d).
5. Multi-State Plans and Multi-State Coordination
    The EPA views the ability of a state to implement an individual 
plan or a multi-state plan as a significant flexibility that allows a 
state to tailor implementation of its plan to state policy objectives 
and circumstances. The EPA sees particular value in multi-state plans 
and multi-state coordination, which allow states to implement a plan in 
a coordinated fashion with other states. Such approaches can lead to 
more efficient implementation, lower compliance costs for affected EGUs 
and lower impacts on electricity ratepayers. Coordinated approaches 
also will help states identify and address any potential electric 
reliability impacts when developing plans.
    The EPA received broad support in comments for allowing states to 
implement multi-state plan approaches, and has made multiple changes in 
the final rule to address many suggestions outlining different 
approaches states may want to take. These changes are intended to 
provide streamlined approaches for multi-state coordination while 
maintaining transparency and assuring that the CO2 emission 
performance rates or state CO2 emission goals are achieved.
    The EPA is finalizing two approaches that allow states to 
coordinate implementation in order to meet the emission 
guidelines.\800\
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    \800\ The EPA notes that in addition to these approved 
approaches, other types of multi-state approaches may be acceptable 
in an approvable plan, provided the obligations of each state under 
the multi-state plan are clear and the submitted plan(s) meets 
applicable emission guideline requirements.
---------------------------------------------------------------------------

    First, states may meet the requirements of the emission guidelines 
and CAA section 111(d) by submitting multi-state plans that address the 
affected EGUs in a group of states. The EPA is finalizing the proposed 
approach by which multiple states aggregate their rate or mass 
CO2 goals and submit a multi-state plan that will achieve a 
joint CO2 emission goal for the fleet of affected EGUs 
located within those states (or a joint mass-based CO2 goal 
plus a joint new source CO2 emission complement).\801\
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    \801\ The concept of a new source CO2 emission 
complement is addressed in section VIII.J.2.b. Table 14 provides 
individual state new source CO2 emission complements. For 
a multi-state plan, a joint new source CO2 emission 
complement would be the sum of the individual new source 
CO2 emission complements in Table 14 for the states 
participating in the multi-state plan.
---------------------------------------------------------------------------

    Second, the EPA is also finalizing another approach, in response to 
comments received on the proposed rule. This approach enables states to 
retain their individual state goals for affected EGUs and submit 
individual plans, but to coordinate plan implementation with other 
states through the interstate transfer of ERCs or emission 
allowances.\802\ This approach facilitates interstate emission trading 
without requiring states to submit joint plans.\803\ The EPA considers 
these to be individual state plans, not multi-state plans.
---------------------------------------------------------------------------

    \802\ This approach also applies where a state plan is designed 
to meet a state mass-based CO2 goal plus a state's new 
source CO2 emission complement.
    \803\ States may submit individual plans with such linkages, or 
if they choose, provide a joint submittal. Forms of joint submittals 
are described at section VIII.E.
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    States have the option to implement this second approach in 
different ways, as discussed in section VIII.C.5.c. These different 
implementation options allow states to tailor their implementation of 
linked emission trading programs, based on state policy preferences, as 
well as economic and other considerations. These different options 
provide varying levels of state control over emission trading system 
partners and require varying levels of coordination in the course of 
state plan development.
    In response to comments, the EPA is also further clarifying how 
multi-state plans with a joint goal for affected EGUs may be 
implemented. The EPA is clarifying that states may participate in more 
than one multi-state plan, if necessary, for example, to address 
affected EGUs in states that are served by more than one ISO or RTO. 
The EPA is further clarifying that a subset of affected EGUs in a state 
may participate in a multi-state plan. These clarifications are 
discussed in section VIII.C.5.d.
    a. Summary of comments on multi-state plans.
    Multiple commenters supported the EPA's proposed approach that 
would allow states to implement a multi-state plan to meet a joint 
CO2 emission goal. However, a number of states commented 
that states should also be allowed to coordinate without aggregating 
multiple individual state goals into a single joint goal. Many states 
questioned the incentives that a state would have to aggregate its goal 
with other states that have different goals, and also noted the 
administrative complexities presented by states seeking to formally 
coordinate state plans with one another.
    The EPA notes that there are multiple incentives for states to 
collaborate by implementing a multi-state plan to meet an aggregated 
joint goal, regardless of the specific level of their individual goals, 
because states share grid regions and impacts from plan implementation 
will be regional in nature. Further, multiple analyses, including those 
by ISOs and RTOs, indicate that regional approaches could achieve state 
goals at lesser cost than individual state plan approaches. However, 
the EPA also recognizes the value in allowing for collaboration where 
states retain individual goals. These approaches could provide some of 
the benefits of a joint goal while reducing the negotiations among 
states necessary to develop a multi-state plan with a joint goal. As a 
result, the EPA has finalized the additional approaches described in 
section VIII.C.5 to provide for coordination while maintaining 
individual goals. These approaches would allow for interstate transfer 
of ERCs or emission allowances while retaining individual state goals.

[[Page 64839]]

    Many commenters suggested that states should be encouraged to join 
or form regional market-based programs. Many commenters touted the 
economic efficiency benefits of such approaches, and noted that such 
programs have features that support electric reliability.
    The EPA agrees with these comments, and notes that it encouraged 
such approaches in the proposal. While the EPA is not requiring states 
to join and/or form regional market-based programs, we note that such 
programs can be helpful for many reasons, including features that 
support reliability. Market-based programs allow greater flexibility 
for affected EGUs both in the short-term and long-term. Under a market-
based program, affected EGUs have the ability to obtain sufficient 
allowances or credits to cover their emissions in order to comply with 
their emission standards. Additionally, we continue to encourage states 
to cooperate regionally. Regional cooperation in planning and 
reliability assessments is an important tool to meeting system needs in 
the most cost-effective, efficient, and reliable way.
    b. Multi-state coordination through a joint emission goal.
    Multiple states may submit a multi-state plan that achieves an 
aggregated joint CO2 emission goal for the affected EGUs in 
the participating states (or a joint mass-based CO2 goal 
plus a joint new source CO2 emission complement).\804\ The 
joint emission goal approach is acceptable for both types of state 
plans, the ``emission standards'' plan type and the ``state measures'' 
plan type. However, the EPA is requiring that a joint goal may apply 
only to states implementing the same type of plan, either an ``emission 
standards'' plan or a ``state measures'' plan.\805\
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    \804\ As a conceptual and legal matter, the relationship between 
states coordinating to meet a joint CO2 emission goal 
under this rule is similar to the relationship between states 
coordinating SIP submissions to attain the NAAQS in an interstate 
nonattainment area. In both cases, the states coordinate their 
actions in a way that, cumulatively, the measures applicable in each 
state will lead to achievement of a common interstate goal (with the 
EPA evaluating the sufficiency and success of the plans on a 
holistic, interstate basis). Despite the shared goal, in both cases, 
the mere fact of coordination has no effect on each state's 
sovereign legal authority. For example, the legally applicable rules 
in a given state are adopted by that state individually, not by a 
joint entity or other interstate mechanism. Similarly, the fact that 
the states coordinate their rules does not grant them the authority 
to directly enforce each other's rules, or to take direct legal 
action against a state that is failing to implement its own rules. 
Although some states may jointly submit their coordinated rules to 
the EPA as a matter of administrative convenience, the state rules 
within such a plan are nothing more than reciprocal laws of the sort 
that states routinely enact in voluntary coordination with each 
other.
    \805\ This is necessary because if the joint goal is not 
achieved during a plan performance period, different remedies would 
apply under an emission standards plan and a state measures plan. 
Under an emission standards plan, corrective measures would be 
triggered. Under a state measures plan, the federally enforceable 
backstop emission standards would be triggered. See section 
VIII.F.3.
---------------------------------------------------------------------------

    Under this approach, a rate-based multi-state plan would include a 
weighted average rate-based emission goal, derived by calculating a 
weighted average CO2 emission rate based on the individual 
rate-based goals for each of the participating states and 2012 
generation from affected EGUs. A mass-based multi-state plan would 
include an aggregated mass-based CO2 emission goal for the 
participating states, in cumulative tons of CO2, derived by 
summing the individual mass-based CO2 emission goals of the 
participating states.\806\
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    \806\ Where a multi-state plan is designed to meet a joint mass-
based CO2 goal plus a joint new source CO2 
emission complement, the joint new source CO2 emission 
complement would be the sum of the individual new source 
CO2 emission complements in section VIII.J.2.b, Table 14, 
for the states participating in the multi-state plan.
---------------------------------------------------------------------------

    Such plans could include emission standards in the form of a multi-
state rate-based or mass-based emission trading program.\807\ 
Alternatively, states could submit a multi-state plan using a state 
measures approach.\808\ Both approaches could provide for 
implementation of a multi-state emission trading program.
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    \807\ A potential example of this approach is the method by 
which the states participating in RGGI have implemented individual 
CO2 Budget Trading Program regulations in a linked manner 
using a shared emission and allowance tracking system. Each state's 
regulations implementing RGGI stand alone on a legal basis, but 
provide for the use of CO2 allowances issued in other 
participating states for compliance under the state regulations. 
These states are not listed by name in state regulations, which 
instead refer to participating states that have established a 
corresponding CO2 Budget Trading Program regulation. More 
information is available at http://www.rggi.org.
    \808\ Under this approach, a state measure could include, if a 
state chose, a multi-state emission trading program that is 
enforceable at the state level.
---------------------------------------------------------------------------

    c. Multi-state coordination among states retaining individual state 
goals.
    States that do not wish to pursue a joint CO2 emission 
goal with other states may pursue a second pathway to multi-state 
collaboration. States may submit individual plans that will meet the 
CO2 emission performance rates or a state mass 
CO2 goal for affected EGUs (or mass-based CO2 
goal plus the new source CO2 emission complement), but 
include implementation in coordination with other state plans by 
providing for the interstate transfer of ERCs or CO2 
allowances, depending on whether the state is implementing a rate-based 
or mass-based emission trading program. This form of coordinated 
implementation may occur under both an ``emission standards'' type of 
plan and a ``state measures'' type of plan, where states are 
implementing emission trading programs.\809\ For rate-based plans, this 
type of coordinated approach is limited to state plans with rate-based 
emission standards that are equal to the CO2 emission 
performance rates in the emission guidelines.
---------------------------------------------------------------------------

    \809\ ERCs may only be transferred among states implementing 
rate-based emission limits. Likewise, emission allowances may only 
be transferred among states implementing mass-based emission limits.
---------------------------------------------------------------------------

    Under this approach, a state plan could indicate that ERCs or 
CO2 allowances issued by other states with an EPA-approved 
state plan could be used by affected EGUs for compliance with the 
state's rate-based or mass-based emission standard, respectively. Such 
plans must indicate how ERCs or emission allowances will be tracked 
from issuance through use by affected EGUs for compliance,\810\ through 
either a joint tracking system, interoperable tracking systems, or an 
EPA-administered tracking system.\811\
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    \810\ Referred to in different programs as ``surrender,'' 
``retirement,'' or ``cancellation.''
    \811\ The EPA received a number of comments from states and 
stakeholders about the value of the EPA's support in developing and/
or administering tracking systems to support state administration of 
rate-based emission trading programs. The EPA is exploring options 
for providing such support and is conducting an initial scoping 
assessment of tracking system support needs and functionality.
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    The EPA would assess the approvability of each state's plan 
individually--the use of ERCs or emission allowances issued in another 
state would not impact the approvability of the components of the 
individual state plan.\812\ However, the EPA would also assess linkages 
with other state plans, to ensure that the joint tracking system or 
interoperable tracking systems used to implement rate-based or mass-
based emission trading programs across states are properly designed 
with necessary components, systems, and procedures to maintain the 
integrity of the linked emission trading programs.
---------------------------------------------------------------------------

    \812\ Note that for mass-based plans, the approvability 
requirements for a state plan would differ, depending on the 
structure of the emission budget trading program included in the 
state plan. For example, approvability requirements and basic 
accounting with regard to whether a plan achieves a state's mass 
CO2 goal would differ for emission budget trading 
programs that cover only affected EGUs subject to CAA section 111(d) 
vs. programs that apply to a broader set of emission sources. These 
considerations are addressed in section VIII.J.
---------------------------------------------------------------------------

    Coordinated state plan implementation among states that retain 
individual state mass-based CO2 goals (or that implement 
individual state plans with rate-based emission standards consistent 
with the CO2

[[Page 64840]]

emission performance rates in the emission guidelines) is discussed in 
more detail in sections VIII.J and K. Section VIII.J discusses 
coordinated implementation among states implementing individual mass-
based emission budget trading programs and section VIII.K discusses 
coordinated implementation among states implementing individual rate-
based emission trading programs.
    d. Multi-state plans that address a subset of EGUs in a state.
    The EPA is clarifying in the final emission guidelines that a state 
may participate in more than one multi-state plan. Under this approach, 
the state would identify in its submittal the subset of affected EGUs 
in the state that are subject to the multi-state plan or plans. This 
could involve a subset of affected EGUs that are subject to a multi-
state plan, with the remainder of affected EGUs subject to a state's 
individual plan. Alternatively, different affected EGUs in a state may 
be subject to different multi-state plans. In all cases, the state 
would need to identify in each specific plan which affected EGUs are 
subject to such plan, with each affected EGU subject to only one multi-
state plan or subject only to the state's individual plan (if 
relevant).
    These scenarios may occur where a state chooses to cover affected 
EGUs in different ISOs or RTOs in different multi-state plans. This 
will provide states with flexibility to participate in multi-state 
plans that address the affected EGUs in a respective grid region, in 
the case where state borders cross grid regions.
    These scenarios may also occur where a state is served by multiple 
vertically integrated electric utilities with service territories that 
cross state lines. This will provide states with flexibility to 
participate in multi-state plans that address the affected EGUs owned 
and operated by a utility with a multi-state service territory.
6. Legal Bases and Considerations for State Plan Types and Approaches
    a. Legal basis for emission standards approach.
    The emission standards approach is consistent with the requirements 
of CAA section 111(d). If a state simply adopts the CO2 
emission performance rates, then the corresponding rate-based emission 
standards in the state plan establish standards of performance for 
affected EGUs as required under section 111(d)(1)(A). Similarly, if a 
state chooses to achieve the rate-based CO2 emission goal 
through rate-based emission standards applicable only to affected EGUs, 
or to achieve the mass-based CO2 emission goal through mass-
based emission standards applicable only to affected EGUs (or, 
alternatively, to achieve the mass CO2 goal and a new source 
CO2 emission complement through federally enforceable mass-
based emission standards in conjunction with state enforceable emission 
standards on new sources), then the set of rate-based emission 
standards or the set of mass-based emission standards in the state plan 
establishes standards of performance for affected EGUs as required 
under section 111(d)(1)(A). The EPA has the authority to approve 
emission standards for affected EGUs as part of a state plan under all 
three cases (as long as such emission standards meet the requirements 
of CAA section 111(d) and the final emission guidelines), thereby 
making such emission standards federally enforceable upon approval by 
the EPA. In all three cases, the emission standards must be 
quantifiable, verifiable, enforceable, non-duplicative and permanent; 
this ensures that the plan provides for implementation and enforcement 
of the standards of performance (i.e. the emission standards) as 
required by section 111(d)(1)(B). Finally, as described in section 
VIII.B.7.b below, standards of performance may include emission 
trading. Thus, the credit and allowance trading that is allowed under 
the emission standards approach is consistent with the statutory 
requirement that the plan establish standards of performance.
    We note that the standard the statute provides for the EPA's review 
of a state plan is whether it is ``satisfactory.'' We interpret a 
``satisfactory'' plan as one that meets all applicable requirements of 
the CAA, including applicable requirements of these guidelines. Some 
commenters suggested that ``satisfactory'' should be taken to mean 
something less (such as mostly or substantially meeting requirements) 
but the structure of 111(d) shows otherwise. When a state plan is 
unsatisfactory, section 111(d)(2) gives the EPA the ``same'' authority 
to promulgate a federal plan as the EPA has under section 110(c). Under 
section 110(c), the EPA has authority to promulgate a federal 
implementation plan if a SIP does not comply with all CAA requirements 
(see sections 110(k)(3) and 110(l)).
    For example, if an emission standards type plan includes an 
emission standard that is unenforceable due to defective rule language, 
then the plan is not satisfactory because it does not comply with the 
guideline requirement that emission standards must be enforceable. On 
the other hand, if a state plan complies with all applicable 
requirements of the CAA (including these guidelines), then the EPA must 
approve it as satisfactory. This is true even if the emission standards 
in the state plan are more stringent than the minimum requirements of 
these guidelines, or the state plan achieves more emission reductions 
than required by these guidelines. This follows from section 116 of the 
CAA as interpreted by the U.S. Supreme Court in Union Elec. Co. v. EPA, 
427 U.S. 246, 263-64 (1976).
    b. Legal basis for emissions trading in state plans.
    There are three legal considerations with respect to emissions 
trading in state plans. First, we explain how the definition of 
``standard of performance'' in section 111(a)(1) allows section 111(d) 
plans to include standards of performance that authorize emissions 
trading. Second, we explain how the EPA interprets the phrase 
``provides for implementation and enforcement of [the] standards of 
performance'' in the context of a rate-based ERC trading program. 
Third, we give a similar explanation of the EPA's interpretation of the 
same phrase in the context of a mass-based allowance trading program.
    (1). In the proposal, the EPA proposed that CAA section 111(d) 
plans may include standards of performance that authorize emissions 
averaging and trading. 79 FR 34830, 34927/1 (June 18, 2014). We are 
finalizing that states may include the use of emission trading in 
approvable state plans.
    For purposes of this legal discussion, in the case of an emission 
limitation expressed as an emission rate, trading takes the form of 
buying or selling ERCs that an affected EGU may generate if its actual 
emission rate is lower than its allowed emission rate or that an 
eligible resource may generate. In the case of an emission limitation 
expressed as a mass-based limit, trading takes the form of buying or 
selling allowances.
    As quoted in full above, the definition of ``standard of 
performance'' under CAA section 111(a)(1) is a ``standard for emissions 
of air pollutants which reflects the degree of emission limitation 
achievable through the application of the best system of emission 
reduction which . . . the Administrator determines has been adequately 
demonstrated.''
    Both an emission rate that may be met through tradable ERCs, and a 
mass limit requirement that emissions not exceed the number of tradable 
allowances surrendered by an affected source, qualify as a ``standard 
for emissions.'' The term ``standard'' is not defined, but its everyday 
meaning is a rule or

[[Page 64841]]

requirement,\813\ which, under the only (or at least a permissible) 
reading of the provision, would include an emission rate that may be 
met through tradable ERCs and a requirement to retire tradable 
allowances.
---------------------------------------------------------------------------

    \813\ E.g., ``Something that is set up and established by 
authority as a rule for the measure of quantity, weight, value, or 
quality.'' Webster's Third New International Dictionary 2223 (1967); 
see also The American College Dictionary (C.L. Barnhart, ed. 1970) 
(``an authoritative model or measure'').
---------------------------------------------------------------------------

    Treating a tradable emission rate or mass limit requirement as a 
``standard of performance'' is consistent with past EPA practice. In 
the Clean Air Mercury Rule, promulgated in 2005, the EPA established 
tradable mass limits as the emission guidelines for certain air 
pollutants from fossil fuel-fired EGUs, and explained that a tradable 
mass limit qualifies as a ``standard for emissions.'' \814\ In 
addition, in the 1995 Municipal Solid Waste (MSW) Combustor rule the 
EPA authorized emission trading by sources.\815\
---------------------------------------------------------------------------

    \814\ 70 FR 28606, 28616-17 (May 18, 2005).
    \815\ 60 FR 65387, 6540/2 (Dec. 19, 1995).
---------------------------------------------------------------------------

    It should be noted that CAA section 302(l) includes another 
definition of ``standard of performance,'' which is ``a requirement of 
continuous emission reduction, including any requirement relating to 
the operation or maintenance of a source to assure continuous emission 
reduction.'' As described above, section 111(d) contains its own, more 
specific definition of ``standard of performance,'' which a tradable 
emission rate or mass limit satisfies. Whether or not section 302(l) 
applies in light of section 111(d)'s more specific definition, a 
tradable emission rate or mass limit also meets section 302(l)'s 
requirements. A tradable emission rate applies continuously in that the 
source is under a continuous obligation to meet its emission rate, and 
that is so regardless of the averaging time, e.g., a rate that must be 
met on an annual basis. Similarly, a mass limit requirement implemented 
through the use of allowances applies continuously in that the source 
is continuously under an obligation to assure that at the appropriate 
time, its emissions will not exceed the allowances it will surrender. 
In this respect, a tradable emission rate or mass limit requirement is 
similar to a non-tradable emission rate that must be met over a 
specified period, such as one year. In all of these cases, a source is 
continuously subject to its requirement although it may be able to emit 
at different levels at different points in time. It should also be 
noted that a tradable emission rate or mass limit requirement is 
appropriate for CO2 emissions, the air pollutant covered by 
this rule, because the environmental effects of CO2 
emissions are not dependent on the location of the emissions.
    (2). In our final rule, we are prescribing certain specific 
requirements for trading systems for ERCs in a rate-based approach. 
These specific requirements are in addition to the generic requirements 
for any state plan (see section VIII.D.2.d below for the legal basis 
for the generic components for state plans) and are intended to ensure 
the integrity of the ERC trading system. The integrity of the trading 
system is key to ensuring that a state plan provides for implementation 
and enforcement of the standards of performance, as required by section 
111(d)(1)(B). Requirements relating to ERCs in a rate-based trading 
system, and allowances in a mass-based system, must also be submitted 
as federally enforceable components of the state plan, as such 
requirements provide for the implementation and enforcement of a 
tradable emission rate or mass limit for an affected EGU.
    However, as described in section VIII.C.6.d, the EPA has legal 
concerns regarding whether federally enforceable requirements under a 
CAA section 111(d) state plan can be imposed on entities other than 
affected EGUs. It is important to note that the use of ERCs and 
inclusion of state plan requirements regarding a rate-based trading 
system, and the use of allowances and inclusion of state plan 
requirements regarding a mass-based trading system, does not run afoul 
of these legal concerns, as neither the requirements of section 111(d) 
nor of the federally enforceable state plan in either case extend to 
non-EGU generators or third-party verifiers of such compliance units.
    (3). In our final rule, we are prescribing certain specific 
requirements for trading systems for allowances in a mass-based 
approach. These specific requirements are in addition to the generic 
requirements for any state plan (see section VIII.D.2.d below for the 
legal basis for the generic requirements for state plans) and are 
intended to ensure the integrity of the allowance trading system. The 
integrity of the trading system is key to ensuring that a state plan 
provides for implementation and enforcement of the standards of 
performance.
    c. Legal basis for state measures plan type.
    The EPA believes the state measures plan type is consistent with 
CAA section 111(d). Section 111(d)(1) requires a state to submit a plan 
that ``(A) establishes standards of performance for any existing source 
for [certain] air pollutant[s] . . . and (B) provides for the 
implementation and enforcement of such standards of performance.'' 
Section 111(d)(2)(A) indicates that the EPA must approve the state plan 
if it is ``satisfactory.''
    For states that choose to adopt and submit a state measures plan, 
such state must submit a state plan that includes standards of 
performance for CO2 emissions from affected EGUs in the form 
of a federally enforceable backstop in order to meet the requirements 
of section 111(d). Section 111(d) unambiguously requires a state to 
submit a plan that establishes standards of performance for certain 
sources, but does not mandate when such standards of performance must 
be in effect or implemented in order to meet applicable compliance 
deadlines. Instead, Congress has delegated to the EPA the determination 
of the appropriate effective date of standards of performance submitted 
under state plans to meet the requirements of section 111(d). In other 
words, where the statute is silent, the EPA has authority to provide a 
reasonable interpretation. The EPA's interpretation is that for states 
that submit state plans establishing standards of performance under 
section 111(d), the effective date of such standards of performance may 
be later in time, perhaps indefinitely, for a number of reasons and 
under certain conditions. A key condition is that the state plan 
provides for the achievement of the required reduction by means other 
than the standards of performance on the timetable required by the 
BSER, with provision for federally enforceable standards of performance 
to be implemented if those other means fall short. The EPA believes it 
is reasonable to defer the effective date for standards of performance 
for affected EGUs as long as affected EGU CO2 emissions are 
projected to achieve, and do achieve, the requisite state goal.
    Additionally, under the state measures plan type, if a state 
chooses to impose emission standards for the affected EGUs in 
conjunction with state measures that apply to other entities for any 
period prior to the triggering of the backstop, this final rule 
requires such emission standards to be submitted as federally 
enforceable measures included in the state plan. The EPA believes this 
is appropriate to help ensure the performance of a state measures plan 
will meet the requirements of this final rule. Section 111(d) clearly 
authorizes states to impose, and the EPA to approve, federally 
enforceable emission standards for affected EGUs. Though federally 
enforceable emission standards for affected EGUs in a state

[[Page 64842]]

measures plan themselves would not necessarily achieve the requisite 
state goals, the EPA is authorized to approve state plans when they 
satisfactorily meet applicable requirements. The EPA can evaluate 
whether a state measures plan is satisfactory by determining whether 
any federally enforceable emission standards for affected EGUs in 
conjunction with state measures on other entities will result in the 
achievement of the requisite emissions performance level. As previously 
explained in this final rule, the performance rates and the state goals 
are the arithmetic expression of BSER as applied across affected EGUs 
in a state as a source category. In a state measures plan, the 
evaluation of whether a state measures plan is satisfactory goes to 
evaluating both the state measures and any federally enforceable 
emission standards on the affected EGUs to determine whether the plan 
as a whole will result in the affected EGUs achieving the applicable 
goals that reflect BSER.
    Section 111(d)(1)(B) also requires a state to submit a program that 
provides for the implementation and enforcement of the applicable 
standards of performance. Under the state measures approach, this 
requirement regarding implementation is satisfied in part by the 
submission of an approvable trigger mechanism for the backstop and 
appropriate monitoring, reporting and recordkeeping requirements. The 
trigger mechanism provides for the ``implementation'' of the backstop, 
i.e., the standards of performance, by putting the backstop into effect 
once the associated trigger is deployed. In other words, when the 
CO2 performance level under a state plan exceeds the trigger 
as described in section VIII.C.4.b, the emission standards that were 
submitted as the federally enforceable backstop and any attendant 
requirements must be implemented and in effect. The statutory 
requirement under CAA section 111(d)(2) regarding enforcement is also 
satisfied under the state measures plan type by the state submitting 
standards of performance sufficient to meet the requisite emission 
performance rates or state goal, in the form of the backstop, for 
inclusion as part of the federally enforceable state plan.
    Additionally, by requiring states that choose to impose emission 
standards on affected EGUs under the state measures approach to submit 
such emission standards for inclusion in the federally enforceable 
plan, this requirement further provides for implementation and 
enforcement as required by the statute. Regulating the affected EGUs 
through federally enforceable emission standards themselves in 
conjunction with any state measures the state chooses to rely upon 
further assures the likelihood of the affected EGUs achieving the state 
goals as required under this rule and section 111(d).
    The state measures plan is a variation of the proposed portfolio 
approach in that both plan types allow the state to rely upon measures 
that impose requirements on sources other than affected EGUs in meeting 
the requisite state CO2 emission goal. The state measures 
plan type is also a variation of the proposed state commitment approach 
in that the measures involving entities other than affected EGUs are 
not included as part of the federally enforceable 111(d) state plan, 
but the state may rely upon such measures that have the effect of 
reducing CO2 emissions from affected EGUs as a matter of 
state law. The EPA took comment on the proposed portfolio approach and 
state commitment approach, and on the utilization of measures on 
entities other than affected EGUs in meeting the requirements of the 
emission guidelines and CAA section 111(d). With respect to the 
proposed state commitment approach, the EPA received comments 
recommending that the EPA require a federally enforceable backstop with 
emission standards sufficient to achieve the requisite CO2 
emission performance. The backstop component the EPA is finalizing as 
part of the state measures plan type is consistent with the EPA's 
statements in the proposal regarding states' obligations under section 
111(d) to establish emission standards for affected EGUs, as the 
backstop contains federally enforceable emission standards for affected 
EGUs that will achieve the requisite CO2 emission 
performance, and is consistent with comments received regarding the 
proposed state commitment approach.
    The state measures plan type the EPA is finalizing is also a 
logical outgrowth of the comments received on the proposed portfolio 
approach. As further explained below, legal questions remain as to 
whether state plans under section 111(d) can include federally 
enforceable measures that impose requirements on sources other than 
affected EGUs. However, a number of commenters and stakeholders 
expressed robust support for the ability to rely on measures and 
programs that do not impose requirements on affected EGUs themselves 
through plan types such as the proposed portfolio and state commitment 
approaches. The EPA is reasonably interpreting 111(d) as authorizing 
the state measures plan type, and believes this plan type is also 
responsive to, and accommodating of, states and stakeholders who have 
expressed the importance of being able to rely upon various measures 
that have the effect of reducing CO2 emissions from affected 
EGUs. The EPA is finalizing the state measures plan type upon careful 
consideration of statutory requirements and comments received based on 
the proposed portfolio approach and state commitment approach.
    The EPA additionally notes that the state measures plan type is not 
precluded by the recent Ninth Circuit Court of Appeals' decision in 
Committee for a Better Arvin et al. v. US EPA et al., Nos. 11-73924 and 
12-71332 (May 20, 2015). The court held that the EPA violated the CAA 
by approving a California SIP which relied on emission reductions from 
state-only mobile source standards (``waiver measures'') without 
including those standards in the SIP. The court first looked at the 
plain language of section 110(a)(2)(A) of the CAA, which states that 
SIPs ``shall include'' the emission limitations and other control 
measures on which a state relies to comply with the CAA. The court then 
stated that the EPA's action was also inconsistent with the structure 
of the CAA. The EPA has the primary responsibility to protect the 
nation's air quality, but in the court's view, the EPA itself would be 
unable to enforce the state-only standards. In addition, the court 
stated that the EPA's action was inconsistent with citizens' right to 
enforce SIP provisions under section 304.
    There are a number of reasons why this decision does not preclude 
the state measures plan type. The Ninth Circuit's textual analysis does 
not apply here, as the language of section 110(a)(2)(A) does not 
control for 111(d) state plans. Section 111(d)(1) requires state plans 
to ``establish standards of performance'' and to ``provide for 
implementation and enforcement'' of the standards of performance, but, 
unlike section 110(a)(2)(A), section 111(d) does not specifically say 
that every emission reduction measure must be ``included'' in the state 
plan and be made federally enforceable. Even if section 111(d) did 
impose such requirements, the state measures approach satisfies them 
because the trigger is included in the plan as a federally enforceable 
implementation measure, and the backstop included in the plan also 
contains standards of performance that reflect the BSER and are 
federally enforceable once they are triggered.
    The Ninth Circuit's structural analysis also does not apply. The 
availability of the trigger and backstop gives the EPA

[[Page 64843]]

and citizens a federally enforceable route to ensure that all necessary 
emission reductions take place in order to achieve the standards of 
performance. This is markedly different than the state-only standards, 
where according to the Ninth Circuit, the EPA and citizens had no route 
to ensure that all necessary emission reductions took place in order to 
attain the NAAQS. In addition, case law suggests that federal 
enforceability for every requirement may not be necessary when there 
are sufficient federally enforceable requirements to satisfy the 
statute, see National Mining Ass'n v. United States EPA, 59 F.3d 1351 
(D.C. Cir. 1995); in this case federal enforceability for the state-
only measures is not necessary to meet the statutory requirements of 
section 111(d)(1) as the federally enforceable trigger and backstop are 
sufficient.
    d. Legal considerations with proposed portfolio approach.
    The EPA is not finalizing the portfolio approach that was included 
in the proposed rulemaking, 79 FR 34830, 34902 (June 18, 2014). In the 
proposal, the EPA noted that the portfolio approach raised legal 
questions. 79 FR 34830, 34902-03. A number of commenters stated that 
the portfolio approach is unlawful because it exceeds the limitations 
that section 111(d)(1) places on state plans. Upon further review, we 
agree with these comments.
    Section 111(d)(1) provides that state plans shall ``establish[] 
``standards of performance for any existing source'' and ``provide[] 
for the implementation and enforcement of . . . standards of 
performance'' under CAA section 111(d)(1). Although in the proposal we 
identified possible interpretations of section 111(d)(1) that could 
justify the proposed portfolio approach, after reviewing the comments, 
we are not adopting those interpretations. Because section 111(d)(1) 
specifically requires state plans to include only (A) standards for 
emissions imposed on affected sources and (B) measures that implement 
and enforce such standards,\816\ we interpret it as allowing federal 
enforceability only of requirements or measures that are in those two 
specifically required provisions. We therefore do not interpret the 
term ``implementation of . . . such standards of performance'' to 
authorize the EPA to approve state plans with obligations enforceable 
against the broad array of non-emitting entities that would have been 
implicated by the portfolio approach. Thus, the EPA is not finalizing 
the portfolio approach, and in the event that states submit such 
measures to the EPA for inclusion in the state plan, the EPA would not 
approve them into the state plan and therefore would not make them 
federally enforceable.
---------------------------------------------------------------------------

    \816\ Such measures include, for example, in this rule, 
requirements for ERCs.
---------------------------------------------------------------------------

    We note that section 111(d) limits on federal enforceability of 
requirements against non-affected sources do not imply that the BSER 
cannot be based on actions by non-affected sources. As discussed in 
section V, the BSER may be based on the ability of owners/operators of 
affected sources to engage in commercial relationships with a wide 
range of other entities, from the vendors, installers, and operators of 
air pollution control equipment to, in this rulemaking, owners/
operators of RE.
    The EPA notes it is also not finalizing the proposed state 
commitment approach or state crediting approach. The EPA believes the 
finalized state measures plan type provides states with the same 
flexibilities as would have been allowed under these two proposed 
approaches, and does so in a way that is legally supportable by the 
CAA. Therefore, the EPA does not believe it necessary to finalize the 
state commitment approach or state crediting approach.
    e. Legal basis for multi-state plans.
    While nothing in section 111(d)(1) explicitly authorizes either 
states to adopt and submit multi-state plans, or the EPA to approve 
them as satisfactory, nothing in section 111(d)(1) explicitly prohibits 
it, either. In addition, nothing in section 111(d)(2)(A)'s standard of 
``satisfactory'' prohibits the EPA from considering multi-state plans 
as satisfactory. There is thus a gap that the EPA may reasonably fill.
    In light of the purpose of these emission guidelines, to reduce 
emissions of a pollutant that globally mixes in the stratosphere, and 
the mechanisms to reduce those emissions, which may have beneficial 
effects across state lines, it is reasonable to allow for multi-state 
plans. Thus, our gap-filling interpretation of section 111(d) in this 
context is reasonable.

D. State Plan Components and Approvability Criteria

1. Approvability Criteria
    In the ``Criteria for Approving State Plans'' section of the 
preamble to the June 2014 proposal (section VIII.C), the EPA proposed 
the following as necessary components of an approvable state plan:
    1. The plan must contain enforceable measures that reduce EGU 
CO2 emissions;
    2. The projected CO2 emission performance by affected 
EGUs must be equivalent to or better than the required CO2 
emission performance level in the state plan;
    3. The EGU CO2 emission performance must be quantifiable 
and verifiable;
    4. The plan must include a process for state reporting of plan 
implementation, CO2 emission performance outcomes, and 
implementation of corrective measures, if necessary.
    After reviewing the comments we received concerning the 
approvability criteria, the EPA has decided against maintaining the 
four proposed approvability criteria separately from the list of 
components required for an approvable plan, which may be confusing and 
potentially redundant. The EPA has determined that a satisfactory state 
plan that meets the required plan components discussed below will 
inevitably meet the proposed approvability criteria. The EPA, 
therefore, has incorporated the proposed approvability criteria into 
the section titled ``Components of a state plan submittal'' (section 
VIII.D.2 below). There is no functional change in the approvability 
criteria or the components of a state plan addressed in the proposal; 
they are simply combined and this change does not have a substantive 
effect on state plan development or approval.
    Under the proposed ``Enforceable Measures'' criterion (section 
VIII.C.1 of the proposal preamble), the EPA specifically requested 
comment on the appropriateness of applying existing EPA guidance on 
enforceability to state plans under CAA section 111(d), considering the 
types of entities that might be included in a state plan.\817\
---------------------------------------------------------------------------

    \817\ The existing guidance documents referenced were: (1) 
September 23, 1987 memorandum and accompanying implementing 
guidance, ``Review of State Implementation Plans and Revisions for 
Enforceability and Legal Sufficiency,'' (2) August 5, 2004 
``Guidance on SIP Credits for Emission Reductions from Electric-
Sector Energy Efficiency and Renewable Energy Measures,'' and (3) 
July 2012 ``Roadmap for Incorporating Energy Efficiency/Renewable 
Energy Policies and Programs into State and Tribal Implementation 
Plans, Appendix F.''
---------------------------------------------------------------------------

    The EPA also requested comment on whether the agency should provide 
guidance on enforceability considerations related to requirements in a 
state plan for entities other than affected EGUs, and if so, what types 
of entities. Comments received strongly suggested that the EPA provide 
guidance on enforceability considerations for non-EGU affected 
entities, particularly for RE and EE. Comments also requested 
additional guidance specific to this rulemaking, including examples of 
enforceable measures for specific activities, such as

[[Page 64844]]

solar thermal technologies, waste heat recovery, net-metering energy 
savings and state RPS.
    These enforcement considerations arose primarily under the proposed 
portfolio approach for state plans, which would have allowed state 
plans to include federally enforceable measures that apply to entities 
that are not affected EGUs. In this action, the EPA is finalizing the 
state measures approach instead of the portfolio approach, under which 
a state can rely upon measures that are not federally enforceable as 
long as the plan also includes a backstop of federally enforceable 
emission standards that apply to affected EGUs. As explained in depth 
in section VIII.C, if the state is adopting the state measures 
approach, the state plan submittal will need to specify, in the 
supporting materials, the state-enforceable measures that the state is 
relying upon, in conjunction with any federally enforceable emission 
standards for affected EGUs, to meet the emission guidelines. As part 
of the state measures approach, the EPA is finalizing a requirement for 
a federally enforceable backstop, which requires the affected EGUs to 
meet emission standards that fully achieve the CO2 emission 
performance rates or the state's CO2 emission goal if the 
state measures do not meet the state's mass-based CO2 
emission goal. Because the EPA is not finalizing the portfolio 
approach, which would have allowed states to include federally 
enforceable measures in a state plan that apply to entities that are 
not affected EGUs, the agency is not providing additional guidance on 
federal enforceability of measures that might apply to such entities. 
As proposed, we are requiring that state plans include a demonstration 
that plan measures are enforceable, which for emission standards plan 
types is discussed in section VIII.D.2.b.3 below and for state measures 
plan types is discussed in section VIII.D.2.c.6 below.
    Commenters also requested that the EPA allow states to rely on 
provisions with flexible compliance mechanisms in state plans and 
clarify how to address flexible compliance mechanisms when 
demonstrating achievement of a state CO2 emission goal. 
Additionally, a commenter requested that the enforceability mechanisms 
that the EPA requires in state plans should support existing programs, 
as well as new programs in other states, by minimizing program changes 
required purely to conform with federal requirements, while still 
providing enough additional program review and accounting to ensure 
that CO2 emission reductions are achieved. These and related 
comments contributed to the EPA's decision to finalize the option for 
states to submit a state measures plan, which would be comprised, at 
least in part, of measures implemented by the state that are not 
included as federally enforceable components of the plan, with a 
backstop of federally enforceable emission standards for affected EGUs 
that fully meet the emission guidelines and that would be triggered if 
the plan failed to achieve the CO2 emission performance 
levels specified in the plan on schedule. For more information on the 
state measures plan approach, see section VIII.C.3 of this preamble 
above.
2. Components of a State Plan Submittal
    In this action, the EPA is finalizing that a state plan submittal 
must include the components described below. As a result of 
constructive comments received from many commenters and additional 
considerations, the EPA is finalizing state plan components that are 
responsive to that input and are appropriate for the types of state 
plans allowed in the final emission guidelines. A state plan submittal 
must also be consistent with additional specific requirements elsewhere 
in this final rule and with the EPA implementing regulations at 40 CFR 
60.23-60.29, except as otherwise specified by this final rule. These 
requirements apply to both individual state plan submittals and multi-
state plan submittals. When a state plan submittal is approved by the 
EPA, the EPA will codify the approved CAA section 111(d) state plan in 
40 CFR part 62. Section VIII.D.3 discusses the components of a state 
plan submittal that would be codified as the state CAA section 111(d) 
plan when the state plan submittal is approved by the EPA.
    The EPA is finalizing that states can choose to meet the emission 
guidelines through one of two types of state plans: an emission 
standards plan type or a state measures plan type. A state pursuing the 
emission standards plan type may opt to submit a plan that meets the 
CO2 emission performance rates for affected EGUs or meets 
the state rate-based or mass-based CO2 emission goal for 
affected EGUs. A state implementing a state measures approach plan type 
must submit a plan where the state measures, in conjunction with any 
emission standards on the affected EGUs, result in achievement of the 
state mass-based CO2 goal for affected EGUs. The backstop 
required to be submitted as part of a state measures plan may achieve 
the CO2 emission performance rates for affected EGUs or the 
state rate-based or mass-based CO2 emission goal. The 
content of the state plan submittal will vary depending on which plan 
type the state decides to adopt. States that choose to participate in 
multi-state plans must adequately address plan components that apply to 
all participating states in the multi-state plan.
    The rest of this section covers components that are required for 
all types of plans, as well as components specific to each specific 
type of plans. Section VIII.D.2.a addresses the components required for 
all plan submittals. Section VIII.D.2.b addresses the additional 
components required for submittals under the emission standards plan 
type. Section VIII.D.2.c addresses additional components required for 
submittals under the state measures plan type.
    a. Components required for all state plan submittals.
    The EPA is finalizing requirements that a final plan submittal must 
contain the following components, in addition to those in either 
section VIII.D.2.b (for the emission standards plan type) or VIII.D.2.c 
(for the state measures plan type) of this section.
    (1) Description of the plan approach and geographic scope.
    The description of the plan type must indicate whether the state 
will meet the emission guidelines on an individual state basis or 
jointly through a multi-state plan, and whether the state is adopting 
an emission standards plan type or a state measures plan type. For 
multi-state plans this component must identify all participating states 
and geographic boundaries applicable to each component in the plan 
submittal. If a state intends to implement its individual plan in 
coordination with other states by allowing for the interstate transfer 
of ERCs or emission allowances, such links must also be 
identified.\818\
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    \818\ If applicable, this plan component must also identify if 
the plan is being submitted as a ``ready-for-interstate-trading'' 
plan, as discussed in section VIII.J.3 and VIII.K.4.
---------------------------------------------------------------------------

    (2) Applicability of state plans to affected EGUs.
    The state plan submittal must list the individual affected EGUs 
that meet the applicability criteria of 40 CFR 60.5845 and provide an 
inventory of CO2 emissions from those affected EGUs for the 
most recent calendar year prior to plan submission for which data are 
available.
    (3) Demonstration that a state plan will achieve the CO2 
emission performance rates or state CO2 emission goal.
    A state plan submittal must demonstrate that the federally

[[Page 64845]]

enforceable emission standards for affected EGUs and/or state measures 
are sufficient to meet either the CO2 emission performance 
rates or the state's CO2 emission goal for affected EGUs in 
the emission guidelines for the interim and final plan performance 
periods. This includes during the interim period of 2022-2029, 
including the interim step 1 period (2022-2024); interim step 2 period 
(2025-2027); and interim step 3 period (2028-2029) period, as well as 
during the final period of 2030-2031 and subsequent 2-year 
periods.\819\ A demonstration of CO2 emission performance is 
required through 2031. For the post-2031 period, the demonstration 
requirement may be satisfied by showing that emission standards or 
state measures on which the demonstration through 2031 is based are 
permanent and will remain in place. As discussed in more detail in 
section VIII.J, states adopting a plan based upon a mass-based state 
CO2 emission goal must demonstrate that they have addressed 
the risk of potential emission leakage in their mass-based state plan.
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    \819\ State plans may meet the CO2 emission 
performance rates in the emission guidelines during the interim plan 
performance step periods, or assign different interim step 
CO2 emission performance rates, provided the 
CO2 emission performance rates in the emission guidelines 
are achieved during the full interim period. Likewise, a state plan 
may meet the interim step state CO2 emission goals in the 
emission guidelines or establish different interim step 
CO2 emission levels, provided the state interim 
CO2 goal is achieved during the full interim period.
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    The type of demonstration of CO2 emission performance 
and documentation required for such a demonstration in a state plan 
submittal will vary depending on how the CO2 emission 
standards for affected EGUs and/or state measures in a state plan are 
applied across the fleet of affected EGUs in a state, as discussed 
below.\820\
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    \820\ For simplicity, the EPA refers here to state measures 
under a state measures plan as being included ``in the state plan'' 
although such state-enforceable measures are not codified as part of 
the federally enforceable approved state plan. However, the approval 
of a state measures plan is dependent on a demonstration in the 
state plan submittal that those state-enforceable measures meet the 
requirements in the emission guidelines and that those state 
measures, alone or in combination with federally enforceable 
emission standards for affected EGUs, will meet the mass-based 
CO2 goal.
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    (a) State plan type designs that require a projection of 
CO2 emission performance. Whether a projection of affected 
EGU CO2 emission performance must be included in a state 
plan submittal depends on the design of the state plan. The following 
plan designs do not require a projection of CO2 emission 
performance by affected EGUs under the state plan because they ensure 
that the CO2 emission performance rates or state rate-based 
or mass-based CO2 goals are achieved when affected EGUs 
comply with the emission standards:

     State plan establishes separate rate-based 
CO2 emission standards for affected fossil fuel-fired 
electric utility steam generating units and stationary combustion 
turbines (in lb CO2/MWh) that are equal to or lower than 
the CO2 emission performance rates in the emission 
guidelines during the interim and final plan performance periods.
     State plan establishes a single rate-based 
CO2 emission standard for all affected EGUs that is equal 
to or lower than the state's rate-based CO2 goal in the 
emission guidelines during the interim and final plan performance 
periods.
     State plan establishes mass-based CO2 
emission standards for affected EGUs that cumulatively do not exceed 
a state's mass-based CO2 goal in the emission guidelines 
during the interim and final plan performance periods.
     State plan establishes mass-based CO2 
emission standards for affected EGUs that, together with state 
enforceable limits on mass emissions from new EGUs, cumulatively do 
not exceed the state's EPA-specified mass CO2 emission 
budget \821\ in the emission guidelines during the interim and final 
plan performance periods.
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    \821\ A state's EPA-specified mass CO2 emission 
budget is the state's mass-based CO2 goal for affected 
EGUs plus the EPA-specified new source CO2 emission 
complement. See section VIII.J.2.b.

    All other state plan designs must include a projection of 
CO2 emission performance by affected EGUs under the state 
plan.
    For example, if a state chooses to apply rate-based CO2 
emission standards to individual affected EGUs, or to subcategories of 
affected EGUs (such as fossil fuel-fired electric utility steam 
generating units and stationary combustion turbines), at a lb 
CO2/MWh rate that differs from the CO2 emission 
performance rates or the state's rate-based CO2 goal in the 
emission guidelines, then a projection is required. Also, if a state 
chooses to implement a mass-based program including both affected EGUs 
and new EGUs, but with total allowable emissions in excess of the 
presumptively approvable EPA-specified mass CO2 emission 
budget for that state, the state must provide a projection of 
CO2 emission performance. Likewise, if a state chooses a 
state measures state plan approach, a projection of CO2 
emission performance is required.
    (b) Methods and tools. A satisfactory demonstration of the future 
CO2 emission performance of affected EGUs must use 
technically sound methods that are reliable and replicable. A state 
plan submittal must explain how the projection method and/or tool works 
and why the method and/or tool chosen is appropriate considering the 
type of emission standards and/or state measures included (or relied 
upon, in the case of state measures) in a state plan. The results of 
the demonstration must be reproducible using the documented assumptions 
described in the state plan submittal. The method and projection of EGU 
generation and CO2 emissions can differ from the EPA's 
forecast in the RIA. The EPA received comments on whether it would 
require specific modeling tools and input assumptions. Commenters 
raised concerns that the EPA may require states to use proprietary 
models, and that states do not have the financial resources to use such 
models. The EPA is not requiring a specific type of method or model, as 
long as the one chosen uses technically sound methods and tools that 
establish a clear relationship between electricity grid interactions 
and the range of factors that impact future EGU economic behavior, 
generation, and CO2 emissions. The EPA will assess whether a 
method or tool is technically sound based on its capability to 
represent changes in the electric system commensurate to the set of 
emission standards and state measures in a state plan while accounting 
for the key parameters specified in section VIII.D.2.a.(3)(c) below. 
Including a base case CO2 emission projection in the state 
plan submittal (i.e., one that does not include any federally 
enforceable CO2 emission standards included in a plan or 
state-enforceable measures referenced in a plan submittal), will help 
facilitate the EPA's assessment of the CO2 emission 
performance projection. Methods and tools could range from applying 
future growth rates to historical generation and emissions data, using 
statistical analysis, or electric sector energy modeling.
    (c) Required documentation of projections. When required to provide 
a CO2 emission performance projection, the state must also 
provide comprehensive documentation of analytic parameters for the EPA 
to assess the reasonableness of the projection. The analytic 
parameters, when considered as a whole, should reflect a logically 
consistent future outlook of the electric system. Refer to the 
Incorporating RE and Demand-side EE Impacts into State Plan 
Demonstrations TSD of the final rule for further details on quantifying 
impacts of eligible RE and demand-side EE measures.
    The CO2 emission performance projection documentation 
must include:


[[Page 64846]]


     Geographic representation, which must be appropriate 
for capturing impacts and/or changes in the electric system
     Time period of analysis, which must extend through 2031
     Electricity demand forecast (MWh load and MW peak 
demand) at the state and regional level. If the demand forecast is 
not from NERC, an ISO or RTO, EIA, or other publicly available 
source, then the projection must include justification and 
documentation of underlying assumptions that inform the development 
of the demand forecast, such as annual economic and demand growth 
rate, population growth rate.
     Planning reserve margins
     Planned new electric generating capacity
     Analytic treatment of the potential for building 
unplanned new electric generating capacity
     Wholesale electricity prices
     Fuel prices, when applicable;
     Fuel carbon content
     Unit-level fixed operations and maintenance costs, when 
applicable;
     Unit-level variable operations and maintenance costs, 
when applicable;
     Unit-level capacity
     Unit-level heat rate
     If applicable, EGU-specific actions in the state plan 
designed to meet the required CO2 emission performance, 
including their timeline for implementation
     If applicable, state-enforceable measures, with 
electricity savings and renewable electricity generation (MWhs) 
expected for individual and collective measures, as applicable. 
Quantification of MWhs expected from EE and RE measures will involve 
assumptions that states must document, as described in the 
Incorporating RE and Demand-side EE Impacts into State Plan 
Demonstrations TSD.
     Annual electricity generation (MWh) by fuel type and 
CO2 emission levels, for each affected EGU
     ERC or emission allowance prices, when applicable

    The state must also provide a clear demonstration that the state 
measures and/or federally enforceable emission standards informing the 
projected achievement of the emission performance requirements will be 
permanent and remain in place.
    The EPA encourages participation in regional modeling efforts which 
are designed to allow sharing of data and help promote consistent 
approaches across state boundaries. A state that submits a single-state 
plan must consider interstate transfer of electricity across state 
boundaries, taking into account other states' plan types reflecting the 
best available information at the time of the CO2 emission 
performance projection. Projections of CO2 emission 
performance for multi-state plans and single-state plans that include 
multi-state coordination must either use a single (regional) 
electricity demand forecast or must document the use of electricity 
demand forecasts from different information sources and demonstrate how 
any inconsistencies between the individual electricity demand forecasts 
have been reconciled.
    (d) Additional projection requirements under a rate-based emission 
standards plan. For an emission standards plan that applies rate-based 
CO2 emission standards to individual affected EGUs, or to 
subcategories of affected EGUs, at a lb CO2/MWh rate that 
differs from the CO2 emission performance rates or the 
state's rate-based CO2 goal in the emission guidelines, a 
projection of affected EGU CO2 emission performance is 
required. The state must demonstrate that the weighted average 
CO2 emission rate of affected EGUs, when weighted by 
generation (in MWh) from affected EGUs subject to the different rate-
based emission standards, will be equal to or less than the 
CO2 emission performance rates or the state's rate-based 
CO2 emission goal during the interim and final plan 
performance periods.
    The projection will involve an analysis of the change in generation 
of affected EGUs given the compliance costs and incentives under the 
application of different emission rate standards across affected EGUs 
in a state. It must accurately represent the emission standards in the 
plan, including the use of market-based aspects of the emission 
standards (if applicable), such as use of ERCs or emission allowances 
as compliance instruments.
    In addition to the elements described in the previous section (c), 
the projection under this plan design must include:

     The assignment of federally enforceable emission 
standards for each affected EGUs;
     A projection showing how generation is expected to 
shift between affected EGUs and across affected EGUs and non-
affected EGUs over time;
     Underlying assumptions regarding the availability and 
anticipated use of the MWh of electricity generation or electricity 
savings from eligible measures that can be issued ERCs;
     The specific calculation (or assumption) of how 
eligible MWh of electricity generation or savings that can be issued 
ERCs are being used in the projection to adjust the reported 
CO2 emission rate of affected EGUs, consistent with the 
accounting methods for adjusting the CO2 emission rate of 
an affected EGU specified in section VIII.K.1 of the emission 
guidelines, if applicable;
     ERC prices, if applicable;
     If a state plan provides for the ability of RE 
resources located in states with mass-based plans to be issued ERCs 
for use in adjusting the reported CO2 emission rates of 
affected EGUs, consideration in the projection that such resources 
must meet geographic eligibility requirements, based on power 
purchase agreements or related documentation, consistent with the 
requirements at section VIII.K.1 and section VIII.L; and
     Any other applicable assumptions used in the 
projection.

    (e) Additional projections requirements for a state measures plan. 
For a state measures plan, a projection of affected EGU CO2 
emission performance must demonstrate that the state measures, whether 
alone or in conjunction with any federally enforceable CO2 
emission standards for affected EGUs, will achieve the state's mass-
based CO2 goals in the emission guidelines for the interim 
and final periods. The projection must accurately represent individual 
state-enforceable measures (or bundled measures) and timing for 
implementation of these state measures.
    A state must demonstrate that its state-enforceable measures, along 
with any federally enforceable CO2 emission standards for 
affected EGUs included in a state plan, will achieve the state mass-
based CO2 goal. In addition to the elements described in 
section VIII.D.2.a.(3).(c), the state must clearly document, at a 
minimum:

     The assignment of federally enforceable emission 
standards for each affected EGUs, if applicable; and
     the individual state measures, including their 
projected impacts over time.

    Because different types of state measures could have varying 
degrees of impact on reducing or avoiding CO2 emissions from 
affected EGUs, and different state measures may interact with one 
another in terms of CO2 emission reduction impacts, the 
method and tools a state uses to project CO2 emissions 
impacts must have the capability to project how the combined set of 
state-enforceable measures are likely to impact CO2 
emissions at affected EGUs. If a state chooses to use an emission 
budget trading program as a mass-based state measure, for example, the 
state must choose an analytic method or tool that can account for and 
properly represent any program flexibilities that impact CO2 
emissions from affected EGUs, such as use of out-of-sector GHG offsets 
and cost-containment provisions. The state would show that the 
emissions budget trading program relied upon for the state measures 
plan, as well as any other state measures, ensure that the sum of 
emissions at all affected EGUs will be lower than or equal to the 
state's CO2 emission goal in the time periods specified in 
these guidelines. All flexibilities must be clearly documented in the 
demonstration.

[[Page 64847]]

    (4) Monitoring, reporting and recordkeeping requirements for 
affected EGUs.
    The state plan submittal must specify how each emission standard is 
quantifiable and verifiable by describing the CO2 emission 
monitoring, reporting and recordkeeping requirements for affected EGUs. 
The applicable monitoring, recordkeeping and reporting requirements for 
affected EGUs are outlined in section VIII.F.
    In the June 2014 proposal, the EPA proposed that states must 
include in their state plans a record retention requirement for 
affected EGUs to maintain records for at least 10 years following the 
date of each occurrence, measurement, maintenance, corrective action, 
report or record. Commenters requested clarification of the record 
retention requirements for states as compared to for affected EGUs and 
also requested that the EPA clarify onsite versus offsite record 
maintenance requirements for affected EGUs. The EPA is finalizing that 
states must include in their plans a record retention requirement for 
affected EGUs of not less than 5 years following the date of each 
compliance period, compliance true-up period, occurrence, measurement, 
maintenance, corrective action, report, or record, whichever is latest. 
Affected EGUs must maintain each record onsite for at least 2 years 
after the date of the occurrence of each record and may maintain 
records offsite and electronically for the remaining years. Each record 
must be in a form suitable and readily available for expeditious 
review. The EPA finds that these final recordkeeping requirements are 
appropriate and consistent with the requirements for other CAA section 
111(d) emission guidelines.
    (5) State reporting and recordkeeping requirements.
    A state plan submittal must contain the process, content and 
schedule for state reporting to the EPA on plan implementation and 
progress toward meeting the CO2 emission performance rates 
or state CO2 emission goal.
    The EPA requested comments on whether full reports containing all 
of the report elements should only be required every 2 years and on the 
appropriate frequency of reporting of the different proposed elements, 
considering both the goals of minimizing unnecessary burdens on states 
and ensuring program transparency and effectiveness. Commenters 
recognized that different reporting frequencies may be appropriate for 
different types of state plans. The EPA agrees with the commenters and 
is finalizing state reporting requirements based on the type of plan 
the state chooses to adopt and implement. These state reporting 
requirements and reporting periods are discussed in section VIII.D.2.b 
(for emission standards plan types) and VIII.D.2.c (for state measures 
plan types). The EPA finalizes that each state report is due to the EPA 
no later than the July 1 following the end of each reporting period. 
The EPA recognizes the multiple comments received recommending 
extending the state report due date from July 1 to a later date or to 
allow the states the flexibility to propose an alternative report 
submittal date. The EPA is not pursuing these recommendations due to 
the implications of the state reports' due date and the trigger and 
schedule for implementation of corrective measures (for the emission 
standards approach) or the backstop federally enforceable emission 
standards (for the state measures approach). The EPA believes the July 
1 deadline for states to submit reports to the EPA on plan 
implementation is feasible given that the information required to be 
included in the reports will be available per the reporting 
requirements for affected EGUs in state plans.
    In addition to the state reporting requirements discussed in 
section VIII.D.2.b (for emission standards approach) and VIII.D.2.c 
(for state measures approach) and as discussed below, states must 
include in the supporting material of a final state plan submittal a 
timeline with all the programmatic plan milestone steps the state will 
take between the time of the final state plan submittal and 2022 to 
ensure the plan is effective as of 2022. The EPA is also finalizing a 
requirement that states must submit a report to the EPA in 2021 that 
demonstrates that the state has met the programmatic plan milestone 
steps that the state indicated it would take from the submittal of the 
final plan through the end of 2020, and that the state is on track to 
implement the approved state plan as of January 1, 2022. A final state 
plan submission must include a requirement for the state to submit this 
report to the EPA no later than July 1, 2021. This report will help the 
EPA further assist and facilitate plan implementation with states as 
part of an ongoing joint effort to ensure the necessary reductions are 
achieved.
    The EPA is finalizing the requirement that submissions related to 
this program be submitted electronically. Specifically, this includes 
negative declarations, state plan submittals (including any supporting 
materials that are part of a state plan submittal), any plan revisions, 
and all reports required by the state plan. The EPA is developing an 
electronic system to support this requirement that can be accessed at 
the EPA's Central Data Exchange (CDX) (http://www.epa.gov/cdx/). See 
section VIII.E.8 for additional information on electronic submittal 
requirements.
    In the June 2014 proposal, the EPA proposed that states must keep 
records, for a minimum of 20 years, of all plan components, plan 
requirements, plan supporting documentation and status of meeting the 
plan requirements, including records of all data submitted by each 
affected EGU used to determine compliance with its emission standards. 
The EPA received multiple comments recommending that the EPA reduce 
recordkeeping requirements due to the burden in expenditure of 
resources and manpower to maintain records for at least 20 years. 
Commenters recommended that recordkeeping requirements be reduced to 5 
years consistent with emission guidelines for other existing sources.
    After considering the comments received, this final rule requires 
that a state must keep records of all plan components, plan 
requirements, supporting documentation, and the status of meeting the 
plan requirements defined in the plan for the interim plan period from 
2022-2029 (including interim steps 1, 2 and 3). After 2029, states must 
keep records of all information relied upon in support of any continued 
demonstration that the final CO2 emission performance rates 
or goals are being achieved. The EPA agrees with comments that a 20-
year record retention requirement could be unduly burdensome, and has 
reduced the length of the record retention requirement for the final 
rule. During the interim period, states must keep records for 10 years 
from the date the record is used to determine compliance with an 
emission standard, plan requirement, CO2 emission 
performance rate or CO2 emission goal. During the final 
period, states must keep records for 5 years from the date the record 
is used to determine compliance with an emission standard, plan 
requirement, CO2 emission performance rate or CO2 
emissions goal. All records must be in a form suitable and readily 
available for expeditious review. States must also keep records of all 
data submitted by each affected EGU that was used to determine 
compliance with each affected EGU's emission standard, and such data 
must meet the requirements of the emission guidelines, except for any 
information that is submitted to the EPA electronically pursuant to 
requirements in 40 CFR part 75. If the state is adopting and 
implementing the state measures approach, the state must also

[[Page 64848]]

maintain records of all data regarding implementation of each state 
measure and all data used to demonstrate achievement of the mass 
CO2 emission goal and such data must meet the requirements 
of the emission guidelines. The EPA finds that these final 
recordkeeping requirements balance the need to maintain records while 
reducing the strain on state resources.
    (6) Public participation and certification of hearing on state 
plan.
    A robust and meaningful public participation process during state 
plan development is critical. For the final plan submittal, states must 
meaningfully engage with members of the public, including vulnerable 
communities, during the plan development process. This section 
describes how the EPA will evaluate a state plan for compliance with 
the minimum required elements for public participation provided in the 
existing implementing regulations as well as recommendations for other 
steps the state can take to assure robust and inclusive public 
participation.
    The existing implementing regulations regarding public 
participation requirements are in 40 CFR 60.23(c)-(f). Per the 
implementing regulations, states must conduct a public hearing on a 
final state plan before such plan is adopted and submitted. State plan 
development can be enhanced by tapping the expertise and program 
experience of several state government agencies. The EPA encourages 
states to include utility regulators (e.g. the PUCs) and state energy 
offices as appropriate early on and throughout in the development of 
the state plan.\822\ The EPA notes that utility regulators and state 
energy offices have the opportunity during the public participation 
processes required for state plans to provide input as well. The EPA 
also encourages states to conduct outreach meetings (that could include 
public hearings or meetings) with vulnerable communities on its initial 
submittal before the plan is submitted. In its final plan submittal, a 
state must provide certification that the state made the plan submittal 
available to the public and gave reasonable notice and opportunity for 
public comment on the state plan submittal. The state must demonstrate 
that the public hearing on the state plan was held only after 
reasonable notice, which will be considered to include, at least 30 
days prior to the date of such hearing, notice given to the public by 
prominent advertisement announcing the date(s), time(s) and place(s) of 
such hearing(s). For each hearing held, a state plan submittal must 
include in the supporting documentation the list of witnesses and their 
organizational affiliations, if any, appearing at the hearing, and a 
brief written summary of each presentation or written submission 
pursuant to the requirements of the implementing regulations at 40 CFR 
60.23. Additionally, the EPA recommends that states work with local 
municipalities, community-based organizations and the press to 
advertise their state public hearing(s). The EPA also encourages states 
to provide background information about their proposed final state plan 
or their initial submittal in the appropriate languages in advance of 
their public hearing and at their public hearing. Additionally, the EPA 
recommends that states provide translators and other resources at their 
public hearings, to ensure that all members of the public can provide 
oral feedback.
---------------------------------------------------------------------------

    \822\ While we specifically encourage state environmental 
agencies and utility regulators to consult here, we note that, under 
CAA programs, state agencies have a history of consultation with one 
another as appropriate.
---------------------------------------------------------------------------

    As previously discussed in this rule, recent studies also find that 
certain communities, including low-income communities and some 
communities of color (more specifically, populations defined jointly by 
ethnic/racial characteristics and geographic location) are 
disproportionately affected by certain climate change related 
impacts.\823\ Also as discussed in this rule, effects from this rule 
can be anticipated to affect vulnerable communities in various ways. 
Because certain communities have a potential likelihood to be impacted 
by state plans, the EPA believes that the existing public participation 
requirements under 40 CFR 60.23 are effectuated for the purposes of 
this final rule by states engaging in meaningful, active ways with such 
communities.
---------------------------------------------------------------------------

    \823\ USGCRP 2014: Melillo, Jerry M., Terese (T.C.) Richmond, 
and Gary W. Yohe, Eds., 2014: Climate Change Impacts in the United 
States: The Third National Climate Assessment. U.S. Global Change 
Research Program, 841 pp.
---------------------------------------------------------------------------

    In addition, certain communities whose economies are significantly 
dependent on coal, or whose economies may be affected by ongoing 
changes in the utility power and related sectors, may be particularly 
concerned about the final rule. The EPA encourages states to make an 
effort to provide background information about their proposed initial 
submittal and final state plans to these communities in advance of 
their public hearing. In particular, the EPA encourages states to 
engage with workers and their representatives in the utility and 
related sectors, including the EE sector.
    The EPA notes that meaningful public involvement goes beyond the 
holding of a public hearing. The EPA envisions meaningful engagement to 
include outreach to vulnerable communities, sharing information and 
soliciting input on state plan development and on any accompanying 
assessments, such as those described in section IX. The agency uses the 
terms ``vulnerable'' and ``overburdened'' in referring to low-income 
communities, communities of color, and indigenous populations that are 
most affected by, and least resilient to, the impacts of climate 
change, and are central to our community and environmental justice 
considerations. In section VIII.E, the EPA provides states with 
examples of resources on how they can engage with vulnerable 
communities in a meaningful way. With respect specifically to ensuring 
meaningful community involvement in their public hearing(s), however, 
the EPA recommends that states have both a Web site and toll-free 
number that all stakeholders, including overburdened communities, labor 
unions, and others can access to get more information regarding the 
upcoming hearing(s) and to get their questions related to upcoming 
hearings answered. Furthermore, the EPA recommends that states work 
with their local government partners to help them in reaching out to 
all stakeholders, including vulnerable communities, about the upcoming 
public hearing(s).
    (7) Supporting documentation.
    The state plan submittal must provide supporting material and 
technical documentation related to applicable components of the plan 
submittal.
    (a) Legal authority.
    In its submittal, a state must adequately demonstrate that it has 
the legal authority (regulations/legislation) and funding to implement 
and enforce each component of the state plan submittal, including 
federally enforceable emission standards for affected EGUs and state 
measures. A state can make such a demonstration by providing supporting 
material related to the state's legal authority used to implement and 
enforce each component of the plan, such as copies of statutes, 
regulations, PUC orders, and any other applicable legal instruments. 
For states participating in a multi-state plan, the submittal(s) must 
also include as supporting documentation each state's necessary legal 
authority to implement the portion of the plan that applies within the 
particular state, such as copies of state regulations and statutes, 
including a showing that the states have

[[Page 64849]]

the necessary authority to enter into a multi-state agreement.
    (b) Technical documentation.
    As applicable, the state submittal must include materials necessary 
to support the EPA's evaluation of the submittal including analytical 
materials used in the calculation of interim goal steps (if 
applicable), analytical materials used in the multi-state goal 
calculation (if multi-state plan), analytical materials used in 
projecting CO2 emission performance that will be achieved 
through the plan, relevant implementation materials and any additional 
technical requirements and guidance the state proposes to use to 
implement elements of the plan.
    (c) Programmatic plan milestones and timeline.
    As part of the state plan supporting documentation, the state must 
include in its submittal a timeline with all the programmatic plan 
milestone steps the state will take between the time of the state plan 
submittal and 2022 to ensure the plan is effective as of January 1, 
2022. The programmatic plan milestones and timeline should be 
appropriate to the overall state plan approach included in the state 
plan submittal.
    (d) Reliability.
    As discussed in more detail in section VIII.G.2, each state must 
demonstrate as part of its state plan submission that it has considered 
reliability issues while developing its plan.
    b. Additional components required for the emission standards plan 
type. The EPA is finalizing requirements that a final plan submittal 
using the emission standards plan type must contain the following 
components, in addition to the components discussed in the preceding 
section VIII.D.2.a.
    (1) Identification of interim period emission performance rates or 
state goal (for 2022-2029), interim step performance rates or interim 
state goals (2022-2024; 2025-2027; 2028-2029) and final emission 
performance rates or state goal (2030 and beyond).
    The state plan submittal must indicate whether the plan is designed 
to meet the CO2 emission performance rates or the state 
rate-based or mass-based CO2 emission goal. As noted in the 
emission guidelines, the EPA is finalizing CO2 emission 
performance rates for fossil fuel-fired steam generating units and for 
stationary combustion turbines. The EPA has translated the source 
category-specific CO2 emission performance rates into 
equivalent state-level rate-based and mass-based CO2 goals 
in order to maximize the range of choices that states will have in 
developing their plans. The state may choose to develop a state plan 
that meets the CO2 performance rates for the two 
subcategories of affected EGUs or develop a plan that adopts either the 
rate-based or the mass-based state CO2 emission goal 
provided in the emission guidelines.
    Each state plan submittal must identify the emission performance 
rates or rate-based or mass-based CO2 emission goal that 
must be achieved through the plan (expressed in numeric values, 
including the units of measurement, such as pounds of CO2 
per net MWh of useful energy output or tons of CO2). The 
plan submittal must identify the CO2 interim period 
performance rates or state goal (for 2022-2029), interim step 
performance rates or state goals (interim step performance rates or 
state goal 1 for 2022-2024; interim step performance rates or state 
goal 2 for 2025-2027; interim step performance rates or state goal 3 
for 2028-2029) and final CO2 emission performance rates or 
state goal of 2030 and beyond.
    The EPA has finalized an interim performance rates or state goal 
for the interim period of 2022-2029 and a final performance rates or 
state goal to be met by 2030. For the interim period, the EPA has also 
finalized three interim step performance rates or state goals: interim 
step 1 performance rates or state goal for 2022-2024, interim step 2 
performance rates or state goal for 2025-2027 and interim step 3 
performance rates or state goal for 2028-2029.\824\ States are free to 
establish different interim step performance rates or interim step 
state goals than those the EPA has specified in this final rule. If 
states choose to determine their own interim step performance rates or 
state goals, the state must demonstrate that the plan will still meet 
the interim performance rates or state goal for 2022-2029 finalized in 
the emission guidelines and the plan submittal must include in its 
supporting documentation a description of the analytic process, tools, 
methods, and assumptions used to make this demonstration.
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    \824\ In this action, the EPA is providing interim state goals 
in the form of a CO2 emission rate (emission rate-based 
goal) and in the form of tonnage CO2 emissions (mass-
based goal).
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    For states participating in a multi-state plan with a joint goal 
(for interim and final periods), the individual state goals in the 
emission guidelines would be replaced with an equivalent multi-state 
goal for each period (interim and final). For a rate-based multi-state 
plan this would be a weighted average rate-based emission goal, derived 
by the participating states, by calculating a weighted average 
CO2 emission rate based on the individual rate-based goals 
for each of the participating states and 2012 generation from affected 
EGUs. For a mass-based multi-state plan, the joint goal would be a sum 
of the individual mass-based goals of the participating states, in tons 
of CO2. The plan submittal must include in its supporting 
documentation a description of the analytic process, tools, methods, 
and assumptions used to calculate the joint multi-state goal.
    (2) Identification of federally enforceable emission standards for 
affected EGUs.
    The state plan submittal for an emission standards plan type must 
include federally enforceable emission standards that apply to affected 
EGUs. The emission standards must meet the requirement of component (3) 
of this section, ``Demonstrations that each emission standard is 
quantifiable, non-duplicative, permanent, verifiable, and 
enforceable.'' The plan must identify the affected EGUs to which these 
standards apply. The compliance periods for each emission standard for 
affected EGUs, on a calendar year basis, must be as follows for the 
interim period: January 1, 2022-December 31, 2024; January 1, 2025-
December 31, 2027; and January 1, 2028-December 31, 2029. Starting on 
January 1, 2030, the compliance period for each emission standard is 
every 2 calendar years. States can choose to set shorter compliance 
periods for the emission standards than the compliance periods the EPA 
is finalizing in this rulemaking, but cannot set longer periods. As 
discussed in more detail in section VIII.F, the EPA recognizes that the 
compliance periods provided for in this rulemaking are longer than 
those historically and typically specified in CAA rulemakings. The EPA 
determined that the longer compliance periods provided for in this 
rulemaking are acceptable in the context of this specific rulemaking 
because of the unique characteristics of this rulemaking, including 
that CO2 is long-lived in the atmosphere, and this 
rulemaking is focused on performance standards related to those long-
term impacts.
    For state plans in which affected EGUs may rely upon the use of 
ERCs for meeting a rate-based federally enforceable emission standard, 
the state plan must include requirements addressing the issuance, 
tracking and use for compliance of ERCs consistent with the 
requirements in the emission guidelines. These requirements are 
discussed in sections VIII.K.1-2. The state plan must also demonstrate 
that the appropriate ERC tracking infrastructure that meets the

[[Page 64850]]

requirements of the emission guidelines will be in place to administer 
the state plan requirements regarding ERCs and document the 
functionality of the tracking system. State plan requirements must 
include provisions to ensure that ERCs are properly tracked from 
issuance to submission for compliance. The state plan must also 
demonstrate that the MWh for which ERCs are issued are properly 
quantified and verified, through plan requirements for EM&V and 
verification that meet the requirements in the emission guidelines. 
EM&V requirements are discussed in section VIII.K.3. Rate-based 
emission standards must also include monitoring, reporting, and 
recordkeeping requirements for CO2 emissions and useful 
energy output for affected EGUs; and related compliance demonstration 
requirements and mechanisms. These requirements are discussed in more 
detail in sections VIII.F and VIII.K.
    For state plans using a mass-based emission trading program 
approach, the state plan must include implementation requirements that 
specify the emission budget and related compliance requirements and 
mechanisms. These requirements must include: CO2 emission 
monitoring, reporting, and recordkeeping requirements for affected 
EGUs; provisions for state allocation of allowances; provisions for 
tracking of allowances, from issuance through submission for 
compliance; and the process for affected EGUs to demonstrate compliance 
(allowance ``true-up'' with reported CO2 emissions).
    (3) Demonstration that each emission standard is quantifiable, non-
duplicative, permanent, verifiable and enforceable.
    The plan submittal must demonstrate that each emission standard is 
quantifiable, non-duplicative, permanent, verifiable and enforceable 
with respect to an affected EGU, as outlined below.
    An emission standard is quantifiable if it can be reliably 
measured, using technically sound methods, in a manner that can be 
replicated.\825\
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    \825\ A CO2 continuous emissions monitoring system 
(CEMS) is the most technically reliable method of emission 
measurement for EGUs. A CEMS provides a measurement method that is 
performance based rather than equipment specific and is verified 
based on NIST traceable standards. A CEMS provides a continuous 
measurement stream that can account for variability in the fuels and 
the combustion process. Reference methods have been developed to 
ensure that all CEMS meet the same performance criteria, which helps 
to ensure a level playing field and consistent, accurate data.
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    An emission standard is non-duplicative with respect to an affected 
EGU if it is not already incorporated in another state plan, except in 
instances where incorporated as part of a multi-state plan. An example 
of a duplicative emission standard would occur, for example, where a 
quantified and verified MWh from a wind turbine could be applied in 
more than one state's CAA section 111(d) plan to adjust the reported 
CO2 emission rate of an affected EGU (e.g., through issuance 
and use of an ERC), except in the case of a multi-state plan where 
CO2 emission performance is demonstrated jointly for all 
affected EGUs subject to the multi-state plan or where states are 
implementing coordinated individual plans that allow for the interstate 
transfer of ERCs.\826\ This does not mean that measures used to comply 
with an emission standard cannot also be used for other purposes. For 
example, a MWh of electric generation from a wind turbine could be used 
by an electric distribution utility to comply with state RPS 
requirements and also be used by an affected EGU to comply with 
emission standard requirements under a state plan. Another example is 
when actions taken pursuant to CAA section 111(d) requirements can 
satisfy other CAA program requirements (e.g., Regional Haze 
requirements, MATS).
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    \826\ For example, an ERC that is issued by a state under its 
rate-based emission standards may be used only once by an affected 
EGU to adjust its reported CO2 emission rate when 
demonstrating compliance with the emission standards. However, an 
ERC issued in one state could be used by an affected EGU to 
demonstrate compliance with its emission standard in another state, 
where states are collaborating in the implementation of their 
individual emission trading programs through interstate transfer of 
ERCs, or participating in a multi-state plan with a rate-based 
emission trading program. These coordinated multi-state approaches 
are addressed in sections VIII.C.5, VIII.J.3, and VIII.K.4.
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    An emission standard is permanent if the emission standard must be 
met for each applicable compliance period.
    An emission standard is verifiable if adequate monitoring, 
recordkeeping and reporting requirements are in place to enable the 
state and the Administrator to independently evaluate, measure, and 
verify compliance with it.
    An emission standard is enforceable if: (1) It represents a 
technically accurate limitation or requirement and the time period for 
the limitation or requirement is specified; (2) compliance requirements 
are clearly defined; (3) the entities responsible for compliance and 
liable for violations can be identified; and (4) each compliance 
activity or measure is enforceable as a practical matter in accordance 
with EPA guidance on practical enforceability,\827\ and the 
Administrator, the state, and third parties maintain the ability to 
enforce against affected EGUs for violations and secure appropriate 
corrective actions, in the case of the Administrator pursuant to CAA 
sections 113(a)-(h), in the case of a state, pursuant to its state 
plan, state law or CAA section 304, as applicable, and in the case of 
third parties, pursuant to CAA section 304.
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    \827\ The EPA guidance on enforceability includes: (1) September 
23, 1987, memorandum and accompanying implementing guidance, 
``Review of State Implementation Plans and Revisions for 
Enforceability and Legal Sufficiency,'' (2) August 5, 2004, 
``Guidance on SIP Credits for Emission Reductions from Electric-
Sector Energy Efficiency and Renewable Energy Measures,'' and (3) 
July 2012 ``Roadmap for Incorporating Energy Efficiency/Renewable 
Energy Policies and Programs into State and Tribal Implementation 
Plans, Appendix F.''
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    In developing its CAA section 111(d) plan, to ensure that the plan 
submittal is enforceable and in conformance with the CAA, a state 
should follow the EPA's prior guidance on enforceability.\828\ These 
guidance documents serve as the foundation for the types of monitoring, 
reporting, and emission standards that the EPA has found can be, as a 
practical matter, enforced.
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    \828\ See prior footnote.
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    In the proposed regulatory text describing the enforcing measures 
that states must include in state plans, the EPA inadvertently excluded 
a required demonstration that states and other third parties can 
enforce against affected EGUs for violations of an emission standard 
included in a state plan via civil action pursuant to CAA section 304. 
Commenters noted the EPA's intent to require this demonstration based 
on statements in both the proposal preamble text and ``State Plan 
Considerations'' TSD \829\ and based on the requirements of CAA section 
304. We are finalizing a requirement for a demonstration that states 
and other third parties can enforce against affected EGUs for 
violations of an emission standard included in a state plan via civil 
action as part of the required plan component demonstrating 
enforceability. We are finalizing this requirement as a logical 
outgrowth of proposal preamble text, the proposal preamble citation to 
existing enforceability guidance documents that discuss this 
requirement, comments received, and the clear statutory foundation.
---------------------------------------------------------------------------

    \829\ State Plan Considerations technical support document for 
the Clean Power Plan Proposed Rule: http://www2.epa.gov/carbon-pollution-standards/clean-power-plan-proposed-rule-state-plan-considerations.
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    (4) State reporting requirements.
    After consideration of the comments received regarding state 
reporting

[[Page 64851]]

requirements, the EPA is finalizing for state plans using the emission 
standards approach that a state report is due to the EPA no later than 
the July 1 following the end of each reporting period. Within the 
interim period (2022-2029) the EPA is finalizing the following interim 
reporting periods: Interim step 1 covers the three calendar years 2022-
2024, interim step 2 covers the three calendar years 2025-2027, and 
interim step 3 covers the two calendar years 2028-2029. A biennial 
state report is required starting in 2030 and beyond covering the two 
calendar years of each reporting period. This final reporting schedule 
reduces the reporting frequency for states implementing the emission 
standards approach and is responsive to comments received that 
different reporting frequencies may be appropriate for different type 
of state plans. The EPA believes that because of the federally 
enforceable emission standards that apply to affected EGUs and their 
corresponding monitoring, reporting and recordkeeping requirements 
under the emission standards plan type, a lesser frequency of reporting 
by the state is warranted.
    The state must include in each report to the EPA the status of 
implementation of emission standards for affected EGUs under the state 
plan, including current aggregate and individual CO2 
emission performance by affected EGUs during the reporting period. The 
state report must include compliance demonstrations for affected EGUs 
and identify whether affected EGUs are on schedule to meet the 
applicable CO2 emission performance rate or emission goal 
during the performance periods and compliance periods, as specified in 
the state plan. For rate-based emission trading programs, the report 
must also include for EPA review the state's review of the 
administration of their state rate-based emission trading program, as 
discussed in section VIII.K.2.g.
    As discussed in more detail in section VIII.F, the state must 
include an interim performance check in the report submitted after each 
of the first two interim step periods. The interim performance check 
will compare the CO2 emission performance level identified 
in the state plan for the applicable interim step period with the 
actual CO2 emission performance achieved by affected EGUs 
during the period. In the report due to the EPA on July 1, 2030, the 
state must include a comparison of the actual CO2 emission 
performance achieved by affected EGUs for the interim period (2022-
2029) with the interim CO2 emission performance rates or 
state rate-based or mass-based CO2 interim goal, as 
applicable. The report due on July 1, 2030, must also include the 
actual CO2 emission performance achieved by affected EGUs 
during the interim step 3 period (2028-2029). Starting in 2032, the 
biennial state report must include a final performance check to 
demonstrate that the affected EGUs continue to meet the final 
CO2 emission performance rates or state rate-based or mass-
based CO2 goal.
    For state plans that use the emission standards approach and are 
subject to the corrective measures provisions in the emission 
guidelines, if actual CO2 emission performance (i.e., the 
emissions or emission rate) of affected EGUs exceeds the specified 
level of CO2 emission performance in the state plan by 10 
percent or more during the interim step 1 or step 2 reporting periods, 
the state report must include a notification to the EPA that corrective 
measures have been triggered. The same notification is required if 
actual CO2 emission performance fails to meet the specified 
level of emission performance in the state plan for the 8-year interim 
performance period or any final plan reporting period. Corrective 
measures are discussed in detail in section VIII.F.
    c. Additional components required for the state measures approach.
    The EPA is finalizing requirements that a final plan submittal 
using the state measures approach must contain the following 
components, in addition to the components discussed in section 
VIII.D.2.a. We note again that states choosing the state measures plan 
type must use a mass-based state goal for the state measures and any 
emission standards on the affected EGUs prior to the triggering of the 
backstop.
    (1) Identification of interim state mass goal (for 2022-2029), 
interim step state mass goals (2022-2024; 2025-2027; 2028-2029) and 
final state mass goal (2030 and beyond).
    The state plan submittal must identify the mass-based 
CO2 emission goal that must be achieved through the plan 
(expressed in tons of CO2). The plan submittal must identify 
the state CO2 interim period goal (for 2022-2029), interim 
step goals (interim step goal 1 for 2022-2024; interim step goal 2 for 
2025-2027; interim step goal 3 for 2028-2029) and final CO2 
emission goal of 2030 and beyond.
    For each state, the EPA has finalized an interim goal for the 
interim period of 2022-2029 and a final goal to be met by 2030. For the 
interim period, the EPA has also finalized three interim step goals: 
Interim step 1 goal for 2022-2024, interim step 2 goal for 2025-2027 
and interim step 3 goal for 2028-2029.\830\ States are free to 
establish different interim step goals than those the EPA has specified 
in this final rule. If states choose to determine their own interim 
step goals, the state must demonstrate that it will still meet the 
interim goal for 2022-2029 finalized in this action and the plan 
submittal must include in its supporting documentation a description of 
the analytic process, tools, methods, and assumptions used to make this 
demonstration.
---------------------------------------------------------------------------

    \830\ In this action, the EPA is providing interim state goals 
in the form of a CO2 emission rate (emission rate-based 
goal) and in the form of tonnage CO2 emissions (mass-
based goal).
---------------------------------------------------------------------------

    For states participating in a multi-state plan with a joint goal 
(for interim and final periods), the individual state goals in the 
emission guidelines would be replaced with an equivalent multi-state 
goal for each period (interim and final). The joint goal would be a sum 
of the individual mass-based goals of the participating states, in tons 
of CO2. The plan submittal must include in its supporting 
documentation a description of the analytic process, tools, methods, 
and assumptions used to calculate the joint multi-state goal.
    (2) Identification of federally enforceable emission standards for 
affected EGUs (if applicable).
    If applicable, the state plan submittal must include any federally 
enforceable CO2 emission standards that apply to affected 
EGUs, and demonstrate that those emission standards meet the 
requirements that apply in the context of an emission standards 
approach, discussed in the preceding section VIII.D.2.b. Specifically, 
the state plan submittal must demonstrate that each federally 
enforceable emission standard is quantifiable, non-duplicative, 
permanent verifiable, and enforceable. If a state measures plan type 
includes CO2 emission standards that apply to affected EGUs, 
these emission standards must be federally enforceable.
    (3) Identification of backstop of federally enforceable emission 
standards.
    A state measures plan must include a backstop of federally 
enforceable emission standards for affected EGUs that fully achieve the 
interim and final CO2 emission performance rates or the 
state's interim and final CO2 emission goal if the state 
plan fails to achieve the intended level of CO2 emission 
performance. The backstop emission standards could be based on the 
finalized model rule that the EPA is proposing in a separate action. 
For the federally enforceable backstop, the state plan submittal must 
identify the

[[Page 64852]]

federally enforceable emission standards for affected EGUs, demonstrate 
that those emission standards meet the requirements that apply in the 
context of an emission standards approach, discussed in the preceding 
section, identify a schedule and trigger for implementation of the 
backstop that is consistent with the requirements in the emission 
guidelines as discussed in section VIII.C.3.b and identify all 
necessary state administrative and technical procedures for 
implementing the backstop (e.g. how and when the state would notify 
affected EGUs that the backstop has been triggered). Aspects of the 
backstop are discussed in detail in section VIII.C.3.b.
    (4) Identification of state measures.
    A state adopting a state measures plan type must provide as a part 
of the supporting documentation of its plan submittal, a description of 
all the state enforceable measures the state will rely upon to achieve 
the requisite state mass-based goal, the applicable state laws or 
regulations related to such measures, and identification of parties or 
entities implementing or complying with such state measures. The state 
must also include in its supporting documentation the schedule and 
milestones for the implementation of the state measures, showing that 
the measures are expected to achieve the mass-based CO2 
emission goal for the interim period (including the interim step 
periods) and meet the final goal by 2030. A state measures plan 
submittal that relies upon state measures that include RE and demand-
side EE programs and projects must also demonstrate in its supporting 
documentation that the minimum EM&V requirements in the emission 
guidelines apply to those programs and projects as a matter of state 
law.
    (5) State reporting requirements.
    After consideration of the comments received regarding state 
reporting requirements, the EPA is requiring in this final rule for 
states using the state measures approach that an annual state report is 
due to the EPA no later than July 1 following the end of each calendar 
year during the interim period. This annual state report must include 
the status of implementation of federally enforceable emission 
standards (if applicable) and state measures, and must include a report 
of the periodic programmatic state measures milestones to show progress 
in program implementation. The programmatic state measures milestones 
with specific dates for achievement should be appropriate to the state 
measures described in the supporting documentation of the state plan 
submittal. The EPA believes that annual state reporting is appropriate 
for state measures approach due to the flexibility inherent to the 
approach described in section VIII.C.3 including the potential use by 
the state of a wider variety of state measures, responsible parties, 
etc. This reporting frequency will also increase the degree of 
certainty on plan performance for states pursuing the state measures 
approach.
    As discussed in section VIII.F, for states using the state measures 
approach, the EPA is finalizing that at the end of the first two 
interim step periods, the state must also include in their annual 
report to the EPA the corresponding emission performance checks. The 
interim performance checks will compare the CO2 emission 
performance level identified in the state plan for the applicable 
interim step period versus the actual CO2 emission 
performance achieved by the aggregate of affected EGUs. In the report 
submitted to the EPA on July 1, 2030, the state must also report the 
actual CO2 performance check for the interim period (2022-
2029) with the interim mass-based CO2 goal, as well as the 
actual CO2 emission performance achieved by affected EGUs 
during the interim step 3 period (2028-2029).
    Beginning with the final period, the state must submit biennial 
reports no later than July 1 after the end of each reporting period 
that includes an actual performance check to demonstrate that the state 
continues to meet the final state CO2 goal.
    If, at the time of the state report to the EPA, the state has not 
met the programmatic state measures milestones for the reporting 
period, or the performance check shows that the actual CO2 
emission performance of affected EGUs warrants implementation of 
backstop requirements,\831\ the state must include in the state report 
a notification to the EPA that the backstop has been triggered and 
describe the steps taken by the state to inform the affected EGUs that 
the backstop has been triggered. In the event of such an exceedance 
under the state measures approach, the backstop federally enforceable 
emission standards for the affected EGUs must be effective within 18 
months of the deadline for the state reporting to the EPA on plan 
implementation and progress toward meeting the emission performance 
rates or mass-based or rate-based state CO2 emission goal. 
For example, if a state report due on July 1, 2025, shows that actual 
CO2 emission performance of affected EGUs is deficient by 10 
percent or more relative to the specified level of emission performance 
for 2022-2024 in the state plan, the backstop federally enforceable 
emission standards for affected EGUs must be effective as of January 1, 
2027.
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    \831\ As explained in section VIII.C.3.b, state plans subject to 
the backstop requirement must require the backstop to take effect if 
actual CO2 emission performance by affected EGUs fails to 
meet the level of emission performance specified in the plan over 
the 8-year interim performance period (2022-2029), or for any 2-year 
final goal performance period. The plan also must require the 
backstop to take effect if actual emission performance is deficient 
by 10 percent or more relative to the performance levels that the 
state has chosen to specify in its plan for the interim step 1 
period (2022-2024) or the interim step 2 period (2025-2027).
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    (6) Supporting documentation.
    (a) Demonstration that each state measure is quantifiable, non-
duplicative, permanent, verifiable and enforceable.
    A state using the state measures approach, in support of its plan, 
must also include in the supporting documentation of the state plan 
submittal the state measures that are not federally enforceable 
emission standards, and describe how each state measure is 
quantifiable, non-duplicative, permanent, verifiable, and enforceable 
with respect to an affected entity.
    A state measure is quantifiable if it can be reliably measured, 
using technically sound methods, in a manner that can be replicated.
    A state measure is non-duplicative with respect to an affected 
entity if it is not already incorporated as a state measure or an 
emission standard in another state plan or state plan supporting 
material, except in instances where incorporated in another state as 
part of a multi-state plan. This does not mean that measures in a state 
measure cannot also be used for other purposes. For example actions 
taken pursuant to CAA section 111(d) requirements can satisfy other CAA 
program requirements (e.g., Regional Haze requirements, MATS) and state 
requirements (e.g., RPS).
    A state measure is permanent if the state measure must be met for 
each applicable compliance period.
    A state measure is verifiable if adequate monitoring, recordkeeping 
and reporting requirements are in place to enable the state to 
independently evaluate, measure and verify compliance with it.
    A state measure is enforceable \832\ if: (1) It represents a 
technically accurate limitation or requirement and the time period for 
the limitation or requirement

[[Page 64853]]

is specified; (2) compliance requirements are clearly defined; (3) the 
affected entities responsible for compliance and liable for violations 
can be identified; and (4) each compliance activity or measure is 
practically enforceable in accordance with EPA guidance on practical 
enforceability,\833\ and the state maintains the ability to enforce 
against affected EGUs for violations and secure appropriate corrective 
actions pursuant to its plan or state law.
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    \832\ Under the state measures approach, state measures are 
enforceable only per applicable state law.
    \833\ The EPA's prior guidance on enforceability serves as the 
foundation for the types of measures that the EPA has found can be, 
as a practical matter, enforced. The EPA's guidance on 
enforceability includes: (1) September 23, 1987, memorandum and 
accompanying implementing guidance, ``Review of State Implementation 
Plans and Revisions for Enforceability and Legal Sufficiency,'' (2) 
August 5, 2004, ``Guidance on SIP Credits for Emission Reductions 
from Electric-Sector Energy Efficiency and Renewable Energy 
Measures,'' and (3) July 2012 ``Roadmap for Incorporating Energy 
Efficiency/Renewable Energy Policies and Programs into State and 
Tribal Implementation Plans,'' Appendix F.
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    The EPA will disapprove a state plan if the documentation is not 
sufficient for the EPA to be able to determine whether the state 
measures are expected to yield CO2 emission reductions 
sufficient to result in the necessary CO2 emission 
performance from affected EGUs for the mass-based state CO2 
emission goal to be achieved.
    d. Legal basis for the components.
    (1) General legal basis.
    Under section 111(d), state plans must ``provide for the 
implementation and enforcement of [the] standards of performance.'' 
Similar language occurs elsewhere in the CAA. First, for SIPs, section 
110(a)(1) requires SIPs to ``provide for implementation, maintenance, 
and enforcement'' of the NAAQS. However, section 110(a)(2), unlike 
111(d), details a number of specific requirements for SIPs that, in 
part, speak exactly to how a SIP should ``provide for implementation, 
maintenance, and enforcement'' of the NAAQS. We note that section 
111(d) provides explicitly only that the ``procedures,'' and not the 
substantive requirements, for section 111(d) state plans should be 
``similar'' to those in section 110, and thus a substantive requirement 
in section 110(a)(2) is not an independent source of authority for the 
EPA to require the same for section 111(d) plans. However, when there 
is a gap for the EPA to fill in interpreting how a section 111(d) plan 
should ``provide for implementation and enforcement of [the] standards 
of performance,'' and Congress explicitly addressed a similar gap in 
section 110, then it may be reasonable for the EPA to fill the gap in 
section 111(d) using an analogous mechanism to that in section 
110(a)(2), to the extent that the section 110(a)(2) requirement makes 
sense and is reasonable in the context of section 111(d). On the other 
hand, that Congress did not explicitly provide such details as are 
found in section 110(a)(2) indicates that Congress intended to give the 
EPA considerable leeway in interpreting the ambiguous phrase ``provides 
for implementation and enforcement of [the] standards of performance.''
    For example, section 110(a)(2)(E)(i) explicitly requires states to 
provide necessary assurances that they have adequate personnel, funding 
and authority to carry out the SIP. Section 111(d), on the other hand, 
does not explicitly contain this requirement. Thus, there is a gap to 
fill with respect to this issue when the EPA interprets section 
111(d)'s requirement that plans ``provide for implementation and 
enforcement'' of the standards of performance, and it is reasonable for 
the EPA to fill the gap by requiring adequate funding and authority, 
both because adequate funding and authority are fundamental 
prerequisites to adequate implementation and enforcement of any 
program, and because Congress has explicitly recognized this 
fundamental nature in the section 110 context.\834\
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    \834\ On the other hand, there are specific requirements in 
110(a)(2) that are fundamental for SIPs, but would not make sense in 
the 111(d) context. For example, the specific requirement for an 
ambient air quality monitoring network in 110(a)(2)(B) is irrelevant 
in the 111(d) context.
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    We note two other places where the CAA requires a state program to 
satisfy similar language regarding implementation and enforcement. 
First, section 112(l)(1) allows states to adopt and submit a program 
for ``implementation and enforcement'' of section 112 standards. 
Section 112(l)(5) further provides that the program must (among other 
things) have adequate authority to enforce against sources, and 
adequate authority and resources to implement the program. Second, 
section 111(c) provides that, if a state develops and submits 
``adequate procedures'' for ``implementing and enforcing'' section 
111(b) standards of performance for new sources in that state, the 
Administrator shall delegate to the state the Administrator's authority 
to ``implement and enforce'' those standards. The EPA has interpreted 
these ambiguous provisions in the EPA's ``Good Practices Manual for 
Delegation of NSPS and NESHAPS'' and recommended (in the context of 
guidance) that state programs have a number of components, such as 
source monitoring, recordkeeping, and reporting, in order to adequately 
implement and enforce section 111(b) or 112 standards. This again 
indicates it is reasonable for the EPA to fill a gap in section 
111(d)'s language and similarly require source monitoring, 
recordkeeping, and reporting, as these are fundamental to implementing 
and enforcing standards of performance that achieve the state 
performance rates or goals.
    Some commenters argued that states have primary authority over the 
content of state plans and that the EPA lacks authority to disapprove a 
state plan as unsatisfactory simply because it lacks one or more of 
these components. We disagree. The EPA has the authority to interpret 
the statutory language of section 111(d) and to make rules that 
effectuate that interpretation. With respect to the components of an 
approvable plan, we are interpreting the statutory phrase ``provide for 
implementation and enforcement'' and making rules that set out the 
minimum elements that are necessary for a state plan to be 
``satisfactory'' in meeting this statutory requirement. This does not 
in any way intrude on the state's ability to decide what mix of 
measures should be used to achieve the necessary emission reductions. 
Nor does it intrude in any way on the state's ability to decide how to 
satisfy a component. For example, for legal authority, we are not 
dictating which state agencies or officials must specifically have the 
necessary legal authority; that is entirely up to the state so long as 
the fundamental requirement to have adequate legal authority to 
implement and enforce the plan is met.
    In addition, the EPA has already determined in the 1975 
implementing regulations that certain components, such as monitoring, 
recordkeeping, and reporting, are necessary for implementation and 
enforcement of section 111(d) standards of performance. 40 FR 53340, 
53348/1 (Nov. 17, 1975). Thus, EPA's position here is hardly novel. The 
EPA notes in discussing the implementing regulations, nothing in this 
final rule reopens provisions or issues that were previously decided in 
the original promulgation of the regulations unless otherwise 
explicitly reopened for this rule.
    (2) Legal considerations with changes to affected EGUs.
    In the proposed rulemaking, the EPA proposed the interpretation 
that if an existing source is subject to a section 111(d) state plan, 
and then undertakes a modification or reconstruction, the source 
remains subject to the state plan, while also becoming subject to the 
modification or reconstruction

[[Page 64854]]

requirements. 79 FR 34830, 34903-4. The EPA is not finalizing a 
position on this issue in this final rule, and is re-proposing and 
taking comment on this issue through the federal plan rulemaking being 
proposed concurrently with this action. The EPA's deferral of action on 
this issue does not impact states' and affected EGUs' pending 
obligations under this final rule relating to plan submission 
deadlines, as this issue concerns potential obligations or impacts 
after an existing source is subject to the requirements of a state 
plan. The EPA will propose and finalize its position on this issue 
through the federal plan rulemaking, which will be well in advance of 
the plan performance period beginning in 2022, at which point state 
plan obligations on existing sources are effectuated.
    (3) Legal considerations regarding design, equipment, work practice 
or operational standards.
    In the proposal, the EPA asked for comment on three approaches to 
inclusion of design, equipment, work practice and operational standards 
in section 111(d) plans. 79 FR 34830, 34926/3 (June 18, 2014). Under 
the first approach, states would be precluded from including these 
standards in section 111(d) plans unless the design, equipment, work 
practice or operational standard could be understood as a ``standard of 
performance'' or could be understood to ``provide for implementation 
and enforcement'' of standards of performance. We also asked, for the 
first approach, whether it was even possible, given the statutory 
language of 111(h), to consider a design, equipment, work practice or 
operational standard as a ``standard of performance.'' Under the second 
approach, states could include design, equipment, work practice or 
operational standards in the event that it could be shown a ``standard 
of performance'' was not feasible, as set out in section 111(h). Under 
the third approach, a state could include design, equipment, work 
practice and operational standards in a 111(d) plan without any 
constraints. We also asked whether, if there was legal uncertainty as 
to the status of these standards, the EPA should authorize states to 
include them in their 111(d) plans with the understanding that if the 
EPA's authorization were invalidated by a court, states would have to 
revise their plans accordingly.
    The EPA is finalizing the first approach. Specifically, a state's 
standards of performance (in other words, either the federally 
enforceable backstop under the state measures approach or the emission 
standards under the emission standards approach) cannot consist of (in 
whole or part) design, equipment, work practice or operational 
standards. A state may include such standards in a 111(d) plan in order 
to implement the standards of performance. For example, a state taking 
a mass-based approach may include in its 111(d) plan a limit on hours 
of operation on a particular affected EGU, but that operational 
standard itself cannot substitute for a mass-based emission standard on 
the affected EGU.\835\
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    \835\ In particular, a state may include in its 111(d) state 
plan an emission standard that is reflective of the CO2 
performance resulting from operational standards the state imposes 
on an affected EGU.
---------------------------------------------------------------------------

    This follows from the statute. First, section 111(h)(1) authorizes 
the Administrator, when it is not feasible for certain reasons 
(specified in 111(h)(2)) to prescribe or enforce a standard of 
performance, to instead promulgate a design, equipment, work practice 
or operational standard. If a standard of performance could include 
design, equipment, work practice or operational standards, such 
authority would be unnecessary. Second, 111(h)(5) states that design, 
equipment, work practice or operational standards ``described in'' 
111(h) shall be treated as standards of performance for the purposes of 
the CAA. This creates a strong inference that standards of performance 
otherwise should not include design, equipment, work practice, or 
operational standards. Finally, the general definition of ``standard of 
performance'' in section 302(l) is similar to the definition of 
``emission limitation'' (or ``emission standard'') in section 302(k), 
with the exception that the definition of ``emission limitation'' 
explicitly includes design, equipment, work practice and operational 
standards, but the definition of ``standard of performance'' omits 
them. Thus, as with our discussion of the term ``standard of 
performance'' above in VIII.C.6.b, even if the general definition of 
``standard of performance'' in 302(l) applies to 111(d), the omission 
of design, equipment, work practice, and operational standards in 
302(l) confirms our interpretation that they cannot be a 111 ``standard 
of performance'' (except under the limited circumstances in 111(h)). We 
conclude that it is reasonable, and perhaps compelled, to interpret the 
term ``standards of performance'' in 111(d) to not include design, 
equipment, work practice and operational standards.
    However, section 111(d) requires plans to ``provide for 
implementation and enforcement of [the] standards of performance.'' 
This language does not explicitly prohibit a plan from including 
design, equipment, work practice and operational standards, and allows 
for them to be included so long as they are understood to provide for 
implementation of the standards of performance. If they are included, 
the 111(d) plan must still be ``satisfactory'' in other respects, in 
particular in establishing standards of performance that are not in 
whole or in part design, equipment, work practice, and operational 
standards.
    (4) Legal basis for engagement with communities.
    As previously discussed, section 111(d)(1) requires the EPA to 
promulgate procedures ``similar'' to those in section 110 under which 
states adopt and submit 111(d) plans. Section 110(a)(1) requires states 
to adopt and submit implementation plans ``after reasonable notice and 
public hearings.'' The implementing regulations under 40 CFR 60.27 
reflect similar public participation requirements with respect to 
section 111(d) state plans. The EPA is sensitive to the legal 
importance of adequate public participation in the state plan process, 
including public participation by affected communities. As previously 
discussed in this rule, recent studies also find that certain 
communities, including low-income communities and some communities of 
color, are disproportionately affected by certain climate change-
related impacts. Because certain communities have a potential 
likelihood to be impacted by state plans for this rule, the EPA 
believes that the existing public participation requirements under 40 
CFR 60.23 are effectuated for the purposes of this final rule by states 
engaging in meaningful, active ways with such communities. By requiring 
states to demonstrate how they have meaningfully engaged with 
vulnerable communities potentially impacted by state plans as part of 
the state plan development process, states meeting this requirement 
will satisfy the applicable statutory and regulatory requirements 
regarding public participation.
3. Components of the Federally Approved State Plan
    In this action the EPA finalizes that, to be fully approved, a 
state plan submittal must meet the criteria and include the required 
components described above. The EPA will propose and take final action 
on each state plan submittal in the Federal Register and provide an 
opportunity for notice and comment. When a state plan submittal

[[Page 64855]]

is approved by the EPA, the EPA will codify the approved 111(d) state 
plan in 40 CFR part 62. The following components of the state plan 
submittal will become the federally enforceable state 111(d) plan:

 Federally enforceable emission standards for affected EGUs
 Federally enforceable backstop of emission standards for 
affected EGUs
 Implementing and enforcing measures for federally 
enforceable emission standards including EGU monitoring, 
recordkeeping and reporting requirements
 State recordkeeping and reporting requirements

E. State Plan Submittal and Approval Process and Timing

1. Overview
    In this action the EPA is finalizing that state plan submittals are 
due on September 6, 2016, with the option of an extension to submit 
final state plans by September 6, 2018, which is 3 years after 
finalization of this rule. The compelling nature of the climate change 
challenge, and the need to begin promptly what will be a lengthy effort 
to implement the requirements of these guidelines, warrant this 
schedule. The EPA also believes, for reasons further described in the 
next section, why this schedule is achievable for states to submit 
final plans. We discuss the timing of state plans in more detail in 
this section below.
    Discussed in the following sections are state plan submittal and 
timing, required components for initial submittals and the 2017 update, 
multi-state plan submissions, process for EPA review of state plans, 
failure to submit a plan, state plan modifications (including 
modifications to interim and final CO2 emission goals), plan 
templates and electronic submittal, and legal bases regarding state 
plan process.
2. State Plan Submittal and Timing
    The implementing regulations (40 CFR 60.23) require that state 
plans be submitted to the EPA within 9 months of promulgation of the 
emission guidelines, unless the EPA specifies otherwise.\836\ For these 
111(d) guidelines, the EPA is finalizing that each state must by 
September 6, 2016, either submit a final plan submittal or seek an 
extension to submit a final plan by September 6, 2018. In the case of a 
state electing to participate in the CEIP, this 2016 submittal must 
include a non-binding statement of intent to participate in the 
program. To seek an extension of the September 6, 2016 deadline until 
no later than September 6, 2018, a state must submit an initial 
submittal by September 6, 2016, that addresses three required 
components sufficiently to demonstrate that a state is able to 
undertake steps and processes necessary to timely submit a final plan 
by the extended date of September 6, 2018. If an extension is requested 
and granted, states must also submit a 2017 update by September 6, 
2017, that documents the state's continued progress towards meeting the 
September 6, 2018 final plan submittal deadline.
---------------------------------------------------------------------------

    \836\ 40 CFR 60.23(a)(1).
---------------------------------------------------------------------------

    In the proposal, EPA proposed a 13 month final state plan submittal 
deadline, with a 1 year possible extension for states submitting 
individual state plans and a 2 year possible extension for states 
submitting multi-state plans as part of a multi-state region. The EPA 
received substantive comment on the achievability of these proposed 
deadlines for state plan submittals. Multiple commenters expressed 
concern that due to timing of legislative cycles (some of which are 
every 2 years), regulatory processes, and other necessary tasks, states 
would find it extremely difficult to submit plans in 1 or 2 years, 
whether or not they were planning to submit as part of a multi-state 
region. The EPA agrees based on this input that a schedule shorter than 
3 years will be challenging for many--though not all--states. In light 
of the comments received and in order to provide maximum flexibility to 
states while still taking timely action to reduce CO2 
emissions, in this final rule the EPA is allowing for a 2 year 
extension until September 6, 2018, for both individual and multi-state 
plans, to provide a total of 3 years for states to submit a final plan 
if an extension is received. Based on comments received, information 
the EPA has regarding steps states have already begun taking towards 
plan development, and extensive experience with similar state plan 
submission deadlines under CAA section 110 SIPs, the EPA believes 
states will be able to submit final plans within 3 years by September 
6, 2018, in the event states are not required to submit a final plan by 
September 6, 2016. We address the substantive requirements of initial 
submittals and the 2017 update in the next section. States that receive 
2-year extensions may submit the final plan earlier than September 6, 
2018, if they so choose.
    The EPA highlights that one purpose of the initial submittal is to 
encourage and potentially facilitate states to do necessary planning 
and engagement with stakeholders so states are able to submit an 
approvable final state plan by the extended deadline of September 6, 
2018. Some states have well-developed existing programs and the 
attendant legal authority underpinning such programs to more easily 
meet the September 6, 2016 deadline by submitting a final plan which 
largely contains or relies upon such existing programs.\837\ Based on 
comments and stakeholder feedback, however, the EPA anticipates that 
many states intending to develop and submit a final plan will seek the 
optional extension given the time it may take to undergo necessary 
legislative, stakeholder, and planning processes. The EPA acknowledges 
that the initial submittal of September 6, 2016, is not essential to 
the ability of states to submit final plans by September 6, 2018, so 
that even without this 2016 deadline, the EPA could require states to 
meet the 2018 deadline. Even so, this earlier date in the 3 year 
planning process serves as a useful ``check-in'' that provides several 
significant advantages. First, this earlier date provides all states an 
opportunity to understand what approaches other states are considering. 
Because there are significant benefits to regional cooperation, the EPA 
believes that a formal process to collect and then provide this 
information will help all states develop better plans. Second, because 
the guidelines provide significant flexibility, the ability for the EPA 
to provide early input to states who may be pursuing more innovative 
approaches will help ensure that all state plans are ultimately 
approvable. The EPA therefore believes the initial submittal is an 
appropriate means by which to offer the optional extension, and for 
reasons further described in section VIII.E.3, that the requirements of 
the initial submittal are achievable by September 6, 2016, so states 
will be able to develop and submit a plan that meets the requirements 
of the final emission guidelines and section 111(d) of the CAA by the 
extended date.
---------------------------------------------------------------------------

    \837\ Based on comments received, we understand that the 
Northeast and Mid-Atlantic states that participate in RGGI may be in 
this position.
---------------------------------------------------------------------------

    Additionally, some states may not submit a state plan as required 
by the final emission guidelines and section 111(d) of the CAA. For 
states that do not submit a state plan, the CAA gives the EPA express 
authority to implement a federal plan for sources in that state upon 
determination by the EPA that a state has failed to submit a state plan 
by the required date. For states that do not intend to submit a state 
plan to meet the obligations of this final rule, by promulgating a 
federal plan for affected EGUs in states that do not submit a plan by 
September 6, 2016, such affected EGUs would have a maximum of an

[[Page 64856]]

additional 2 years to plan for and determine compliance strategies than 
had promulgation of a federal plan been predicated on states failing to 
submit a plan by September 6, 2018. The EPA also notes that this final 
rule affords states and affected EGUs with many implementation 
flexibilities and approaches for state plans that the EPA itself may 
not have the authority to implement through a federal plan. Therefore, 
affected EGUs subject to a federal plan promulgated for a state that 
refuses to submit a state plan may benefit from an additional 2 years 
to plan for compliance with a federal plan with potentially fewer 
flexibilities.
    If no affected EGU is located within a state, the state must submit 
a letter to the EPA certifying that no such facilities exist by 
September 6, 2016.\838\ The EPA will publish a notice in the Federal 
Register to notify the public of receipt of such letters. If an 
affected EGU is later found to be located in that state, the state must 
submit a final plan addressing such affected EGU or the EPA will 
determine the state has failed to submit a plan as required by the 
emission guidelines and CAA section 111(d), and begin the process of 
implementing a federal plan for that affected EGU.
---------------------------------------------------------------------------

    \838\ 40 CFR 60.23(b).
---------------------------------------------------------------------------

    In the case of a tribe that has one or more affected EGUs located 
in its area of Indian country, if the tribe either does not submit a 
CAA section 111(d) plan or does not receive EPA approval of a submitted 
plan, the EPA has the responsibility to establish a CAA section 111(d) 
plan for that area if it determines that such a plan is necessary or 
appropriate to protect air quality.\839\ See the proposed federal plan 
rulemaking for further information.
---------------------------------------------------------------------------

    \839\ See 40 CFR 49.1 to 49.11.
---------------------------------------------------------------------------

    The EPA notes that the current implementing regulations at 40 CFR 
part 60 do not specify who has the authority to make a formal 
submission of the state plan to the EPA for review. In order to clarify 
who on behalf of a state is authorized to submit an initial submittal, 
2017 update, final state plan (or negative declaration, if applicable), 
and any revisions to an approved plan, the EPA has included a 
requirement in this final rule mirroring that of the requirement in 40 
CFR part 51 App. V.2.1.(a) with respect to SIPs that identifies the 
Governor of a state as the authorized official for submitting the state 
plan to the EPA. If the Governor wishes to designate another 
responsible official the authority to submit a state plan, the EPA must 
be notified via letter from the Governor prior to the 2016 deadline for 
plan submittal so that they have the ability to submit the initial 
submittal or final plan in the State Plan Electronic Collection System 
(SPeCS). If the Governor has previously delegated authority to make CAA 
submittals on the Governor's behalf, a state may submit documentation 
of the delegation in lieu of a letter from the Governor. The letter or 
documentation must identify the designee to whom authority is being 
designated and must include the name and contact information for the 
designee and also identify the state plan preparers who will need 
access to SPeCS discussed in section VIII.E.8. A state may also submit 
the names of the state plan preparers via a separate letter prior to 
the designation letter from the Governor in order to expedite the state 
plan administrative process. Required contact information for the 
designee and preparers includes the person's title, organization and 
email address. The EPA recommends this information be submitted early 
in the state planning process to allow sufficient time for completion 
of SPeCS registration so that those authorized to use the system are 
provided access.
3. Components of an Initial Submittal and 2017 Update
    As noted, states may request a 2-year extension to submit a final 
plan through making an initial submittal by September 6, 2016. For the 
extension to be granted, the EPA is finalizing that the initial 
submittal must address three required components sufficiently to 
demonstrate that a state is able to undertake steps and processes 
necessary to timely submit a final plan by the extended date of 
September 6, 2018: \840\
---------------------------------------------------------------------------

    \840\ As stated previously, in the case of a state electing to 
participate in the CEIP, this 2016 submittal must include a non-
binding statement of intent to participate in the program.

     An identification of final plan approach or approaches 
under consideration, including a description of progress made to 
date.
     An appropriate explanation for why the state requires 
additional time to submit a final plan by September 6, 2018.
     Demonstration or description of opportunity for public 
comment on the initial submittal and meaningful engagement with 
stakeholders,\841\ including vulnerable communities, during the time 
in preparation of the initial submittal and plans for engagement 
during development of the final plan.
---------------------------------------------------------------------------

    \841\ Such stakeholders may include labor unions and workers 
that have an interest in the state plan, and communities whose 
economies are dependent on coal.

    During the public comment period, multiple commenters stated that 
the proposed timeframe for states to submit an initial submittal was 
not achievable, citing, among other things, the number of decisions 
needed to be made by a state or states, and that the EPA needed to 
clarify the requirements for an initial submittal. Multiple commenters 
also expressed concern that the requirements for an initial submittal 
required final decisions to be made by states, and that the initial 
submittal deadline was not enough time for states to make these 
decisions.
    It is important to note that the EPA is not requiring the adoption 
of any enforceable measures or final decisions in order for the state 
to address any of the initial submittal components by September 6, 
2016. The EPA believes the absence of requiring enforceable measures to 
be included with the initial submittal greatly supports the ability of 
states intending to develop a final state plan to submit an initial 
submittal by September 6, 2016. States are required to submit 
enforceable measures supported by technically complex documentation, 
such as modeling, and adopted through state public participation and 
regulatory or legislative processes as part of SIPs under other parts 
of the CAA within timeframes comparable to the time the EPA is 
providing for initial submittals.\842\
---------------------------------------------------------------------------

    \842\ For example, 13 states were required to submit SIP 
revisions sufficient to regulate GHGs under the Prevention of 
Significant Deterioration (PSD) permitting requirements of the CAA 
within either 3 weeks or 12 months in response to the EPA's SIP 
call. See ``Action To Ensure Authority To Issue Permits Under the 
Prevention of Significant Deterioration Program to Sources of 
Greenhouse Gas Emissions: Finding of Substantial Inadequacy and SIP 
Call'', 75 FR 77698, (December 13, 2010).
---------------------------------------------------------------------------

    In order to further address the commenters' concerns regarding 
possible ambiguity of the requirements for an initial submittal so that 
an extension is granted, the EPA is providing clarity regarding the 
required components for an initial submittal. Regarding the component 
that states address an appropriate explanation for an extension, the 
EPA proposed that appropriate explanations for seeking an extension 
beyond 2016 for submitting a final plan include: A state's required 
schedule for legislative approval and administrative rulemaking, the 
need for multi-state coordination in the development of an individual 
state plan, or the process and coordination necessary to develop a 
multi-state plan. In this final rule, the EPA is finalizing these as 
appropriate explanations for seeking an extension beyond 2016, but 
makes clear--as explained further below--that other appropriate 
explanations will be acceptable as well. It is important to note that 
the initial submittal does not require legislation

[[Page 64857]]

and/or regulations to be passed prior in order for the state to be 
granted an extension, but the initial submittal should describe any 
concrete steps the state has already taken on legislation and/or 
administrative rulemaking and detail what the remaining steps are in 
those processes before a final plan can be submitted. The EPA also 
sought comment on other circumstances for which an extension of time 
would be appropriate, and also whether some explanations for extensions 
should not be permitted. Commenters stated that states should be able 
to seek extensions whenever an extension can be reasonably justified, 
and that the EPA should take at face value states' good faith efforts 
by accepting any state assertion that more time is needed to develop a 
plan unless there is clear evidence to the contrary. The EPA believes 
there may be appropriate explanations states may submit in addition to 
the ones described in this final rule sufficient to demonstrate that a 
state is able to undertake steps and processes necessary to timely 
submit a final plan by the extended date of September 6, 2018. Given 
the opportunity for states to submit appropriate explanations other 
than the ones detailed here, the EPA believes addressing this component 
requiring an appropriate explanation for an extension is easily 
achievable by September 6, 2016.
    In order to additionally clarify the required components of the 
initial submittal, the following are types of explanations of 
information states may provide as part of the initial submittal to 
sufficiently address each of the three required components for getting 
an extension:

     Details on whether a state is considering a single or 
multi-state plan, a plan that meets the CO2 emission 
performance rates or state CO2 rate or mass emission 
goal, and/or an emission standards or state measures plan type.
     A description of how the state intends to address 
development of the required components of the final state plan, 
including describing what actions have already been taken, what 
steps remain, and the schedule for completing those steps.
     A commitment to maintain any existing measures the 
state intends to rely upon for its final plan in order to achieve 
the necessary reductions once the performance period begins.
     Describing public participation opportunities such as 
stakeholder and community meetings, or public hearings, throughout 
the 3 year plan development process. This could also include 
leverage of public participation approaches that states already use 
to identify and engage potentially affected communities.

    The EPA emphasizes the required initial submittal components are 
intended to provide a reasonable pathway for states to demonstrate 
whether they will be able to submit an approvable plan by the extended 
date of September 6, 2018. The EPA also anticipates that through the 
requirement to address these components, the initial submittal will 
also facilitate state planning and stakeholder engagement, particularly 
as one component requires the public and stakeholders to have an 
opportunity to comment on the initial submittal. As previously 
described, these components do not require final decisions to be made 
by states, and this is further illustrated by the clarifications on how 
states may meet each of the three required components. Accordingly, the 
EPA believes none of these components is onerous for states to address 
in an initial submittal by the September 6, 2016 deadline. To further 
underscore this point, the EPA is further explaining the clarifying 
examples listed above of how states may address the three required 
components, and highlighting the achievability of these examples for 
states to address through the initial submittal by September 6, 2016.
    For identification of the final plan approach or approaches the 
state is considering, and description of progress made to date, states 
could identify whether the state is considering the option of the 
CO2 emission performance rates, a rate-based CO2 
goal, or a mass-based CO2 goal, and whether the state is 
intending to pursue a single-state or multi-state plan. Stakeholders 
commented that states will not be far enough along in the rule 
development process to have made these decisions. Commenters also 
stated that many state legislatures would need to pass legislation 
giving state environmental agencies legal authority and direction 
before they could begin to make decisions such as rate or mass-based 
approach or single or multi-state plan submittal. In order to address 
the commenters' concerns, the EPA wishes to clarify that state 
approaches identified in the initial submittal do not need to be final 
and/or formalized through a state legislature, and that states may opt 
to identify pursuit of more than one approach at the same time, or to 
indicate the status of the deliberation of this issue within the state.
    The EPA received substantive comment regarding the potential 
adverse consequences for states pursuing a multi-state approach and 
receiving an extension until 2018, where, for various reasons, a state 
or states then decide(s) to pursue the single state approach. 
Commenters viewed this as being potentially problematic since, as 
proposed, a single state could only receive an extension until 2017, 
and if a multi-state plan effort does not work out the deadline for 
seeking the extension until 2017 would have passed. The EPA notes 
finalizing a 2 year extension that is available for any state, whether 
they are pursuing an individual state plan or a multi-state plan 
resolves the commenters' concern about conflicting extension deadlines 
if states involved in a multi-state effort decide not to pursue the 
multi-state approach. Importantly, such identification in an initial 
submittal does not obligate the state to then actually adopt that 
approach in their final plan as the EPA acknowledges that based on 
state processes and public input through plan development during the 
extended submission period, a state may end up adopting a state plan 
approach more suitable to the needs of that state and its affected EGUs 
than previously identified in the initial submittal.
    States can also describe progress made to date by identifying steps 
already taken to address development of the final state plan, as the 
EPA recognizes that states in general have already taken a number of 
steps to prepare for state plan development to meet the obligations of 
this rule. For example, since proposal, states have: Begun exploring 
tradeoffs among various state plan approaches such as individual versus 
multistate coordination, increased utilization of demand-side EE and RE 
programs, and implementing rate-based versus mass-based programs; 
increased their understanding of existing state programs and policies 
that reduce carbon emissions; built relationships and communications 
between key state institutions such as environmental agencies, PUCs, 
governors' offices, and energy regulators; hosted public stakeholder 
meetings to educate and solicit input from the public; and begun 
discussing state processes for developing potential state plans. States 
may meet the first required component by describing steps such as these 
already undertaken.
    The EPA underscores that states may easily address the first 
component of the initial submittal by describing such steps, and also 
address the second required component by identifying next steps (which 
may be a natural extension of these already implemented activities), 
and laying out a schedule for development of a final plan. States that 
have taken these steps would especially

[[Page 64858]]

be able to address the component regarding an appropriate explanation 
for an extension as the EPA recognizes the substantial work such states 
have begun to put towards development of state plans, and the 
continuation of this work justifies additional time to complete 
necessary steps to result in an approvable state plan. The EPA 
emphasizes that for states who intend to submit a final plan and need 
an extension, the components of the initial submittal are not intended 
to require burdensome final action by states by September 6, 2016, but 
to identify a viable path to completing a final plan by September 6, 
2018.
    An initial submittal that contains a commitment to maintain any 
existing measures the state intends to rely upon for its final plan in 
order to get the necessary reductions once the performance period 
begins (e.g. RE standards and demand-side EE programs the state intends 
to rely upon through a state measures plan type), at least until the 
final plan is approved, also addresses the requirement that states 
provide an appropriate explanation for an extension. Given the state's 
request for additional time prior to putting in place enforceable 
measures to reduce CO2, it would be reasonable and 
appropriate, and in keeping with the goals of 111(d) to ensure that any 
existing CO2 reduction measures that the state intends to 
rely upon remain in place while the state is developing a final plan. 
Such commitment would demonstrate that the state is taking substantive 
steps towards successful development of a final plan within 3 years.
    Regarding the required public participation component of the 
initial submittal, the EPA believes this requirement is both achievable 
for states to submit an initial submittal by the September 6, 2016 
deadline, and provides a benefit in facilitating state plan development 
so that states are more likely to be able to submit a final plan within 
3 years if the extension is granted. The EPA can use a comment 
opportunity on the initial submittal to advise the state whether 
aspects of the draft initial submittal and overall plan development are 
appropriate for purposes of meeting the requirements of the final rule 
so that the state will be able to procure the extension through an 
acceptable initial submittal and submit a final plan by the extended 
deadline. The EPA notes the comment period on the initial submittal is 
only one opportunity the EPA has to assist a state in the state plan 
development process. The EPA has historically worked with states 
throughout the state plan development process to help ensure that the 
state plan is approvable once submitted to the EPA, and expects this 
level of engagement with states to continue throughout the plan 
development process. This requirement will also facilitate early 
identification of concerns stakeholders and the public may have with 
aspects of a final plan the state is considering. As states have 
longtime and extensive experience with responding to public comments in 
numerous contexts, including in the context of other CAA programs such 
as section 110 SIP development and in permit issuance under NSR and 
Title V, the EPA anticipates states will be able to timely address the 
initial submittal public participation.
    As previously discussed, because certain communities have a 
potential likelihood to be impacted by state plans, the EPA believes 
that the existing public participation requirements under 40 CFR 60.23 
are effectuated for the purposes of this final rule by states engaging 
in meaningful, active ways with such communities. Therefore, the public 
participation component of the initial submittal includes meaningful 
engagement with vulnerable communities, throughout the state plan 
development process and including through the initial submittal. In 
order to demonstrate to the EPA that states are actively engaging with 
communities, states could provide in their initial submittal a summary 
of steps they have already taken to engage the public and how they 
intend to continue meaningful engagement, including with vulnerable 
communities, during the additional time (if an extension is granted) 
for development of the final plan. In addition to approaches that 
states already use to identify and engage potentially affected 
communities, the EPA encourages states to use the proximity analysis 
conducted for this rulemaking (which is described in section IX.A) as a 
tool to help them identify overburdened communities that could be 
potentially impacted by their plans. Other tools, such as EJ screen, 
can also be helpful. The EPA in its continued outreach with states 
during the implementation phase will also provide resources to assist 
them in engaging with communities. The EPA believes that through the 
provision of these resources states will also more easily be able to 
address this required component of the initial submittal regarding 
public engagement, including with vulnerable communities, by September 
6, 2016.
    In addition to the resources the EPA intends to provide to states, 
there are existing resources states can take advantage of to address 
this component as well. On the steps that states could take to engage 
vulnerable communities in a meaningful way, the Agency recommends that 
states consult the EPA's May 2015 Guidance on Considering Environmental 
Justice During the Development of Regulatory Actions. In this document, 
the EPA defines meaningful involvement as ensuring that ``potentially 
affected community members have an appropriate opportunity to 
participate in decisions about a proposed activity (i.e., rulemaking) 
that may affect their environment and/or health; the population's 
contribution can influence the EPA's [regulatory authority's] 
rulemaking decisions; the concerns of all participants involved will be 
considered in the decision-making process; and the EPA [decision-
makers] will seek out and facilitate the involvement of those 
potentially affected by the EPA's [or other regulatory authority's] 
rulemaking process.'' \843\ Additionally, this guidance document also 
encourages those writing rules to consider the positive impacts that a 
rulemaking will have on communities).\844\ Another resource that the 
EPA recommends that states consult when devising their state plans is 
the document ``Considering Environmental Justice in Permitting'' 
available on the agency's Web site.\845\ Both of the resources 
discussed above can add to what states may already have in place to 
effectively engage vulnerable communities in the rulemaking process.
---------------------------------------------------------------------------

    \843\ Guidance on Considering Environmental Justice During the 
Development of Regulatory Actions. http://epa.gov/environmentaljustice/resources/policy/considering-ej-in-rulemaking-guide-final.pdf. May 2015.
    \844\ Ibid.
    \845\ Considering Environmental Justice in Permitting. http://www.epa.gov/environmentaljustice/plan-ej/permitting.html#actions.
---------------------------------------------------------------------------

    The EPA recommends that as part of their meaningful engagement with 
vulnerable communities, states work with communities to ensure that 
they have a clear understanding of the benefits and any potential 
adverse impacts that a state plan might have on their overburdened 
communities and that there is a clear process for states to respond to 
input from communities.
    If a state seeks an extension by submitting an appropriate initial 
submittal addressing the three required components as described above 
by September 6, 2016, the EPA will review the submittal. If the state 
does not submit an initial submittal by September 6, 2016, that 
contains the three required components, the EPA

[[Page 64859]]

will notify the state by letter, within 90 days, that the agency cannot 
grant the extension request based the state's initial submittal. The 
EPA will notify a state by letter only if the initial submittal does 
not address the three required components. An extension for submitting 
a final plan will be deemed granted if the EPA does not deny the 
extension request based on the initial submittal. The EPA has 
determined this approach is authorized by, and consistent with, 40 CFR 
60.27(a) of the implementing regulations.
    For states that request and receive a 2-year extension, the state 
must submit an update halfway through that extension, by September 6, 
2017. In the proposal the EPA included a requirement regarding a 2017 
check in. Because the EPA is finalizing that states are able to get a 
2-year extension regardless of whether they are submitting an 
individual or multi state final plan, the EPA believes it appropriate 
to ensure through the 2017 update that the state is making continuous 
progress on its initial submittal and that it is on track to meet the 
final plan submittal deadline of September 6, 2018. The EPA will also 
be able to use the information provided through the 2017 update to 
further assist states in plan development.
    The final rule requires that states address in the 2017 update the 
following components:

     A summary of the status with respect to required 
components of the final plan, including a list of which components 
are not yet complete.
     A commitment to a plan approach (e.g., single or multi-
state, rate or mass emission performance level), including draft or 
proposed legislation and/or regulations.
     An updated comprehensive roadmap with a schedule and 
milestones for completing the plan, including progress to date in 
developing a final plan and steps taken in furtherance of actions 
needed to finalize a final plan.

    In order to assess whether a state is on track to submit a final 
plan by the 2018 extension deadline, the EPA is requiring that the 2017 
update must contain a progress update on components from the initial 
submittal and a list of which final plan components are still not 
complete.
    The EPA is also requiring that the 2017 update include a commitment 
to the type of plan approach the state will take in the final plan 
submittal. During the public comment period, many commenters stated 
that legislative action would be required to enact this final rule at 
the state level, and that the proposal did not provide enough time for 
legislative action or other regulatory actions needed for a state to be 
granted an extension. In order to respond to these comments, the EPA is 
clarifying that proposed or passed legislation or regulations are not 
required in the initial submittal due by September 6, 2016. While a 
state may indicate consideration of multiple state plan approaches in 
the initial submittal, the EPA is requiring that the state commit to 
one approach in the 2017 update. This commitment must include draft or 
proposed legislation or regulations that must become final at the state 
level prior to submitting a final plan submittal to the EPA. While 
commenters expressed concern with not being able to have legislation 
enacted in time to receive an extension until 2018, the EPA has 
determined that 2 years is a reasonable timeframe for a state to decide 
on the type of approach it will take in the final plan submittal and to 
draft legislation or regulations for this approach in order to timely 
meet the extended September 6, 2018 deadline.
4. Multi-State Plan Submittals
    For states wishing to participate in a multi-state plan, the EPA is 
finalizing three forms of submittal that states may choose for the 
submittal of a multi-state plan.
    First, the EPA is finalizing its proposed approach where one multi-
state plan submittal is made on behalf of all participating states. The 
joint submittal must be signed by authorized officials for each of the 
states participating in the multi-state plan and would have the same 
legal effect as an individual submittal for each participating state. 
The joint submittal must adequately address plan components that apply 
jointly for all participating states and for each individual state in 
the multi-state plan, including necessary state legal authority to 
implement the plan, such as state regulations and statutes. Because the 
multi-state plan functions as a single plan, each of the required plan 
components (e.g., plan emission goals, program implementation 
milestones, emission performance checks, and reporting) would be 
designed and implemented by the participating states on a multi-state 
basis.
    The EPA received comments from states requesting flexibility for 
multi-state plan submittals. In response to these comments, the EPA is 
also finalizing two additional options on which it solicited comment. 
First, states participating in a multi-state plan can provide a single 
submittal--signed by authorized officials from each participating 
state--that addresses common plan elements. This option requires 
individual participating states to provide supplemental individual 
submittals that provide state-specific elements of the multi-state 
plan. The common multi-state submittal must address all relevant common 
plan elements and each individual participating state submittal must 
address all required plan components (including common plan elements, 
even if only through cross reference to the common plan submittal). 
Under this approach, the combined common submittal and each of the 
individual participating state submittals would constitute the multi-
state plan submitted for EPA review. The joint common submittal must be 
signed by authorized officials for each of the states participating in 
the multi-state plan and would have the same legal effect as an 
individual submittal for each participating state.
    Second, the EPA is finalizing an approach where all states 
participating in a multi-state plan separately make individual 
submittals that address all elements of the multi-state plan. These 
submittals would need to be materially consistent for all common plan 
elements that apply to all participating states, and would also address 
individual state-specific aspects of the multi-state plan. Each 
individual state plan submittal would need to address all required plan 
components. The EPA encourages states participating in this type of 
multi-state plan to use as much common material as possible to ease 
review of the state plans.
    These approaches will provide states with flexibility in addressing 
contingencies where one or more states submit plan components that are 
not approvable. In such instances, these options simplify the EPA's 
approval of remaining common or individual portions of a multi-state 
plan and help address contingencies during plan development where a 
state fails to finalize its participation in a multi-state plan, with 
minimal disruption to the submittals of the remaining participating 
states. These additional submittal approaches also facilitate multi-
state plans where the participating states are coordinating the 
implementation of their plans but are not taking on a joint multi-state 
emission goal for affected EGUs. For example, states may seek to engage 
in a multi-state approach that links rate-based or mass-based emission 
trading programs through appropriate authorizations (e.g. reciprocity 
agreements, or state regulations) that allow affected EGUs to use 
emission allowances or RE/EE credits issued in

[[Page 64860]]

one state for compliance with an emission standard in another state.
    In order to avoid a multi-state plan becoming unapprovable due to 
one state submitting an unapprovable portion of a multi-state plan, 
withdrawing from the multi-state plan, or failing to implement the 
multi-state plan, states may include express severability clauses if 
their multi-state plan is able to stand without further revision if one 
of the situations described above occurs. The severability clause must 
specify how the remainder of the multi-state plan or individual state 
plan would continue to function with the withdrawal of a state or 
states, and may also include pre-specified revisions. The EPA will 
evaluate the appropriateness of such a clause as part of its review of 
the multi-state plan submittal.
5. Process for EPA Review of State Plans
    Our proposal laid out the basic steps for the EPA's review and 
action on submitted state plans and, at some length, discussed the 
required components of state plans, as further described in the 
preceding sections. We received a number of thoughtful and helpful 
comments on these issues. We are finalizing the basic requirements in 
this rule and are proposing, in the companion proposed federal plan 
under section 111(d), some additional procedural elements we believe 
will be helpful to states, stakeholders and the EPA moving forward.
    Following the September 6, 2016 deadline for state plan submittals, 
the EPA will review plan submittals. For a state that submits an 
initial submittal by September 6, 2016, and requests an extension of 
the deadline for the submission of a final state plan submittal, the 
EPA will determine if the initial submittal meets the minimum 
requirements for an initial submittal. If the state does not submit an 
initial submittal by September 6, 2016, that contains the three 
required components, the EPA will notify the state by letter, within 90 
days, that the agency cannot grant the extension request based the 
state's initial submittal. If the initial submittal meets the minimum 
requirements specified in the emission guidelines, the state's request 
for a deadline extension to submit a final plan submittal will be 
deemed granted, and the final plan submittal must be submitted to the 
EPA by no later than September 6, 2018.
    After receipt of a final plan submittal, the EPA will review the 
plan submittal and, within 12 months, approve or disapprove the plan 
through a notice-and-comment rulemaking process publicized in the 
Federal Register, similar to that used for acting upon SIP submittals 
under section 110 of the CAA. The implementing regulations currently 
provide for the EPA to act on a final plan within 4 months after the 
deadline for submission, which is consistent with versions of section 
110 prior to the 1990 Amendments to the CAA. 40 CFR 60.27(b). To be 
consistent with the current version of section 110, the EPA intends to 
adopt a timeline of 12 months to review final plan submittals upon 
receipt of complete submittals, as is generally consistent with the 
timing requirements of section 110 with respect to complete SIP 
submittals. Such a timeline would also provide the EPA with adequate 
time for review and rulemaking procedures, and ensuring an opportunity 
for public notice and opportunity for comment. We note, however, that 
we proposed this timeline for review and action on state plans in our 
proposal, but our proposal was specific to the timeline for state plans 
submitted pursuant to this rule rather than for state plans submitted 
under 111(d) generally.\846\ We are finalizing as part of this rule 
that state plans submitted to meet the requirements of this rule will 
be reviewed and acted upon by the EPA within 12 months of submission. 
Because such timeline would be appropriate to be made to 111(d) state 
plans more generally, we are also proposing the appropriate revisions 
to the implementing regulations as part of the federal plan proposal 
for section 111(d).
---------------------------------------------------------------------------

    \846\ The EPA proposed 12 months after the date required for 
submission of a plan or plan revision to approve or disapprove such 
plan or revision or each portion thereof.
---------------------------------------------------------------------------

    In addition, while the proposal and this final rule lay out in 
considerable detail the required components of a state plan, the EPA 
believes that it would also be helpful to include in the rule a 
completeness determination process, similar to that used for SIP 
submittals under section 110, which will allow the EPA to determine 
whether a final plan submittal contains the components necessary to 
enable the EPA to determine through notice and comment rulemaking 
whether such submittal complies with the requirements of section 
111(d). This is a procedural requirement under CAA section 110(k)(1) 
for SIPs, and the EPA believes this requirement is appropriate to 
establish under section 111(d)'s direction to the EPA to prescribe 
through regulations a procedure similar to that provided by section 
110. However, because the EPA did not propose such regulations as part 
of the proposal for this action, the EPA is proposing such regulations 
as part of the federal plan proposal for section 111(d). The EPA notes 
that this preamble (in section VIII.D) and final rule lay out required 
components of state plans and all the requirements for a state plan 
submittal, and therefore states have the necessary information at this 
time to develop state plans. The upcoming completeness criteria will 
not add to or change these required components, but only add a 
procedural step that allows the EPA to identify whether there are 
absent or insufficient components in the plan submittal that would 
render the EPA unable to act on such submittal because it is 
incomplete. As we further explain in the federal plan proposal, a 
determination by the EPA that a plan submittal is incomplete has the 
effect of a state having a still-pending statutory obligation to submit 
a plan that meets the requirements of section 111(d).
    The EPA is planning to propose an amendment to the section 111(d) 
implementing regulations that will add the partial approval/disapproval 
and conditional approval mechanisms in section 110(k)(3) and (4) to the 
procedure for acting on section 111(d) plans. The input the agency 
received in response to the proposal for these guidelines indicated 
that the flexibility provided by these mechanisms could be useful 
getting state plans in place. The EPA agrees, and is proposing to amend 
the implementing regulations as part of the rulemaking for the federal 
111(d) plan. The EPA is not taking final action on these changes in 
this action.
    The later timing for our action on partial approval/disapproval and 
conditional procedures does not create any issue with finalizing this 
rule. These procedural adjustments will only come into play after 
states have submitted their plans and the EPA is required to act on 
them, and we intend to finalize these procedural changes prior to 
September 6, 2016, when the first plan submittals would occur. Until 
then, the EPA believes that every plan is submitted with the intent to 
be fully approvable and there is no need for states to rely on the 
possibility of these procedures when developing their plans. 
Conditional approval and partial approval/disapproval should be used to 
deal with approvability issues that arise despite the best efforts of 
states and the EPA to work together to make sure a submittal in the 
first instance is fully approvable. The EPA plans to finalize any 
changes in the implementing regulations before the EPA is required to 
act on state submittals, so that the EPA and states will have 
appropriate flexibility in the plan approval process.

[[Page 64861]]

6. Failure To Submit a Plan
    If a state does not submit a final plan submittal by the applicable 
deadline, or submits a final plan the EPA determines to be incomplete, 
the EPA will notify the state by letter of its failure to submit. The 
EPA will publish a Federal Register notice informing the public of its 
finding of failure to submit. Upon a finding of failure to submit for a 
state, a regulatory clock will run requiring the EPA to promulgate a 
federal plan for such state no later than 1 year after the EPA makes 
the finding unless the state submits, and the EPA approves, a state 
plan during this time. Refer to the federal plan proposal for more 
details on how and when a federal plan would be triggered.
7. State Plan Modifications
    a. Modifications to an approved state plan.
    During the course of implementation of an approved state plan, a 
state may wish to update or alter one or more of the enforceable 
measures in the state plan, or replace certain existing enforceable 
measures with new measures. The EPA received broad support for allowing 
states to submit modifications to approved state plans, and we agree 
that this is an important aspect of this program. In this rulemaking, 
therefore, the EPA is finalizing that a state may revise its state 
plan, and states in a multi-state plan may revise their joint plan. 
Consistent with the timing for final plan submittals originally 
submitted by states, the EPA will act on state plan revisions within 12 
months of a complete submittal. The EPA expects that the long plan 
performance timeframes in this final rule and flexibility provided to 
states in developing state plans will lessen the need for modifications 
to approved state plans.
    A state may enter or exit a multi-state plan through a plan 
modification, with certain limitations. Multiple commenters stated that 
the EPA should clarify the plan modification process in such instances.
    Where a state with a single-state approved plan seeks to join a 
multi-state plan, the state may submit a modification of its plan 
indicating that it is joining the multi-state plan and including the 
necessary plan components under the multi-state plan. The current 
participants of the multi-state plan will also need to submit a plan 
modification, to acknowledge the new state participant and to 
recalculate the multi-state rate-based or mass-based CO2 
goal. Functionally, both the modification of the single-state plan of 
the new participant and the multi-state plan of the current plan 
participants could be addressed through the same plan modification 
submittal or addressed under a plan modification submittal comparable 
to the alternate formats for multi-state plan submittals addressed in 
section VIII.E.4.
    The entry or exit of a state to/from a multi-state plan involves 
the recalculation of the multi-state rate-based or mass-based 
CO2 goal for affected EGUs in the participating states. The 
recalculated multi-state rate-based or mass-based CO2 goal 
must take into account and ensure achievement of the individual state 
rate-based or mass-based CO2 goal for any state that is 
joining the multi-state plan. If implementation of the individual state 
plan has triggered corrective measures or backstop emission standards 
prior to the plan modification, as described in section VIII.F.3, the 
modification must take into account the need to make up for any 
shortfall in CO2 emission performance in the individual 
state plan prior to joining the multi-state plan. Where one or more 
states are leaving a multi-state plan through a plan modification, the 
process is similar and the same considerations must be taken into 
account in connection with the states that are leaving the multi-state 
plan.
    As a result of these requirements and considerations, the EPA is 
finalizing certain requirements for multi-state plan modifications. A 
multi-state plan modification may be submitted to the EPA at any time. 
However, an approved multi-state plan modification may only take effect 
at the beginning of a new interim or final plan performance period. 
These requirements are necessary to ensure that the emission 
performance rates or state rate-based or mass-based CO2 
goals in the emission guidelines are achieved. In addition, such 
requirements for the timing of the effective date of multi-state plan 
modifications are necessary for coordination of the implementation of 
multi-state plans, especially where such plans include a multi-state 
emission trading approach. This approach is also consistent with the 
approach the EPA is proposing for the implementation of federal plan, 
where relevant for a state(s).
    The EPA solicited comment on whether, for new projections of 
emission performance included in a submitted plan modification, the 
projection methods, tools, and assumptions used should match those used 
for the projection in the original demonstration of plan performance, 
or should be updated to reflect the latest data and assumptions, such 
as assumptions for current and future economic conditions and 
technology cost and performance. Comments received on this topic were 
generally supportive of allowing the use of updated data in state plan 
modifications, citing that states should have the ability to determine 
whether the original data and assumptions or updated data and 
assumptions are appropriate. The EPA is finalizing that new projections 
of emission performance, the projection methods, tools, and assumptions 
do not have to match those used for the projection in the original 
demonstration of plan performance; they can be updated to reflect the 
latest data and assumptions, such as assumptions for current and future 
economic conditions and technology cost and performance.
    As discussed in more detail in section VIII.G.2, the final rule has 
several measures to ensure that it does not interfere with the 
industry's ability to maintain reliability. One such measure is that if 
a state cannot address a reliability issue in accordance with an 
approved state plan, the state can submit a request to the EPA to 
modify the state plan. See section VIII.G.2 for a more detailed 
discussion of this issue.
    The EPA is not finalizing any circumstances under which a state may 
or may not revise its state plan, with the exception that a state may 
not revise its state plan in a way that results in the affected EGU or 
EGUs not meeting the requisite CO2 emission performance 
levels.
    b. Modifications to interim and final CO2 emission 
goals.
    As discussed in section VII, the final rule specifies that the 
state interim and final CO2 emission goals for affected EGUs 
in a state may be adjusted to address changes within a state's fleet of 
affected EGUs. If these changes occur before a state submits its 
initial submittal or final plan, the state should indicate in its 
submittal the circumstance that necessitates the goal adjustment and 
the revised interim or final CO2 emission goal. If the 
circumstances occur after a state has an approved plan, a state must 
submit a modification to its approved plan. The plan revision submittal 
must indicate the circumstance that necessitates the goal adjustment, 
the revised interim and/or final CO2 emission goal, and the 
adjustments to the enforceable measures in the plan.
8. Plan Templates and Electronic Submittal
    The EPA is finalizing the requirement that submissions related to 
this program

[[Page 64862]]

be submitted electronically. Specifically, that includes negative 
declarations, state plan submittals (including any supporting materials 
that are part of a state plan submittal), any plan revisions, and all 
reports required by the state plan. The rule provides that files that 
are submitted to the EPA in an electronic format may be maintained by 
states in an electronic format. The submission of the information by 
the authorized official must be in a non-editable format. In addition 
to the non-editable version, the EPA is also requiring that all plan 
components designated as federally enforceable must be submitted in an 
editable version as well, as discussed below.
    a. Submittal of an editable version of federally enforceable plan 
components.
    To ensure that the EPA has the ability to identify, evaluate, 
merge, update and track federally enforceable plan components in a 
timely and comprehensive manner, the EPA is requiring states to submit 
an editable copy of the specific plan components in their submittals 
that are designated as federally enforceable, either effective upon the 
EPA plan approval or as a state plan backstop measure. The editable 
version is in addition to the non-editable version. Examples of 
editable file formats include Microsoft Word, Apple Pages and 
WordPerfect.
    b. Revisions to an approved plan.
    States shall provide the EPA with both a non-editable and editable 
copy of any submitted revision to existing approved federally 
enforceable plan components, including state plan backstop measures. 
The editable copy of any such submitted plan revision must indicate the 
changes made, if any, to the existing approved federally enforceable 
plan components, using a mechanism such as redline/strikethrough. This 
approach to identifying the changes made to the existing federally 
enforceable plan components is consistent with the criteria for 
determining the completeness of SIP submissions set forth in Section 
2.1(d) of Appendix V to 40 CFR part 51.
    c. Electronic submittal.
    It is the EPA's experience that electronic submittal of information 
has increased the ease and efficiency of data submittal and data 
accessibility. The EPA is developing the SPeCS, a web accessible 
electronic system to support this requirement that will be accessed at 
the EPA's Central Data Exchange (CDX) (http://www.epa.gov/cdx/). The 
EPA will pre-register authorized officials and plan preparers in CDX. 
See section VIII.E.2 for additional information on the pre-registration 
process for authorized officials and plan preparers. Detailed 
instructions for accessing CDX and SPeCS will be outlined in the 
``111(d) SPeCS User Guide: How to submit state 111(d) plan material to 
EPA'' which will be available on the EPA's Clean Power Plan Toolbox for 
States. The EPA will provide SPeCS training for states prior to the 
state plan submittal due date.
    Once in CDX, SPeCS can be selected from the Active Program Service 
List. The preparer (e.g., state representative compiling a state plan 
submittal) assembles the submission package. The preparer can upload 
files and complete electronic forms. However, the preparer may not 
formally submit and sign packages. Only registered authorized officials 
may submit and sign for the state with the exception of draft 
submittals. The EPA's intent is to allow submittal of draft plans or 
parts of plans for early EPA review prior to formal submission by the 
authorized official and will allow preparers, as well as authorized 
officials, to submit draft documents. The authorized official will be 
able to assemble submission packages and will be able to modify 
submission packages that a preparer has assembled. The key difference 
between the preparer and the authorized official is that the authorized 
official can submit and sign a package for formal EPA review using an 
electronic signature. In the case of a multi-state plan, each 
participating state's authorized official must provide an electronic 
signature.
    The process has been designed to be compliant with the Cross-Media 
Electronic Reporting Rule (CROMERR), under 40 CFR part 3, which 
provides the legal framework for electronic reporting under all of the 
EPA's environmental regulations. The framework includes criteria for 
assuring that the electronic signature is legally associated with an 
electronic document for the purpose of expressing the same meaning and 
intention as would a handwritten signature if affixed to an equivalent 
paper document. In other words, the electronic signature is as equally 
enforceable as a paper signature. For more information on CROMERR, see 
the Web site: http://www.epa.gov/cromerr/. States who claim that a 
state plan submittal or supporting documentation includes confidential 
business information (CBI) must submit that information on a compact 
disc, flash drive, or other commonly used electronic storage media to 
the EPA. The electronic media must be clearly marked as CBI and mailed 
to U.S. EPA/OAQPS/CORE CBI Office, Attention: State and Local Programs 
Group, MD C539-01, 4930 Old Page Rd., Durham, NC 27703.
    The EPA received a number of comments on the electronic submittal 
of state plans. Some commenters preferred the option to submit 
electronically rather than the requirement to do so. In the final rule, 
for the reasons discussed below, the EPA is requiring electronic 
submittal of state plans and not allowing alternate options for plan 
submittal (e.g. paper submittal).
    Requiring electronic submittal is in keeping with current trends in 
data availability and will result in less burden on the regulated 
community. Electronic submittal will facilitate two-way business 
communication between states and the EPA, will guide states through the 
submittal process to ensure submission of all required plan components, 
and will enable states to submit proposed plans to the EPA 
electronically for early EPA comments. Electronic submittal will also 
facilitate, expedite and promote national consistency in the EPA's 
review of state plans and promote transparency by providing 
stakeholder-specific access to updated information on state plan status 
and posting of plan requirements for viewing by the public, government 
regulators and regulated entities. The EPA recently implemented an 
electronic submittal process for SIPs under CAA section 110 and 
continues to explore opportunities to increase the ease and efficiency 
with which states and the regulated community can meet regulatory data 
submittal requirements. In summary, the EPA believes electronic 
submittal will be enormously beneficial in terms of improving 
coordination and cooperation between the EPA and its state partners in 
developing approvable state plans. We note, however, that there may be 
some circumstances where having paper copies of the plan is needed to 
facilitate public engagement, and encourage states to take those 
considerations into account.
    d. Plan templates.
    In the proposal, the EPA requested comment on the creation of 
templates for initial submittals and final state plan submittals. 
Multiple commenters requested the EPA provide state plan templates. One 
commenter requested templates for different plan designs (e.g. a mass-
based trading framework, a rate-based trading framework, multi-state 
compliance and a utility-based portfolio approach) and for specific 
plan components (e.g. how to incorporate a state RE standard and an EE 
program into a state plan, how to assess the emission reductions 
delivered by RE and EE). The EPA has determined that the broad range of 
approaches states may take in preparing individual or multi-state plans 
makes the

[[Page 64863]]

development of specific templates challenging and likely not useful to 
states. However, concurrent with this final rule, the EPA is proposing 
model rules for both rate- and mass-based programs in conjunction with 
the proposed federal plan. These effectively can serve as a template 
for states when preparing their state plan submittals. The EPA will 
continue extensive outreach to states and work closely with them on the 
need for additional tools and guidance to facilitate the development of 
approvable state plans.
9. Legal Basis Regarding State Plan Process
    CAA section 111(d)(1) requires the EPA to promulgate procedures 
``similar'' to those in section 110 under which states adopt and submit 
CAA section 111(d) plans. The EPA has interpreted this provision 
previously in the implementing regulations found in 40 CFR part 60 
subpart B. As discussed above, the EPA intends that planned revisions 
to the part 60 implementing regulations will clarify (among other 
things) whether certain procedures are appropriate for the EPA's action 
on CAA section 111(d) state plans, and if so, precisely how those 
procedures should apply. The EPA is proposing these revisions to the 
CAA section 111(d) implementing regulations in the notice of proposed 
rulemaking for the federal plan being issued concurrently with this 
final rule. In this section we discuss the legal basis for procedures 
that the EPA is finalizing in this action: Initial submittals, 
extensions, and plan revisions.
    First, by using the ambiguous word ``similar,'' Congress delegated 
authority to the EPA to determine precisely what procedures would 
govern 111(d) plans. ``Similar'' does not have an identical meaning as 
the word ``same.'' One definition of ``similar'' is ``having likeness 
or resemblance, especially in a general way.'' The American College 
Dictionary 1127 (C.L. Barnhart, ed. 1970). On the other hand, ``same'' 
is defined as ``alike in kind, degree, quality; that is, identical'' or 
``unchanged in character.'' Id. at 1073.
    Had Congress intended that the procedures for section 111(d) plans 
be indistinguishable from those in section 110, Congress knew how to 
say so. See, e.g., 36 U.S.C. 2352(b)(2)(B) (``same procedures''). And 
had Congress intended that the procedures for section 111(d) plans be 
as close as possible to those in section 110, Congress knew how to say 
that. See, e.g., 38 U.S.C. 4325(c) (agency ``shall ensure, to the 
maximum extent practicable, that the procedures are similar to'' 
certain other procedures). Therefore, Congress must have intended to 
give the EPA leeway to create procedures for section 111(d) state plans 
that somewhat vary from those in section 110, so long as the section 
111(d) procedures are reasonably tied to the purpose and text of 
section 111(d). In other words, ``similar'' creates a gap in the 
statute that the EPA may reasonably fill.
    a. Initial submittals and extensions.
    Initial submittals in this instance are a reasonable gap-filling 
procedural step. As explained in our proposal, certain aspects of 
section 111(d) plan development for these particular guidelines warrant 
our creation of this procedural step, even though section 110 does not 
provide for initial submittals. As explained above, though, we are not 
bound under section 111(d)(1) to follow exactly the same procedures.
    With respect to the timing of initial submittals, final submittals, 
and extensions, we note that section 111 does not prescribe any 
particular deadlines, instead leaving it to EPA's discretion to 
establish ``similar'' procedures to section 110. The implementing 
regulations for section 111(d) plans require state plans to be 
submitted within 9 months of finalization of emission guidelines. 
Section 110(a)(1) provides that states should adopt and submit SIPs 
that provide for implementation, maintenance, and enforcement of the 
NAAQS within 3 years, or such shorter period as the Administrator may 
prescribe.\847\ As further explained in Section VIII.E., the EPA is 
providing states with up to 3 years to submit a final plan under this 
rule, contingent upon the grant of an extension through an initial 
submittal due by September 6, 2016. Section 110(a)(1) does not provide 
any particular factors for the Administrator to consider in prescribing 
a shorter period. Thus, the EPA's prescription of a shorter period for 
either an initial submittal or a final plan submittal is consistent 
with the discretion granted in section 110(a)(1). We further discuss 
why the September 6, 2016 initial submittal deadline is reasonable in 
Section VIII.E., and such deadline is achievable by states seeking to 
submit a final plan within 3 years. We also note that section 110(b) 
provides for extensions of 2 years for plans to implement secondary 
NAAQS, that other provisions in part D provide for extensions of due 
dates of attainment plans in certain circumstances, and that the 
section 111(d) implementing regulations provide for extensions 
generally. We conclude, in view of the above discussion of ``similar,'' 
that the approach of initial submittals and extensions of due dates as 
proposed are reasonable procedures that, while not identical to the 
procedures in section 110, are still similar.
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    \847\ Under this grant of authority to prescribe shorter 
deadlines, the EPA has in a number of occasions required SIPs to be 
submitted in 1 year.
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    Some commenters argued that the 1-year period for initial 
submittals and, even assuming an extension, the additional 1- to 2-year 
period for final submittals were unreasonably short, particularly in 
light of the possibility that some state legislatures might need to act 
to provide adequate legal authority for these particular plans. We are 
not finalizing the 1-year extension for single state submittals, and we 
have addressed concerns about legal authority for the initial 
submittals by allowing states to identify remaining legislative action 
in those submittals.
    With respect to the overall period of up to 3 years for submittals, 
we continue to find it reasonable and consistent with other deadlines 
in the CAA. First, section 110(a)(1) requires states to submit a plan 
for implementation, maintenance, and enforcement of new NAAQS within 3 
years of promulgation of that NAAQS. This is true even if the EPA 
promulgates a NAAQS for a previously non-criteria pollutant. In that 
case, it is possible and even likely that at least some state agencies 
will lack statutory authority to regulate the new pollutant. 
Nonetheless, Congress dictated that states should submit section 
110(a)(1) plans within 3 years.
    Furthermore, we note that under subpart 1 of Part D of Title 1, 
attainment plans are generally due no later than 3 years after 
designation of a nonattainment area, and under other subparts of Part 
D, plans are due even more quickly. For example, under subpart 4, 
attainment plans for particulate matter are generally due 18 months 
after designation, and under subpart 5, the same deadline applies for 
attainment plans for sulfur oxides, nitrogen dioxide and lead. 
Developing attainment plans may or may not require states to seek 
additional legislative authority, but certainly in terms of complexity 
they are similar to section 111(d) plans for this guideline. In 
general, attainment plans must contain (among other things) a 
comprehensive inventory of sources of the relevant pollutant and its 
precursors (which in populated areas can be very numerous), control 
measures for those sources (including individualized control measures 
for the larger sources), and modeled demonstrations of

[[Page 64864]]

attainment (which in some instances requires photochemical grid 
modeling). Thus, it is reasonable to have the same timeline for these 
section 111(d) plans as Congress generally provided for attainment 
plans in section 172(b).
    b. State plan modifications.
    Section 110(l) provides for states to revise their SIPs, as does 40 
CFR 60.28 for section 111(d) plans. Section 110(l) also sets out a 
standard for revisions: It prohibits the EPA from approving a SIP 
revision that would interfere with any applicable requirement 
concerning attainment or reasonable further progress, or any other 
applicable requirement of the CAA. Under the existing section 111(d) 
implementing regulations, the Administrator will disapprove section 
111(d) plan revisions as unsatisfactory when they do not meet the 
requirements of subpart B to part 60. See 40 CFR 60.27(c)(3). However, 
the implementing regulations do not set forth a substantive standard 
like that in section 110(l).
    Section 111(d)(1) does not mention revisions (except indirectly 
through the reference to section 110) and, therefore, does not 
explicitly provide any substantive requirements for them. There is, 
therefore, a gap in the statute that the EPA may reasonably fill, since 
many stakeholders commented on the desirability of states being able to 
modify their plans, and the EPA agrees. It is reasonable, at a minimum, 
that the state plan as revised should continue to provide for 
implementation and enforcement of the standards of performance, and to 
achieve the CO2 emission performance rates or state 
CO2 emission performance goal. This is analogous to the 
substantive requirements of section 110(l), which as explained above 
for section 110(a)(2), we may consider in determining how to reasonably 
fill statutory gaps for section 111(d) plans.
    In our proposal, we stated that certain revisions to state plans 
under these emission guidelines, those that revised enforceable 
measures for affected EGUs, should satisfy some additional conditions. 
First, the state should demonstrate that the plan continues to achieve 
the CO2 emission performance rates or state CO2 
emission performance goal. We proposed that this demonstration might be 
simple for minor revisions, but for major revisions a more complete 
demonstration may be required. We are finalizing this proposal. As 
legal basis for this position, we note that a demonstration is 
necessary to show that a state plan provides for implementation of 
standards of performance that achieve the CO2 emission 
performance rates or state CO2 emission performance goal, 
and as explained above we can reasonably require the same of revisions.
    It is also reasonable to tailor the requirements of the 
demonstration to the magnitude of the revision. The EPA has taken a 
similar approach to tailoring the requirements for a technical 
demonstration that, under section 110(l), a SIP revision does not 
interfere with any applicable requirement concerning attainment of the 
NAAQS. If a SIP revision does not relax the stringency of any SIP 
measure, then the demonstration is simple. If the SIP revision does 
relax the stringency of SIP measures, then a qualitative or 
quantitative analysis may be necessary to show non-interference, 
depending on the nature of the revision, the current air quality in the 
area, and other factors.
    Finally, we proposed that revisions ``should not result in reducing 
the required emission performance for affected EGUs specified in the 
original approved plan. In other words, no `backsliding' on overall 
plan emission performance through a plan modification would be 
allowed.'' 79 FR 34917/1. We received adverse comments that this 
standard did not have a basis in section 111(d). According to 
commenters, since the standard for EPA approval of a section 111(d) 
plan is whether the plan is satisfactory in establishing and providing 
for implementation and enforcement of standards of performance that 
achieve the emission performance rates or goal, the same standard 
should apply to revisions. In other words, the standard for revisions 
should be whether the plan as revised is satisfactory. We believe that 
our proposal was unclear as to this point, and we agree that the 
standard for revisions should be the same as for submittals. We have 
finalized this position.

F. State Plan Performance Demonstrations

    This section describes state plan requirements related to 
compliance periods, monitoring and reporting for affected EGUs; plan 
performance demonstrations; consequences if the CO2 emission 
performance rates or state CO2 emission goals are not met; 
and out-year requirements.
1. Compliance Periods, Monitoring and Reporting Requirements for 
Affected EGUs
    For plans that include emission standards on affected EGUs, the EGU 
emission standards for the interim period must have schedules of 
compliance for each interim step 1, 2 and 3 for the calendar years 
2022-2024, 2025-2027 and 2028-2029, respectively. For the final period, 
EGUs must have emission standards that have schedules of compliance for 
each 2 calendar years starting in 2030 (i.e., 2030-2031, 2032-2033, 
2034-2035, etc.). If a backstop is triggered for a state measures plan, 
the schedule of compliance for the federally enforceable emission 
standards must begin no later than 18 months after the backstop is 
triggered and end at the end of the same compliance period. For 
example, if a backstop is triggered on July 1, 2025, the compliance 
period for the backstop emission standards must begin no later than 
January 1, 2027, and end on December 31, 2027. The next compliance 
period for the backstop emission standards would be January 1, 2028-
December 31, 2029.
    In the June 2014 proposal, the EPA proposed that the appropriate 
averaging time for any rate-based emission standard for affected EGUs 
be no longer than 12 months within a plan performance period and no 
longer than 3 years for a mass-based standard. The EPA solicited 
comments on longer and shorter averaging times for emission standards 
included in state plans. The EPA received comments stating that the 
proposed 12-month averaging was too short and that there was no reason 
why the compliance period under a rate-based plan should be different 
from a mass-based plan. Comments stated that a multi-year averaging 
period is appropriate for rate-based and mass-based plans to account 
for variations that can occur in a single year, allowing operators the 
flexibility they need to manage unforeseen events. The commenters also 
recommended that the final rule use discrete 3-year periods for 
compliance reconciliation instead of the rolling-average approach 
proposed.
    The EPA has considered all comments received on this matter and is 
finalizing the compliance periods specified above, which respond to the 
comments by applying to both rate- and mass-based programs, providing 
compliance periods longer than 1 year, and establishing block 
compliance periods rather than a rolling average approach. We agree 
with comments that longer averaging periods allow for operational and 
seasonal variability to even out. The EPA finalizes that states can 
choose to set shorter compliance periods for their emission standards 
but none that are longer than the compliance periods the EPA is 
finalizing in this rulemaking. If a state chooses to set shorter 
compliance periods, we urge them to make efforts to be cognizant of 
other deadlines facing EGUs to assure that there will not be

[[Page 64865]]

conflicts. The EPA recognizes that the compliance periods provided for 
in this rulemaking are longer than those historically and typically 
specified in CAA rulemakings. ``The time over which [the compliance 
standards] extend should be as short term as possible and should 
generally not exceed one month.'' See e.g., June 13, 1989 ``Guidance on 
Limiting Potential to Emit in New Source Permitting'' and January 25, 
1995 ``Guidance on Enforceability Requirements for Limiting Potential 
to Emit through SIP and Sec.  112 Rules and General Permits.'' However, 
the EPA has determined that the longer compliance periods provided for 
in this rulemaking are acceptable in the context of this specific 
rulemaking because of the unique characteristics of this rulemaking, 
including that CO2 is long-lived in the atmosphere, and this 
rulemaking is focused on performance standards related to those long-
term impacts. The distinction between these unique characteristics and 
the EPA's general practice regarding compliance periods is bolstered by 
the EPA guidance on appropriate averaging periods for emission 
limitations in NAAQS implementation. For example, the EPA guidance has 
stated that in implementation of the ozone standards, which have a 
short averaging period, the averaging period for VOC emission 
limitations should be correspondingly short. See 51 FR 43857. A longer 
averaging period for VOC emission limitations (VOCs are one of the key 
precursors to ozone formation) can allow spikes in emissions that 
adversely impact ambient air and violate the short term ozone 
standards. This is precisely the opposite of the unique characteristics 
cited above: the long-lived persistence of CO2 in the 
stratosphere and the intent of these guidelines to address the long-
term impacts.
    State plans must contain requirements for tracking and reporting 
actual plan performance during implementation, which includes reporting 
of CO2 emissions from affected EGUs. Affected EGUs must 
comply with emissions monitoring and reporting requirements that are 
largely incorporated from 40 CFR part 75 monitoring and reporting 
requirements. The majority of affected EGUs are already familiar with 
the reporting requirements of part 75, and because of this, the EPA has 
chosen to streamline the applicable reporting requirements for affected 
EGUs under the state plans in the final rule. States must require all 
affected EGUs to monitor and report hourly CO2 emissions and 
net energy output (including total net MWh output that is comprised of 
generation, and where applicable, useful thermal output converted to 
net MWhs) on a quarterly basis in accordance with 40 CFR part 75. Note 
that this requirement applies for all types of state plans, regardless 
of whether the state chooses the option of the CO2 emission 
performance rates, a state rate-based CO2 emission goal, or 
a state mass-based CO2 emission goal.
    In the June 2014 proposal, the EPA proposed that state plans must 
include monitoring, reporting and recordkeeping requirements for useful 
energy output from affected EGUs. Multiple commenters questioned 
whether gross rather than net electrical production should be reported 
by affected EGUs and recommended that the EPA should utilize gross 
rather than net generation. Many commenters recommended electricity be 
reported in the form used in the 111(b) rules for consistency between 
reporting requirements and simplification of calculation of emission 
limitations between new and old sources. Commenters also stated that to 
the extent the EPA seeks to provide guidance to states regarding its 
preferred monitoring and reporting procedures, the EPA should encourage 
states to avoid imposing additional monitoring and reporting burdens by 
taking advantage of the monitoring requirements that already exist to 
the greatest extent possible. For example, the commenters noted that 
the 40 CFR part 75 monitoring procedures used to comply with other 
programs, such as the Title IV Acid Rain Program, provide much of the 
data that would be needed to demonstrate compliance under the rule. 
Comments stated that the June 2014 proposal appeared to mandate a 
monitoring approach that would eliminate key flexibilities provided in 
the part 75 regulations, thus requiring utilities to maintain separate 
document collection and reporting procedures and potentially 
eliminating important alternative monitoring options intended to ensure 
representative, cost-effective monitoring approaches are available. The 
commenters asked the EPA to revise its proposal to make clear that the 
procedures established under part 75 will suffice or explain the need 
for any exceptions. Commenters indicated that the rule should require 
all affected EGUs to monitor CO2 emissions and net hourly 
electric output under 40 CFR part 75, and report the data using the 
EPA's Emission Collection and Monitoring Plan System (ECMPS) assuring a 
more uniform monitoring and reporting process for all EGUs. The EPA 
believes that the final monitoring and reporting requirements (via 
ECMPS) address the issue of duplicative requirements and alleviate 
concern about lost flexibility raised by commenters.
2. Plan Performance Demonstrations
    The state plan must include emission performance checks, and for 
state measures plans, periodic program implementation milestones. The 
state plan must provide for tracking of emission performance, and for 
measures to be implemented if the emission performance of affected EGUs 
in the state does not meet the applicable CO2 emission 
performance rates or state CO2 emission goal during a 
performance period.
    As discussed above in section VII, the agency is finalizing 
CO2 emission performance rates or state-specific 
CO2 emission goals that represent emission levels to be 
achieved by 2030 and emission levels to be achieved over the 2022-2029 
interim period, and over three interim steps of 2022-2024, 2025-2027 
and 2028-2029. A state may choose to define different interim step 
emission levels for achieving its required 2022-2029 average 
performance rate. The EPA recognizes the importance of ensuring that, 
during the 8-year interim period (2022-2029) for the interim 
performance rates or interim state goal, a state is making steady 
progress toward achieving the required level of emission performance. 
For both emission standards plans and state measures plans, the final 
rule requires periodic checks on overall emission performance leading 
to corrective measures or implementation of the backstop, if necessary, 
as described in section VIII.F.3 below. States must demonstrate that 
the interim steps were achieved at the end of the first two interim 
step periods.
    In 2032 and every 2 years thereafter, states must demonstrate that 
affected EGUs achieved the final performance rates or state goal on 
average or cumulatively, as appropriate, during each 2-year reporting 
period (i.e., 2030-31, 2032-33, 2034-2035 etc.). The multi-year 
performance periods for measuring actual plan performance against the 
performance rates or state goals allow states some flexibility that 
accounts for seasonal operation of affected EGUs, and inclusion of RE 
and demand-side EE efforts.
    For a rate-based plan, emission performance is an average 
CO2 emission rate for affected EGUs representing cumulative 
CO2 emissions for affected EGUs over the course of each 
reporting period divided by cumulative MWh

[[Page 64866]]

energy output \848\ from affected EGUs over the reporting period, with 
rate adjustments for qualifying measures, such as RE and demand-side EE 
measures. For a mass-based plan, emission performance is total tons of 
CO2 emitted by affected EGUs over the reporting period.
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    \848\ For EGUs that produce both electric energy output and 
other useful energy output, there would also be a credit for non-
electric output, expressed in MWh.
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    For emission standards plans, as discussed in section VIII.D, the 
state must submit a report to the EPA containing the emissions 
performance comparison for each reporting period no later than the July 
1 following the end of each reporting period (i.e., by July 1, 2025; 
July 1, 2028; July 1, 2030; July 1, 2032; and so on). As discussed in 
section VIII.D, the emission comparison required in the July 1, 2030 
report must compare the actual emissions from affected EGUs over the 
interim period (2022-2029) with the interim CO2 emission 
performance rates or state CO2 emission goal. The report is 
not required to include a comparison for the interim step 3 period, but 
must include the actual emissions from affected EGUs during the interim 
step 3 period.
    The EPA notes that for certain types of emission standards plans, 
with mass-based emission standards in the form of an emission budget 
trading program, achievement of a state's mass-based CO2 
goal (including interim step goals and final goal) will be assessed by 
the EPA based on compliance by affected EGUs with their emission 
standards under the program, rather than CO2 emissions 
during a specific interim step period or final period. This approach is 
limited to plans with emission budget trading programs where compliance 
by affected EGUs with the emission standards will ensure that, on a 
cumulative basis, the state interim and final mass-based CO2 
goals are achieved.\849\ This approach allows for CO2 
allowance banking across plan performance periods, including from the 
interim period to the final period. As a result, CO2 
emissions by affected EGUs could differ from the state mass-based 
CO2 goal during an individual plan performance period, but 
on a cumulative basis CO2 emissions from affected EGUs would 
not exceed what is allowable if the interim and final CO2 
goals are achieved.
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    \849\ Emission budget trading programs in such plans establish 
CO2 emission budgets equal to or less than the state mass 
CO2 goal, as specified for the interim plan performance 
period (including specified levels in interim steps 1 through 3) and 
the final 2-year plan performance periods.
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    Also as discussed in section VIII.D, states that choose a state 
measures plan must submit an annual report no later than July 1 
following the end of each calendar year in the interim period. This 
annual report must include the status of the implementation of 
programmatic state measures milestones identified in the state plan 
submittal. The annual report that follows the end of each reporting 
period (i.e., 2022-2024, 2025-2027, and 2028-2029) must also include an 
emissions performance comparison for the reporting period, as described 
above for the emission standards plan. As discussed in section VIII.D, 
the emission comparison required in the July 1, 2030 report must 
compare the actual emissions from affected EGUs over the interim period 
(2022-2029) with the interim CO2 emission performance rates 
or state CO2 emission goal. The report is not required to 
include a comparison for the interim step 3 period, but must include 
the actual emissions from affected EGUs during the interim step 3 
period. Beginning with the final period of 2030 and onward, states 
using a state measures plan must submit a biennial report no later than 
July 1 following the end of each reporting period with an emission 
performance comparison for each reporting period, consistent with the 
reporting requirements for emission standards plans.
    In the June 2014 proposal, the EPA proposed that a state report is 
due to the EPA no later than July 1 of the year immediately following 
the end of each reporting period. The EPA requested comment on the 
appropriate frequency of reporting of the different proposed reporting 
elements, considering both the goals of minimizing unnecessary burdens 
on states and ensuring program effectiveness. In particular, the agency 
requested comment on whether full reports containing all of the 
elements should only be required every 2 years rather than annually and 
whether these reports should be submitted electronically, to streamline 
transmission.
    The EPA mainly received adverse comments for requiring annual state 
reporting; commenters stated that this requirement was too burdensome 
for both states and the EPA. Commenters also requested that the EPA 
extend the due date of the annual report from July 1 to at least 
December 31. Commenters stated that because of the timing of current 
data collection and the need to leave time to organize and submit the 
reports, allowing only 6 months after the close of the year is 
problematic. Commenters asked that the EPA consider reducing the amount 
of data required if annual reporting was required.
    Considering the comments received and the goals of minimizing 
unnecessary burdens on states and ensuring program effectiveness, the 
EPA has reduced the frequency of reporting of emissions data to every 3 
years for the first two interim steps and every 2 years thereafter. 
However, the EPA is finalizing that state reports are due to the EPA no 
later than July 1 following the end of each reporting period. The EPA 
believes states can design their state plans to receive the data and 
information needed for these reports in a timely manner so that this 
requirement can be met. Furthermore, some of the state reporting 
requirements, such as reporting of EGU emissions, can be met through 
existing reporting mechanisms (ECMPS) and would not place additional 
burdens on states.
3. Consequences if Actual Emission Performance Does Not Meet the 
CO2 Emission Performance Rates or State CO2 
Emission Goal
    The EPA recognizes that, under certain scenarios, an approved state 
plan might fail to achieve a level of emission performance that meets 
the emission guidelines or the level of performance established in a 
state plan for an interim milestone. Despite successful implementation 
of certain types of plans, emissions under the plan could turn out to 
be higher than projected at the time of plan approval because actual 
conditions vary from assumptions used when projecting emission 
performance. Emissions also could theoretically exceed projections 
because affected entities under a state plan did not fulfill their 
responsibilities, or because the state did not fulfill its 
responsibilities.
    The final rule specifies the consequences in the event that actual 
emission performance under a state plan does not meet, or is not on 
track to meet, the applicable interim and interim step CO2 
emission performance rates or state goals in 2022-2029, or does not 
meet the applicable final CO2 emission performance rates or 
state CO2 emission goal in 2030-2031 or later. The 
determination that a state is not on track to meet the applicable 
interim goal or interim step goals in 2022-2029 or the applicable final 
goal in 2030-2031 or later, or the CO2 emission performance 
rates, will be made through the actual performance checks to be 
included in state reports of performance data described in section 
VIII.D.2.a above.
    For emission standards plans, the final rule specifies that 
corrective measures must be enacted once triggered. Corrective measures 
apply

[[Page 64867]]

only to emission standard plans in which full compliance by affected 
EGUs would not necessarily lead to achievement of the emission 
performance rates or CO2 emission goals.\850\ For such 
plans, corrective measures are triggered if actual CO2 
emission performance by affected EGUs is deficient by 10 percent or 
more relative to the specified level of emission performance in the 
state plan for the step 1 or step 2 interim performance periods. 
Corrective measures also are triggered if actual emission performance 
fails to meet the specified level in the plan for the 8-year interim 
period 2022-2029, or for any 2-year final goal performance period 
(beginning in 2030). In such cases, the state report must include a 
notification to the EPA that corrective measures have been triggered. 
If, in the event of such an exceedance, the EPA determines that 
corrective measures have been triggered and the state has failed to 
notify the EPA, the EPA will inform the affected EGUs that corrective 
measures have been triggered.\851\
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    \850\ To be specific, corrective measures requirements apply to 
all emission standard plan designs that do not mathematically assure 
that the plan performance level will be achieved when all affected 
EGUs are in compliance with their emission standards, regardless of 
electricity production and electricity mix. Corrective measures 
requirements apply, for example, to emission standards plans that 
include standards on affected EGUs that differ from the emission 
performance rates in the guidelines. Backstop requirements apply to 
state measures plans.
    \851\ The EPA notes that as part of the proposed federal plan 
rulemaking, it is proposing a regulatory mechanism to call plans in 
the instances of substantial inadequacy to meet applicable 
requirements or failure to implement an approved plan.
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    When corrective measures are triggered, if the state plan does not 
already contain corrective measures, the state must submit to the EPA a 
plan revision including corrective measures that adjust requirements or 
add new measures. The corrective measures must both ensure future 
achievement of the CO2 emission performance rates or state 
CO2 emission goal and achieve additional emission reductions 
to offset any emission performance shortfall that occurred during a 
performance period. The shortfall must be made up as expeditiously as 
practicable. The state plan revision submission must explain how the 
corrective measures both make up for the shortfall and address the 
state plan deficiency that caused the shortfall. The state must submit 
the revised plan to the EPA as expeditiously as practicable and within 
24 months after submitting the state report indicating the exceedance. 
The 24-month time period allows time to identify corrective measures 
and make rule changes through state regulatory processes. The EPA will 
then act on the plan revision within 12 months, consistent with other 
plan revisions and with the timing for final plan submittals originally 
submitted by states. The state must implement corrective measures 
within 6 months of the EPA's approval of a plan revision adding them.
    For states using the state measures approach, the EPA is finalizing 
the backstop requirement as described in section VIII.C.3 of this 
preamble. As discussed in section VIII.D.2, the determination that a 
state using the state measures approach is not on track to meet the 
applicable interim goal or interim step goals in 2022-2029, or the 
applicable final goal in 2030-2031 or later, is based on checks that 
must be included in state reports that must be submitted annually 
during the interim period and biennially during the final period. The 
state must annually report on its progress in meeting its programmatic 
state measures milestones during the interim period. In addition, the 
state must report actual emission performance checks, similar to the 
requirements discussed above for emission standards plans, in 2025, 
2028, 2030, and every 2 years thereafter. If, at the time of the state 
report to the EPA, the state did not meet the programmatic state 
measures milestones for the reporting period, or the performance check 
shows that the plan's actual CO2 emission performance 
warrants implementation of backstop requirements,\852\ the state must 
include in the state report a notification to the EPA that the backstop 
has been triggered. If, in the event of such an exceedance, the EPA 
determines that the backstop has been triggered and the state has 
failed to notify the EPA, the EPA will inform the affected EGUs that 
the backstop has been triggered.\853\
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    \852\ As explained in section VIII.C.3.b., state measures plans 
must require the backstop to take effect if actual CO2 
emission performance fails to meet the level of emission performance 
specified in the plan over the 8-year interim performance period 
(2022-2029), or for any 2-year final goal performance period. The 
plan also must require the backstop to take effect if actual 
emission performance is deficient by 10 percent or more relative to 
the performance levels that the state has chosen to specify in its 
plan for the interim step 1 period (2022-2024) or the interim step 2 
period (2025-2027).
    \853\ The EPA notes that as part of the proposed federal plan 
rulemaking, it is proposing a regulatory mechanism to call plans in 
the instances of substantial inadequacy to meet applicable 
requirements or failure to implement an approved plan.
---------------------------------------------------------------------------

    For multi-state plans, corrective measure or backstop provisions 
would be required for the same plan approaches for which those 
provisions are required in individual state plans. For multi-state 
plans using plan approaches to which corrective measures or backstop 
requirements apply, all states that are party to the multi-state plan 
would be subject to corrective action or backstop requirements, and 
requirements to make up the past CO2 emission performance 
shortfall, if those requirements were triggered. This is because multi-
state plans are joint plans (even if created through separate state 
submittals). That would not be the case for coordinated individual 
state plans linked through interstate ERC or emission allowance 
trading. In the case of coordinated individual state plans, for plan 
types subject to corrective measure or backstop requirements, the state 
where the CO2 emission performance deficiency occurs would 
be required to implement corrective measures or backstop requirements 
for affected EGUs, as applicable, and remedy the past CO2 
emission performance shortfall.
    Multiple commenters requested that corrective measures not be 
required in the case of a catastrophic, uncontrollable event. We 
recognize that there are potential system emergencies that cannot be 
anticipated that could cause a severe stress on the electricity system 
for a length of time such that the multi-year requirements in a state 
plan may not be achievable by certain affected EGUs without posing an 
otherwise unmanageable risk to reliability. We are finalizing a 
reliability safety valve, which includes an initial period of up to 90 
days during which a reliability-critical affected EGU or EGUs will not 
be required to meet the emission standard established for it under the 
state plan but rather will meet an alternative standard. While the 
initial 90-day period is in use, the emissions of the affected EGU or 
EGUs that exceed their obligations under the approved state plan will 
not be counted against the state's overall goal or emission performance 
rate for affected EGUs and will not be counted as an exceedance that 
would otherwise trigger corrective measures under an emission standard 
plan type or an exceedance that would trigger a backstop under a state 
measures plan type. Use of the reliability safety valve will not alter 
or abrogate any other obligations under the approved state plan. After 
the initial period of up to 90 days, the reliability-critical affected 
EGU is required to continue to operate under the original state plan 
emission standard or an alternative standard as part of the

[[Page 64868]]

reliability safety valve, and the state must revise its plan to 
accommodate changes needed to respond to ongoing reliability 
requirements and to ensure than any emissions excess of the applicable 
state goals or performance rates occurring after the initial period of 
up to 90 days are accounted for and offset. See section VIII.G.2.e of 
this preamble.
    Multiple commenters supported the inclusion of strong enforcement 
measures for ensuring the interim and final goals are met, including 
the required use of corrective measures when triggered. Other 
commenters provided feedback as to the percentage that actual emission 
performance would need to exceed the level of emission performance 
specified in the statewide plan to trigger corrective measures. Some 
commenters supported the trigger that we are finalizing (actual 
emissions or emission rate performance that is 10 percent or more than 
the specified level of emission performance in the state plan for the 
interim step 1 or step 2 performance periods), while some recommended a 
lower or higher trigger.
    The agency is finalizing the trigger at the level of 10 percent for 
the interim step 1 or step 2 performance periods. Ten percent is a 
reasonable level to ensure that when deficiencies in state plan 
performance begin to emerge, corrective measures (or backstop 
requirements) will be implemented promptly to avoid emissions 
shortfalls (or minimize the extent of shortfalls) relative to the 8-
year interim goal and the final goal, which reflect the BSER. The 10 
percent figure also provides latitude for a state's emission 
improvement trajectory during the interim period to deviate a bit from 
its planned path without triggering these requirements, as the state 
initiates or ramps up programs to meet the 8-year interim goal and 
final goal.
    The EPA requested comment on whether the agency should promulgate a 
mechanism under CAA section 111(d) similar to the SIP call mechanism in 
CAA section 110. Under this approach, after the agency makes a finding 
of the plan's failure to achieve the CO2 emission 
performance rates or state CO2 emission goal during a 
performance period, the EPA would require the state to cure the 
deficiency with a new plan within a specified period of time. If the 
state still lacked an approved plan by the end of that time period, the 
EPA would have the authority to promulgate a federal plan under CAA 
section 111(d)(2)(A). 79 FR 34830, 34908/1-2 (June 18, 2014).
    The EPA intends that planned revisions to the part 60 implementing 
regulations will clarify (among other things) whether the EPA has 
authority to call for plan revisions under section 111(d) when a 
state's plan is not complying with the requirements of this guideline, 
and if so, precisely what procedures should apply. The EPA is proposing 
these revisions to the 111(d) implementing regulations in the notice of 
proposed rulemaking for the federal plan. The EPA is not taking final 
action now on this issue or the related change to the implementing 
regulations.
    a. Legal basis for corrective measures.
    The EPA discussed the concept of corrective measures in our 1992 
General Preamble for the Implementation of Title I of the CAA 
Amendments of 1990. 57 FR 13498 (Apr. 16, 1992). The General Preamble 
sets out four general principles that apply to all SIPs, ``including 
those involving emissions trading, marketable permits and allowances.'' 
Id. at 13568. The fourth principle, accountability, means (among other 
things) that ``the SIP must contain means . . . to track emission 
changes at sources and provide for corrective action if emissions 
reductions are not achieved according to the plan.'' In the General 
Preamble, we noted that Part D of Title I explicitly provided for this 
in certain instances by requiring milestones and contingency measures.
    Some commenters noted that the contingency measures explicitly 
required by part D are required to be adopted in the attainment plan 
and ready to implement when a milestone is not achieved or the area 
fails to attain the relevant NAAQS. These commenters therefore 
concluded that corrective measures for 111(d) plans should likewise 
already be adopted in the 111(d) plan and ready to implement. We 
disagree. Under Part D, contingency measures are not expected to fully 
bring the area into attainment. In fact, this would not be possible 
given the difficulty of predicting in advance exactly what measures 
would be needed to fully attain. A better analogue in Part D for the 
corrective measures in these guidelines is the primary way Part D 
addresses failure to attain: The state is required to revise its plan 
in various ways within a certain time in order to bring about 
attainment. See, e.g., section 179(d). This is analogous to what we are 
requiring for corrective measures. Thus, part D contingency measures 
are unlike the corrective measures in this rule.
    However, the requirement to revise an attainment plan in response 
to failure to attain differs somewhat from the corrective measures in 
these guidelines. Under these guidelines, the corrective measures must 
make up the difference by which the plan fell short of the goal, 
including any prior shortfall that had accumulated if the plan fell 
short of the goal in prior years. There is no corresponding requirement 
in attainment planning to increase the stringency of the plan by an 
amount that somehow makes up for any shortfall in attainment from prior 
years; instead the revised plan must demonstrate attainment going 
forward, and other more stringent requirements (such as requirements 
for best available control measures) may be triggered.
    This distinction is the natural result of the difference between 
these guidelines and NAAQS attainment planning. In this case, we are 
finalizing guidelines representing technology-based standards for a 
pollutant with cumulative and long-lasting effects. If a plan falls 
short of a performance goal, then in effect the standards of 
performance in the plan have failed to reflect the BSER over the 
corresponding period. Due to the cumulative effects of CO2, 
it is possible to remedy this failure by requiring the plan to be 
revised in such a way that the standards of performance in the revised 
plan will reflect the BSER over the cumulative plan period, and this 
can be done by requiring the revised plan to make up the shortfall from 
the previous period. In short, the flexibility that these guidelines 
provide should not come at the cost of allowing the standards of 
performance to reflect less than the BSER over the long run.\854\
---------------------------------------------------------------------------

    \854\ Similar considerations apply to the requirement under the 
state measures approach to revise the plan to make up the shortfall.
---------------------------------------------------------------------------

    Some commenters noted that 111(d) does not contain explicit 
provisions regarding corrective measures, and they therefore inferred 
that the EPA is not authorized to require them. That inference is 
mistaken. The requirement for 111(d) plans to ``provide for 
implementation and enforcement'' of the standards of performance is 
ambiguous and does not directly speak to whether corrective measures 
should or should not be required. There is therefore a gap for the EPA 
to fill. While the discussion above about Part D does not independently 
provide any authority to fill this gap, the fact that Congress created 
a scheme with stages of planning in Part D suggests that it would be 
reasonable, if appropriate, to fill this gap in 111(d) in a similar 
way.
    In this guideline, it is appropriate for emission standards plans 
to fill this gap with corrective measures if triggered. There are two 
ways an emission standards plan can provide for implementation of 
standards of performance that achieve the CO2

[[Page 64869]]

emission performance rates or requisite state CO2 emission 
performance goal. First, the state can set emission standards that 
necessarily achieve the performance rates or goal, even if the affected 
EGUs in the future vary in their relative amounts of electricity 
generated. Second, the state can set emission standards that are 
demonstrated to achieve the performance rates or goal based on 
assumptions about the relative amounts of electricity generated, but 
which may turn out to not actually achieve the goal even if all 
affected EGUs comply. This is analogous to an attainment plan that 
demonstrated attainment by the applicable attainment date, but due to 
unpredicted economic changes actually failed to attain. In this second 
case, the EPA interprets the ambiguous language ``provide for 
implementation . . . of standards of performance'' in the context of 
achieving the performance rate or emissions goal, to mean that at the 
time the plan is submitted it must contain some mechanism to check the 
progress of the plan and correct course. The EPA has determined that, 
for this particular rule, the minimum mechanism is the set of 
milestones and provisions for corrective measures specified in this 
rule. Indeed, not requiring corrective measures in the case of 
deficient plan performance would undercut the viability of state plan 
options other than emission standard plans with uniform rates applied 
to all affected EGUs within the state.
4. Out-Year Requirements: Maintaining or Improving the Level of 
Emission Performance Required by the Emission Guidelines
    The agency is determining CO2 emission performance rates 
and state CO2 emission goals for affected EGU emission 
performance based on application of the BSER during specified time 
periods. This raises the question of whether affected EGU emission 
performance should be maintained at the 2030 level--or instead should 
be further improved--once the final CO2 emission performance 
rate or state CO2 emission goal is met in 2030. This 
involves questions of performance rate and goal-setting as well as 
questions about state planning. The EPA believes that Congress either 
intended the emission performance improvements required under CAA 
section 111(d) to be maintained or, through silence, authorized the EPA 
to reasonably require maintenance. Other CAA section 111(d) emission 
guidelines set emission limits that do not expire. Therefore, the EPA 
is finalizing that the level of emission performance for affected EGUs 
represented by the final CO2 emission performance rates or 
state CO2 emission goal must continue to be maintained in 
the years after 2030.
    As noted above, the state plan must demonstrate that plan measures 
are projected to achieve the final emission performance level by 2030. 
In addition, the state plan must identify requirements that continue to 
apply after 2030 and are likely to maintain affected EGU emission 
performance meeting the final goal. The state plan would be considered 
to provide for maintenance of emission performance consistent with the 
final goal if the plan measures used to demonstrate projected 
achievement of the final goal by 2030 will continue in force and not 
sunset. After implementation, the state is required to compare actual 
plan performance against the final goal on a 2-year average basis 
starting in 2030, and to implement corrective measures or a backstop if 
triggered.
    In the proposal, the EPA noted that ``CAA section 111(b)(1)(B) 
calls for the EPA, at least every eight years, to review and, if 
appropriate, revise federal standards of performance for new sources'' 
in order to assure regular updating of performance standards as 
technical advances provide technologies that are cleaner or less 
costly. The proposal ``requests comment on the implications of this 
concept, if any, for CAA section 111(d).'' 79 FR 34830, 34908/3 (June 
18, 2014).
    We acknowledge the obligation to review section 111(b) standards as 
stated. The EPA is not finalizing any position with respect to any 
implications of this concept for section 111(d). We are promulgating 
rules for section 111(d) state plans that will establish standards of 
performance for existing sources to which a section 111(b) standard of 
performance would apply if such sources were new sources, within the 
definition in section 111(a)(2) of ``new source.'' It is not necessary 
to address at this time whether subsequent review and/or appropriate 
revision of the corresponding section 111(b) standard of performance 
have any implications for review and/or revision of this rule.
    a. Legal basis for maintaining emission performance.
    In the proposal, the EPA proposed ``that the level of emission 
performance for affected EGUs represented by the final goal should 
continue to be maintained.'' The EPA explained that ``Congress either 
intended the emission performance improvements required under CAA 
section 111(d) to be permanent or, through silence, authorized the EPA 
to reasonably require permanence. Other CAA section 111(d) emission 
guidelines set emission limits to be met permanently.'' 79 FR 34830, 
34908/2 (June 18, 2014). We also requested comment on whether ``we 
should establish BSER-based state performance goals that extend further 
into the future (e.g. beyond the proposed planning period), and if so, 
what those levels of improved performance should be.'' Id. at 34908/3.
    We received adverse comment on establishing BSER-based state 
performance goals beyond the proposed planning period. Commenters 
argued that we did not have a sufficient basis at this time to 
determine what those future goals should be. We agree and have decided 
not to establish such goals. We are finalizing, though, that the level 
of emission performance for affected EGUs represented by the final goal 
should continue to be maintained, for the reasons given in our proposal 
and quoted above.
    The general structure of the CAA supports our interpretation. 
Section 111(d) plans establish standards of performance that reflect 
the BSER, a technology-based standard. Generally speaking, in the 
future technology will only improve, and correspondingly the CAA does 
not provide explicit processes to relax technology-based standards. In 
contrast, the provisions in Part D of title I that address attainment 
of health-based standards, the NAAQS, explicitly provide that once the 
NAAQS are attained, emission reduction measures may be relaxed so long 
as the NAAQS are maintained. The absence in section 111(d) of explicit 
provisions for future relaxation of emission reduction measures, as 
compared to Part D, supports our interpretation that the emission 
reductions continue to be on-going after the CO2 emission 
performance rates or state CO2 emission goals are achieved 
in 2030. This is consistent with our past practice for section 111(d) 
rules, which do not contain any provision that in the future removes or 
relaxes the promulgated guidelines. In light of the persistence of 
CO2 as a pollutant and its long-term impacts, it is 
particularly critical in these guidelines to explicitly provide for 
continuing emission reductions.

G. Additional Considerations for State Plans

1. Consideration of a Facility's ``Remaining Useful Life'' and ``Other 
Factors''
    This section discusses the way in which the final emission 
guidelines address the CAA section 111(d)(1)

[[Page 64870]]

provision requiring the Administrator, in promulgating 111(d) 
regulations, to ``permit the State in applying a standard of 
performance to any particular source under a [111(d)] plan . . . to 
take into consideration, among other factors, the remaining useful life 
of the existing source to which such standard applies.''
    The final guidelines permit a state, in developing its state plan, 
to fully consider and take into account the remaining useful life of an 
affected EGU and other factors in establishing the requirements that 
apply to that EGU, as discussed further below. Therefore, consideration 
of facility-specific factors and in particular, remaining useful life, 
does not justify a state making further adjustments to the performance 
rates or aggregate emission goal that the guidelines define for 
affected EGUs in a state and that must be achieved by the state plan. 
Thus, these guidelines do not provide for states to make additional 
goal adjustments based on remaining useful life and other facility-
specific factors because they can fully consider these factors in 
designing their plans.
    a. Statutory and regulatory backdrop.
    This section describes the statutory and existing regulatory 
background concerning facility-specific considerations in 
implementation of section 111(d).
    Section 111(d)(1)(A) requires states to submit a plan that 
``establishes standards of performance'' for existing sources. Under 
section 111(d)(1)(B), the plan must also ``provide for implementation 
and enforcement of such standards of performance.'' Finally, the last 
sentence of section 111(d)(1) provides: ``Regulations of the 
Administrator under this paragraph shall permit the State in applying a 
standard of performance to any particular source under a plan submitted 
under this paragraph to take into consideration, among other factors, 
the remaining useful life of the existing source to which such standard 
applies.''
    The EPA's 1975 implementing regulations \855\ addressed a number of 
facility-specific factors that might affect requirements for an 
existing source under section 111(d). Those regulations provide that 
for designated pollutants, standards of performance in state plans must 
be as stringent as the EPA's emission guidelines. Deviation from the 
standard might be appropriate where the state demonstrates with respect 
to a specific facility (or class of facilities):
---------------------------------------------------------------------------

    \855\ 40 FR 53340 (Nov. 17, 1975).
---------------------------------------------------------------------------

    (1) Unreasonable cost of control resulting from plant age, 
location, or basic process design;
    (2) Physical impossibility of installing necessary control 
equipment; or
    (3) Other factors specific to the facility (or class of facilities) 
that make application of a less stringent standard or final compliance 
time significantly more reasonable.
    This provision was amended in 1995 (60 FR 65387, December 19, 
1995), and is now prefaced with the language ``Unless otherwise 
specified in the applicable subpart on a case-by-case basis for 
particular designated facilities or classes of facilities.'' 40 CFR 
60.24(f).
    b. Our proposal regarding the implementing regulations.
    Our proposal stated that the reference to ``[u]nreasonable cost of 
control resulting from plant age'' in 60.24(f) ``implements'' the 
statutory provision on remaining useful life. We also stated that the 
implementing regulations ``provide the EPA's default structure for 
implementing the remaining useful life provision of CAA section 
111(d).'' We noted that the prefatory language ``unless otherwise 
specified in the applicable subpart'' gives the EPA discretion to alter 
the extent to which the implementing rules applied if appropriate for a 
particular source category and guidelines. We requested comment on our 
analysis of the existing implementing regulations and any implications 
for our regulatory text in respect to how these guidelines relate to 
those regulations.
    Commenters stated, among other things, that the sentence concerning 
``remaining useful life'' was added in the 1977 CAA Amendments and that 
therefore it could not be said that provisions from the 1975 
implementing regulations ``implement'' the sentence. The EPA does not 
think as a general matter that it is necessarily impossible that a pre-
statutory amendment rule could continue to serve as a reasonable 
implementation of a post-statutory amendment provision. However, we 
also think it is appropriate, as we suggested in the June 2014 
proposal, to specify in the applicable subpart for these guidelines 
that the provisions in 60.24(f) should not apply to the class of 
facilities covered by these guidelines. As a result, regardless of 
whether the implementing regulations appropriately implement the 
``remaining useful life'' provision in general, the relevant 
consideration is that, as we now explain, these particular guidelines 
``permit the State in applying a standard of performance to any 
particular source under a plan submitted under this paragraph to take 
into consideration, among other factors, the remaining useful life of 
the existing source to which such standard applies.''
    c. How these emission guidelines permit states to consider 
remaining useful life and other facility-specific factors.
    The EPA notes that, in general, the implementing regulation 
provisions for remaining useful life and other facility-specific 
factors are relevant for emission guidelines in which the EPA specifies 
a presumptive standard of performance that must be fully and directly 
implemented by each individual existing source within a specified 
source category. Such guidelines are similar to a CAA section 111(b) 
standard in their form. For example, the EPA emission guidelines for 
sulfuric acid plants, phosphate fertilizer plants, primary aluminum 
plants, Kraft pulp plants, and municipal solid waste landfills specify 
emission limits for sources.\856\ In the case of such emission 
guidelines, some individual sources, by virtue of their age or other 
unique circumstances, may warrant special accommodation.
---------------------------------------------------------------------------

    \856\ See ``Phosphate Fertilizer Plants; Final Guideline 
Document Availability,'' 42 FR 12022 (Mar. 1, 1977); ``Standards of 
Performance for New Stationary Sources; Emission Guideline for 
Sulfuric Acid Mist,'' 42 FR 55796 (Oct. 18, 1977); ``Kraft Pulp 
Mills, Notice of Availability of Final Guideline Document,'' 44 FR 
29828 (May 22, 1979); ``Primary Aluminum Plants; Availability of 
Final Guideline Document,'' 45 FR 26294 (Apr. 17, 1980); ``Standards 
of Performance for New Stationary Sources and Guidelines for Control 
of Existing Sources: Municipal Solid Waste Landfills, Final Rule,'' 
61 FR 9905 (Mar. 12, 1996).
---------------------------------------------------------------------------

    In these final guidelines for state plans to limit CO2 
from affected EGUs, however, the agency does not specify presumptive 
performance rates that each individual EGU is to achieve in the absence 
of trading. Instead, these guidelines provide collective performance 
rates for two classes of affected EGUs (steam generating units and 
stationary combustion turbines), and give states the alternative of 
developing plans to achieve a state emission goal for the collective 
group of all affected EGUs in a state. Providing states with the 
ability to consider facility-specific factors such as remaining useful 
life in designing their state plans is one of the fundamental reasons 
that the EPA designed the final rule in this way. In addition, the 
significant revisions since proposal to address achievability concerns 
(e.g., moving the start date from 2020 to 2022, and other changes in 
interim and final state goals summarized in the next section) will help 
to ensure that states in practice can consider remaining useful life 
and other facility-specific factors in setting EGU requirements. Of 
course, EGUs vary considerably in age, so remaining useful life is 
potentially

[[Page 64871]]

relevant to regulation of some units and not others.
    The guidelines capitalize on the inherent flexibility offered by 
the CO2 emission performance rates and by the state 
CO2 emission goals approach, allowing states flexibility on 
the form of the EGU standards that they include in CAA section 111(d) 
plans. A state could select a form of standards (e.g., marketable 
credits or permits, retirement of certain older facilities after their 
useful life, etc.) that avoids or diminishes concerns about facility-
specific factors such as remaining useful life. If a state adopted the 
CO2 emission performance rates for fossil fuel-fired 
electric utility steam generating units and stationary combustion 
turbines in conjunction with rate-based trading, though, the state 
would be taking remaining useful life into consideration by allowing 
affected EGUs to comply using ERCs. In effect, under a trading program 
with repeating compliance periods, a facility with a short remaining 
useful life has a total outlay that is proportionately smaller than a 
facility with a long remaining useful life, simply because the first 
facility would need to comply for fewer compliance periods and would 
need proportionately fewer ERCs than the second facility. Buying ERCs 
would avoid excessive up-front capital expenditures that might be 
unreasonable for a facility with a short remaining useful life, and 
would reduce the potential for stranded assets.
    In addition to providing states with flexibility on the form of the 
standards of performance in their plans, the guidelines leave to each 
state the design of the specific requirements that fall on each 
affected EGU in applying those standards. To the extent that an 
emission standard that a state may wish to adopt for affected EGUs 
raises facility-specific issues, the state may make adjustments to a 
particular facility's requirements on facility-specific grounds, so 
long as any such adjustments are reflected (along with any necessary 
compensating emission reductions to meet the state goal) in the state's 
CAA section 111(d) plan submission.
    Finally, we note that these guidelines permit states to use a rate 
or mass CO2 emission goal, and that each of these pathways 
allow states multiple design choices. Under either pathway states can 
take into consideration remaining useful life and seek to avoid 
stranded assets.
    The EPA believes that this approach to permitting states to 
consider remaining useful life is appropriate because it reflects, and 
is compatible with, the interconnected nature of the electricity 
system.
    Although this discussion emphasizes state flexibility on plan 
design, it is important to note that the main intended beneficiaries of 
state flexibility are the affected EGUs themselves. As a key case in 
point, the EPA has endeavored to craft the final guidelines to support 
and facilitate state plans that include trading systems, including 
interstate trading systems that can help EGUs continue to operate with 
the flexibility that they currently enjoy on regional grid levels.
    Trading can provide affected EGUs that have a limited remaining 
useful life with the flexibility to comply through purchasing 
allowances or ERCs, thereby avoiding major capital expenditures that 
would create long-term debt. By buying allowances or ERCs, affected 
EGUs with a limited remaining useful life contribute to achieving 
emission reductions from the source category during the years that they 
operate. During its lifetime, a facility with a short remaining useful 
life will need fewer total credits or allowances than an otherwise 
comparable facility with a long remaining useful life, but the 
annualized cost to the two facilities is the same.\857\
---------------------------------------------------------------------------

    \857\ Trading of course has other benefits beyond helping to 
address remaining useful life concerns. For example, trading can 
lower costs of achieving a given level of emission reduction and can 
provide economic incentives for innovation and development of 
cleaner technologies.
---------------------------------------------------------------------------

    In part to help states address remaining useful life 
considerations, the final guidelines facilitate state plans that employ 
trading in multiple ways:

     By allowing trading under emission standards plans and 
state measures plans, and under rate-based plans and mass-based 
plans;
     By defining national EGU performance rates that make it 
easier for states to set up rate-based trading regimes that allow 
for interstate trading of ERCs;
     By clearly defining the requirements for mass-based and 
rate-based trading systems to ensure their integrity; and
     By providing information on potential allocation 
approaches for mass-based trading.

    In addition, the EPA is separately proposing model trading rules 
for rate-based and mass-based trading to assist states with design of 
these programs in the section 111(d) context.
    d. Why remaining useful life and other facility-specific factors do 
not warrant adjustments in the guidelines' performance rates and state 
goals.
    Under the final guidelines, remaining useful life and other 
facility-specific considerations do not provide a basis for adjusting 
the CO2 emission performance rates, or the state's rate-
based or mass-based CO2 emission goals, nor do they affect 
the state's obligation to develop and submit an approvable CAA section 
111(d) plan that adopts the CO2 emission performance rates 
or achieves the goal by the applicable deadline. After considering 
public comments discussed below and in the response to comments 
document, the EPA has retained this aspect of the proposed rule for the 
reasons described below.
    As noted above, the final guidelines provide aggregate emission 
goals for affected EGUs in each state, in addition to the 
CO2 emission performance rates. The guidelines also reflect 
a number of changes from proposal to address concerns about 
achievability of proposed state goals that were raised in public 
comments, many of which were explicitly prompted by consideration of 
the remaining useful life issue. The result is to afford states with 
broad flexibility to design requirements for affected EGUs to achieve 
the CO2 emission performance rates or state CO2 
emission goals in ways that avoid requiring major capital expenditures, 
or imposing unreasonable costs, on those affected EGUs that have a 
limited remaining useful life. State plans may use any combination of 
the emissions reduction methods represented by the building blocks, and 
may also choose to employ emission reduction methods that were not 
assumed in calculating state goals.
    To be more specific, the EPA notes that a state is not required to 
achieve the same level of emission reductions with respect to any one 
building block as assumed in the EPA's BSER analysis. A state may use 
any combination of measures, including those not specifically factored 
into the BSER by the EPA. The EPA has estimated reasonable rather than 
maximum possible implementation levels for each building block in order 
to establish EGU emission rates and state goals that are achievable 
while allowing states to take advantage of the flexibility to pursue 
some building blocks more aggressively, and others less aggressively, 
than is reflected in the agency's computations, according to each 
state's needs and preferences. The guidelines provide further 
flexibility by allowing state plans to use emission reduction methods 
not reflected in the BSER. A description of multiple emission reduction 
methods is provided in sections VIII.I-K.
    e. Response to key comments on remaining useful life.
    In response to the proposed guidelines, some commenters said that 
the proposed state goals were

[[Page 64872]]

unachievable and therefore too stringent to provide states, as a 
practical matter, with the flexibility to consider remaining useful 
life for individual units. These commenters said the result would be 
premature retirements and stranded assets.
    In the final guidelines, the EPA has addressed the comments about 
lack of practical flexibility to consider remaining useful life by 
revising key elements of the guidelines in ways that will ensure that 
the CO2 emission performance rates and state CO2 
emission goals are achievable considering cost. At the same time, the 
final guidelines maintain the broad flexibility of each state to design 
its own compliance pathway, taking into account any facility-level 
concerns--including remaining useful life--in designing EGU 
requirements.
    The changes to the BSER and goal-setting methodologies include:

 Starting the interim goal period in 2022 rather than 2020, 
which allows more lead time for states and regulated entities and 
helps to ensure that the interim goal is achievable
 Revising the goal-setting formula and the state goals 
themselves
 Updating analyses of achievable levels of improvement 
through the building blocks that together represent the BSER, while 
keeping them at reasonable, rather than maximum, levels (thus 
creating headroom which can, and is intended to, help to accommodate 
the range of ages of different facilities)
 Providing an explicit phase-in schedule for meeting the 
revised interim goals, while also allowing a state the option of 
choosing its own emission reduction trajectory

    The final guidelines also contain changes to avoid certain 
inconsistencies between the goal-setting methodology and accounting of 
reductions under state plans that could have made state goals less 
achievable for some states.
    Together, the changes described above help to ensure that the 
CO2 emission performance rates and state CO2 
emission goals established in the final guidelines are achievable, and 
leave states with the practical ability to issue rules that take into 
account the remaining useful life of affected EGU.
    As explained in the Legal Memorandum accompanying this rule, the 
EPA believes that Congress intended the remaining useful life provision 
to provide a mechanism for states to avoid the imposition of 
unreasonable retrofit costs on existing sources with relatively short 
remaining useful lives, a scenario that could result in stranded 
assets. However, commenters on the proposed rule raised a different 
stranded assets concern not primarily related to retrofit costs--a 
concern that the proposed rule could cause changes in economic 
competitiveness of particular EGUs that would prompt their retirement 
before the end of their economically useful lives. These commenters 
said the proposed state goals were so stringent that states would have 
no choice but to adopt requirements that would result in retirements of 
coal-fired capacity that had been built relatively recently or had 
recently made pollution control investments. In response to these 
comments, the EPA has conducted a stranded assets analysis which 
demonstrates that the CO2 emission performance rates and 
state goals in the final guidelines provide sufficient flexibility to 
states to address stranded asset concerns. The EPA shares the goal of 
minimizing stranded assets. Although nothing in section 111(d) 
explicitly bars a guideline that results in some facilities becoming 
uneconomic before the end of their useful lives, the EPA nonetheless 
has striven to design the guidelines so as to give states flexibility 
to develop plans that include, for example, differential treatment of 
affected EGUs or opportunities to rely on emissions trading, to allow 
power companies to recover their investments in generation units.
    For purposes of the stranded assets analysis, the EPA considered a 
potential ``stranded asset'' to be an investment in a coal-fired EGU 
(or in a capital-intensive pollution control installed at such an EGU) 
that retires before it is fully depreciated. Book life is the period 
over which long-lived assets are depreciated for financial reporting 
purposes. The agency estimated typical book life by researching 
financial statements of utility and merchant generation companies in 
filings to the Securities and Exchange Commission. The agency estimated 
the book life of coal-fired EGUs to be 40 years, and assumed a 20-year 
book life for pollution control retrofits. The book life of coal-fired 
EGUs (coal steam and IGCC) is twice as long as the debt life and the 
depreciation schedule used for federal tax purposes. Although the book 
life for environmental retrofits is often 15 years, the agency 
conservatively assumed 20 years in this analysis.
    The analysis examined coal generation in the three large regional 
interconnections of the U.S. The analysis found that in both 2025 and 
2030, for each region, the amount of 2012 coal generation included in 
the final guidelines' emission performance rate calculation--
specifically, the generation remaining after the BSER calculation--is 
greater than the amount of 2012 generation from coal-fired EGUs that 
are not fully depreciated in those years under the book life 
assumptions described above. This shows that the final rule allows 
flexibility for states to preserve these units as part of their plans.
    To put this analysis in perspective: The EPA's role is to set 
emission guidelines that meet the statutory requirements, which 
includes consideration of cost in identifying the BSER, as the EPA has 
done in these guidelines. States have a broad degree of flexibility to 
design plans to achieve the rates in the emission guidelines in a 
manner that meets their policy priorities, including ensuring cost-
effective compliance. Although not a required component of the EPA's 
consideration of cost, this analysis shows that the CO2 
emission performance rates in the final guidelines can be met without 
the retirement of affected EGUs before the end of their book life, and 
without the retirement of affected EGUs before the end of the book life 
of capital-intensive pollution control retrofits installed on those 
EGUs. Thus, according to this analysis, the CO2 emission 
performance rates and state CO2 emission goals need not 
result in stranded assets. The EPA recognizes that power plant 
economics are determined by many aspects of markets that are outside of 
the EPA's control, such as wholesale power prices and capacity prices, 
and that the compliance path of least cost may involve retiring assets 
that have not fully depreciated. Nonetheless, this analysis further 
demonstrates the extent of flexibility available to states in designing 
their plans to best serve the policy priorities of the state. Details 
are available in a memorandum to the docket.\858\
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    \858\ Memorandum to Clean Power Plan Docket titled ``Stranded 
Assets Analysis'' dated July 2015.
---------------------------------------------------------------------------

    Several commenters said that the statute does not authorize the EPA 
to require other facilities to achieve greater reductions to compensate 
for a facility that warrants relief based on remaining useful life. One 
said that consideration of remaining useful life and other relevant 
factors is a one-way ratchet that provides relief to sources that 
cannot achieve the BSER, and that the EPA turns that approach on its 
head by prohibiting a state from providing such relief to a specific 
facility unless it can identify another facility to ``punish'' by 
requiring additional emissions reductions to offset that relief.
    The EPA disagrees with these comments, which proceed from an 
incorrect premise. The EPA is not determining a BSER-based emission 
level achievable by each individual facility without trading, and then

[[Page 64873]]

requiring better-than-BSER from some facilities to make up for worse-
than-BSER performance that a state authorizes for other facilities 
because of a short remaining useful life. Rather, as previously noted, 
the guidelines set CO2 emission performance rates and state 
CO2 emission goals that represent the average or aggregate 
emission level achievable by affected EGUs based on regional average 
estimates of the impact of applying the BSER to collective groupings of 
affected EGUs.\859\ In estimating the amount of improvement achievable 
through each building block (e.g., improvement in heat rate or amount 
of generation shift to lower-emitting EGUs), the EPA has estimated the 
average level achievable by EGUs in a region rather than attempting to 
estimate the level achievable by each and every affected EGU in the 
absence of trading. Thus, the fact that an individual facility may be 
unable, for example, to achieve the average level of heat rate 
improvement assumed in goal-setting is consistent with the EPA's 
analysis, and does not undermine the EPA's determination of 
CO2 emission performance rates and state CO2 
emission goals. The Legal Memorandum discusses additional reasons that 
the agency disagrees with comments that the guideline must permit 
adjustments in the guidelines' CO2 emission performance 
rates and state CO2 emission goals based on remaining useful 
life considerations.
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    \859\ The EPA expects that states that choose to adopt the 
national CO2 emission performance rates for all of their 
EGUs would permit ERC trading, rather than requiring each facility 
to meet the applicable rate without trading. In effect, the presence 
of trading means that the EGU performance rates can be achieved by 
each EGU involved in trading.
---------------------------------------------------------------------------

    An additional reason that the EPA believes that consideration of 
remaining useful life and other facility-specific factors does not 
warrant adjustments to state goals is that the design of the guidelines 
does not mandate that states impose requirements that would call for 
substantial capital investments at affected EGUs late in their useful 
life. Multiple methods are available for reducing emissions from 
affected EGUs that do not involve capital investments by the owner/
operator of an affected EGU. For example, generation shifts among 
affected EGUs, and addition of new RE generating capacity do not 
generally involve capital investments by the owner/operator at an 
affected EGU. Additional emission reduction methods available to states 
that do not entail significant capital costs at affected EGUs are 
discussed elsewhere in this preamble.
    Heat rate improvements at affected EGUs may require capital 
investments. However, states have flexibility to design their plan 
requirements; they are not required to mandate heat rate improvements 
at plants that have limited remaining useful life. In fact, a state can 
choose whether or not to require heat rate improvements at all. The 
agency also notes that capital expenditures for heat rate improvements 
would be much smaller than capital expenditures required for example, 
for purchase and installation of scrubbers to remove SO2; a 
fleet-wide average cost for heat rate improvements based primarily on 
best practices at coal-fired generating units would not likely exceed 
$100/kW, compared with a typical SO2 wet scrubber cost of 
$500/kW (costs vary with unit size).\860\ Even if a state did choose to 
adopt requirements for heat rate improvements, the proposed guidelines 
would allow states to regulate affected EGUs through flexible 
regulatory approaches that do not require affected EGUs to incur large 
capital costs (e.g., averaging and trading programs). Under the EPA's 
final approach--establishing state goals and providing states with 
flexibility in plan design--states have flexibility to make exactly the 
kind of judgments necessary to avoid requiring capital investments that 
would result in stranded assets.
---------------------------------------------------------------------------

    \860\ Heat rate improvement methods and related capital costs 
are discussed in the GHG Mitigation Measures TSD; SO2 
scrubber capital costs are from the documentation for the EPA's IPM 
Base Case v5.13, Chapter 5, Table 5-3, available at http://www.epa.gov/airmarkets/documents/ipm/Chapter_5.pdf.
---------------------------------------------------------------------------

    Remaining useful life and other factors, because of their facility-
specific nature, are potentially relevant as states determine 
requirements that are directly applicable to affected EGUs. If relief 
is due a particular facility, the state has an available toolbox of 
emission reduction methods that it can use to develop a section 111(d) 
plan that will achieve the CO2 emission performance rates or 
state CO2 emission goals on time. The EPA therefore 
concludes that the remaining useful life of affected EGUs, and the 
other facility-specific factors identified in the existing implementing 
regulations, should not be regarded as a basis for adjusting the 
CO2 emission performance rates or a state CO2 
emission goal, and should not relieve a state of its obligation to 
develop and submit an approvable plan that achieves that goal on time.
    f. Legal considerations regarding remaining useful life. Section 
111(d)(1) requires the EPA in promulgating section 111(d) regulations 
to ``permit the State in applying a standard of performance to any 
particular source under a plan submitted under this paragraph to take 
into consideration, among other factors, the remaining useful life of 
the existing source to which such standard applies.'' Here, we discuss 
the legal basis for determining that the emission guidelines are 
consistent with this statutory requirement. For details, please see the 
Legal Memorandum.
    Section 111(d)(1) only requires that EPA emission guidelines permit 
states to take into account remaining useful life (among other 
factors), but section 111(d)(1) does not specify how the EPA must 
permit that. In other words, the meaning of the provision and the way 
that the EPA is to implement it in promulgating guidelines are not 
specified further in the provision. The provision is ambiguous and 
capable of implementation in several ways, and therefore the EPA has 
discretion to interpret and apply it. Furthermore, section 111(d)(1) 
does not suggest that states must be given carte blanche to consider 
remaining useful life in any way that can be imagined. As detailed 
above in sections VIII.G.1.c-e, these guidelines permit states to take 
into account remaining useful life in a number of reasonable ways and 
thus the guidelines satisfy the statutory obligation.
    The phrase ``remaining useful life'' also appears in the visibility 
provisions of section 169A. There, in determining best available 
retrofit technology (BART), the state (or the EPA) must take into 
consideration (among other factors) ``the remaining useful life of the 
source.'' 42 U.S.C. 7491(g)(2); see also id. (g)(1) (reasonable 
progress). In the context of the visibility program, we have 
interpreted this provision to mean that the remaining useful life 
should be considered when calculating the annualized costs of retrofit 
controls. See 40 CFR Pt. 51, App. Y, IV.D.4.k.1. This annualized cost 
is then used to determine a cost effectiveness, in dollars per ton of 
pollutant removed on an annual basis. As a result, a technology with a 
large initial capital cost that might have a reasonable cost-
effectiveness for a facility with a long remaining useful life would 
have a much higher and possibly unreasonable cost-effectiveness for a 
facility with a short remaining useful life.
    Although section 111(d)(1) is different than section 169A(g)(2) and 
need not be interpreted in the same way, we would note (as discussed in 
detail in sections VIII.G.1.c-e, section 5.11 of the Response to 
Comments document, and the Legal Memorandum) that (for

[[Page 64874]]

example) a trading program under these section 111(d) guidelines only 
requires compliance on a periodic basis and does not require any 
initial capital expenditures. Thus, over the life of the facility, a 
facility with a short remaining useful life will need fewer total 
credits or allowances than an otherwise comparable facility with a long 
remaining useful life, but the annualized cost to the two facilities is 
the same. In other words, under a trading program remaining useful life 
of a source is automatically accounted for in the way it is accounted 
for under the visibility program.
    Some commenters stated that the EPA's interpretation of remaining 
useful life is impermissible. These commenters claimed that states, if 
they wish to take into account remaining useful life at one affected 
EGU, must relax the stringency of the emission standard for that EGU. 
Then, the state would be compelled to increase the stringency of 
emission standards at other affected EGUs in order to achieve the state 
performance goal. According to these commenters, section 111(d) does 
not allow this outcome.
    First, the commenters are mistaken in their premise. As discussed 
in section VIII.G.1, section 5.11 of the Response to Comments document, 
the Legal Memorandum, and in the example immediately above, states can 
impose the exact same emission standards on two affected EGUs and still 
take into account remaining useful life through the availability of 
trading. In other words, states need not relax an emission standard 
here and strengthen an emission standard there in order to take into 
account remaining useful life. Thus, these guidelines permit states to 
take into account remaining useful life without any of the effects 
commenters are concerned about.
    Second, even if states decide to relax emission standards at one 
EGU, on the basis of remaining useful life or any other factor, nothing 
in the last sentence of section 111(d)(1) prohibits these guidelines 
from requiring the state plan to still meet the CO2 emission 
performance rates or state CO2 emission goal. In fact, that 
sentence is completely silent on the issue. Thus, the EPA has the 
discretion to determine what should be the concomitant effects if a 
state chooses to consider remaining useful life in a particular way. In 
this case the concomitant effect of a state relaxing one emission 
standard may be that the state must make up for it elsewhere in order 
to meet the goal, but nothing in section 111(d)(1), including the 
statutory requirement to permit consideration of remaining useful life, 
prohibits that outcome.
2. Electric Reliability
    The final rule features overall flexibility, a long planning and 
implementation horizon, and a wide range of options for states and 
affected EGUs to achieve the CO2 emission performance rates 
or state CO2 emission goal. This design reflects, among 
other things, the EPA's commitment to ensuring that compliance with the 
final rule does not interfere with the industry's ability to maintain 
the reliability of the nation's electricity supply. Comments from 
state, regional and federal reliability entities, power companies and 
others, as well as consultation with the Department of Energy (DOE) and 
Federal Energy Regulatory Commission (FERC), helped inform a number of 
changes made in this final rule to address reliability. In addition, 
FERC conducted one national and three regional technical conferences on 
the proposed rule in which the EPA participated and at which the issue 
of reliability was raised by numerous participants.
    As discussed throughout the preamble and TSDs, the electricity 
sector is undergoing a period of intense change. While the change in 
the resource mix has accelerated in recent years, wind, solar, other 
RE, and EE resources have been reliably participating in the electric 
sector for a number of years. Many of the potential changes to the 
electric system that the final rule may encourage, such as shifts to 
cleaner sources of power and efforts to reduce electricity demand, are 
already well underway in the electric industry. To the extent that the 
final rule accelerates these changes, there are multiple features well 
embedded in the electricity system that ensure that electric system 
reliability will be maintained. Electric system reliability is 
continually being considered and planned for. For example, in the 
Energy Policy Act of 2005, Congress added a section to the Federal 
Power Act to make reliability standards mandatory and enforceable by 
FERC and the North American Electric Reliability Corporation (NERC), 
the Electric Reliability Organization which FERC designated and 
oversees. Along with its standards development work, NERC conducts 
annual reliability assessments via a 10-year forecast and winter and 
summer forecasts; audits owners, operators, and users for preparedness; 
and educates and trains industry personnel. Numerous other entities 
such as FERC, DOE, state PUCs, ISOs/RTOs, and other planning 
authorities also consider the reliability of the electric system. There 
are also numerous remedies that are routinely employed when there is a 
specific local or regional reliability issue. These include 
transmission system upgrades, installation of new generating capacity, 
calling on demand response, and other demand-side actions.
    Additionally, planning authorities and system operators constantly 
consider, plan for, and monitor the reliability of the electricity 
system with both a long-term and short-term perspective. Over the last 
century, the electric industry's efforts regarding electric system 
reliability have become multidimensional, comprehensive, and 
sophisticated. Under this approach, planning authorities plan the 
system to assure the availability of sufficient generation, 
transmission, and distribution capacity to meet system needs in a way 
that minimizes the likelihood of equipment failure.\861\ Long-term 
system planning happens at both the local and regional levels with all 
segments of the electric system needing to operate together in an 
efficient and reliable manner. In the short-term, electric system 
operators operate the system within safe operating margins and work to 
restore the system quickly if a disruption occurs.\862\ Mandatory 
reliability standards apply to how the bulk electric system is planned 
and operated. For example, transmission operators and balancing 
authorities have to develop, maintain, and implement a set of plans to 
mitigate operating emergencies.\863\
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    \861\ Casazza, J. and Delea, F., Understanding Electric Power 
Systems: An Overview of the Technology, the Marketplace, and 
Government Regulations, IEEE Press, at 160 (2010).
    \862\ Id.
    \863\ NERC Reliability Standard EOP-001-2.1b--Emergency 
Operations Planning, available at http://www.nerc.net/standardsreports/standardssummary.aspx.
---------------------------------------------------------------------------

    As the electricity market changes and new challenges emerge, 
electric system regulators and industry participants make changes to 
how the electric system is designed and operated to respond to these 
challenges. For example, expressing reliability and rate concerns about 
fuel assurance issues, FERC recently issued an order requiring ISOs/
RTOs to report on the status of their efforts to address market and 
system performance associated with fuel assurance.\864\ In February of 
2015, Midcontinent Independent System

[[Page 64875]]

Operator (MISO), California Independent System Operator Corporation 
(CAISO), New York Independent System Operator (NYISO), Southwest Power 
Pool (SPP), ISO New England (ISO-NE), and PJM Interconnection (PJM) 
each filed a report with FERC highlighting their efforts to respond to 
fuel assurance concerns.\865\ This is just one of many examples where 
electric system regulators and industry participants recognize a 
potential reliability issue and are proactively searching for 
solutions.
---------------------------------------------------------------------------

    \864\ Centralized Capacity Markets in Regional Transmission 
Organizations and Independent System Operators, 149 FERC ] 61,145 
(2014). FERC generally defines fuel assurance as ``generator access 
to sufficient fuel supplies and the firmness of generator fuel 
arrangements''. Id. P 5.
    \865\ For example, ISO-NE and PJM each filed ``pay-for-
performance'' proposals to address fuel assurance in their regions. 
FERC recently acted on ISO-NE market rule changes providing 
increased market incentives in capacity, energy, and ancillary 
services markets for generators to be available to meet their 
obligations during reserve shortages. ISO New England Inc., 147 FERC 
] 61,172 (2014). Additionally, FERC conditionally approved a PJM 
``pay-for-performance'' proposal that creates a new capacity product 
to provide greater assurance of delivery of energy and reserves 
during emergency conditions, establishing credits for superior 
performance and charges for poor performance. PJM Interconnection, 
L.L.C., 151 FERC ] 61,208 (2015).
---------------------------------------------------------------------------

    The EPA's approach in this final rule is consistent with our 
commitment to ensuring that compliance with the final rule does not 
interfere with the industry's ability to maintain the reliability of 
the nation's electricity supply. Many aspects of the final rule's 
design are intended to support system reliability, especially the long 
compliance period and the basic design that allows states and affected 
EGUs flexibility to include a large variety of approaches and measures 
to achieve the environmental goals in a way that is tailored to each 
state's and utility's energy resources and policies. Despite the 
flexibility built into the design of the proposal, and the long 
emission reduction trajectory, many commenters expressed concerns that 
the proposed rule could jeopardize electric system reliability. We note 
that the EPA has received similar comments in EPA rulemakings dating as 
far back as the 1970s. The EPA has always taken and continues to take 
electric system reliability comments very seriously. These reoccurring 
comments with regard to reliability notwithstanding, the electric 
industry has done an excellent job of maintaining reliability, 
including when it has had to comply with environmental rules with much 
shorter compliance periods and much less flexibility than this final 
rule provides. Now, more than ever, the electric industry has tools 
available to maintain reliability, including mandatory and enforceable 
reliability standards.\866\
---------------------------------------------------------------------------

    \866\ For example, Andrew Ott, then Executive Vice President-
Markets and current President of PJM, an RTO with a substantial 
amount of coal-fired capacity and generation, discussed the success 
of PJM's market design in assuring that PJM met and exceeded target 
reserve margins while MATS was being implemented. See Statement of 
Andrew Ott, PJM Executive Vice President-Markets, FERC Technical 
Conference on Centralized Capacity Markets in Regional Transmission 
Organizations and Independent System Operators, AD13-7-000, at 3, 7 
(Sept. 25, 2013), available at http://www.ferc.gov/EventCalendar/EventDetails.aspx?ID=6944&CalType=&CalendarID=116&Date=09/25/2013&View=Listview. At the FERC national Clean Power Plan Technical 
Conference, Michael J. Kormos, PJM Executive Vice President-
Operations, said that PJM's markets have proven, ``resilient enough 
to respond to different policy initiatives . . . Whether it is the 
Sulfur Dioxide Trading Program of the 1990s, the MATS rule or 
individual state RPS initiatives, the markets have been able to send 
the appropriate price signals that produce competitive outcomes.'' 
See Michael J. Kormos, PJM Executive Vice President, Statement at 
FERC Technical Conference on EPA's Clean Power Plan, AD15-4-000, at 
3 (Feb. 19, 2015), available at http://www.ferc.gov/CalendarFiles/20150213081650-Kormos,%20PJM.pdf.
---------------------------------------------------------------------------

    As with numerous prior CAA regulations affecting the electric power 
sector, environmental requirements for this industry are accommodated 
within the existing extensive framework established by federal and 
state law to ensure that electricity production and delivery are 
balanced on an ongoing basis and planned sufficiently to ensure 
reliability and affordability into the future. In addition, changes 
that the EPA is making in this final rule respond directly to the 
comments and the suggestions that we received on reliability and 
provide further assurance that implementation of the final rule will 
not create reliability concerns.
    First, the final rule allows significant flexibility in how the 
applicable CO2 emission performance rates or the statewide 
CO2 goals are met. Given the differing characteristics of 
the electric grid within each state and region, there are many paths to 
meeting the final rule's requirements that can be taken while 
continuing to maintain a reliable electricity supply. As further 
described elsewhere in section VIII, states can develop plans to meet 
the CO2 emission performance rates or state CO2 
emission goals by choosing from a variety of state plan types and 
approaches that afford states and affected EGUs appropriate 
flexibility. EE and other measures that were not included in the 
determination of the BSER can strengthen a state's ability to establish 
a plan to meet the CO2 emission performance rates or state 
CO2 emission goals by providing a considerable amount of 
headroom above the levels of the rates and goals. EE especially, 
because it reduces load, can provide assurance that reliability can and 
will be maintained. Additionally, the final rule offers opportunities 
for trading among affected EGUs within and between states, and other 
multi-state approaches that will further support electric system 
reliability.
    Second, the final rule provides sufficient time to ensure system 
reliability. The final rule retains the 2030 date for the final period, 
which commenters largely supported as reasonable and not a concern for 
reliability, and addresses one of the key issues that commenters 
pointed to as a reliability-related concern by both moving the start of 
the interim period from 2020 to 2022 and adjusting the interim goals to 
provide a more gradual phasing-in of the initial reduction requirement 
and thus a more gradual emissions reduction trajectory or glide path to 
the final 2030 goals. These changes deliver on the intent of the 
proposal to afford states and affected EGUs the latitude to determine 
their own emissions reduction schedules over the interim period. Both 
FERC's May 15, 2015 letter \867\ and the comment record made it clear 
that providing sufficient time for planning and implementation is 
essential to ensuring electric system reliability. The EPA has 
responded by providing additional time to allow for planning and 
implementation of the final rule requirements, while at the same time 
allowing enough time between the beginning of the interim period and 
2030 to achieve state goals or emission performance rates. We note that 
the final rule does not require that all states have met their interim 
goal or performance rate by 2022 but rather that they meet it on 
average or cumulatively, as appropriate, during the 2022 to 2029 
period.
---------------------------------------------------------------------------

    \867\ On May 15, 2015, the five FERC Commissioners sent a letter 
to Acting Assistant Administrator Janet McCabe regarding the EPA's 
Clean Power Plan proposal. See FERC letter, available at http://ferc.gov/media/headlines/2015/ferc-letter-epa.pdf.
---------------------------------------------------------------------------

    As a result of these changes, the states themselves will have a 
meaningful opportunity--which, again, many commenters suggested the 
timing and stringency of the proposal failed to create despite our 
intent to do so--to determine the timing, cadence and sequence of 
actions needed for states and sources to meet final rule requirements 
while accommodating the ongoing activity needed to ensure system 
reliability. The final rule provides more than 6 years before 
reductions are required and an 8-year period from 2022 to 2029 to meet 
interim goals. Moreover, while the final rule requires each state to 
submit a plan by September 6, 2016, we recognize that some states may 
need more than 1 year to complete all of the actions needed for their 
final state plans, including

[[Page 64876]]

consideration of reliability. Therefore, states have the opportunity to 
receive an extension for submitting a final plan. If the state needs 
additional time to submit a final plan, then the state may submit an 
initial submittal by September 6, 2016, that must address three 
required components sufficiently to demonstrate that a state is able to 
undertake steps and processes necessary to timely submit a final plan 
by the extended date of September 6, 2018.
    Third, we are including in the final rule a requirement that each 
state demonstrate in its final state plan submittal that it has 
considered reliability issues in developing its plan. This was 
suggested by a number of commenters, and we agree that it is a useful 
element to state plan development.
    Fourth, the final rule provides a mechanism for a state to seek a 
revision to its plan in order to address changes in circumstances that 
could have reliability impacts if not accommodated in the plan. The 
long compliance timeframe, with several interim steps, naturally 
provides opportunities for states, working with their utilities and 
reliability entities, to assess how implementation is proceeding, 
identify unforeseen changes that may warrant plan revisions, and work 
with the EPA to make necessary revisions. Similarly, the ready 
availability of emissions trading as a compliance tool affords EGUs 
ample flexibility to integrate compliance with both routine and 
critical reliability needs.
    Fifth, in response to a variety of comments, we are providing a 
reliability safety mechanism that provides a path for a state to come 
to the EPA during an immediate, unforeseen, emergency situation that 
threatens reliability to notify the EPA that an affected EGU or EGUs 
may need to temporarily comply with modified emission standards to 
respond to this kind of reliability concern.
    Sixth and finally, we are committed to maintaining an ongoing 
relationship with FERC and DOE as this final rule is implemented to 
help ensure continued reliable electric generation and transmission.
    We provide more details about these various elements of the final 
rule, as well as other features of the rule that support system 
reliability, below.

    a. Summary of key comments.

    The EPA received a number of comments regarding the proposed rule 
and electric reliability. Many commenters provided specific, useful 
ideas regarding changes that could be made to the proposal to 
specifically address their reliability concerns. For example, many 
commenters state that allowing additional time to comply could help in 
meeting the final rule requirements while addressing their reliability 
concerns. Some commenters suggest that additional time would allow them 
to evaluate potential reliability impacts and system changes that need 
to be made to comply with final rule requirements while allowing 
affected EGUs time to meet interim CO2 emissions goals. The 
EPA also received comment that market-based approaches have features 
that could help support reliability, and therefore we should encourage 
states to join or form regional market-based programs. Commenters also 
stated that the EPA should require states to consult with grid 
operators who would analyze the impact of state plans on reliability. A 
number of commenters also suggested that the EPA should include some 
sort of reliability safety valve in the final rule. We note that many 
participants at the FERC technical conferences on the proposed rule 
also discussed a reliability safety valve in great detail with many 
suggestions for how such a reliability mechanism could be designed. The 
EPA appreciates these and all the comments we received regarding the 
interaction of the proposal and electric reliability. We have carefully 
considered all comments, consulted further with FERC and incorporated 
many of the suggested changes in this final rule.

    b. Final rule flexibility.

    In issuing this final rule, the EPA considered public comments on 
the potential interaction between the proposal and electric 
reliability. While we have made every effort to develop guidelines that 
would allow states and utilities to steer clear of potential 
reliability disruptions, a number of commenters argued that the 
possibility of an unanticipated reliability event cannot be entirely 
eliminated. It is important to note that there are many factors that 
influence system reliability and, given the complexity of the electric 
grid, electric system planners and operators likely will not completely 
avoid reliability issues, even in the absence of these guidelines. The 
EPA designed the final rule to ensure to the greatest extent possible 
that actions taken by states and affected EGUs to comply with the final 
rule do not increase potential reliability issues or complicate their 
resolution. In fact, to the extent that meeting final rule requirements 
results in the reduction of demand, upgrades in transmission efficiency 
and infrastructure, and investment in new, more efficient technologies, 
the outcome could be that the system is more robust and faces fewer 
risks to electric reliability.
    One specific concern raised by many commenters is that the proposed 
plan development schedule may not leave sufficient time to conduct 
reliability planning between the development of state plans and the 
proposed start of the interim period in 2020. To address these concerns 
and to support a more effective reliability planning process, the EPA 
is moving the start of the interim period from 2020 to 2022 and 
adjusting the interim goals to provide a gradually phased-in initial 
reduction requirement and a more gradual glide path to the final 2030 
goals. This more gradual application of the BSER over the 2022-2029 
interim period provides the state with substantial latitude in 
selecting the emission reduction glide path for affected EGUs over that 
period. As noted above, the final rule also provides states with up to 
3 years to adopt and submit their final state plans, and afterwards 
states can, if necessary, revise their plans, as discussed in section 
VIII.E.7. This timing gives system planners and operators the 
opportunity to do what they have already been doing; looking ahead to 
forecast potential contingencies that pose reliability risks and 
identifying those actions needed to mitigate those risks. The final 
rule allows states to develop a pathway over the interim period that 
reflects their own circumstances, such as reflecting planned additions 
and changes in generation mix and potentially taking advantage of 
opportunities for trading of credits or allowances by affected EGUs 
within and between states. Because achievement of the emission rates or 
goals can be demonstrated over several years, state plans can 
accommodate situations where, for example, it may take time to develop 
new generation, pipelines, or transmission while still providing many 
options for meeting the final rule requirements and planning for the 
reliability of the system.

    c. Considering reliability during state plan development process.

    Under CAA section 111(d)(1)(B), state plans must provide for the 
implementation and enforcement of standards of performance for affected 
EGUs. The EPA does not believe a state that establishes standards of 
performance for affected EGUs without taking reliability concerns into 
consideration satisfactorily provides for the implementation of such 
standards of performance as required by CAA section 111(d)(1)(B), as a 
serious reliability issue would disrupt the state's provision

[[Page 64877]]

of implementation of the state plan. Therefore, the EPA is requiring 
that each state demonstrate as part of its final state plan submission 
that it has considered reliability issues while developing its plan in 
order to ensure that standards of performance can be implemented and 
enforced as required by the CAA. If system reliability is threatened, 
the ability of affected EGUs to meet the requirements of this final 
rule could be compromised if they are required to operate beyond the 
emission standards established in state plans in order to maintain the 
reliability of the electric grid. The requirement that states consider 
reliability as part of the development of state plans is therefore 
designed to ensure that state plans are flexible enough to avoid this 
kind of potential conflict between maintaining reliability and 
providing for the implementation of emission standards for affected 
EGUs as required by the CAA.
    A number of commenters, notably ISOs and RTOs, also discussed 
reliability concerns in the context of state plans and pointed out that 
planning and anticipation of change are among the essential ingredients 
of ensuring the ongoing reliability of the electricity system. To that 
end, they recommended that as states are developing state plans, their 
activity include the consideration of the reliability needs of the 
region in which affected EGUs operate and of the potential impact of 
actions to be taken in compliance with state plans. Therefore, we are 
requiring that each state demonstrate in its final state plan submittal 
that it has considered reliability issues in developing its plan. One 
particularly effective way in which states can make this demonstration 
is by consulting with the relevant ISOs/RTOs or other planning 
authorities as they develop their plans and documenting this 
consultation process in their state plan submissions. If a state 
chooses to consider reliability through consultation with the ISO/RTO 
or other planning authority, the EPA recommends that the state request 
that the planning authority review the state plan at least once during 
the plan development stage and provide its assessment of any 
reliability implications of the plan. Additionally, we encourage states 
that are considering reliability through an ISO/RTO or other planning 
authority consultation process to have a continuing dialogue with those 
entities during development of their final state plan. While following 
the recommendations of the planning authority would not be mandatory, 
the state should document its consultation process, any response and 
recommendations from the planning authority, and the state's response 
to those recommendations in its final state plan submittal to the EPA. 
This consultation is designed to inform how the state might adjust its 
plan for meeting the CO2 reduction requirements under this 
guideline; the consultation is not a basis for relaxing that 
requirement. While we consider this process to be an effective way for 
a state to demonstrate that it considered reliability in developing its 
final state plan, a state may provide other comparable support for a 
demonstration that it has considered reliability during the state plan 
development process.\868\ Also as discussed elsewhere in this preamble, 
the EPA encourages states to include state utility regulators and the 
state energy offices in the development of the state plan. These 
agencies have expertise that can help to assure that state plans 
complement the state's power sector. The EPA believes that this 
requirement to demonstrate consideration of reliability will provide an 
effective reliability evaluation in the state plan development process. 
It should further help states avoid any conflicts between state plans 
and the maintenance of reliability during implementation of the state 
plan and associated emission standards. Finally, we also encourage 
states as they develop their plans to consider, to the extent possible, 
other potential issues that may impact affected EGUs. For example, an 
affected EGU may be in an ISO/RTO that puts certain deadlines on 
generators that may not line up perfectly with state plan deadlines.
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    \868\ While the EPA is requiring that the states demonstrate 
that they have considered reliability in developing their plans, 
state plan submissions will not be evaluated substantively regarding 
reliability impacts.
---------------------------------------------------------------------------

    d. State plan modifications.
    If, during the implementation of a state plan, a reliability issue 
cannot be addressed within the range of actions or mechanisms 
encompassed in an approved state plan, the state can submit a plan 
revision to the EPA to amend its plan. In such a circumstance, the 
state plan may need to be adjusted to enable affected EGUs to continue 
to meet final rule requirements without causing an otherwise 
unmanageable reliability threat. In all cases the plan revision must 
still ensure the affected EGUs meet the emission performance level set 
out in the 111(d) final rule. Whether or not these circumstances occur 
will depend in part upon how each state designs its state plan. States 
that design plans with a high level of flexibility, such as market-
based plans or multi-state plans, are less likely to face a potential 
conflict between state plan requirements and the maintenance of 
reliability. States that participate in multi-state programs will be 
better able to weather unexpected reliability risks.
    Events not anticipated at the time of the final plan submittal--
such as the retirement of a large low- or zero-emitting unit--may 
trigger the request for state plan revisions. It may also be the case 
that affected EGU-specific emission standards in a state plan are 
proving to be too inflexible to allow the plan to accommodate market or 
other changes in the power sector. In such instances, there should be a 
lead time between the announced retirement of the unit and the need to 
amend the state plan. Therefore, the state should be able to utilize 
the revisions process that the EPA provides.
    The EPA will review a plan revision per the implementing regulation 
requirements of 40 CFR part 60.28. If the state's request for a state 
plan revision must be addressed in an expedited manner to assure a 
reliable supply of electricity, the state must document the risks to 
reliability that would be addressed by the plan revision by providing 
the EPA with a separate analysis of the reliability risk from the ISO/
RTO or other planning authority. This analysis should be accompanied by 
a statement from the ISO/RTO or other planning/reliability authority 
that there are no practicable alternative resolutions to the 
reliability risk. In this case, the EPA will conduct an expedited 
review of the state plan revision.\869\
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    \869\ The EPA will still undertake notice and comment rulemaking 
per the requirements of the Administrative Procedures Act when 
acting on such state plan revision, but intends to prioritize review 
of plan revisions needed to address reliability concerns.
---------------------------------------------------------------------------

    e. Reliability safety valve.
    In this section we describe a reliability safety valve, available 
to states with affected EGUs providing reliability-critical generation 
in emergency circumstances. Specifically and as discussed below the 
reliability safety valve provides i) a 90-day period during which the 
affected EGU will not be required to meet the emission standard 
established for it under the state plan but rather will meet an 
alternative standard, and ii) a period beginning after the initial 90 
days during which the reliability-critical affected EGU may be required 
to continue to operate under an alternative standard rather than under 
the original state plan emission standard, as needed in light of the 
emergency circumstances, and the state must during this period revise 
its plan to accommodate changes

[[Page 64878]]

needed to respond to ongoing reliability requirements. Any emissions in 
excess of the applicable state goals or performance rates occurring 
after the initial 90-day period must be accounted for and offset.
    Many commenters expressed concerns that a serious, unforeseen event 
could occur during the final rule implementation period that would 
require immediate reliability-critical responses by system operators 
and affected EGUs that would result in unplanned or unauthorized 
emissions increases. After reviewing the comments, we believe that it 
is highly unlikely that there would be a conflict between activities 
undertaken under an approved state plan and the maintenance of electric 
reliability, except in the case of a state plan that puts relatively 
inflexible requirements on specific EGUs. While some have pointed out 
that severe weather or other short-term events could potentially 
conflict with state plans, we note that most of those events are of 
short duration and would not require major--if any--adjustments to 
emission standards for affected EGUs or to state plans. For example, 
during an event like the extreme cold experienced in periods of the 
winter of 2013-2014, affected EGUs may need to run at a higher level 
for a short period of time to accommodate increased demand and/or 
short-term unavailability of other generators. However, because 
compliance by affected EGUs will be demonstrated over 2-3 years, such a 
short-term event would not cause affected EGUs to be out of compliance 
with their applicable emission standards. States can also ensure that 
this is true by developing plans that allow adequate compliance 
flexibility to accommodate such short-term events. We note that we have 
included in this final rule a number of different features designed to 
facilitate emissions trading between and among EGUs on an interstate 
basis--and have done so, in no small part, in response to comments from 
states and stakeholders seeking to put in place or operate under state-
level and interstate emissions trading regimes. Affected EGUs operating 
in those circumstances and operating, in addition, subject to state 
plans that incorporate flexible glide paths and trading would be able 
to accommodate an unanticipated reliability event.
    We recognize, however, that affected EGUs operating in a state with 
a relatively inflexible state plan could face unanticipated system 
emergencies that could cause a severe stress on the electricity system 
for a length of time such that the requirements in that state's plan 
may not be achievable by certain affected EGUs without posing an 
otherwise unmanageable risk to reliability. In particular, there could 
be extremely serious events, outside the control of affected EGUs, that 
would require an affected EGU or EGUs operating under an inflexible 
state plan to temporarily operate under modified emission standards to 
respond to this kind of reliability concern. Examples of such an event 
could include, a catastrophic event that damages critical or vulnerable 
equipment necessary for reliable grid operation; a major storm that 
floods and causes severe damage to a large NGCC plant so that it must 
shut down; or a nuclear unit that must cease generating unexpectedly 
and therefore other affected EGUs need to run so as to exceed their 
requirements under the approved state plan. This is not an all-
inclusive list, but the examples illustrate several key attributes of 
the kinds of circumstances in which the reliability safety valve would 
apply. First, the event creating the reliability emergency would be 
unforeseeable, brought about by an extraordinary, unanticipated, 
potentially catastrophic event. Second, the relief provided would be 
for EGUs compelled to operate for purposes of providing generation 
without which the affected electricity grid would face some form of 
failure. Third, the EGU or EGUs in question would be subject to the 
requirements of a state plan that imposes emissions constraints such 
that the EGU or EGUs' operation in response to the reliability 
emergency resulted in levels of emissions that violated those 
constraints. We do not anticipate that EGUs operating under a plan that 
permitted emissions trading would meet these criteria.
    The final guidelines provide a reliability safety valve for these 
types of situations. If an emergency situation arises, the state must 
submit an initial notification to the appropriate EPA regional office 
within 48 hours that it is necessary to modify the emission standards 
for a reliability-critical affected EGU or EGUs for up to an initial 90 
days. The notification must include a full description, to the extent 
it is known at the time, of the emergency situation that is being 
addressed. It must also identify with particularity the affected EGU or 
EGUs that are required to run to assure reliability. It must also 
specify the modified emission standards at which the affected EGU or 
EGUs will operate. The EPA will consider this notification to be an 
approved short-term modification to the state plan, allowing the EGU to 
operate at an emission standard that is an alternative to the emission 
standard originally specified in the relevant state plan, subject to 
confirmation by the further documentation described below.\870\
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    \870\ The EPA reserves the right to review such notification, 
and in the event that the EPA finds such notification is improper, 
the EPA may disallow the short-term modification and affected EGUs 
must continue to operate under the original approved state plan 
emission standards.
---------------------------------------------------------------------------

    Within 7 days of submitting the initial notification, the state 
must submit a second notification providing documentation to the 
appropriate EPA regional office that includes a full description of the 
reliability concern and why an unforeseen, emergency situation that 
threatens reliability requires the affected EGU or EGUs to operate 
under modified emission standards (including discussion of why the 
flexibilities provided under the state's plan are insufficient to 
address the concern). The state must also describe in its documentation 
how it is coordinating or will coordinate with relevant reliability 
coordinators and planning authorities to alleviate the problem in an 
expedited manner, and indicate the maximum time that the state 
anticipates the affected EGU or EGUs will need to operate in a manner 
inconsistent with its or their obligations under the state's approved 
plan, and the modified emission standards or levels at which the 
affected EGU or EGUs will be operating at during this period if it has 
changed from the initial notification. The documentation must also 
include a written concurrence from the relevant reliability coordinator 
and/or planning authority confirming the existence of the imminent 
reliability threat and supporting the temporary modification request or 
an explanation of why this kind of concurrence cannot be provided. 
Additionally, if the relevant planning authority has conducted a 
system-wide or other analysis of the reliability concern, the state 
must include that information in its request. If the state fails to 
submit this documentation on a timely basis, the EPA will notify the 
state, which must then notify the affected EGU(s) that they must 
operate or resume operations under the original approved state plan 
emission standards.
    It is important to note that the affected EGUs must continue to 
monitor and report their emissions and generation pursuant to 
requirements in this final rule and under the state plan during any 
short-term modification. For the duration of the up to 90-day short-
term modification, the emissions of the affected EGU or EGUs that 
exceed their obligations under the approved state

[[Page 64879]]

plan will not be counted against the state's overall goal or emission 
performance rate for affected EGUs. Such a modification will not alter 
or abrogate any other obligations under the approved state plan.
    During this short-term modification period, the EPA expects that 
the source, the state and the relevant reliability coordinator and/or 
planning authority will assess whether the reliability issue can be 
addressed in a way that would allow the EGU or EGUs to resume operating 
under the original approved state plan within the 90-day period or 
whether revisions to the state plan need to be made to address the 
unexpected circumstances for the longer term (the unexpected 
unavailability of a nuclear unit, for example).
    The EPA recognizes that an emergency may persist past 90 days. At 
least 7 days before the end of the initial 90-day reliability safety 
valve period, the state must notify the appropriate EPA regional office 
whether the reliability concern has been addressed and that the EGU or 
EGUs can resume meeting the original emission standards established in 
the state plan prior to the short-term modification.
    If there still is a serious, ongoing reliability issue at the end 
of the short-term modification period that necessitates the EGU or EGUs 
to emit beyond the amount allowed under the state plan, the state must 
provide to the EPA a notification that it will be submitting a state 
plan revision and submit the plan revision as expeditiously as 
possible, specifying in the notice the date by which the revision will 
be submitted. The state must document the ongoing emergency with a 
second written concurrence from the relevant reliability coordinator 
and/or planning authority confirming the continuing urgent need for the 
EGU or EGUs to operate beyond the requirements of the state plan and 
that there is no other reasonable way of addressing the ongoing 
reliability emergency but for the EGU or EGUs to operate under an 
alternative emission standard than originally approved under the state 
plan. In this event, the EPA will work with the state on a case-by-case 
basis to identify an emission standard for the affected EGU or EGUs for 
the period before a new state plan revision is approved. After the 
initial 90-day period, any excess emissions beyond what is authorized 
in the original approved state plan will count against the state's 
overall goal or emission performance rate for affected EGUs.
    The EPA intends for this reliability safety valve to be used only 
in exceptional situations. In addition, this reliability safety valve 
applies only to this final rule and has no effect on CAA requirements 
to which the state or the affected EGUs are otherwise subject. As 
discussed earlier, we are providing states with the flexibility to 
design programs that allow affected EGUs to meet compliance obligations 
while responding to reliability needs, even in emergency situations. 
This flexibility means that a conflict between the requirements of the 
state plan and maintenance of reliability should be extremely rare. We 
recognize, however, that a state with an inflexible plan could be faced 
with more than one emergency and in this case the reliability safety 
valve may be used more than once. If the state finds that a second 
reliability emergency arises that conflicts with the state plan, the 
state must submit a revision to its state plan so that the state plan 
is flexible enough to assure that such conflicts do not recur and that 
the state is providing for the implementation of the standards of 
performance for affected EGUs as required by the CAA.
    f. Coordination among federal partners.
    The EPA, DOE, and FERC have agreed to coordinate efforts to help 
ensure continued reliable electricity generation and transmission 
during the implementation of the final rule. The three agencies have 
developed a coordination strategy that reflects their joint 
understanding of how they will work together to monitor final rule 
implementation, share information, and resolve any difficulties that 
may be encountered. This strategy is based on the successful working 
relationship that the three agencies established in their joint effort 
to work together to monitor reliability during MATS implementation.
    g. Analyses of the reliability impacts of the proposal.
    The EPA appreciates that a large number of entities from many 
different industry perspectives have published reports and analysis 
with respect to electric reliability and the 111(d) proposed rule. We 
take concerns about reliability very seriously, and we appreciate the 
attention given to this issue in the comments and shared with us in 
public forums. It is important to note that these studies were 
conducted prior to promulgation of this final rule, and thus were only 
able to consider electric reliability with respect to the proposal. The 
EPA has made changes and improvements to the proposal in response to 
comments and new information, and some of the changes are relevant to 
the final rule's potential effect on electric reliability. One notable 
change pertains to the start of the interim period, which is now 2022 
rather than 2020. Another important change to the final rule is a more 
gradual phase-in of the BSER for affected EGUs over the interim period 
(from 2022 through 2029). The final rule also provides considerable 
flexibility and multiple pathways to states, including allowing their 
EGUs to use multi-state trading and other approaches, which would allow 
essential units to continue to meet their compliance obligation while 
generating even at unplanned but reliability-critical levels. In 
addition, we have included in the final rule a reliability safety valve 
provision that can be utilized in certain emergency situations. These 
changes, in addition to already existing industry mechanisms and 
planning requirements, will help to ensure that industry will be able 
to maintain electric reliability. The EPA is confident that the final 
rule will cut harmful electric power plant pollution while maintaining 
a reliable electric grid because the final rule provides industry with 
the time and flexibility needed to continue its current and ongoing 
planning and investing to modernize and upgrade the electric power 
system.
    In June of 2015, M.J. Bradley & Associates issued a report that 
enumerated a set of useful guiding principles for studying and 
evaluating the reliability impacts of the final rule.\871\ The report 
enumerated six principles: (1) A study should be transparent about the 
assumptions and data used; (2) a study should accurately reflect the 
existing status of the grid in its modeling assumptions; (3) a study 
should clearly identify the base case and not confuse what will happen 
as a result of the final rule with what would have happened anyway; (4) 
where possible, a study should contain sensitivities and probabilities 
as they are looking into the future which is necessarily uncertain; (5) 
a study should reflect the flexibility provided to states to allow them 
to design compliance approaches to maximize reliability; and (6) a 
study should provide realistic and reliability-focused results. These 
principles are helpful to keep in mind when reviewing recent studies.
---------------------------------------------------------------------------

    \871\ M.J. Bradley & Associates, Guiding Principles for 
Reliability Assessments Under EPA's Clean Power Plan (June 3, 2015), 
available at http://www.mjbradley.com/node/295.
---------------------------------------------------------------------------

    NERC published its analyses of the proposed rule in November 2014 
and again in April 2015.\872\ The EPA

[[Page 64880]]

appreciates NERC's attention to, and interest in, the proposed rule. 
However, we note that like some other studies, NERC assumes 
considerably less flexibility than actually is provided to states and 
EGUs in this final rule. The final rule provides states with 
considerable time and latitude in designing plans that are tailored to 
the system in which their EGUs operate, which should be reflected in 
any reliability analysis. Also, the NERC study does not fully reflect 
the current electric grid. For example, the amount of RE generation 
that NERC assumes for 2020 is similar to levels of generation that we 
see today whereas projections for 2020 are considerably higher.\873\ 
Further, NERC conflates retirements that may happen as a result of the 
rule with those that are already planned. The Brattle Group has also 
reviewed NERC's November 2014 initial analysis of the proposed rule, 
noting that it is important to distinguish between concerns about the 
building blocks and reliability concerns about compliance with state 
plans.\874\ The Brattle Group concluded that there are real world 
solutions to NERC's concerns. These include making use of the many 
flexible options available to states under the rule to mitigate 
reliability risks.
---------------------------------------------------------------------------

    \872\ North American Electric Reliability Corporation, Potential 
Reliability Impacts of EPA's Proposed Clean Power Plan (Nov. 5, 
2014), available at http://www.nerc.com/news/Pages/Reliability-Review-of-Proposed-Clean-Power-Plan-Identifies-Areas-for-Further-Study,-Makes-Recommendations-for-Stakeholders.aspx; North American 
Electric Reliability Corporation, Potential Reliability Impact of 
EPA's Proposed Clean Power Plan: Phase 1 (Apr. 21, 2015), available 
at http://www.nerc.com/news/Pages/Assessment-Uses-Scenario-Analysis-to-Identify-Potential-Reliability-Risks-from-Proposed-Clean-Power-Plan.aspx.
    \873\ EIA, Annual Energy Outlook 2015, with Projections to 2040, 
April 2015, available at http://www.eia.gov/forecasts/aeo/pdf/0382(2015).pdf.
    \874\ Brattle Group, EPA's Clean Power Plan and Reliability, 
Assessing NERC's Initial Reliability Review (Feb. 2015), available 
at http://info.aee.net/hs-fs/hub/211732/file-2486162659-pdf/PDF/EPAs-Clean-Power-Plan-Reliability-Brattle.pdf?t=1434398407867.
---------------------------------------------------------------------------

    Multiple ISOs/RTOs also provided analyses of the proposed rule, 
including MISO, PJM, ERCOT, and SPP.\875\ For example, MISO conducted 
an analysis of coal units at risk for retirement, finding that 14 GW of 
coal may be at risk.\876\ SPP performed a resource adequacy analysis 
that assumes planned retirements plus the EPA's projected retirements, 
but did not similarly account for the building of new generation 
capacity.\877\ While we appreciate MISO's and SPP's concerns regarding 
retirements and the potential that reserves will fall below reserve 
requirement levels, it is important to consider the many ways in which 
states can develop plans that account for their potential reliability 
concerns. The final rule continues to give states significant 
flexibility in how they comply with requirements, including both BSER 
measures and measures that were not included in the determination of 
the BSER as a means to comply. For example, demand-side EE measures can 
greatly assist states and affected EGUs in meeting the standards and/or 
state plan. Many studies assume that state plans will simply apply the 
BSER and do not recognize the large number of compliance approaches and 
opportunities that states and affected EGUs have available to them. The 
Analysis Group recently analyzed reliability considerations in MISO as 
the region considers how to comply with the final rule.\878\ The 
Analysis Group found that despite the large amount of coal-fired 
generating capacity that will likely be retired in MISO in the coming 
years, the entities responsible for electric system reliability in MISO 
are prepared to collaboratively address any reliability issues that 
arise and that there is a ``strong tool kit for managing `Essential 
Reliability Services' needed to assure high-quality electric service.'' 
\879\
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    \875\ See MISO, Analysis of EPA's Proposal to Reduce 
CO2 Emissions from Existing Units (Nov. 12, 2014), 
available at https://www.misoenergy.org/Library/Repository/Communication%20Material/EPA%20Regulations/AnalysisofEPAProposalReduceCO2Emissions.pdf; PJM, PJM 
Interconnection Economic Analysis of the EPA Clean Power Plan 
Proposal (Mar. 2, 2015), report listed at http://www.pjm.com/documents/reports.aspx; SPP, SPP's Reliability Impact Assessment of 
the EPA's Proposed Clean Power Plan, (Oct. 8, 2014), available at 
http://www.spp.org/publications/CPP%20Reliability%20Analysis%20Results%20Final%20Version.pdf; ERCOT, 
ERCOT Analysis of the Clean Power Plan (Nov. 17, 2014), available 
athttp://www.ercot.com/content/news/presentations/2014/ERCOTAnalysis-ImpactsCleanPowerPlan.pdf; and
    \876\ MISO, Analysis of EPA's Proposal to Reduce CO2 
Emissions from Existing Units, at 14 (Nov. 12, 2014), available at 
https://www.misoenergy.org/Library/Repository/Communication%20Material/EPA%20Regulations/AnalysisofEPAProposalReduceCO2Emissions.pdf.
    \877\ SPP, SPP's Reliability Impact Assessment of the EPA's 
Proposed Clean Power Plan, (Oct. 8, 2014), available at http://www.spp.org/publications/CPP%20Reliability%20Analysis%20Results%20Final%20Version.pdf.
    \878\ Analysis Group, Electric System Reliability and EPA's 
Clean Power Plan: The Case of MISO (June 8, 2015), available at 
http://www.analysisgroup.com/uploadedfiles/content/insights/publishing/analysis_group_clean_power_plan_miso_reliability.pdf.
    \879\ Analysis Group, Electric System Reliability and EPA's 
Clean Power Plan: The Case of MISO, at 2 (June 8, 2015), available 
at http://www.analysisgroup.com/uploadedfiles/content/insights/publishing/analysis_group_clean_power_plan_miso_reliability.pdf.
---------------------------------------------------------------------------

    ERCOT also performed an analysis, modeling numerous scenarios.\880\ 
ERCOT stated that its modeling identified two potential reliability 
problems--impacts of units retiring and increased levels of renewable 
generation on the ERCOT grid.\881\ As noted above, the final rule gives 
additional time for compliance, providing needed time to obtain new or 
replacement generation necessary as some existing generators retire. 
Moreover, affected EGUs needed for reliability should be able to employ 
the flexibilities afforded to them as they seek lower and zero-emitting 
generation. Finally, we note that ERCOT has a history of notable 
success in integrating RE into its electric grid, giving ERCOT 
significant expertise regarding challenges that may arise with the 
addition of new RE in order to comply with the final rule. In fact, a 
recent Brattle Group report used ERCOT as a case study for how to 
effectively integrate a large number of RE into the electric grid.\882\
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    \880\ ERCOT, ERCOT Analysis of the Clean Power Plan (Nov. 17, 
2014), available at http://www.ercot.com/content/news/presentations/2014/ERCOTAnalysis-ImpactsCleanPowerPlan.pdf.
    \881\ ERCOT, ERCOT Analysis of the Clean Power Plan, at 9 (Nov. 
17, 2014), available at http://www.ercot.com/content/news/presentations/2014/ERCOTAnalysis-ImpactsCleanPowerPlan.pdf.
    \882\ Brattle Group, Integrating Renewable Energy Into the 
Electricity Grid: Case Studies Showing How System Operators are 
Maintaining Reliability (June 2015), available at http://info.aee.net/integrating-renewable-energy-into-the-electricity-grid.
---------------------------------------------------------------------------

    PJM conducted its own analysis at the request of the Organization 
of PJM States (OPSI).\883\ This analysis is consistent with many of the 
M.J. Bradley guiding principles. PJM designed various scenarios to 
capture the impact of the proposed rule under a series of assumptions. 
Because the EPA had not yet issued the final rule, PJM cautioned 
against using the report as a reliability analysis or predictor of the 
future. PJM stated that, since 2007, PJM's capacity markets have helped 
to attract 35,000 MWs of additional generation. Even though 26,000 MWs 
will retire between 2009 and 2016, the PJM capacity market has procured 
sufficient resources to maintain reliability.
---------------------------------------------------------------------------

    \883\ PJM, PJM Interconnection Economic Analysis of the EPA 
Clean Power Plan Proposal (Mar. 2, 2015), report listed at http://www.pjm.com/documents/reports.aspx.
---------------------------------------------------------------------------

    WECC also produced a study which is part of a longer-term, phased 
effort.\884\ The assumptions, methodology, and limitations were all 
clearly presented, and there was extensive involvement by a range of 
stakeholders. WECC stated that it is embarking on a phased-study 
process that seeks to ``provide the industry with unbiased and

[[Page 64881]]

independent analysis of this issue.'' \885\ WECC concluded that the 
effects of the proposal on resource adequacy may be minimal but that 
resource adequacy cannot be fully assessed without realistic and/or 
proposed compliance scenarios.\886\
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    \884\ WECC, EPA Clean Power Plan: Phase I--Preliminary Technical 
Report (Sept. 19, 2014), available at https://www.wecc.biz/_layouts/15/WopiFrame.aspx?sourcedoc=/Reliability/140912_EPA-111(d)_PhaseI_Tech-Final.pdf&action=default&DefaultItemOpen=1.
    \885\ WECC, EPA Clean Power Plan: Phase I--Preliminary Technical 
Report, at 1 (Sept. 19, 2014), available at https://www.wecc.biz/_layouts/15/WopiFrame.aspx?sourcedoc=/Reliability/140912_EPA-111(d)_PhaseI_Tech-Final.pdf&action=default&DefaultItemOpen=1.
    \886\ WECC, EPA Clean Power Plan: Phase I--Preliminary Technical 
Report, at 30 (Sept. 19, 2014), available at https://www.wecc.biz/_layouts/15/WopiFrame.aspx?sourcedoc=/Reliability/140912_EPA-111(d)_PhaseI_Tech-Final.pdf&action=default&DefaultItemOpen=1.
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    Analysis Group analyzed the proposed rule, finding that it provides 
states and affected EGUs with a wide range of options and operational 
discretion that can prevent reliability issues while also reducing 
carbon pollution and costs.\887\ Analysis Group noted that some of the 
concerns raised by stakeholders about the proposed rule assume 
``inflexible implementation, are based upon worst-case scenarios, and 
assume that policy makers, regulators, and market participants will 
stand on the sidelines until it is far too late to act'' to ensure 
reliability.\888\ It stated that these assumptions are not consistent 
with past actions.
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    \887\ Analysis Group, Electric System Reliability and EPA's 
Clean Power Plan Tools and Practices (Feb. 2015), available at 
http://www.analysisgroup.com/uploadedfiles/content/insights/publishing/electric_system_reliability_and_epas_clean_power_plan_tools_and_practices.pdf.
    \888\ Analysis Group, Electric System Reliability and EPA's 
Clean Power Plan Tools and Practices, at ES-3 (Feb. 2015), available 
at http://www.analysisgroup.com/uploadedfiles/content/insights/publishing/electric_system_reliability_and_epas_clean_power_plan_tools_and_practices.pdf.
---------------------------------------------------------------------------

    We appreciate the time that multiple entities took to analyze and 
consider the potential impacts of the proposed rule. As we issue the 
final rule and states draft plans to implement the rule, we look 
forward to further analysis by these and other groups. Such analysis 
can provide states with needed resources to help them design state 
plans that will augment the efforts of the industry to maintain 
electric reliability.
3. Consideration of Effects on Employment and Economic Development
    States in designing their state plans should consider the effects 
of their plans on employment and overall economic development to assure 
that the opportunities for economic growth and jobs that the plans 
offer are manifest. To the extent possible, states should try to assure 
that any communities that can be expected to experience job losses can 
also take advantage of the opportunities for job growth or otherwise 
transition to healthy, sustainable economic growth. The EPA's 
illustrative analysis indicates that there may be some additional job 
losses in sectors related to coal extraction and generation that are 
attributable to implementation of this rule. At the same time, the 
EPA's illustrative analysis indicates that there may be new jobs in the 
utility power sector associated with both improving the efficiency of 
fossil fuel-fired power plants, construction and operation of new 
natural gas-fired and RE production, and actions to increase demand-
side EE. Consideration of these effects in the context of the 
particulars of the state plan can help states craft plans that, to the 
extent possible, meet multiple environmental, economic, and workforce 
development goals.
    The Partnerships for Opportunity and Workforce and Economic 
Revitalization (POWER) Initiative is a new interagency effort led by 
the Economic Development Administration in the Department of Commerce. 
POWER was launched to respond to current trends in the power sector: 
``The United States is undergoing a rapid energy transformation, 
particularly in the power sector. This transformation is producing 
cleaner air and healthier communities, and spurring new jobs and 
industries. At the same time, it is impacting workers and communities 
who have relied on the coal industry as a source of good jobs and 
economic prosperity, particularly in Appalachia, where competition with 
other coal basins provides additional pressure.'' \889\ The POWER 
Initiative aligns, leverages, and targets economic and workforce 
development assistance to communities and workers affected by changes 
in the coal industry and the utility power sector. The POWER Initiative 
is competitively awarding planning assistance and implementation grants 
with funding from the Department of Commerce, Department of Labor, 
Small Business Administration, and the Appalachian Regional Commission 
to partnerships anchored in impacted communities. These grants will 
help communities organize themselves, develop comprehensive strategic 
plans that chart their economic future, and execute coordinated 
economic and workforce development activities based on their strategic 
plans.\890\
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    \889\ http://www.eda.gov/power/.
    \890\ https://www.whitehouse.gov/the-press-office/2015/03/27/fact-sheet-partnerships-opportunity-and-workforce-and-economic-revitaliz.
---------------------------------------------------------------------------

    In addition to POWER, however, the EPA encourages states to use 
economic and labor market analysis to identify where they can deploy 
strategies to: (1) Provide a range of employment and training 
assistance to workers, and economic development assistance to 
communities affected by the rapid changes underway in the power sector 
and closely related industries, to diversify their economies, attract 
new sources of investment, and create new jobs; and (2) mobilize 
existing education and training resources, including those of community 
and technical colleges and registered apprenticeship programs, to 
ensure that both incumbent and new workers are trained for the skills 
necessary to meet employer demand for new workers in the utility, 
construction and related sectors, that such training includes career 
pathways for members of low-income communities and other vulnerable 
communities to attain employment in these sectors, and that such 
training results in validated skill certifications for workers.
4. Workforce Considerations
    Some stakeholders commented that, to ensure that emission 
reductions are realized, it is important that construction, operations 
and other skilled work undertaken pursuant to state plans is performed 
to specifications, and is effective, safe, and timely. A good way to 
ensure a highly proficient workforce is to require that workers have 
been certified by: (1) An apprenticeship program that is registered 
with the U.S. DOL, Office of Apprenticeship or a state apprenticeship 
program approved by the DOL; (2) a skill certification aligned with the 
U.S. DOE Better Building Workforce Guidelines and validated by a third 
party accrediting body recognized by DOE; or (3) other skill 
certification validated by a third party accrediting body.
5. Tenth Amendment Legal Considerations
    Some commenters have raised concerns that the emission guidelines 
and requirements for 111(d) state plans violate principles of 
federalism embodied in the U.S. Constitution, particularly the Tenth 
Amendment. These commenters claim that states will be 
unconstitutionally ``coerced'' or ``commandeered'' into taking certain 
actions in order to avoid the prospect of either a federal 111(d) plan 
applying to sources in the state, or of losing federal funds.
    We disagree on both fronts. First, the prospect of a federal plan 
applying to sources in a state does not ``coerce'' or

[[Page 64882]]

``commandeer'' that state into submitting its own satisfactory plan. 
Far from violating principles of federalism, this rule provides states 
with the initial opportunity to submit a satisfactory state plan, and 
provides states flexibility in developing that plan. If a state 
declines to take advantage of that opportunity, affected EGUs in that 
state will instead be subject to a federal plan that satisfies 
statutory requirements.\891\ This approach is consistent with ordinary 
cooperative federalism regimes that federal courts have routinely 
upheld against Tenth Amendment challenges.\892\
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    \891\ Among other things, a federal plan will implement 
standards of performance subject to specific statutory requirements. 
See 42 U.S.C. 7411(a)(1). The APA and CAA would prohibit the 
imposition of any federal plan that is ``arbitrary, capricious, an 
abuse of discretion, or otherwise not in accordance with law.'' 5 
U.S.C. 706(2)(a). Particularly given these independent constraints 
on the EPA's authority with respect to any potential federal plan, 
the prospect of any such plan would not commandeer states or coerce 
them into submitting their own state plans.
    \892\ See, e.g., Hodel v. Va. Surface Mining & Reclamation 
Ass'n, Inc., 452 U.S. 264, 283-93 (1981); Texas v. EPA, 726 F.3d 
180, 196-97 (D.C. Cir. 2013) (noting that ``Supreme Court precedent 
repeatedly affirm[s] the constitutionality of federal statutes that 
allow States to administer federal programs but provide for direct 
federal administration if a State chooses not to administer it'').
---------------------------------------------------------------------------

    Second, states that decline to take certain actions under this rule 
will not face the prospect of sanctions, such as withdrawn federal 
highway funds. CAA section 111 does not contain sanctions provisions, 
and we are finalizing revisions to these emission guidelines making 
explicit that the EPA will not withhold federal funds from a state on 
account of that state's failure to submit or implement an approvable 
111(d) state plan.
    Some commenters pointed to section 110(m) as a possible source of 
the EPA's sanction authority.\893\ Section 110(m) grants the EPA 
discretionary authority to withhold some federal highway funds under 
certain conditions. However, section 110(m) requires the EPA to adopt 
regulations to ``establish criteria for exercising'' this discretionary 
authority, and the only EPA regulations implementing section 110(m) 
apply to SIPs submitted under section 110.\894\
---------------------------------------------------------------------------

    \893\ Other commenters point to CAA section 179 as a possible 
direct source of this sanctions authority. However, the mandatory 
sanctions outlined in section 179 clearly apply only in the contexts 
of nonattainment SIPs and responses to SIP Calls made under CAA 
section 110(k)(5). See 42 U.S.C. 7509(a).
    \894\ 40 CFR 52.30 (defining ``plan or plan item'').
---------------------------------------------------------------------------

    The EPA never intended to even imply that we would contemplate 
using this authority to encourage state participation in this rule 
under section 111. To the contrary, we believe that imposition of a 
federal plan rather than sanctions is the appropriate path in the 
context of this program. Accordingly, regardless of whether the EPA 
could theoretically apply discretionary sanctions against states in the 
section 111(d) context, the final rule forbids the agency from 
exercising any such authority. We have included in this rule a 
provision that prohibits the agency from imposing sanctions in the 
event that a state fails to submit or implement a satisfactory plan 
under this rule. As states consider whether to take advantage of the 
opportunity to develop state plans, they can be assured that the EPA 
will not withdraw federal funding should they decline to participate.
6. Title VI
    States that are recipients of EPA financial assistance must comply 
with all federal nondiscrimination statutes that together prohibit 
discrimination on the bases of race, color, national origin (including 
limited-English proficiency), disability, sex and age. These laws 
include: Title VI of the Civil Rights Act of 1964; Section 504 of the 
Rehabilitation Act of 1973; Section 13 of the Federal Water Pollution 
Control Act Amendments of 1972; Title IX of the Education Act 
Amendments of 1972; and the Age Discrimination Act of 1975. Compliance 
with these nondiscrimination statutes is a recipient's separate and 
distinct obligation from compliance with environmental regulations. In 
other words, all recipients are required to ensure that all aspects of 
their state plans do not violate any of the federal nondiscrimination 
statutes, including Title VI.
    The EPA's Office of Civil Rights (OCR) is responsible for carrying 
out compliance with these federal nondiscrimination statutes and does 
so through a variety of means including: Complaint investigation; 
agency-initiated compliance reviews; pre-grant award assurances and 
audits; and technical assistance and outreach activities. Anyone who 
believes that any of the federal nondiscrimination laws enforced by OCR 
have been violated by a recipient of EPA financial assistance may file 
an administrative complaint with the EPA's OCR.

H. Resources for States To Consider in Developing Plans

    As part of the stakeholder outreach and comment processes, the EPA 
asked states what the agency could do to facilitate state plan 
development and implementation. In addition, after the comment period 
closed, the EPA continued to consult with state organizations including 
the Association of Air Pollution Control Agencies (AAPCA), 
Environmental Council of the States (ECOS), National Association of 
Clean Air Agencies (NACAA), National Association of Regulatory Utility 
Commissioners (NARUC), National Association of State Energy Officials 
(NASEO) and the National Governors Association (NGA).
    Some states indicated that they wanted the EPA to create resources 
to assist with state plan development, especially resources related to 
accounting for RE and demand-side EE in state plans. They requested 
clear methodologies for estimating emission reductions from RE and 
demand-side EE policies and programs so that these could be included as 
part of their compliance strategies. Stakeholders said that these tools 
and metrics should build upon the EPA's ``Roadmap for Incorporating 
Energy Efficiency/Renewable Energy Policies and Programs into State and 
Tribal Implementation Plans,'' as well as the State Energy Efficiency 
Action Network's ``Energy Efficiency Program Impact Evaluation Guide.'' 
In addition, stakeholders requested clear guidance on how to measure 
the impacts of RE and demand-side EE programs using established EM&V 
protocols.
    The EPA also heard that states would like guidance on plan 
development to be released at the same time as this final rule. This 
guidance should include allowable programs and policies for compliance, 
examples of compliance pathways, clear information on multi-state plan 
development, and identification of tools.
    As a result of this feedback, in consultation with U.S. DOE and 
other federal agencies, the EPA continued to refine its toolbox of 
decision support resources at: http://www2.epa.gov/www2.epa.gov/cleanpowerplantoolbox. The site includes information on regulatory 
requirements, including state plan guidance and state plan decision 
support. The state plan guidance section serves as a central repository 
for the final emission guidelines, RIA, guidance documents, TSDs and 
other supporting materials. The state plan decision support section 
includes information to help states evaluate different approaches and 
measures they might consider as they initiate plan development. This 
section includes, for example, a summary of existing state climate and 
RE and demand-side EE policies and programs, information on electric 
utility actions that reduce CO2, and tools and information 
to estimate

[[Page 64883]]

the emissions impact of RE and demand-side EE programs.
    The EPA notes that our inclusion of a measure in the toolbox does 
not mean that a state plan must include that measure. In fact, 
inclusion of measures provided at the Web site does not necessarily 
imply the approvability of an approach or method for use in a state 
plan. States will need to demonstrate that any measure included in a 
state plan meets all relevant criteria and adequately addresses 
elements of the plan components discussed in section VIII.D of this 
preamble.

I. Considerations for CO2 Emission Reduction Measures That Occur at 
Affected EGUs

    This section describes a range of emission reduction actions that 
may be taken at affected EGUs that reduce CO2 emissions from 
an affected EGU and/or improve its CO2 emission rate, and 
the accounting treatment for these actions in a state plan. Some of 
these actions do not necessitate additional accounting, monitoring or 
reporting requirements. Such actions are discussed in section VIII.I.1 
below, and include heat rate improvements, fuel switching from one 
fossil fuel to another, integration of RE into EGU operations, and 
combined heat and power (CHP) expansion or retrofit. Other actions, 
however, do necessitate additional accounting, monitoring, or reporting 
requirements. These include use of CCS, CCU and biomass, as discussed 
in section VIII.I.2 below.
    The discussion in this section applies for both rate-based and 
mass-based plans. Additional accounting considerations for mass-based 
plans are discussed in section VIII.J. Additional accounting 
considerations for rate-based plans, including how actions that 
substitute for generation from affected EGUs or avoid the need for 
generation from affected EGUs may be used in a state plan to adjust the 
CO2 emission rate of an affected EGU, are discussed in 
section VIII.K.
1. Actions Without Additional Accounting and Reporting Requirements
    Many actions will reduce the reported CO2 emissions or 
CO2 emission rate of an affected EGU, without the need for 
additional accounting or monitoring and reporting requirements beyond 
the required CEMS tracking of actual stack CO2 emissions and 
tracking of actual energy output.\895\ The effect of these actions will 
result in changes in reported CO2 emissions and/or energy 
output by an affected EGU. These actions include:
---------------------------------------------------------------------------

    \895\ Monitoring and reporting requirements for affected EGU 
CO2 emissions and useful energy output are addressed in 
section VIII.F.
---------------------------------------------------------------------------

     heat rate improvements;
     fuel switching to a fossil fuel with lower carbon 
content (e.g., from coal to natural gas);
     integrated RE; \896\ and
---------------------------------------------------------------------------

    \896\ ``Integrated RE'' refers to RE that is directly 
incorporated into the mechanical systems and operation of the EGU. 
An example is a solar thermal energy system used to preheat boiler 
feedwater. Such approaches reduce the amount of fossil fuel heat 
input per unit of useful energy output.
---------------------------------------------------------------------------

     CHP, including retrofit of an affected EGU to a CHP 
configuration, or revising the useful energy outputs (electrical and 
thermal) at an affected EGU already operating in a CHP 
configuration.\897\
---------------------------------------------------------------------------

    \897\ The emission reduction potential from CHP stems from the 
unit using less fuel for producing useful electrical and thermal 
outputs than would be required to run separate electrical and 
thermal units. The emission reduction would depend on the type of 
affected EGU and available steam hosts in the vicinity of the 
affected EGU. A conventional combustion turbine generator, for 
example, converted into a CHP unit could effectively result in a 
reduction of 25 percent or more in the reported CO2 
emission rate. The potential retrofitte EGU CHP market consists of 
converted simple cycle turbines, older steam plants in urban areas, 
and combined cycle units near beneficial thermal loads.

    Heat rate improvements, fuel switching, integrating RE and CHP 
would not require any additional accounting or monitoring and 
reporting, because under the emission guidelines affected EGUs are 
already required to monitor and report CO2 emissions at the 
stack level, and to monitor and report useful energy outputs. Stack 
monitoring would reflect reductions in CO2 emissions from 
efficiency improvements, changes in fuel use (including incorporation 
of RE), and other on-site changes.
2. Actions With Additional Accounting and Reporting Requirements
    Certain actions that may be taken at an affected EGU to reduce 
CO2 emissions, specifically application of CCS and CCU, and 
use of biomass, require additional accounting and reporting.
    a. Application of CCS. Affected EGUs may utilize retrofit CCS 
technology to reduce reported stack CO2 emissions from the 
EGU.\898\ Affected EGUs that apply CCS under a state plan must meet the 
same monitoring, recordkeeping and reporting requirements for 
sequestered CO2 as new units that implement CCS to meet 
final standards of performance under CAA section 111(b) for new 
EGUs.\899\ Specifically, the final CAA section 111(b) rule for new 
sources requires that, if a new affected EGU uses CCS to meet the 
applicable CO2 emission limit, the EGU must report in 
accordance with 40 CFR part 98 subpart PP (Suppliers of Carbon 
Dioxide), and the captured CO2 must be injected at a 
facility or facilities that report in accordance with 40 CFR part 98 
subpart RR (Geologic Sequestration of Carbon Dioxide).\900,901\ See 40 
CFR 60.5555(f). Taken together, these requirements ensure that the 
amount of captured and sequestered CO2 will be tracked as 
appropriate at project- and national-levels, and that the status of the 
CO2 in its sequestration site will be monitored, including 
air-side monitoring and reporting. As detailed in the preamble for the 
CAA section 111(b) standards for new EGUs, the EPA found that there is 
ample evidence that CCS is technically feasible and that partial CCS 
can be implemented at a new fossil fuel-fired steam generating EGU at a 
cost that is reasonable and that is consistent with the cost of other 
dispatchable, non-NGCC generating options. In the June 2014 proposal, 
the EPA noted that CCS technology at existing EGUs would entail 
additional considerations beyond those at issue for newly constructed 
EGUs. Specifically, the cost of integrating a retrofit CCS system into 
an existing facility may be expected to be substantial, and some 
existing EGUs may have space limitations and thus may not be able to 
accommodate the expansion needed to install the equipment to implement 
CCS. Further, the EPA noted that aggregated costs of applying CCS as a 
component of the BSER for the large number of existing fossil fuel-
fired steam EGUs would be substantial and would be expected to affect 
the cost and potentially the supply of electricity on a national basis. 
Because there are lower-cost systems of emission reduction available to 
reduce emissions from existing plants, the EPA

[[Page 64884]]

did not propose nor finalize CCS as a component of the BSER for 
existing EGUs.
---------------------------------------------------------------------------

    \898\ Addition of retrofit CCS technology should not trigger CAA 
section 111(b) applicability for modified or reconstructed sources. 
Pollution control projects do not trigger NSPS modifications and 
addition of CCS technology does not count toward the capital costs 
of reconstruction for NSPS.
    \899\ Standards of Performance for Greenhouse Gas Emissions from 
New, Modified, and Reconstructed Stationary Sources: Electric 
Utility Generating Units.
    \900\ The final CAA section 111(b) rule finalizes amendments to 
subpart PP reporting requirements, specifically requiring that the 
following pieces of information be reported: (1) The electronic GHG 
Reporting Tool identification (e-GGRT ID) of the EGU facility from 
which CO2 was captured, and (2) the e-GGRT ID(s) for, and 
mass of CO2 transferred to, each GS site reporting under 
subpart RR. As noted, the final 111(b) rule also requires that any 
affected EGU unit that captures CO2 to meet the 
applicable emission limit must transfer the captured CO2 
to a facility that reports under 40 CFR part 98 subpart RR.
    \901\ Under final requirements in the CAA 111(b) NSPS, any well 
receiving CO2 captured from an affected EGU, be it a 
Class VI or Class II well, must report under subpart RR. A UIC Class 
II well's regulatory status does not change because it receives such 
CO2, nor does it change by virtue of reporting under 
subpart RR.
---------------------------------------------------------------------------

    However, the EPA noted that CCS may be a viable CO2 
mitigation technology at some existing sources and that it would be 
available to states and to sources as a compliance option. Numerous 
commenters agreed with the EPA's proposed determination that CCS 
technology is not part of the BSER building blocks for existing EGUs. 
Other commenters opposed inclusion of CCS requirements in state plans 
and provided specific reasons why CCS would not be applicable in 
certain states. Many commenters felt that CCS technology is not 
adequately demonstrated and is not economically practical at this time. 
Other commenters argued that CCS is an available technology and that it 
can be implemented at more EGUs than predicted by EPA modeling.
    Some commenters noted that there are opportunities to reduce the 
cost of CCS implementation by selling the captured CO2 for 
use in Enhanced Oil Recovery (EOR) operations. One commenter expressed 
concern that federal requirements under the Greenhouse Gas Reporting 
Program--specifically the requirement (mentioned above) to report under 
40 CFR part 98 subpart RR--would foreclose, rather than encourage, the 
use of captured CO2 for EOR. The EPA received similar public 
comments on the CAA 111(b) proposal for new EGUs. The EPA disagrees 
with the commenters' assertions and addressed those in the preamble for 
the final standards of performance and in the Response-to-Comments 
(RTC) document for the CAA 111(b) NSPS rulemaking. The EPA noted that 
the cost of compliance with subpart RR is not significant enough to 
offset the potential revenue for the EOR operator from the sale of 
produced oil for CCS projects that are reliant on EOR. The costs 
associated with subpart RR are relatively modest, especially in 
comparison with revenues from an EOR field.
    After consideration of the variety of comments we received on this 
issue, we are confirming our proposal that CCS is not an element of the 
BSER, but it is an available compliance measure for a state plan. EGUs 
implementing CCS would need to follow reporting requirements 
established in the final CAA section 111(b) rule for new affected EGUs.
    b. Application of CCU.
    The EPA received comments suggesting that carbon capture and 
utilization (CCU) technologies should also be allowed as a 
CO2 emission rate adjustment measure for affected EGUs.
    Potential alternatives to storing CO2 in geologic 
formations are emerging and may offer the opportunity to offset the 
cost of CO2 capture. For example, captured anthropogenic 
CO2 may be stored in solid carbonate materials such as 
precipitated calcium carbonate (PCC) or magnesium or calcium carbonate, 
bauxite residue carbonation, and certain types of cement through 
mineralization. The carbonate materials produced can be tailored to 
optimize performance in specific industrial and commercial 
applications. For example, these carbonate materials have been used in 
the construction industry and, more recently and innovatively, in 
cement production processes to replace Portland cement.
    The Skyonics Skymine[supreg] project, which opened its 
demonstration project in October 2014, is an example of captured 
CO2 being used in the production of carbonate products. This 
plant converts CO2 into commercial products. It captures 
over 75,000 tons of CO2 annually from a San Antonio, Texas, 
cement plant and converts the CO2 into other products 
including sodium carbonate and sodium bicarbonate.\902\ Other 
companies--including Calera \903\ and New Sky \904\--also offer 
commercially available technology for the beneficial use of captured 
CO2. These processes can be utilized in a variety of 
industrial applications--including at fossil fuel-fired power plants.
---------------------------------------------------------------------------

    \902\ http://skyonic.com/technologies/skymine.
    \903\ http://www.calera.com/beneficial-reuse-of-co2/process.html.
    \904\ http://www.newskyenergy.com/index.php/products/carboncycle.
---------------------------------------------------------------------------

    However, consideration of how these emerging alternatives could be 
used to meet CO2 emission performance rates or state 
CO2 emission goals would require a better understanding of 
the ultimate fate of the captured CO2 and the degree to 
which the method permanently isolates the captured CO2 or 
displaces other CO2 emissions from the atmosphere.
    Several commenters also suggested that algae-based CCU (i.e., the 
use of algae to convert captured CO2 to useful products--
especially biofuels) should be recognized for its potential to reduce 
emissions from existing fossil-fueled EGUs.
    Unlike geologic sequestration, there are currently no uniform 
monitoring and reporting mechanisms to demonstrate that these 
alternative end uses of captured CO2 result in overall 
reductions of CO2 emissions to the atmosphere. As these 
alternative technologies are developed, the EPA is committed to working 
collaboratively with stakeholders to evaluate the efficacy of 
alternative utilization technologies, to address any regulatory 
hurdles, and to develop appropriate monitoring and reporting protocols 
to demonstrate CO2 reductions.
    In the meantime, state plans may allow affected EGUs to use 
qualifying CCU technologies to reduce CO2 emissions that are 
subject to an emission standard, or those that are counted when 
demonstrating achievement of the CO2 emission performance 
rates or a state rate-based or mass-based CO2 emission. 
State plans must include analysis supporting how the proposed 
qualifying CCU technology results in CO2 emission mitigation 
from affected EGUs and provide monitoring, reporting, and verification 
requirements to demonstrate the reductions. The EPA would then review 
the appropriateness and basis for the analysis and the verification 
requirements in the course of its review of the state plan.
    c. Application of biomass co-firing and repowering.
    The EPA received multiple comments supporting the use of biomass 
feedstocks as a means of reducing CO2 emissions within state 
plans. Several commenters also asserted that states should be able to 
determine how biomass can be used in their plans. Additionally, the EPA 
received a range of comments regarding the valuation of CO2 
emissions from biomass combustion. Some argued that all biomass 
feedstocks should be considered ``carbon neutral,'' while others 
maintained that only the full stack emissions from biomass combustion 
should be counted. As discussed in the next section, the revised 
Framework for Assessing Biogenic Carbon Dioxide for Stationary Sources 
\905\ and 2012 Science Advisory Board peer review of the 2011 Draft 
Framework find that it is not scientifically valid to assume that all 
biogenic feedstocks are ``carbon neutral, but that the net biogenic 
CO2 atmospheric contribution of different biomass feedstocks 
can vary and depends on various factors, including feedstock type and 
characteristics, production practices, and, in some cases, the 
alternative fate of the feedstock.\906\ Other comments focused on the 
use of sustainably-derived agricultural and forest biomass feedstocks, 
including stakeholders who

[[Page 64885]]

supported and those against such feedstocks as approvable elements, and 
those who wanted further definition of these feedstocks. As discussed 
above and in more detail below, these final guidelines provide that 
states can include qualified biomass in their plans and include 
provisions for how qualified biomass feedstocks or feedstock categories 
will be determined. The EPA will review the appropriateness and basis 
for determining qualified biomass feedstocks or feedstock categories in 
its review of the approvability of a state plan.
---------------------------------------------------------------------------

    \905\ www.epa.gov/climatechange/downloads/Framework-for-Assessing-Biogenic-CO2-Emissions.pdf.
    \906\ www.epa.gov/climatechange/ghgemissions/biogenic-emissions.html.
---------------------------------------------------------------------------

    (1) Considerations for use of biomass in state plans.
    The EPA recognizes that the use of some biomass-derived fuels can 
play a role in controlling increases of CO2 levels in the 
atmosphere. The use of some kinds of biomass has the potential to offer 
a wide range of environmental benefits, including carbon benefits. 
However, these benefits can typically only be realized if biomass 
feedstocks are sourced responsibly and attributes of the carbon cycle 
related to the biomass feedstock are taken into account.
    In November 2014, the agency released a second draft of the 
technical report, Framework for Assessing Biogenic Carbon Dioxide for 
Stationary Sources. The revised Framework, and the EPA's Science 
Advisory Board (SAB) peer review of the 2011 Draft Framework, finds 
that it is not scientifically valid to assume that all biogenic 
feedstocks are ``carbon neutral'' and that the net biogenic 
CO2 atmospheric contribution of different biogenic 
feedstocks generally depends on various factors related to feedstock 
characteristics, production, processing and combustion practices, and, 
in some cases, what would happen to that feedstock and the related 
biogenic emissions if not used for energy production.\907\ The revised 
Framework also found that the production and use of some biogenic 
feedstocks and subsequent biogenic CO2 emissions from 
stationary sources will not inevitably result in increased levels of 
CO2 to the atmosphere, unlike CO2 emissions from 
combustion of fossil fuels.
---------------------------------------------------------------------------

    \907\ Specifically, the SAB found that ``There are circumstances 
in which biomass is grown, harvested and combusted in a carbon 
neutral fashion but carbon neutrality is not an appropriate a priori 
assumption; it is a conclusion that should be reached only after 
considering a particular feedstock's production and consumption 
cycle. There is considerable heterogeneity in feedstock types, 
sources and production methods and thus net biogenic carbon 
emissions will vary considerably.'' www.epa.gov/climatechange/ghgemissions/biogenic-emissions.html.
---------------------------------------------------------------------------

    The SAB peer review panel agreed that the use of biomass feedstocks 
derived from the decomposition of biogenic waste in landfills, compost 
facilities or anaerobic digesters did not constitute a net contribution 
of biogenic CO2 emissions to the atmosphere. And further, 
information considered in preparing the second draft of the Framework, 
including the SAB peer review and stakeholder input, supports the 
finding that use of waste-derived feedstocks \908\ and certain forest-
derived industrial byproducts (such as those without alternative 
markets) are likely to have minimal or no net atmospheric contributions 
of biogenic CO2 emissions, or even reduce such impacts, when 
compared with an alternate fate of disposal.
---------------------------------------------------------------------------

    \908\ Types of waste-derived biogenic feedstocks may include: 
Landfill gas generated through the decomposition of MSW in a 
landfill; biogas generated from the decomposition of livestock 
waste, biogenic MSW, and/or other food waste in an anaerobic 
digester; biogas generated through the treatment of waste water, due 
to the anaerobic decomposition of biological materials; livestock 
waste; and the biogenic fraction of MSW at waste-to-energy 
facilities.
---------------------------------------------------------------------------

    In addition, as detailed in the President's Climate Action 
Plan,\909\ part of the strategy to address climate change includes 
efforts to protect and restore our forests, as well as other critical 
landscapes including grasslands and wetlands, in the face of a changing 
climate. This country's forests currently play a critical role in 
addressing carbon pollution, removing more than 13 percent of total 
U.S. GHG emissions each year.\910\ Conservation and sustainable 
management can help ensure our forests and other lands will continue to 
remove carbon from the atmosphere while also improving soil and water 
quality, reducing wildfire risk and enhancing forests' resilience in 
the face of climate change.
---------------------------------------------------------------------------

    \909\ www.whitehouse.gov/sites/default/files/image/president27sclimateactionplan.pdf.
    \910\ www.epa.gov/climatechange/Downloads/ghgemissions/US-GHG-Inventory-2015-Chapter-6-Land-Use-Land-Use-Change-and-Forestry.pdf.
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    Many states have recognized the importance of forests and other 
lands for climate resilience and mitigation, and have developed a 
variety of sustainable forestry policies, RE incentives and standards, 
and GHG accounting procedures. Some states, for example Oregon and 
California, have programs that recognize the multiple benefits that 
forests provide, including biodiversity and ecosystem services 
protection as well as climate change mitigation through carbon storage. 
Oregon has several programs focused on best forest management practices 
and sustainability, including the Oregon Indicators of Sustainable 
Forests, that promote environmentally, economically and socially 
sustainable management of state forests. California's Forest Practice 
Regulations support sustained production of high-quality timber while 
considering ecological, economic and social values, and the state's 
Greenhouse Gas Reduction Fund provides resources for forestry projects 
to improve forest health, maintain carbon storage and avoid GHG 
emissions from pests, wildfires and conversion to non-forest uses.
    Several states focus on sustainable bioenergy, as seen with the 
sustainability requirements for eligible biomass in the Massachusetts 
RPS, which, among other requirements, limits old growth forest 
harvests. Many states employ complementary programs that together work 
to address sustainable forestry practices. For example, Wisconsin uses 
a state forest sustainability framework that provides a common system 
to measure the sustainability of the state's public and private 
forests, in conjunction with a series of voluntary best management 
guideline manuals for sustainable woody biomass and agriculturally-
derived biomass. In addition to state-specific programs, some states 
also actively participate in sustainable forest management or 
certification programs through third-party entities such as the 
Sustainable Forestry Initiative (SFI) and the Forest Stewardship 
Council (FSC). For example, in addition to other state sustainability 
programs, New York has certified more than 780,000 acres of state 
forestland to both SFI and FSC's sustainable forest management 
programs. SFI and FSC have certified more than 63 and 35 million acres 
of forestland across the U.S., respectively.
    These examples demonstrate how states already use diverse 
strategies to promote sustainable forestry and agricultural management 
while realizing their unique economic, environmental and RE goals. As 
states evaluate options for meeting the emission guidelines, they may 
consider how sustainably-derived biomass and sustainable forestry and 
agriculture programs, such as the examples highlighted above, may help 
them control increases of CO2 levels in the atmosphere. In 
addition, the EPA's work on assessing biogenic CO2 emissions 
from stationary sources may also help inform states' efforts to assess 
the role of different biogenic

[[Page 64886]]

feedstocks in their plans and broader climate strategies.\911\
---------------------------------------------------------------------------

    \911\ As highlighted in a November 2014 memorandum to the EPA's 
Regional Air Division Directors. www.epa.gov/climatechange/ghgemissions/biogenic-emissions.html.
---------------------------------------------------------------------------

    The EPA is engaging in a second round of targeted peer review on 
the revised Framework with the SAB in 2015.\912\ As part of this 
technical process, and as the EPA and states implement these emission 
guidelines, the EPA will continue to assess and closely monitor overall 
bioenergy demand and associated landscape conditions for changes that 
might have negative impacts on public health or the environment.
---------------------------------------------------------------------------

    \912\ www.epa.gov/sab.
---------------------------------------------------------------------------

    (2) Additional considerations and requirements for biomass fuels.
    The EPA anticipates that some states may consider the use of 
certain biomass-derived fuels used in electricity generation as a way 
to control increases of CO2 levels in the atmosphere, and 
will include them as part of their state plans to meet the emission 
guidelines. Not all forms of biomass are expected to be approvable as 
qualified biomass (i.e., biomass that can be considered as an approach 
for controlling increases of CO2 levels in the atmosphere). 
Affected EGUs may use qualified biomass in order to control or reduce 
CO2 emissions that are subject to an emission standard 
requirement, or those that are counted when demonstrating achievement 
of the CO2 emission performance rates or a state rate-based 
or mass-based CO2 emission goal.
    State plan submissions must describe the types of biomass that are 
being proposed for use under the state plan and how those proposed 
feedstocks or feedstock categories should be considered as ``qualified 
biomass'' (i.e., a biomass feedstock that is demonstrated as a method 
to control increases of CO2 levels in the atmosphere). The 
submission must also address the proposed valuation of biogenic 
CO2 emissions (i.e., the proposed portion of biogenic 
CO2 emissions from use of the biomass feedstock that would 
not be counted when demonstrating compliance with an emission standard, 
or when demonstrating achievement of the CO2 emission 
performance rates or a state rate-based or mass-based CO2 
emission goal).
    With regard to assessing qualified biomass proposed in state plans, 
the EPA generally acknowledges the CO2 and climate policy 
benefits of waste-derived biogenic feedstocks and certain forest- and 
agriculture-derived industrial byproduct feedstocks, based on the 
conclusions supported by a variety of technical studies, including the 
revised Framework for Assessing Biogenic Carbon Dioxide for Stationary 
Sources. The use of such waste-derived and certain industrial byproduct 
biomass feedstocks would likely be approvable as qualified biomass in a 
state plan when proposed with measures that meet the biomass 
monitoring, reporting and verification requirements discussed below and 
other measures as required elsewhere in these emission guidelines.
    Given the importance of sustainable land management in achieving 
the carbon goals of the President's Climate Action Plan, sustainably-
derived agricultural and forest biomass feedstocks may also be 
acceptable as qualified biomass in a state plan, if the state-supplied 
analysis of proposed qualified feedstocks or feedstock categories can 
adequately demonstrate that such feedstocks or feedstock categories 
appropriately control increases of CO2 levels in the 
atmosphere and can adequately monitor and verify feedstock sources and 
related sustainability practices. Information in the revised Framework, 
the second SAB peer review process, and the state and third party 
programs highlighted in the previous section can assist states when 
considering the role of qualified biomass in state plan submittals.
    Regardless of what biomass feedstocks are proposed, state plans 
must specify how biogenic CO2 emissions will be monitored 
and reported, and identify specific EM&V, tracking and auditing 
approaches for qualified biomass feedstocks. As discussed in section 
VIII.D.2, state plan submittals must include CO2 emission 
monitoring, reporting and recordkeeping measures. In the case of 
sustainably-derived forest- and agriculture-derived feedstocks, this 
will also include measures for verifying feedstock type, origin and 
associated sustainability practices. Section VIII.K describes how state 
plan submittals must specify the requirements and procedures that EM&V 
measures must meet. As discussed in section VIII.K, the EPA is 
addressing potential EM&V measures for qualified biomass in EPA's model 
trading rule and draft EM&V guidance, such as measures that would 
ensure that biomass-related biogenic CO2 benefits are 
quantifiable, verifiable, non-duplicative, permanent and enforceable.
    State plan submittals must ensure that all biomass used meets the 
state plan requirements for qualified biomass and associated biogenic 
CO2 benefits, such as using robust, independent third party 
verification and establishing measures to maintain transparency, 
including disclosure of relevant documentation and reports. State plan 
submittals must include measures for tracking and auditing performance 
to ensure that biomass used meets the state plan requirements for 
qualified biomass and associated biogenic CO2 benefits. 
Details on how to adjust CO2 rates through the use of 
qualified biomass feedstocks are provided in section VIII.K.1.
    The EPA will review the appropriateness and basis for proposed 
qualified biomass and biomass treatment determinations and related 
accounting, monitoring and reporting measures in the course of its 
review of a state plan. The EPA's determination that a state plan 
satisfactorily proves that proposed biomass fuels qualify would be 
based in part on whether the plan submittal demonstrates that proposed 
state measures for qualified biomass and related biogenic 
CO2 benefits are quantifiable, verifiable, enforceable, non-
duplicative and permanent. The EPA recognizes that CCS technology 
(described above in section VIII.I.2.a) could be applied in conjunction 
with the use of qualified biomass.
    (3) Biomass co-firing.
    Affected EGUs may use qualified biomass co-fired with fossil fuels 
at an affected EGU. As discussed above in this section, not all forms 
of biomass are expected to be approvable and states should propose 
biomass feedstocks and treatment of biogenic CO2 emissions 
in state plans, along with supporting analysis where applicable. The 
EPA will review the appropriateness and basis for such determinations 
and accounting measures in the course of its review of a state plan.
    An affected EGU using qualified biomass as a fuel must monitor and 
report both its overall CO2 emissions and its biogenic 
CO2 emissions. If biomass is to be used as means to control 
increases of CO2 levels in the atmosphere in a state plan, 
the plan must specify requirements for reporting biogenic 
CO2 emissions from affected EGUs.
    (4) Biomass repowering.
    Affected EGUs could fully repower to use primarily qualified 
biomass. The characteristics of affected EGUs, as discussed in section 
IV.D, include the use of at least 10 percent fossil fuel for 
applicability of these emission guidelines. An EGU repowering with at 
least 90 percent biomass fuels instead of fossil fuels becomes a non-
affected

[[Page 64887]]

EGU.\913\ An EGU repowering with less than 90 percent biomass would 
remain an affected EGU and therefore need to propose biomass feedstocks 
and treatment of biogenic CO2 emissions in state plans, 
along with supporting analysis where applicable.
---------------------------------------------------------------------------

    \913\ For such an EGU to be considered non-affected, the EGU 
must be subject to a federally enforceable or practically 
enforceable condition, expressed in (for example) a construction 
permit or otherwise, that limits the amount of fossil fuel that may 
be used to 10 percent or less.
---------------------------------------------------------------------------

J. Additional Considerations and Requirements for Mass-Based State 
Plans

    This section discusses considerations and requirements for 
different types of mass-based state plans. This includes mass-based 
state plans using emission budget trading programs, and coordination 
among such programs where states retain individual mass CO2 
emission goals. CAA section 111(d) requires states to submit, in part, 
a plan that establishes standards of performance for affected EGUs 
which reflect the BSER. The state plan must be satisfactory with 
respect to this requirement in order for the EPA to approve the plan. 
As previously described, states meet the statutory requirements of 
111(d) and the requirements of the final emission guidelines by 
establishing emission standards for affected EGUs that meet the 
performance rates, which reflect the application of BSER as determined 
by the EPA. This final rule allows states to alternatively establish 
emission standards that meet rate-based or mass-based goals. The state 
goals must be equivalent to the performance rates in order to reflect 
the application of the BSER as required by the statute and the final 
emission guidelines. Therefore, a state choosing a mass-based 
implementation must address leakage as part of its mass-based plan in 
order to satisfactorily establish emission standards for affected EGUs 
that reflect the BSER as set by the EPA.
1. Accounting for CO2 Emission Reduction Measures in Mass-
Based State Plans
    As discussed in section VIII.I, measures that occur at affected 
EGUs will result in CO2 emission reductions that are 
automatically accounted for in reported CO2 emissions. Other 
measures that provide substitute generation for affected EGUs or avoid 
the need for generation from affected EGUs, such as demand-side EE, are 
automatically accounted for under a mass-based plan to the extent that 
these measures reduce reported CO2 emissions from affected 
EGUs. Unlike under a rate-based plan, no additional accounting is 
necessary in order to recognize these emission reductions.
2. Use of Emission Budget Trading Programs
    This section addresses the use of emission budget trading programs 
in a mass-based state plan, including provisions required for such 
programs and the design of such programs in the context of a state 
plan. This includes program design approaches that ensure achievement 
of a state mass-based CO2 emission goal (or mass-based 
CO2 goal plus new source CO2 emission complement) 
(section VIII.J.2.b), as well as how states can use emission budget 
trading programs with broader source coverage and other flexibility 
features in a state plan, such as the programs currently implemented by 
California and the RGGI participating states (section VIII.J.2.c). 
Section VIII.J.2.d addresses other considerations for the design of 
emission budget trading programs that states may want to consider, such 
as allowance allocation approaches. Section VIII.J.3 addresses multi-
state coordination among emission budget trading programs used in 
states that retain their individual state mass-based CO2 
goals.
    a. State plan provisions required for a mass-based emission budget 
trading program approach.
    For a mass-based emission trading program approach, the state plan 
would include as its federally enforceable emission standards 
requirements that specify the emission budget and related compliance 
requirements and mechanisms. These requirements would include: 
CO2 emission monitoring, reporting, and recordkeeping 
requirements for affected EGUs; provisions for state allocation of 
allowances; provisions for tracking of allowances, from issuance 
through submission for compliance; and the process for affected EGUs to 
demonstrate compliance (allowance ``true-up'' with reported 
CO2 emissions). Mass-based emission standards that take the 
form of an emission budget trading program must be quantifiable, 
verifiable, enforceable, non-duplicative and permanent. These 
requirements are described in more detail at section VIII.D.2.
    Where a state plan establishes mass-based emission standards for 
affected EGUs only, the emission standards and the implementing and 
enforcing measures may be included in the state plan as the full set of 
requirements implementing the emission budget trading program. Where an 
emission budget trading program in a state plan addresses affected EGUs 
and other fossil fuel-fired EGUs or emission sources, pursuant to the 
approaches described in sections VIII.J.2.b-d below, the requirements 
that must be included in the state plan are the federally enforceable 
emission standards in the state plan that apply specifically to 
affected EGUs, and the requirements that specifically require affected 
EGUs to participate in and comply with the requirements of the emission 
budget trading program. This includes the requirement for an affected 
EGU to surrender emission allowances equal to reported CO2 
emissions, and meet monitoring and reporting requirements for 
CO2 emissions, among other requirements. These requirements 
may be submitted as part of the federally enforceable state plan 
through mechanisms with the appropriate legal authority and effect, 
such as state regulations, Title V permit requirements for affected 
EGUs, and other possible instruments that impose these requirements 
specifically with respect to affected EGUs. Under this approach, the 
full set of regulations establishing the emission budget trading 
program that applies to affected EGUs and other fossil fuel-fired EGUs 
and other emission sources (if relevant) must be described as 
supporting documentation in the state plan submittal for EPA to 
evaluate the approvability of the plan by determining whether the 
affected EGUs will achieve the requisite goal.
    b. Requirement for emission budget trading programs to address 
potential leakage.
    In Section VII.D, the EPA specifies that potential emission leakage 
must be addressed in a state plan with mass-based emission standards. 
The EPA received comments suggesting various solutions to this concern, 
such as the inclusion of new sources under the rule and quantitative 
adjustments to mass CO2 goals for affected EGUs. In response 
to this issue, the EPA has sought to give states flexibility in how 
they meet this requirement and base the acceptable solutions on what 
will best suit a state's unique characteristics and state plan 
structure.
    To address the potential for emission leakage to new sources under 
a mass-based plan approach, which could prevent a mass-based program 
from successfully achieving a mass-based CO2 goal consistent 
with BSER, the EPA is requiring that a state submitting a plan that is 
designed to meet a state mass-based CO2 goal for affected 
EGUs demonstrate that the plan addresses and mitigates the risk of 
potential emission leakage to new sources. The following

[[Page 64888]]

options provide sufficient demonstration that potential emission 
leakage has been addressed in a mass-based state plan: \914\

    \914\ The first two options need not be mutually exclusive; they 
can both be implemented as part of a mass-based plan.

    1. Regulate new non-affected fossil EGUs as a matter of state 
law in conjunction with emission standards for affected EGUs in a 
mass-based plan. If a state adopts an EPA-provided mass budget \915\ 
that includes the state mass-based CO2 goal for affected 
EGUs plus a new source CO2 emission complement, this 
option could be presumptively approvable.
---------------------------------------------------------------------------

    \915\ In Table 14, we have provided a mass budget for each state 
that includes the state mass-based CO2 goal and a 
projection for a new source CO2 emission complement.
---------------------------------------------------------------------------

    2. Use allocation methods in the state plan that counteract 
incentives to shift generation from affected EGUs to unaffected 
fossil-fired sources. If a state adopts allowance set-aside 
provisions exactly as they are outlined in the finalized model rule, 
this option could be presumptively approvable.
    3. Provide a demonstration in the state plan, supported by 
analysis, that emission leakage is unlikely to occur due to unique 
state characteristics or state plan design elements that address and 
mitigate the potential for emission leakage.

    In the first option, states may choose to regulate new non-affected 
fossil fuel-fired EGUs, as a matter of state law, in conjunction with 
federally enforceable emission standards for affected EGUs under a 
mass-based plan. This regulation of both new and existing sources, as 
part of a state plan approach, is conceptually analogous to a method 
that has been adopted by the mass-based systems adopted by California 
and the RGGI participating states. To address potential emission 
leakage under this option, the mass-based plan includes federally 
enforceable emission standards for affected EGUs, and the supporting 
documentation for the plan describes state-enforceable regulations for, 
at a minimum, all new grid-connected fossil fuel-fired EGUs that meet 
the applicability standards for EGUs subject to CAA section 111(b). 
States have the option of regulating a wider array of sources if they 
choose, as a matter of state law.
    For this option, a state must adopt, as a matter of state law, a 
mass CO2 emission budget of sufficient size to cover both 
affected EGUs under the existing source mass CO2 goal 
provided in this final rule, along with sufficient CO2 
emission tonnage to cover projected new sources. There are two pathways 
that states can use for adopting such an emission budget that applies 
to both affected EGUs and new sources. The EPA is providing a mass 
budget for each state that account for the state's mass CO2 
goal for affected EGUs and a complementary emission budget for new 
sources, referred to as the new source CO2 emission 
complement. States that both adopt the EPA-provided mass budget, based 
on the state mass-based CO2 goal for affected EGUs plus the 
new source CO2 emission complement, and regulate new sources 
under this emission budget as a matter of state law, in conjunction 
with federally enforceable emission standards for affected EGUs as part 
of the mass-based state plan may be able to submit a presumptively 
approvable plan. Such a plan would include federally enforceable 
emission standards for affected EGUs, and in the supporting 
documentation of the plan, would describe that the state is regulating 
new sources under a mass CO2 emission budget that is equal 
to or less than the state mass-based CO2 goal for affected 
EGUs plus the EPA-specified CO2 emission complement, in 
conjunction with the federally enforceable emission standards for 
affected EGUs. If the state plan is designed to achieve the EPA 
provided mass budget, plan performance will be evaluated based on 
whether the existing affected EGUs, regulated under the federally 
enforceable state plan, and new sources regulated as a matter of state 
law, together meet the total mass budget that includes the state's mass 
CO2 goal for affected EGUs and a complementary emission 
budget for new sources.
    EPA-specified mass CO2 emission budgets for each state, 
including the state's mass CO2 goal and a new source 
CO2 emission complement, are provided in Table 14 below. The 
derivation of the new source CO2 emission complements is 
explained in a TSD titled New Source Complements to Mass Goals, which 
is available in the docket.
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    \916\ The state mass CO2 goals can be found in Table 
13 in section VII.

                                 Table 14--New Source Complements to Mass Goals
----------------------------------------------------------------------------------------------------------------
                                                  New source complements  (short   Mass goals \916\ + new source
                                                           tons of CO2)             complements  (short tons of
                      State                      --------------------------------              CO2)
                                                                                 -------------------------------
                                                      Interim          Final          Interim          Final
----------------------------------------------------------------------------------------------------------------
Alabama.........................................         856,524         755,700      63,066,812      57,636,174
Arizona.........................................       1,424,998       2,209,446      34,486,994      32,380,197
Arkansas........................................         411,315         362,897      34,094,572      30,685,529
California......................................       2,846,529       4,413,516      53,873,603      52,823,635
Colorado........................................       1,239,916       1,922,478      34,627,799      31,822,874
Connecticut.....................................         135,410         119,470       7,373,274       7,060,993
Delaware........................................          78,842          69,561       5,141,711       4,781,386
Florida.........................................       1,753,276       1,546,891     114,738,005     106,641,595
Georgia.........................................         677,284         597,559      51,603,368      46,944,404
Idaho...........................................          94,266         146,158       1,644,407       1,639,013
Illinois........................................         818,349         722,018      75,619,224      67,199,174
Indiana.........................................         939,343         828,769      86,556,407      76,942,604
Iowa............................................         298,934         263,745      28,553,345      25,281,881
Kansas..........................................         260,683         229,997      25,120,015      22,220,822
Kentucky........................................         752,454         663,880      72,065,256      63,790,001
Louisiana.......................................         484,308         427,299      39,794,622      35,854,321
Maine...........................................          40,832          36,026       2,199,016       2,109,968
Maryland........................................         170,930         150,809      16,380,325      14,498,436
Massachusetts...................................         225,127         198,626      12,972,803      12,303,372
Michigan........................................         623,651         550,239      53,680,801      48,094,302
Minnesota.......................................         286,535         252,806      25,720,126      22,931,173

[[Page 64889]]

 
Mississippi.....................................         410,440         362,126      27,748,753      25,666,463
Missouri........................................         668,637         589,929      63,238,070      56,052,813
Montana.........................................         421,674         653,801      13,213,003      11,956,908
Nebraska........................................         216,149         190,706      20,877,665      18,463,444
Nevada..........................................         770,417       1,194,523      15,114,508      14,718,107
New Hampshire...................................          71,419          63,012       4,314,910       4,060,591
New Jersey......................................         313,526         276,619      17,739,906      16,876,364
New Mexico......................................         527,139         817,323      14,342,699      13,229,925
New York........................................         522,227         460,753      34,117,555      31,718,182
North Carolina..................................         692,091         610,623      57,678,116      51,876,856
North Dakota....................................         245,324         216,446      23,878,144      21,099,677
Ohio............................................         949,997         838,170      83,476,510      74,607,975
Oklahoma........................................         581,051         512,654      45,191,382      41,000,852
Oregon..........................................         453,663         703,399       9,096,826       8,822,053
Pennsylvania....................................       1,257,336       1,109,330     100,588,162      90,931,637
Rhode Island....................................          70,035          61,791       3,727,420       3,584,016
South Carolina..................................         344,885         304,287      29,314,508      26,303,255
South Dakota....................................          46,513          41,038       3,995,462       3,580,518
Tennessee.......................................         358,838         316,598      32,143,698      28,664,994
Texas...........................................       5,328,758       8,516,408     213,419,599     198,105,249
Utah............................................         981,947       1,522,500      27,548,327      25,300,693
Virginia........................................         450,039         397,063      30,030,110      27,830,174
Washington......................................         531,761         824,490      12,211,467      11,563,662
West Virginia...................................         602,940         531,966      58,686,029      51,857,307
Wisconsin.......................................         364,841         321,895      31,623,197      28,308,882
Wyoming.........................................       1,185,554       1,838,190      36,965,606      33,472,602
Lands of the Navajo Nation......................         809,562       1,255,217      25,367,354      22,955,804
Lands of the Uintah and Ouray Reservation.......          84,440         130,923       2,645,885       2,394,354
Lands of the Fort Mojave Tribe..................          37,162          57,619         648,264         646,138
                                                 ---------------------------------------------------------------
    Total.......................................      33,717,871      41,187,289   1,878,255,620   1,709,291,348
----------------------------------------------------------------------------------------------------------------

    States can, in the alternative, provide their own projections for a 
new source CO2 emission complement to their mass-based 
CO2 goals for affected EGUs. In the supporting documentation 
for the state plan submittal, the state must specify the new source 
budget, specify the analysis used to derive such a new source 
CO2 emission complement, and demonstrate that under the 
state plan affected EGUs in the state will meet the state mass-based 
CO2 goal for affected EGUs as a result of being regulated 
under the broader CO2 emission cap that applied to both 
affected EGUs and new sources. Such a projection should take into 
account the mass goal quantification method outlined in section VII.C 
and the CO2 Emission Performance Rate and Goal Computation 
TSD, including the fact that the mass-based state goals already 
incorporate a significant growth in generation from historical levels. 
The EPA will evaluate the approvability of the plan based on whether 
the federally enforceable emission standards for affected EGUs in 
conjunction with the state-enforceable regulatory requirements for new 
sources will result in the affected EGUs meeting the state mass-based 
CO2 goal. If, rather than designing a plan to achieve the 
EPA provided mass budget, the state uses its own projections for a new 
source complement and the plan is approved to meet this new source 
complement, plan performance will be evaluated based on whether the 
existing affected EGUs, regulated under the federally enforceable state 
plan, meet the state's mass CO2 goal for affected EGUs.
    The second demonstration option allows states to use allowance 
allocation methods that counteract incentives to shift generation from 
affected EGUs to unaffected fossil-fired sources. These allocation 
approaches must be specified in state plans as part of the provisions 
for state allocation of allowances required under a mass-based plan 
approach (see section VIII.J.2.a). The EPA is proposing the inclusion 
of two allocation strategies as part of the mass-based approach in the 
proposed federal plan and model rule: Updating output-based allocations 
and an allowance set-aside that targets RE. These options are described 
in more detail below. If a state were to adopt allowance set-aside 
provisions exactly as they are outlined in the finalized model rule, 
they could be considered presumptively approvable. The allowance 
allocation alternative for addressing leakage was chosen for the 
federal plan and model rule proposal because EPA does not have 
authority to extend regulation of and federal enforceability to new 
fossil fuel-fired sources under CAA section 111(d), and therefore we 
cannot include them under a federal mass-based plan approach.
    An updating output-based allocation method allocates a portion of 
the total CO2 emission budget to affected EGUs based, in 
part, on their level of electricity generation in a recent period or 
periods. Therefore, the total allocation to an EGU that is eligible to 
receive allowances from an output-based allowance set-aside is not 
fixed, but instead depends on its generation. Under this approach, each 
eligible affected EGU may receive a larger allowance allocation if it 
generates more. Therefore, eligible affected EGUs will have an 
incentive to generate more in order to receive more allowances, 
aligning their incentive to generate with new sources.
    This allocation method can be implemented through the creation of a

[[Page 64890]]

set-aside that reserves a subset of the total allowances available to 
sources, and distributes them based upon the criteria described above. 
Because the total number of allowances is limited, this allocation 
approach will not exceed the overall state mass-based CO2 
goal for affected EGUs. Instead, it merely modifies the distribution of 
allowances in a manner designed to mitigate potential emission leakage.
    The other allocation strategy included as part of the mass-based 
approach in the proposed federal plan and model rule is a set-aside of 
allowances to be allocated to providers of incremental RE. A set-aside 
can also be allocated to providers of demand-side EE, or to both RE and 
demand-side EE. The increased availability of RE generation can serve 
as another source of generation to satisfy electricity demand. 
Increased demand-side EE will reduce the demand that sources need to 
meet. Therefore, both RE and demand-side EE can serve to reduce the 
incentive that new sources have to generate, and therefore align their 
incentives with affected EGUs. Thus, increased RE and demand-side EE, 
supported by a dedicated set-aside, can also serve to address potential 
emission leakage.
    If a state is submitting a plan with an allocations approach that 
differs from that of the finalized model rule, the state should also 
provide a demonstration of how the specified allocation method will 
provide sufficient incentive to counteract potential emission leakage.
    Finally, a state can provide a demonstration that emission leakage 
is unlikely to occur, without implementing either of the two strategies 
above, as a result of unique factors, such as the presence of existing 
state policies addressing emission leakage or unique characteristics of 
the state and its power sector that will mitigate the potential for 
emission leakage. This demonstration must be supported by credible 
analysis. The EPA will determine if the state has provided a sufficient 
demonstration that potential emission leakage has already been 
adequately addressed, or if additional action is required as part of 
the state plan.
    Aside from the possible incentives for emission leakage addressed 
in this section, there may be other potential generation incentives 
across states and unit subcategories that could increase CO2 
emissions, particularly in an environment where various states are 
implementing a variety of state plan approaches in a shared grid 
region. Some examples of these incentives, particularly those that were 
specified by commenters, are discussed in section VIII.L. That section 
also describes how the EPA has structured this final rule to either 
prevent or minimize the potential for foregone emission reductions from 
differential incentives that may result from state plan implementation. 
These safeguards include placing restrictions on interstate trading 
when there could be a risk of such differential incentives. 
Additionally, the nature of the CO2 emission performance 
rates and state rate-based CO2 goals helps to minimize these 
potential effects, as does the MWh-accounting method for adjusting the 
CO2 emission rates of affected EGUs under rate-based plans.
    However, without a better understanding of the different mechanisms 
that states may ultimately choose to meet the emission guidelines, and 
how different requirements in different states may interact, the EPA 
cannot project every potential differential incentive that could lead 
to a loss of CO2 emission reductions. Therefore, once 
program implementation begins, the EPA will assess how emission 
performance across states may be affected by the interaction of 
different regulatory structures implemented through state plans. Based 
upon that evaluation, the EPA will determine whether there are 
potential concerns and what course of action may be appropriate to 
remedy such concerns.
    c. Emission budget trading programs that ensure achievement of a 
state CO2 goal.
    A mass-based emission budget trading program can be designed such 
that compliance by affected EGUs will achieve the state mass-based 
CO2 goal. Under this approach, a state plan would establish 
CO2 emission budgets for affected EGUs during the interim 
and final plan performance periods that are equal to or lower than the 
applicable state mass-based CO2 goals specified in section 
VII. A mass-based emission budget trading program can also be designed 
such that compliance by affected EGUs in conjunction with new fossil 
fuel-fired EGUs meeting applicable requirements under state law will 
achieve a mass-based CO2 goal plus new source CO2 
emission complement. Under this approach, a state would establish 
CO2 emission budgets under state law for affected EGUs plus 
new sources during the interim and final plan performance periods that 
are equal to or lower than the applicable state mass-based 
CO2 emission goal plus the new source CO2 
emission complement specified in Table 14 in section VIII.J.2.b above, 
and describe such emission budgets in the supporting documentation of 
the state plan. Under either program, compliance periods for affected 
EGUs (or for affected EGUs plus new fossil fuel-fired EGUs meeting 
applicable requirements under state law) would also be aligned with the 
interim and final plan performance periods. This approach would limit 
total CO2 emissions from affected EGUs (or total 
CO2 emissions from affected EGUs and new fossil fuel-fired 
EGUs meeting applicable requirements under state law) during the 
interim and final plan performance periods to an amount equal to or 
less than the state's mass-based CO2 goal (or mass-based 
CO2 goal plus new source CO2 emission 
complement).
    Under this approach, compliance by affected EGUs with the mass-
based emission standards in a plan would ensure that the state achieves 
its mass-based CO2 goal for affected EGUs (or mass-based 
CO2 goal plus new source CO2 emission 
complement). No further demonstration would be necessary by the state 
to demonstrate that its plan would achieve the state's mass-based 
CO2 goal (or mass-based CO2 goal plus new source 
CO2 emission complement).
    For this type of plan, where the emission budget is equal to or 
less than the state mass CO2 goal (or mass-based 
CO2 goal plus new source CO2 emission 
complement),\917\ the EPA would assess achievement of the state goal 
based on compliance by affected EGUs with the mass-based emission 
standards, rather than reported CO2 emissions by affected 
EGUs during the interim plan performance periods and final plan 
performance periods. This approach would allow for allowance banking 
between performance periods, including the interim and final 
performance periods outlined in this final rule.
---------------------------------------------------------------------------

    \917\ As specified for the interim plan performance period 
(including specified levels in interim steps 1 through 3) and the 
final two-year plan performance periods.
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    Banking provisions have been used extensively in rate-based 
environmental programs and mass-based emission budget trading programs. 
This is because banking reduces the cost of attaining the requirements 
of the regulation. The EPA has determined that the same rationale and 
outcomes apply under a CO2 emission rate approach, in that 
allowing banking will reduce compliance costs. Banking encourages 
additional emission reductions in the near-term if economic to meet a 
long-term emission rate constraint, which is beneficial due to social 
preferences for environmental improvements sooner rather than later. It 
is also beneficial when addressing pollutants that are long-lived in 
the atmosphere, such as CO2, and where increasing 
atmospheric concentration of

[[Page 64891]]

the pollutant leads to increasing adverse atmospheric impacts.
    Banking also provides long-term economic signals to affected 
emission sources and other market participants where actions taken 
today will have economic value in helping meet tighter emission 
constraints in the future, provided those emission sources expect that 
the banked ERCs or emission allowances may be used for compliance in 
the future. Linking short-term and long-term economic incentives, which 
allows owners or operators of affected EGUs and other market 
participants to assess both short-term and long-term incentives when 
making decisions about compliance approaches or emission reduction 
investments, reduces long-term compliance costs for affected EGUs and 
ratepayer impacts. In addition, the increased temporal flexibility 
provided by banking would further help address potential electric 
reliability concerns, as banked ERCs can be used to meet emission 
standard requirements for an affected EGU.
    d. Addressing emission budget trading programs with broader source 
coverage and other flexibility features.
    As described in section VIII.C above, under the emission standards 
plan type, a mass-based emission budget trading program with broader 
source coverage and other flexibility features may be designed such 
that compliance by affected EGUs (or compliance by affected EGUs plus 
new fossil fuel-fired EGUs meeting applicable requirements under state 
law) would assure achievement of the applicable state mass-based 
CO2 goal (or mass-based CO2 goal plus new source 
CO2 emission complement).\918\
---------------------------------------------------------------------------

    \918\ Section VIII.J.2.a describes how state plan submittals 
must include as requirements, or describe as part of supporting 
documentation, relevant aspects of such emission budget trading 
programs.
---------------------------------------------------------------------------

    However, emission budget trading programs, including those 
currently implemented by California and the RGGI participating states, 
include a number of different design elements that functionally expand 
the emission budget under certain circumstances. If a state chose, it 
could apply such mass-based emission standards, in the form of an 
emission budget trading program that differs in design from that 
outlined in section VIII.J.2.c above. These types of emission budget 
trading programs must be submitted as a part of a state measures plan 
type. Where an emission budget trading program addresses affected EGUs 
and other fossil fuel-fired EGUs, the requirements that must be 
included in the state plan are the federally enforceable emission 
standards in the state plan that apply specifically to affected EGUs, 
and the requirements that specifically require affected EGUs to 
participate in and comply with the requirements of the emission budget 
trading program. This includes the requirement for an affected EGU to 
surrender emission allowances equal to reported CO2 
emissions, and meet monitoring and reporting requirements for 
CO2 emissions, among other requirements. These requirements 
may be submitted as part of the federally enforceable state plan 
through mechanisms with the appropriate legal authority and effect, 
such as state regulations, relevant Title V permit requirements for 
affected EGUs, and other possible instruments that impose these 
requirements specifically with respect to affected EGUs.\919\ Under 
this approach, the full set of regulations establishing the emission 
budget trading program that applies to affected EGUs and other fossil 
fuel-fired EGUs and other emission sources (if relevant) must be 
described as supporting documentation in the state plan submittal. This 
structure is appropriate to ensure that states with an emission budget 
trading program that addresses both affected EGUs and other fossil 
fuel-fired EGUs do not inappropriately submit requirements regarding 
entities other than affected EGUs for inclusion in the federally 
enforceable state plan.
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    \919\ This approach for establishing federally enforceable 
emission standards based on requirements for affected EGUs subject 
to a broader emission budget trading program that also covers non-
affected emission sources is addressed in section VIII.J.2.d. above.
---------------------------------------------------------------------------

    Such state programs could include a number of different design 
elements. This includes broader program scope, where a program includes 
other emission sources beyond affected EGUs subject to CAA section 
111(d) and new fossil fuel-fired EGUs, such as industrial sources. 
Programs might also include design elements that make allowances 
available in addition to the established emission budget. This includes 
project-based offset allowances or credits from GHG emission reduction 
projects outside the covered sector and cost containment reserve 
provisions that make additional allowances available at specified 
allowance prices.\920\
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    \920\ For example, both the California and RGGI programs allow 
for the use of allowances awarded to GHG offset projects to be used 
to meet a specified portion of an affected emission source's 
compliance obligation. The RGGI program contains a cost containment 
allowance reserve that makes available additional allowances up to a 
certain amount, at specified allowance price triggers.
---------------------------------------------------------------------------

    In the case where an emission budget trading program contains 
elements that functionally expand the emission budget in certain 
circumstances, compliance by affected EGUs with the mass-based emission 
standards would not necessarily ensure that CO2 emissions 
from affected EGUs do not exceed the state's mass-based CO2 
goal (or mass-based CO2 goal plus new source CO2 
emission complement). However, states could modify such programs to 
remove flexibility mechanisms that functionally expand the emission 
budget, such as out-of-sector offsets and certain cost containment 
reserve mechanisms, and submit the program under an emission standards 
plan type.
    Where a state chooses to retain such flexibility mechanisms as part 
of an emission budget trading program, the program may only be 
implemented as part of a state measures plan type because these state 
flexibility mechanisms would not assure CO2 emissions from 
affected EGUs do not exceed the state's mass-based CO2 goal 
(or mass-based CO2 goal plus new source CO2 
emission complement). A description of the state measures plan type and 
related requirements is provided in section VIII.C.3.
    Under this type of approach, the state would be required to include 
a demonstration,\921\ in its state plan submittal, of how its state 
measures, in conjunction with any emission standards on affected EGUs, 
would achieve the state mass-based CO2 goal (or mass-based 
CO2 goal plus new source CO2 emission 
complement). This demonstration would include a projection of the total 
CO2 emissions from the fleet of affected EGUs that would 
occur as a result of compliance with the emission standards in the 
plan. Section VIII.D.2 discusses how such demonstrations could address 
design elements of emission budget trading programs with broader scope 
and additional compliance flexibility mechanisms, such as those 
included in the California and RGGI programs. Once the plan is 
implemented, if the mass-based CO2 goal is not achieved 
during a plan performance period, the backstop federally enforceable 
emission standards included in the state plan that apply to affected 
EGUs would be implemented, as described in section VIII.C.3.b.\922\
---------------------------------------------------------------------------

    \921\ A demonstration of how a plan will achieve a state's rate-
based or mass-based CO2 goal (or mass-based 
CO2 goal plus new source CO2 emission 
complement) is one of the required plan components, as described in 
section VIII.D.2.
    \922\ Achievement of the state mass-based CO2 goal 
would be determined based solely on stack CO2 emissions 
from affected EGUs. Where a state program includes the ability of an 
affected emission source to use GHG offsets to meet a portion of its 
allowance compliance obligation, no ``credit'' is applied to 
reported CO2 emissions by the affected EGU. The use of 
offset allowances or credits in such programs merely allows an 
affected EGU to emit a ton of CO2 in the amount of 
submitted offset allowances or credits. In all cases, there is no 
adjustment applied to reported stack emissions of CO2 
from an affected EGU when determining compliance with its emission 
limit.

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[[Page 64892]]

    e. Considerations for mass-based emission budget trading programs.
    The EPA notes that while an emission budget trading program 
included in an emission standards plan must be designed to achieve a 
state mass-based CO2 goal (or mass-based CO2 goal 
plus new source CO2 emission complement), states have wide 
discretion in the design of such programs, provided the emission 
standards included in the plan are quantifiable, verifiable, 
enforceable, non-duplicative, and permanent.
    (1) Allowance allocation. A key example is state discretion in the 
CO2 allowance allocation methods included in the 
program.\923\ This includes the methods used to distribute 
CO2 allowances and the parties to which allowances are 
distributed. For example, if a state chose, it could include 
CO2 allowance allocation provisions that provide incentives 
for certain types of complementary activities, such as RE generation, 
that help achieve the overall CO2 emission limit for 
affected EGUs established under the program. In addition, a state could 
use its allocation provisions to encourage investments in RE and 
demand-side EE in low-income communities. States could also use 
CO2 allowance allocation provisions to provide incentives 
for early action, such as RE generation or demand-side EE savings that 
occur prior to the beginning of the interim plan performance period in 
2022. For example, a state could include CO2 allowance 
allocation provisions where CO2 allowances are distributed 
to RE generators based on MWh of RE generation that occurs prior to 
2022. Such provisions might be addressed through a finite set-aside of 
CO2 allowances that are available for allocation under these 
provisions. This set-aside could be additional to a set-aside created 
by the state for the CEIP discussed in section VIII.B.2.
---------------------------------------------------------------------------

    \923\ Allowance allocation refers to the methods used to 
distribute CO2 allowances to the owners or operators of 
affected EGUs and/or other market participants.
---------------------------------------------------------------------------

    (2) Facility-level compliance. If a state chose, it could evaluate 
compliance (i.e., allowance true-up) under its emission budget trading 
program at the facility level, rather than at the individual unit 
level. The EPA has adopted facility-level compliance in the emission 
budget-trading programs it administers, including the Acid Rain Program 
(70 FR 25162), Clean Air Interstate Rule (70 FR 25162), and Cross-State 
Air Pollution Rule (76 FR 48208). Under this approach, states would 
still track reported unit-level CO2 emissions--while 
evaluating compliance at the facility level--allowing them to track 
increases and decreases of CO2 emissions at individual EGUs.
    3. Multi-state coordination: Mass-based emission trading programs.
    An individual state may provide for the use of CO2 
allowances issued by another state(s) for compliance with the mass-
based emission standards in its plan. This type of state plan would 
include requirements that enable affected EGUs to use allowances issued 
in other states for compliance under the state's emission budget 
trading program. This type of state plan must also indicate how 
CO2 allowances will be tracked from issuance through use for 
compliance, through either a joint tracking system, interoperable 
tracking systems, or use of an EPA-administered tracking system.\924\
---------------------------------------------------------------------------

    \924\ The emission standards in each individual state plan must 
include requirements that address the issuance of CO2 
allowances and tracking of CO2 allowances from issuance 
through use for compliance. The description here addresses how those 
requirements will be implemented through the use of a joint tracking 
system, interoperable tracking systems, or an EPA-administered 
tracking system.
---------------------------------------------------------------------------

    Two different implementation approaches could be used to create 
such links. A state could submit a ``ready-for-interstate-trading'' 
plan using an EPA-approved tracking system, but the plan would not 
identify links with other states. A state could also submit a plan with 
specified bilateral or multilateral links that explicitly identify 
partner states.
    Interstate allowance linkages would not affect the approvability of 
each state's individual plan. However, different considerations apply 
for the approvability of an individual plan with such links, based on 
whether the emission budget trading program in the plan applies only to 
affected EGUs or includes other emission sources, and if the plan is 
designed to meet a state mass-based CO2 goal for affected 
EGUs only or to meet a mass-based CO2 goal plus a new source 
CO2 emission complement).
    Under the first ``ready-for-interstate-trading'' implementation 
approach, a state would indicate in its state plan that its emission 
budget trading program will be administered using an EPA-approved (or 
EPA-administered) emission and allowance tracking system.\925\ State 
plans using a specified EPA-approved tracking system would be deemed by 
the EPA as ready for interstate linkage upon approval of the state 
plan. No additional EPA approval would be necessary for states to link 
their emission budget trading programs, and affected EGUs in those 
states could engage in interstate trading subsequent to EPA plan 
approval.
---------------------------------------------------------------------------

    \925\ The EPA would designate tracking systems that it has 
determined adequately address the integrity elements necessary for 
the issuance and tracking of emission allowances. Under this 
approach, a state could include in its plan such a designated 
tracking system, which has already been reviewed by the EPA.
---------------------------------------------------------------------------

    A state would indicate in its plan submittal that its emission 
budget trading system will use a specified EPA-approved tracking 
system. The state would also indicate in the regulatory provisions for 
its emission budget trading program that it would recognize as usable 
for compliance any emission allowance issued by any other state with an 
EPA-approved state plan that also uses the specified EPA-approved 
tracking system.
    States could also adopt such a collaborative emission trading 
approach over time (through appropriate state plan revisions if the 
plan is not already structured as ready-for-interstate-trading), 
without requiring all of the original participating states to revise 
their EPA-approved plans.
    Under the second implementation approach, a state could specify the 
other states from which it would recognize issued emission allowances 
as usable for compliance with its emission budget trading program. The 
state would indicate in the regulatory provisions for its emission 
budget trading program that emission allowances issued in other 
identified partner states may be used by affected EGUs for compliance. 
Such plans must indicate how allowances will be tracked from issuance 
through use for compliance, through either a joint tracking system, 
interoperable tracking systems, or EPA-administered tracking system. 
The EPA would assess the design and functionality of this tracking 
system(s) when reviewing individual submitted state plans.
    Under this approach, states could also join such a collaborative 
emission trading approach over time. However, all participating states 
would need to revise their EPA-approved plans. If the expanded linkage 
is among previously approved plans with mass-based emission standards, 
approval of the plan revision would be limited to assessing the 
functionality of the shared tracking system or interoperable tracking 
systems

[[Page 64893]]

in order to maintain the integrity of the linked programs.\926\
---------------------------------------------------------------------------

    \926\ Depending on the specific regulatory provisions in the 
emission standards in their approved state plans, participating 
states may also need to revise their implementing regulations (and 
by extension their state plans) to accept CO2 emission 
allowances issued by new partner states as usable for compliance 
with their mass-based emission standards.
---------------------------------------------------------------------------

    a. Considerations for linked emission budget trading programs.
    For individually submitted plans, interstate emission allowance 
linkages would not affect the approvability of each state's plan. 
However, approvability of an individual linked plan would differ based 
on the structure of the emission budget trading program included in the 
plan. These differences for plan approvability address distinctions 
among programs that include only affected EGUs and programs that cover 
a broader set of emission sources, as well as if the plan is designed 
to meet a state mass-based CO2 goal for affected EGUs only 
or to meet a mass-based CO2 goal plus a new source 
CO2 emission complement. Differences in approval criteria 
are necessary to ensure that each individual state plan demonstrates it 
will achieve a state's mass-based CO2 emission goal for 
affected EGUs (or mass-based CO2 goal plus new source 
CO2 emission complement). The accounting applied to 
individual plans to assess whether a state achieves its mass-based 
CO2 goal (or mass-based CO2 goal plus new source 
CO2 emission complement) will also differ, based on whether 
an emission budget trading program includes only affected EGUs (or 
affected EGUs and applicable new fossil fuel-fired EGUs) or a broader 
set of emission sources. These considerations are addressed below, for 
both types of emission budget trading programs.
    (1) Links among emission budget trading programs that only include 
affected EGUs or affected EGUs and applicable new fossil fuel-fired 
EGUs. Where the emission budget trading programs in each plan apply 
only to affected EGUs subject to the final rule (or emission budget 
trading programs that apply to affected EGUs under the state plan and 
applicable new fossil fuel-fired EGUs under state law), and include 
compliance timeframes for affected EGUs that align with the interim and 
final plan performance periods, both plans would functionally be 
meeting an aggregated multi-state mass-based goal (or aggregated mass-
based CO2 goal plus new source CO2 emission 
complement), but without formally aggregating the goal (or aggregated 
mass-based CO2 goal plus new source CO2 emission 
complement). CO2 emissions from affected EGUs in both states 
could not exceed the total combined CO2 emission budgets 
under the emission standards in the two states. A net ``import'' of 
CO2 allowances from one state would mean that allowable 
CO2 emissions in the other net ``exporting'' state are less 
than that state's established emission budget. On a multi-state basis, 
CO2 emissions from affected EGUs could not exceed the sum of 
the states' emission budgets.
    Under this approach, if the emission budget for the mass-based 
emission standard in each plan is equal to or lower than the state's 
mass-based CO2 goal (or aggregated mass-based CO2 
goal plus new source CO2 emission complement, if 
applicable), compliance by affected EGUs with the mass emission 
standard in a state \927\ would ensure that cumulatively the mass 
CO2 goals (or mass-based CO2 goals plus new 
source CO2 emission complements) of the linked states are 
achieved. As a result, achievement of an individual state's mass 
CO2 goal (or mass-based CO2 goal plus new source 
CO2 emission complement) would be assessed by the EPA based 
on compliance by affected EGUs with the mass-based emission standards 
in the state plan, rather than reported CO2 emissions by 
affected EGUs in the state.\928\
---------------------------------------------------------------------------

    \927\ Compliance by an affected EGU with the emission standard 
is demonstrated based on surrender to the state of a number of 
CO2 allowances equal to its reported CO2 
emissions.
    \928\ This approach is warranted because under such linked 
programs, CO2 emissions from affected EGUs in one state 
that exceed a state's mass CO2 goal (or mass-based 
CO2 goal plus new source CO2 emission 
complement) would be accompanied by CO2 emissions from 
affected EGUs in another linked state that are below that state's 
mass CO2 goal (or mass-based CO2 goal plus new 
source CO2 emission complement).
---------------------------------------------------------------------------

    The same accounting approach will apply for such plans in all 
cases, even if the state is linked to another state emission budget 
trading program that includes a broader set of emission sources (e.g., 
sources beyond affected EGUs, or beyond affected EGUs plus applicable 
new fossil fuel-fired EGUs), as described below. In all cases, where a 
state plan includes an emission budget trading program that applies 
only to affected EGUs (or beyond affected EGUs plus applicable new 
fossil fuel-fired EGUs), and includes compliance timeframes that align 
with plan performance periods, achievement of a state mass 
CO2 goal (or mass-based CO2 goal plus new source 
CO2 emission complement) will be assessed by the EPA based 
on whether affected EGUs comply with the mass-based emission standard, 
rather than reported CO2 emissions from affected EGUs.
    (2) Links with emission budget trading programs that include a 
broader set of emission sources. State plans may involve emission 
budget trading programs that include affected EGUs, applicable new 
fossil fuel-fired EGUs if a plan includes a new source CO2 
emission complement, and other non-affected emission sources.\929\
---------------------------------------------------------------------------

    \929\ This may apply under both an emission standards plan and a 
state measures plan. Section VIII.J.2.a describes how state plan 
submissions must include as requirements, or describe as part of 
supporting documentation, relevant aspects of such emission budget 
trading programs.
---------------------------------------------------------------------------

    Generally, such plans must demonstrate that the mass-based 
CO2 goal for affected EGUs (or mass-based CO2 
goal plus new source CO2 emission complement) in a state 
will be achieved, as a result of implementation of the emission budget 
trading program.\930\ Where a program includes other non-affected 
emission sources (i.e., non-affected emission sources that are not 
subject to a new source CO2 emission complement) and is 
linked with other programs,\931\ the state plan submittal must include 
a demonstration that the mass-based CO2 goal (or mass-based 
CO2 goal plus new source CO2 emission complement) 
will be achieved, considering the emission allowance links with other 
programs. The EPA, in determining the approvability of each state's 
plan under this approach, would evaluate the linkages between plans. 
Specifically, the EPA would evaluate whether the linkages would enable 
the affected EGUs (or affected EGUs in conjunction with applicable new 
fossil fuel-fired EGUs) in each participating state to meet the state's 
applicable mass-based CO2 goal (or mass-based CO2 
goal plus new source CO2 emission complement).
---------------------------------------------------------------------------

    \930\ Under a program that applies to affected EGUs and other 
emission sources, compliance by affected EGUs with the emission 
standard--a requirement to surrender emission allowances equal to 
reported emissions--will not assure that a state's CO2 
mass goal (or mass-based CO2 goal plus new source 
CO2 emission complement) is achieved. As a result, a 
further demonstration is required in the plan that compliance by 
affected EGUs with the program will result in CO2 
emissions from affected EGUs that are at or below a state's 
CO2 mass goal (or mass-based CO2 goal plus new 
source CO2 emission complement).
    \931\ Section VIII.J.2.a describes how state plan submittals 
must include as requirements, or describe as part of supporting 
documentation, relevant aspects of such emission budget trading 
programs.
---------------------------------------------------------------------------

    During plan implementation, the EPA would assess whether the 
affected EGUs in a state achieved the state's mass-based CO2 
goal (or mass-based CO2 goal plus new source CO2 
emission complement) as follows. Reported CO2

[[Page 64894]]

emissions from affected EGUs under such plans must be at or below a 
state's mass-based CO2 emission goal (or mass-based 
CO2 goal plus new source CO2 emission complement) 
during an identified plan performance period, with the following state 
accounting adjustments for net ``import'' and net ``export'' of 
---------------------------------------------------------------------------
CO2 allowances:

     Net ``imports'' of CO2 allowances: Reported 
CO2 emissions from affected EGUs in a state may exceed 
the state CO2 mass goal (or mass-based CO2 
goal plus new source CO2 emission complement) during an 
identified plan performance period in the amount of an adjustment 
for the net ``imported'' CO2 allowances during the plan 
performance period. The adjustment represents the CO2 
emissions (in tons) equal to the number of net ``imported'' 
CO2 allowances. Under this adjustment, such allowances 
must be issued by a state with an emission budget trading program 
that only applies to affected EGUs (or affected EGUs plus applicable 
new fossil fuel-fired EGUs). Net ``imports'' of allowances are 
determined through review of tracking system compliance accounts.
     Net ``exports'' of CO2 allowances: Reported 
CO2 emissions from affected EGUs in a state during an 
identified plan performance period must be equal to or less than the 
CO2 mass goal (or mass-based CO2 goal plus new 
source CO2 emission complement) minus an adjustment for 
the ``exported'' CO2 allowances during the plan 
performance period. The adjustment represents CO2 
emissions (in tons) equal to the number of net ``exported'' 
CO2 allowances. Net ``exports'' of allowances are 
determined through review of tracking system compliance accounts.

    Where CO2 emissions from affected EGUs exceed these 
levels (based on reported CO2 emissions with applied plus or 
minus adjustments for net CO2 allowance ``imports'' or 
``exports'') over the 8-year interim period or during any final plan 
reporting period, or by 10 percent or more during the interim step 1 or 
step 2 periods, a state would be considered to, in the case of the 
interim and final periods, not have met its CO2 mass goal 
during an identified plan performance period, and in the case of the 
interim step periods, to not be on course to meet the final goal. As a 
result, under a state measures state plan, implementation of the 
backstop federally enforceable emission standards for affected EGUs in 
the state plan would be triggered.
    A net transfer of CO2 allowances during a plan 
performance period represents the net number of CO2 
allowances (issued by a respective state) that are transferred from the 
compliance accounts of affected EGUs in that state to the compliance 
accounts of affected EGUs in another state.\932\ This net transfer is 
determined based on compliance account holdings at the end of the plan 
performance period.\933\ For example, assume two states, State A and 
State B, with emission budgets of 1,000 tons of CO2. Each 
state issues 1,000 CO2 allowances. At the end of a plan 
performance period, affected EGUs in State A collectively hold 500 
CO2 allowances in their compliance accounts that were issued 
by State A. Affected EGUs in State B collectively hold in their 
compliance accounts 500 CO2 allowances issued by State A and 
1,000 CO2 allowances issued by State B. In this simplified 
example, a net transfer of 500 CO2 allowances has occurred 
between State A and State B. State A has ``exported'' 500 
CO2 allowances to State B, while State B has ``imported'' 
500 CO2 allowances from state A.
---------------------------------------------------------------------------

    \932\ A net transfer metric is applied as of the end of the plan 
performance period. This net accounting as of a specified date is 
necessary because multiple individual allowance transfers may occur 
among accounts during a plan performance period, representing normal 
trading activity. In addition, net transfers are based on compliance 
account holdings, because these represent the CO2 
allowances directly available at that point in time for use by an 
affected EGU for complying with its emission limit. Emission budget 
trading programs typically allow non-affected entities to hold 
allowances in general accounts. These parties are free to hold and 
trade CO2 allowances, providing market liquidity. General 
account holdings are not assessed as part of a periodic state net 
transfer accounting, as these allowances may subsequently be 
transferred to other accounts in multiple states and do not 
represent allowances currently held by an affected EGU that can be 
used for complying with its emission limit.
    \933\ Compliance account holdings, as used here, refer to the 
number of CO2 allowances surrendered for compliance 
during a plan performance period, as well as any remaining 
CO2 allowances held in a compliance account as of the end 
of a plan performance period.
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K. Additional Considerations and Requirements for Rate-Based State 
Plans

    This section discusses considerations and requirements for rate-
based state plans. This section discusses eligibility, accounting, and 
quantification and verification requirements (EM&V) for the use of 
CO2 emission reduction measures that provide substitute 
generation for affected EGUs or avoid the need for generation from 
affected EGUs in rate-based state plans. These measures may be used to 
adjust the CO2 emission rate of an affected EGU under a 
rate-based state plan. This adjustment may occur when an affected EGU 
is demonstrating compliance with a rate-based emission standard, or 
when a state is demonstrating achievement of the CO2 
emission performance rates or applicable rate-based state 
CO2 emission goal in the emission guidelines. This section 
also discusses requirements for state plans that include rate-based 
emission trading programs, including approaches and requirements for 
coordination among such programs where states retain individual state 
rate-based CO2 emission goals.
1. Adjustments to CO2 Emission Rates in Rate-Based State 
Plans
    Section VIII.K.1.a below describes the basic accounting method for 
adjusting a CO2 emission rate, as well as eligibility 
requirements for measures that may be used for adjusting a 
CO2 emission rate. Section VIII.K.1.b addresses measures 
that may not be used to adjust the CO2 emission rate of an 
affected EGU in a state plan, and explains the basis for this 
exclusion. Section VIII.K.1.c addresses measures that reduce 
CO2 emissions outside the electric power sector. Such 
measures may not be counted under either a rate-based or mass-based 
state plan.
    a. Measures taken to adjust the CO2 emission rate of an affected 
EGU. This section describes how measures that substitute for generation 
from affected EGUs or avoid the need for generation from affected EGUs 
may be used in a state plan to adjust the CO2 emission rate 
of an affected EGU. This section discusses the required accounting 
method for adjusting a CO2 emission rate, as well as general 
eligibility requirements that apply to different categories of measures 
that may be used to adjust a CO2 emission rate. Where 
relevant, this section also discusses additional specific accounting 
methods and other relevant requirements that apply to different 
categories of measures.
    A CO2 emission rate adjustment may be applied in 
different rate-based state plan contexts. For example, in a rate-based 
emission trading program, adjustments may be applied through the use of 
ERCs.\934\ Regardless of the type of plan in which an adjustment is 
applied, the same basic accounting and general eligibility requirements 
described in this section will apply.
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    \934\ ERCs may be issued for the measures presented in this 
section, as well as to affected EGUs that emit at a CO2 
emission rate below their assigned emission rate limit. ERC issuance 
and trading is discussed in detail in section VIII.K.2. That section 
addresses the accounting method for ERC issuance to affected EGUs 
that perform below their assigned CO2 emission rate.
---------------------------------------------------------------------------

    As discussed in this section, a wide range of actions may be taken 
to adjust the reported CO2 emission rate of an affected EGU 
in order to meet a rate-based emission standard and/or demonstrate 
achievement of a state CO2 rate-based emissions goal. All of 
the measures described in this section will substitute for generation 
from affected EGUs or avoid the need for generation

[[Page 64895]]

from affected EGUs, thereby reducing CO2 emissions. This 
includes incremental NGCC and RE measures included in the EPA's 
determination of the BSER, as well as other measures that were not 
included in the determination of the BSER, such as other RE resources, 
demand-side EE, CHP, WHP, electricity transmission and distribution 
improvements, nuclear energy, and international RE imports connected to 
the grid in the contiguous U.S., as discussed elsewhere in this 
preamble.
    The EPA believes that the broad categories of measures listed in 
this section address the wide range of actions that are available to 
reduce CO2 emissions from affected EGUs under a rate-based 
state plan. However, the actions that a state could include in a rate-
based state plan are not necessarily limited to those described in this 
section. Other specific actions not listed here may be incorporated in 
a state plan, provided they meet the general eligibility requirements 
listed in this section, as well as the other relevant requirements in 
the emission guidelines.\935\ Nor are states required to include in 
their plans all of the actions that are described in this section.
---------------------------------------------------------------------------

    \935\ These requirements are discussed in section VIII.D.
---------------------------------------------------------------------------

    This section discusses the basic accounting method for adjusting 
the reported CO2 emission rate of an affected EGU, through 
the use of measures that substitute for or avoid generation from 
affected EGUs. That method is based on adding MWh from such measures to 
the denominator of an affected EGU's reported CO2 emission 
rate (lb CO2/MWh). Those additional MWh are based on 
quantified and verified electricity generation or electricity savings 
from eligible measures, and in the case of an affected EGU's compliance 
with its emission standard, are reflected in ERCs. This section also 
addresses eligibility requirements for resources that are used to 
adjust an affected EGU's CO2 emission rate.
    (1) General accounting approach for adjusting a CO2 emission rate.
    In this final rule, the reported CO2 emission rate of an 
affected EGU may be adjusted based on quantified and verified MWh from 
qualifying zero-emitting and low-emitting resources, as described in 
sections VIII.K.1.a.(2)-(10) below. These MWh are added to the 
denominator of an affected EGU's reported CO2 emission rate, 
resulting in a lower adjusted CO2 emission rate.
    The measures described in these sections reduce mass CO2 
emissions from affected EGUs by substituting zero- or low-emitting 
generation for generation from affected EGUs, or by avoiding the need 
for generation altogether (in the case of resources that lower 
electricity demand through improved demand-side EE and DSM). In both of 
these cases, generation from an affected EGU is replaced, through 
substitute generation or a reduction in electricity demand. To the 
extent that qualifying zero-emitting and low-emitting resources result 
in reduced generation and CO2 emissions from an individual 
affected EGU, those emission impacts are reflected in lower reported 
CO2 emissions and a reduction in MWh generation from the 
affected EGU. However, while there will be a reduction in 
CO2 emissions at the affected EGU, the fact that both 
CO2 emissions and MWh generation are reduced means that such 
impacts do not alter the reported CO2 emission rate of the 
affected EGU. As a result, the MWh of replacement generation must be 
added to the denominator of the reported CO2 emission rate 
in order to represent those impacts in the form of an adjusted 
CO2 emission rate. In this manner, adding MWh from these 
resources to the denominator of an affected EGU's CO2 
emission rate allows mass CO2 emission reductions from these 
measures to be fully reflected in an adjusted CO2 emission 
rate.
    The following provides a simple calculation example of how MWh of 
replacement generation added to the denominator of an affected EGU's 
reported CO2 emission rate results in a lower adjusted 
CO2 emission rate. Assume an affected EGU with 
CO2 emissions of 200,000 lb and electric generation of 100 
MWh during a reporting period. The affected EGU's reported 
CO2 emission rate is 2,000 lb/MWh (200,000 lb 
CO2/100 MWh = 2,000 lb/MWh). When complying with its rate-
based emission limit, the affected EGU submits 10 ERCs, representing 10 
MWh of replacement generation.\936\ Adding 10 MWh of replacement 
generation to the reported MWh generation of the affected EGU results 
in an adjusted CO2 emission rate of 1,818 lb CO2/
MWh (200,000 lb CO2/110 MWh = 1,818 lb CO2/MWh).
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    \936\ Requirements for the issuance of ERCs and a further 
discussion of how ERCs are used in compliance with rate-based 
emission limits are addressed in section VIII.K.2.
---------------------------------------------------------------------------

    In the case of rate-based CO2 emission standards, an 
affected EGU demonstrates compliance with the emission standards if the 
affected EGU's adjusted CO2 emission rate calculated in the 
aforementioned manner is less than or equal to the applicable 
CO2 emission standard rate.\937\ The CO2 emission 
performance rates or rate-based CO2 goal in the emission 
guidelines are met if the adjusted CO2 emission rate of 
affected EGUs in a state is at or below the specified CO2 
emission rate in a state plan that applies for an identified plan 
performance period.
---------------------------------------------------------------------------

    \937\ Any ERCs used to adjust a CO2 emission rate 
must meet requirements in the emission guidelines.
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    Numerous commenters requested that the EPA ensure consistency 
between goal-setting calculations and the methodology used to 
demonstrate achievement of a CO2 emission rate under a state 
plan. This approach for adjusting a CO2 emission rate 
corresponds with how RE, one of the components of the BSER that 
involves adjustment of a CO2 emission rate, is represented 
in the CO2 emission performance rates in the emission 
guidelines. Specifically, in the calculation of final CO2 
emission performance rates, the MWhs of RE are reflected in two 
adjustments of the rate: A reduction of CO2 emissions from 
affected EGUs in the numerator and a one-to-one replacement of affected 
EGU generation in the denominator, where it is assumed that replaced 
generation from an affected EGU is subtracted from the denominator and 
the same number of zero-emitting MWh are added.\938\
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    \938\ For a detailed discussion of this method, see Section 
VI.C.3. Form of the Performance Rates, in the Equation section.
---------------------------------------------------------------------------

    When demonstrating achievement of a CO2 emission 
performance rate, the reported CO2 emissions already reflect 
the actual emission reductions from the deployment of qualifying zero-
emitting and low-emitting resources across the regional grid; a further 
adjustment of CO2 emissions would double count 
CO2 emissions impacts across the grid. Consistent with the 
EPA's calculation of the CO2 emission performance rates and 
state rate-based CO2 goals in the emission guidelines, the 
zero-emitting MWhs (from substitute generation or a reduction in 
electricity demand) must still be added to the denominator of a 
reported CO2 emission rate to calculate an adjusted 
CO2 emission rate that appropriately reflects the replaced 
generation. Thus, the resultant rate, where the numerator reflects 
CO2 emission reductions from qualifying measures, and the 
denominator reflects replaced generation, is consistent with the goal-
setting calculation.
    Several commenters suggested that the EPA consider the regional 
nature of the electricity grid and how RE and demand-side EE impacts 
generation and CO2 emissions across the grid when accounting 
for the impacts of RE and

[[Page 64896]]

demand-side EE measures in a rate-based plan approach. This MWh 
accounting structure corresponds with the regional treatment of RE 
resources in the BSER that provide substitute generation in the EPA-
calculated CO2 emission performance rates in the emission 
guidelines. Consistent with assumptions used in calculating the 
CO2 emission performance rates in the emission guidelines, 
affected EGUs and states can take full credit for the MWh resulting 
from eligible measures they are responsible for deploying, no matter 
where those measures are implemented. CO2 emission 
reductions from the eligible measures may occur across the region; 
however, an affected EGU or a state may only take credit for avoided 
CO2 emissions at that affected EGU or set of EGUs in 
question, as reflected in the reported stack CO2 emissions 
of affected EGUs.
    Because of the separate accounting of MWhs and CO2 
emissions, with emission impacts inherent in reported stack 
CO2 emissions and zero-emitting MWh impacts requiring 
explicit adjustments, the accounting method corresponds with the use of 
MWh-denominated ERCs in the rate-based emission trading framework 
specified in this rule. The accounting method only requires a 
quantification of the MWh generated or avoided by an eligible measure, 
and thus credits or adjustments can be denominated in MWh and do not 
need to represent an approximation of the CO2 emission 
reductions that result from those MWhs. This creates a crediting system 
or rate adjustment process that is simpler to implement than one that 
requires an approximation of avoided CO2 emissions.
    The MWh accounting method also creates a crediting system or rate 
adjustment process that is indifferent to the rate-based CO2 
emission goals of individual states, or the specific CO2 
emission rate standards that states may apply, and the relative 
stringency of those goals or standards. Use of ERCs in rate-based 
emission trading programs is addressed in detail in section VIII.K.2. 
As a result, the MWh accounting method addresses interstate effects, 
because it inherently accounts for how generation replacement and 
CO2 emission reduction impacts may cross state borders. For 
example, if the accounting method was informed by avoided 
CO2 emission rates, it could create perverse incentives for 
development of zero- or low-emitting resources in states that result in 
the greatest calculated estimate of CO2 emission reductions 
for each replacement MWh. Instead, this accounting method is 
indifferent to avoided CO2 emission rates and creates the 
same number of zero-emitting credits or adjustment for each MWh of 
energy generation or savings, wherever they occur. For a detailed 
discussion on how the accounting method addresses interstate effects, 
see section VIII.L.
    (2) General eligibility requirements for resources used to adjust a 
CO2 emission rate.
    The EPA is finalizing certain general eligibility requirements for 
resources used to adjust a CO2 emission rate. These 
requirements align eligibility with certain factors and assumptions 
used in establishing the BSER, and by extension, application of the 
BSER to the performance levels established for affected EGUs in the 
emission guidelines, as well as state rate and mass CO2 
goals. As a result, the requirements ensure that measures that may be 
used in a state plan are treated consistently (to the extent possible) 
with the EPA's assessment of the BSER.\939\ These general requirements 
also address potential interactions among rate and mass plans, as 
discussed more fully in section VIII.L.
---------------------------------------------------------------------------

    \939\ For example, eligibility requirements include installation 
dates for eligible RE measures that may be used in a state plan. 
These dates generally align with the dates used for broadly defining 
incremental RE resources that were considered in establishing the 
BSER.
---------------------------------------------------------------------------

    As discussed in the sections that follow, the general eligibility 
criteria address:

     The date from which eligible measures may be installed 
(e.g., installation of RE generating capacity and installation of EE 
measures);
     the date from which MWh from eligible measures may be 
counted, and applied toward adjusting a CO2 rate; and
     the need to demonstrate that eligible measures replace 
or avoid generation from affected EGUs.

    (a) Eligibility date for installation of RE/EE and other measures 
and MWh generation and savings.
    Incremental emission reduction measures, such as RE and demand-side 
EE, can be recognized as part of state plans, but only for the emission 
reductions they provide during a plan performance period. Specifically, 
this means that measures installed in any year after 2012 are 
considered eligible measures under this final rule, but only the 
quantified and verified MWh of electricity generation or electricity 
savings that they produce in 2022 and future years may be applied 
toward adjusting a CO2 emission rate. For example, MWh 
generation in 2022 from a wind turbine installed in 2013 may be applied 
toward adjusting a CO2 emission rate. This 2012 date applies 
to all eligible measures that are used to adjust a CO2 
emission rate under a state plan. For example, eligible measures, such 
as CHP, nuclear power and DSM, also must be installed after 2012, but 
only their generation or savings produced in 2022 and after can be used 
to adjust a CO2 emission rate.
    As discussed in section VIII.C.2.a, a MWh of generation or savings 
that occurs in 2022 or a subsequent year may be carried forward (or 
``banked'') and applied in a future year. For example, a MWh of RE 
generation that occurs in 2022 may be applied to adjust a 
CO2 emission rate in 2023 or future years, without 
limitation.\940\ These MWh may be banked from the interim to final 
periods.
---------------------------------------------------------------------------

    \940\ Similarly, as discussed in section VIII.C.2.b.(2).(a), 
allowances may be banked in a mass-based trading program.
---------------------------------------------------------------------------

    This eligibility date criterion is consistent with the date of 
installation for ``incremental'' RE capacity that is included in the 
BSER building block 3, which is the basis for RE MWh incorporated in 
the CO2 emission performance rates for affected EGUs in the 
emission guidelines. For more information on RE in the BSER, see 
section V.E.
    Many commenters asserted that proposed state goals did not 
sufficiently account for actions states take that reduce CO2 
emissions prior to the first plan performance period, and therefore 
requested that MWhs of electricity generation or electricity savings 
that occur prior to the first plan performance period be eligible to 
apply toward adjusting the CO2 emission rates of affected 
EGUs. The EPA recognizes the importance of early state action as the 
basis for significant CO2 emission reductions and as a key 
part of enabling state plans to achieve the CO2 emission 
performance levels or state CO2 goals. The ability to count 
eligible measures installed in 2013 and subsequent years for the MWhs 
they generate during a plan performance period provides significant 
recognition for early action, corresponding with the BSER framework 
that is based on cost-effective actions that many sources are already 
doing, while still conforming to CO2 performance rates and 
state goals that are forward-looking. In order to provide additional 
incentives for early investment in RE and demand-side EE, the EPA is 
also establishing the CEIP, as discussed in section VIII.B.2. ERCs 
distributed by states and the EPA through this program may also be used 
by affected EGUs to demonstrate compliance with an emission standard,

[[Page 64897]]

and may be banked from the interim to final periods.
    Commenters' concerns about treatment of early actions are further 
addressed by changes from proposal to the BSER assumptions and the 
methodology used by the EPA to establish the CO2 emission 
performance levels and rate-based state CO2 goals in the 
emission guidelines. The specifics of these changes are addressed in 
section V.A.3. Three examples of those changes are provided below.
    First, affected EGUs that have maximized their CO2 
emission reduction opportunities available through early action will be 
better positioned to meet the BSER CO2 emission performance 
rates or state goal applied to affected EGUs in their state. For 
example, a steam generating unit that has already reduced its 
CO2 emission rate through a heat rate improvement may have a 
CO2 emission rate of 2,000 lb/MWh whereas its rate was 2,100 
lb/MWh prior to the improvement. Therefore, it has less distance to 
cover to meet its CO2 emission performance rate.
    Second, generation from existing RE capacity installed prior to 
2013 has been excluded from the EPA's calculation of the CO2 
emission performances rates in the emission guidelines. That RE 
generating capacity will still provide zero-emitting generation to the 
grid meeting demand that will not need to be addressed by existing 
affected EGUs and will better position states and affected EGUs to meet 
the CO2 performances rates or state rate- or mass-based 
CO2 goals.
    Third, commenters expressed concern that demand-side EE targets as 
part of proposed state goals reflected an assumption of installation of 
increased EE measures starting in 2017, which seemed to be an implicit 
requirement to take action prior to the performance period. Because 
demand-side EE is not used in calculating the CO2 emission 
performance rates in the final emission guidelines, this is no longer a 
concern. Furthermore, eligible demand-side EE actions that occur after 
2012 can be applied toward adjusting the CO2 emission rates 
of affected EGUs, providing a significant compliance option that is not 
assumed in emission performance rates or state goals.
    (b) Demonstration that measures substitute for grid generation.
    Eligible measures must be grid-connected. This eligibility 
criterion aligns incremental NGCC generation in building block 2. It 
also aligns with RE generation in building block 3 of the BSER, which 
substitutes for the need for generation from affected EGUs.
    All EE measures must result in electricity savings at a building, 
facility, or other end-use location that is connected to the 
electricity grid. EE measures only avoid electric generation from grid-
connected EGUs if the electrical loads where the efficiency 
improvements are made are interconnected to the grid.
    Commenters sought clarity on this issue, so the EPA is providing 
this requirement as part of the final rule. Some commenters advocated 
for the inclusion of measures that were not grid connected as eligible 
resources, arguing that some of these measures substituted for non-
affected EGUs and resulted in reductions in CO2 emissions. 
However, eligible measures must be able to substitute for generation 
from affected EGUs as defined under this rule, and thus must be tied to 
the electrical grid.
    (c) Geographic eligibility.
    All eligible emission reduction measures, including RE generation 
and demand-side EE, may occur in any state, with certain limitations, 
as described below. To the extent these measures are tied to a state 
plan,\941\ these measures may be used to adjust a CO2 
emission rate, regardless of whether the associated generation or 
electricity savings occur inside or outside the state.\942\ This 
approach is generally consistent with the approach used in building 
block 3 of the BSER, which reflects regionally available RE. It also 
recognizes that emission reduction measures have impacts on electricity 
generation across the electricity system, both within and beyond a 
state's borders. A more in-depth discussion of the basis for treatment 
of in-state and out-of-state measures is provided in section VIII.L.
---------------------------------------------------------------------------

    \941\ As used here, a measure is ``tied to a state plan'' if it 
is issued an ERC under approved procedures in a rate-based emission 
standards plan or represents quantified and verified MWh energy 
generation or energy savings achieved by an approved state measure 
in a state measures plan.
    \942\ For example, under a rate-based emission standard with 
credit trading, ERCs may be issued for qualifying actions that occur 
both inside and outside the state, provided the measures meet 
requirements of EPA-approved state regulations and the provider 
applies to the state for the issuance of ERCs. Similarly, under a 
state measures plan, a state might include state requirements such 
as an RPS, where compliance with the RPS can be met through out-of-
state RE generation.
---------------------------------------------------------------------------

    State plans must demonstrate that emission standards and state 
measures (if applicable) are non-duplicative. Given the geographic 
eligibility approach described here, this includes a demonstration that 
a state plan does not allow recognition of a MWh, for use in adjusting 
the CO2 emission rate of an affected EGU, if the MWh is 
being or has been used for such a purpose under another state plan. 
Discussion of how such a demonstration can be made in the context of a 
rate-based emission trading program is in section VIII.D.2.b.
    The EPA received many comments on the treatment of in-state and 
out-of-state RE and demand-side EE. Most commenters recommended 
crediting of both in-state and out-of-state RE and demand-side EE 
measures, similar to the final rule approach for eligible emission 
reductions measures. Commenters argued that this approach makes sense 
based on the nature of the interconnected electricity grid and allows 
states and utilities to fully account for their RE and demand-side EE 
efforts, whether that RE or EE, and its related impacts, occurs inside 
or outside of their state. Some commenters expressed concerns that, at 
proposal, states with significant RE resources had large amounts of 
existing RE capacity included in their state CO2 goals, but 
that RE was functionally credited to other states for use in meeting 
their goals because it was associated with measures (such as an RPS) 
likely to be included in another state's plan. This concern has been 
addressed through changes in the BSER RE assumptions in the final rule. 
This includes regionalization of the RE building block, and removal of 
existing RE capacity constructed prior to 2012 from the building block. 
The result of these changes is that the RE incorporated in the BSER is 
more equally shared across states.
    (i) Measures that occur in states with mass-based plans.
    As discussed above, eligible measures for adjusting the 
CO2 emission rate of an affected EGU may occur in any state, 
with certain conditions. This includes a condition that applies to 
eligible measures that occur in a state with an EPA-approved plan that 
is meeting a state mass-based CO2 goal. Eligible measures 
that could be used to adjust a CO2 emission rate under a 
rate-based state plan which are located in a state with a mass-based 
plan are restricted from being counted under another state's rate-based 
plan. An exception is made for RE measures that occur in such mass-
based states, because of its unique role in BSER. RE measures must meet 
additional eligibility criteria in order to be used to adjust the 
CO2 emission rate of an affected EGU in a state with a rate-
based plan. This exception only applies to RE; other emission reduction 
measures that were not included in the determination of the BSER 
located in mass-based states, including demand-side EE, are restricted 
from ERC issuance in rate-based states.

[[Page 64898]]

    These criteria are intended to address the fact that eligible 
measures should lead to substitution of generation from affected EGUs, 
with related impacts on CO2 emissions from affected EGUs. 
Where states with mass-based plans implement mass-based CO2 
emission standards, CO2 emissions reductions from affected 
EGUs must occur in order to comply with these emission standards and, 
unlike the rate-based approach, zero- and low-emitting MWhs do not play 
a specified role in demonstrating that the mass-based standards have 
been met.\943\ Since they are not counted in the mass-based 
demonstration, eligible measures located in mass-based states could be 
used in a state with a rate-based plan to adjust the CO2 
emission rate of affected EGUs. Such adjustments would obviate the need 
for comparable CO2 emission reductions at affected EGUs in 
the rate-based state or the use of other measures to make a rate 
adjustment. In this scenario, to the extent that eligible measures 
substitute solely for generation from affected EGUs in a state with 
mass-based emission limits, and are also used to adjust the reported 
CO2 emission rate of affected EGUs in a rate-based state, no 
incremental CO2 emissions reductions would occur in the 
rate-based state as a result of the eligible measures.\944\ The result 
would be forgone CO2 emission reductions that would 
otherwise occur across the two states. These dynamics are further 
addressed in section VIII.L.
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    \943\ Where such measures substitute for generation from 
affected EGUs subject to a mass CO2 emission limit, such 
measures reduce the cost of meeting those mass emission limits, but 
do not result in incremental CO2 emission reductions.
    \944\ As used here, incremental emission reductions refers to 
emission reductions that are above and beyond what would be achieved 
solely through compliance with the emission standards in the mass-
based state.
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    For RE measures located in a mass-based state to have some or all 
of its generation counted under a rate-based plan in another state, it 
must be demonstrated that the generation was delivered to the grid to 
meet electricity load in a state with a rate-based plan.\945\ Some 
examples of documentation that can serve as a demonstration include a 
power delivery contract or power purchase agreement. The EPA is giving 
states flexibility regarding the nature of this demonstration, but a 
state plan must describe the nature of the required demonstration and 
have it be approved by the EPA.
---------------------------------------------------------------------------

    \945\ This does not need to necessarily be the state where the 
MWh of energy generation from the measure is used to adjust the 
CO2 emission rate of an affected EGU.
---------------------------------------------------------------------------

    Under an emission standards plan, this demonstration must be made 
by the provider of the RE measure seeking ERC issuance under the rate-
based emission standards in a rate-based state, as part of the 
eligibility application for the measure.\946\ The rate-based state must 
include in its state plan provisions that describe a sufficient 
demonstration of geographic eligibility for the RE generation under 
rate-based emission standards.
---------------------------------------------------------------------------

    \946\ Requirements for ERC issuance are addressed in section 
VIII.K.2.
---------------------------------------------------------------------------

    Further examples of eligible demonstrations and how they should be 
outlined in state plans are provided in section VIII.L.
    (ii) Measures that occur in states, including areas of Indian 
country, that do not have affected EGUs.
    States, including areas of Indian country, that do not have any 
affected EGUs within their borders may be providers of credits for 
generation from zero- or low-emitting resources to adjust 
CO2 emission rates. In its supplemental proposal for the 
proposed rulemaking, the EPA sought comment on whether or not 
jurisdictions without affected fossil fuel generation units subject to 
the proposed emission guidelines should be authorized to participate in 
state plans. Commenters were supportive of allowing those jurisdictions 
without affected EGUs the opportunity to participate in state plans. 
CO2 reduction measures in areas without affected EGUs have 
the potential to provide cost-effective opportunities to reduce 
emissions and should be available on a voluntary basis to affected 
EGUs. Commenters noted that some tribes, for example, have many 
untapped RE resources that could be developed, and they should be able 
to realize the benefits of contributing to a state plan. Commenters 
stated that because of the integrated nature of the U.S. electricity 
grid, it is appropriate to allow all jurisdictions with the ability to 
contribute to and benefit from CO2 emission reductions or 
CO2 emission rate adjustments.
    For participating states, they must adhere to EM&V standards, 
installation dates, and any other criteria that apply to all states. 
Section VIII.K.3 below identifies and discusses the EM&V requirements 
used to quantify MWh savings from generation from zero- or low-emitting 
sources.
    States, including areas of Indian country, that do not have any 
affected EGUs may provide ERCs to adjust CO2 emissions 
provided they are connected to the contiguous U.S. grid and meet the 
other requirements for eligibility. To qualify for ERCs from zero or 
low-emitting resources, it must be demonstrated that the generation was 
delivered to the grid to meet electricity load in a state with a rate-
based plan.\947\ Some examples of documentation that can serve as a 
demonstration include a power delivery contract or power purchase 
agreement. The EPA is giving states flexibility regarding the nature of 
this demonstration, but a state plan must describe the nature of the 
required demonstration and have it be approved by the EPA.
---------------------------------------------------------------------------

    \947\ This does not need to necessarily be the state where the 
MWh of energy generation from the measure is used to adjust the 
CO2 emission rate of an affected EGU.
---------------------------------------------------------------------------

    In addition to generation from zero- or low-emitting resources, 
demand-side EE resources in areas of Indian country located within the 
borders of states with rate-based emission standards for affected EGUs 
may also be issued ERCs. In these instances, the area of Indian country 
is located within the rate-based service area subject to a rate-based 
state plan. The ERCs from demand-side EE resources must meet the 
eligibility requirements to adjust a CO2 emission rate, 
including installation date and EM&V requirements described below in 
section VIII.K.3. If the area of Indian country is located within the 
borders of a state that is meeting a mass-based CO2 goal, 
then the demand-side EE resources are not eligible to be issued ERCs. 
Similarly, demand-side EE resources in any state with a mass-based 
CO2 goal are not eligible to provide ERCs.
    Non-contiguous states and territories may not be providers of ERCs 
to the contiguous U.S. states. As discussed previously in section 
VII.F, we have not set CO2 emission performance goals for 
Alaska, Hawaii, Guam, or Puerto Rico in this final rule at this time.
    (iii) Measures that occur outside the U.S.
    The EPA will work with states using the rate-based approach that 
are interested in allowing the use of RE from outside the U.S. to 
adjust CO2 emission rates. In these cases, all conditions 
for creditable domestic RE must be met, including that RE resources 
must be incremental and installed after 2012, and all EM&V standards 
must be met. In addition, the country generating the ERCs must be 
connected to the U.S. grid, and there must be a power purchase 
agreement or other contract for delivery of the power with an entity in 
the U.S. RE generation capacity outside the U.S. that existed prior to 
2012 but was not exported to the U.S. is not considered new or 
incremental generation and, therefore,

[[Page 64899]]

not eligible for adjusting CO2 emission rates under this 
rule. For example, a new transmission interconnection to existing RE in 
Canada would not be considered incremental, but a new interconnection 
to RE where the RE was built after 2012 would be considered 
incremental. See below in section VIII.K.1.a.(3) for more specifics 
regarding the use of incremental hydroelectric power in a rate-based 
approach.
    The EPA received comments encouraging the use of international 
zero-emitting electricity imports in state plans, particularly 
hydroelectric power from Canada. Canada currently provides states such 
as Minnesota and Wisconsin with RE through existing grid connections. 
New projects are in various stages of development to increase 
generating capacity, which could be called upon as a base load resource 
to supplement variable forms of RE generation. Commenters said that the 
EPA should permit the use of all incremental hydropower--both domestic 
and international--towards EGU CO2 emission rate adjustments 
providing that double-counting can be prevented; and the EPA 
acknowledges this may be allowable, as long as the specified criteria 
have been met.
    (3) RE.
    RE measures may be used to adjust a CO2 emission rate, 
provided they meet the general eligibility requirements outlined above 
and the MWh electricity generation is properly quantified and 
verified.\948\ As used in this section, RE includes electric generating 
technologies using RE resources, such as wind, solar, geothermal, 
hydropower, biomass and wave and tidal power. A capacity uprate at an 
existing RE facility (i.e., an uprate to generating capacity originally 
installed as of 2012 or earlier) is eligible to adjust a CO2 
emission rate. The capacity uprate must occur after 2012. Such uprates 
to capacity represent incremental capacity added after 2012.
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    \948\ All state plans must demonstrate that measures included in 
the plan are quantifiable and verifiable. See section VIII.K.2 for 
discussion of requirements for the issuance of ERCs, and section 
VIII.K.3 for discussion of EM&V requirements for use of RE relied on 
in a state plan.
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    Quantification and accounting criteria for incremental RE (and 
nuclear generation) are as follows. The incremental generating capacity 
(in nameplate MW) is divided by the total uprated generating capacity 
(in nameplate MW) and then multiplied by generation output (in MWh) 
from the uprated generator. For example, if a hydroelectric power plant 
expands generating nameplate capacity from 100 MW to 125 MW and 
generation output increased to 1,000 MWh, then 200 MWh ((25 MW/125 MW) 
* 1,000 MWh) is eligible for use in adjusting a CO2 emission 
rate, regardless of the overall level of generation for the 
period.\949\
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    \949\ For example, the overall generation from the uprated 
hydroelectric power plant may be higher or lower than generation 
levels that occurred at the plant prior to the capacity uprate.
---------------------------------------------------------------------------

    Many commenters supported using RE deployment as measures to adjust 
the CO2 emission rate of affected EGUs. Some commenters 
specifically agreed with the EPA's determination that only new and 
incremental RE (including hydropower) should be used to adjust 
CO2 emission rates. Those commenters objected to counting 
existing RE that are already embedded in the baseline emissions and 
generation mix. A significant number of commenters supported the 
integration of RE into a rate-based credit trading system.
    Certain additional requirements apply for hydropower and biomass 
(including waste-to-energy) RE, as described below.
    (a) Hydroelectric power.
    Consistent with other types of RE, new hydroelectric power 
generating capacity installed after 2012 is eligible for use in 
adjusting a CO2 emission rate.
    Relicensed facilities are considered existing capacity and, 
therefore, are not eligible for use in adjusting a CO2 
emission rate, unless there is a capacity uprate as part of the 
relicensed permit. In such a case, only the incremental capacity is 
eligible for use in adjusting a CO2 emission rate.
    The EPA noted that many commenters preferred that generation from 
hydropower displace generation from fossil sources. One commenter 
suggested that existing zero-emitting sources, including hydropower, do 
not reduce emissions from existing fossil generation, but that new or 
uprated zero-emitting sources would, because of their low variable 
rate, reduce fossil emissions. Several commenters recommended allowing 
incremental generation from new or uprated zero-emitting sources, 
including hydropower, be available for compliance.
    (b) Biomass.
    RE generating capacity installed after 2012 that uses qualified 
biomass as a fuel source is eligible for use in adjusting a 
CO2 emission rate.\950\ As discussed in section VIII.I.2.c., 
if a state intends to allow for the use of biomass as a compliance 
option for an affected EGU to meet a CO2 emission standard, 
a state must propose qualified biomass feedstocks and treatment of 
biogenic CO2 emissions in its plan, along with supporting 
analysis and quality control measures, and the EPA will review the 
appropriateness and basis for such determinations in the course of its 
review of a state plan. Where an RE generating unit uses qualified 
biomass, as designated in an approved state plan, MWh generation from 
the unit could be used to adjust the reported CO2 emission 
rate of an affected EGU. Total MWh generation from an RE generating 
unit that uses qualified biomass must be prorated based on either the 
heat input supplied from qualified biomass as a proportion of total 
heat input or on the proportion of biogenic CO2 emissions 
compared to total stack CO2 emissions from the RE generating 
unit. Either approach must incorporate the approved valuation of 
biogenic CO2 emissions from qualified biomass in the plan 
(i.e., the proportion of biogenic CO2 emissions from use of 
qualified biomass feedstock that would not be counted).
---------------------------------------------------------------------------

    \950\ As with other RE, only generating capacity installed after 
2012 would be eligible for use in adjusting a CO2 
emission rate.
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    Section VIII.K describes the requirements and procedures for EM&V, 
and discusses how all eligible resources must demonstrate how they will 
quantify and verify MWh savings using best-practice EM&V approaches. 
One way to make this demonstration for eligible resources could be to 
use the presumptively approvable EM&V approaches that are included in 
the final model trading rule.
    (c) Waste-to-energy.
    Qualified biomass may include the biogenic portion of MSW combusted 
in a waste-to-energy facility.\951\ With regard to assessing qualified 
biomass proposed in state plans, the EPA generally acknowledges the 
CO2 emissions and climate policy benefits of waste-derived 
biomass, which includes biogenic MSW inputs to waste-to-energy 
facilities. The process and considerations for the use of biomass in 
state plans are discussed in section VIII.I.2.c.
---------------------------------------------------------------------------

    \951\ As with other RE, only generating capacity installed after 
2012 would be eligible for use in adjusting a CO2 
emission rate.
---------------------------------------------------------------------------

    MSW can be directly combusted in waste-to-energy facilities to 
generate electricity as an alternative to landfill disposal. In the 
U.S., almost all incineration of MSW occurs at waste-to-energy 
facilities or industrial facilities where the waste is combusted and 
energy is recovered.\952\ Total MSW generation in 2012 was 251 million 
tons, but of that total volume generated, almost 87 million tons were 
recycled

[[Page 64900]]

and composted.\953\ Increasing demand for electricity generated from 
waste-to-energy facilities could increase competition for and 
generation of waste stream materials--including discarded organic waste 
materials--which could work against programs promoting waste reduction 
or cause diversion of these materials from existing or future efforts 
promoting composting and recycling. The EPA and many states have 
recognized the importance of integrated waste materials management 
strategies that emphasize a hierarchy of waste prevention, starting 
with waste reduction programs as the highest priority and then focusing 
on all other productive uses of waste materials to reduce the volume of 
disposed waste materials.\954\ For example, Oregon and Vermont have 
strategies that emphasize waste prevention, followed by reuse, then 
recycling and composting materials prior to treatment and 
disposal.\955\
---------------------------------------------------------------------------

    \952\ 2014 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 
1990-2012. http://www.epa.gov/climatechange/ghgemissions/usinventoryreport.html.
    \953\ http://www.epa.gov/osw/nonhaz/municipal/pubs/2012_msw_fs.pdf.
    \954\ http://www.epa.gov/wastes/nonhaz/municipal/hierarchy.htm.
    \955\ http://www.anr.state.vt.us/dec/wastediv/WastePrevention/main.htm.
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    Information in the revised Framework for Assessing Biogenic 
CO2 Emissions from Stationary Sources and other technical 
studies and tools (e.g., EPA Waste Reduction Model, EPA Decision 
Support Tool) should assist both states and the EPA in assessing the 
role of biogenic feedstocks used in waste-to-energy processes, where 
use of such feedstocks is included in a state plan.\956\
---------------------------------------------------------------------------

    \956\ http://epa.gov/epawaste/conserve/tools/warm/Warm_Form.html, https://mswdst.rti.org/.
---------------------------------------------------------------------------

    When developing their plans, states planning to use waste-to-energy 
as an option for the adjustment of a CO2 emission rate 
should assess both their capacity to strengthen existing or implement 
new waste reduction, reuse, recycling and composting programs, and 
measures to minimize any potential negative impacts of waste-to-energy 
operations on such programs. States must include that information in 
their plan submissions. The EPA will reject as qualified biomass any 
proposed waste-to-energy component of state plans if states do not 
include information on their efforts to strengthen existing or 
implement new waste reduction as well as reuse, recycling and 
composting programs, and measures to minimize any potential negative 
impacts of waste-to-energy operations on such programs. Only electric 
generation at a waste-to-energy facility that is related to the 
biogenic fraction of MSW and that is added after 2012 is eligible for 
use in adjusting a CO2 emission rate.
    A state plan must include a method for determining the proportion 
of total MWh generation from a waste-to-energy facility that is 
eligible for use in adjusting a CO2 emission rate. The EPA 
will evaluate the method as part of its evaluation of the approvability 
of the state plan. Measuring the proportion of biogenic to fossil 
CO2 emissions can be performed through sampling and testing 
of the biogenic fraction of the MSW used as fuel at a waste-to-energy 
facility (e.g., via ASTM D-6866-12 testing or other methods--ASTM, 
2012; Bohar, et al. 2010), or based on the proportion of biogenic 
CO2 emissions to total CO2 emissions from the 
facility. For an example of the former method, if the biogenic fraction 
of MSW is 50 percent by input weight, only the proportion of MWh output 
attributable to the biogenic portion of MSW at the waste-to-energy 
facility may be used to adjust an affected EGU CO2 emission 
rate. Alternatively, as an example of the latter method, if biogenic 
CO2 emissions represent 50 percent of total reported 
CO2 emissions, a facility would need to estimate the 
fraction of biogenic to fossil MSW utilized and the net energy output 
of each component (based on relative higher heating values) to 
determine the percent of the MWh output from the waste-to-energy 
facility that may be used to adjust an affected EGU's CO2 
emission rate. Section VIII.K describes the requirements and procedures 
for EM&V, and discusses how all eligible resources must demonstrate how 
they will quantify and verify MWh savings using best-practice EM&V 
approaches. One way to make this demonstration for eligible resources 
could be to use the presumptively approvable EM&V approaches that are 
included in the final model trading rule.
    The EPA received multiple comments supporting the use of waste-to-
energy as part of state plans. Some commenters expressed concern that 
non-biogenic materials, such as plastics and metal, would be 
incinerated along with biogenic materials. As discussed above, only 
electric generation related to the biogenic fraction of MSW at a waste-
to-energy facility added after 2012 is eligible for use in adjusting a 
CO2 emission rate. The EPA also received comments that 
expressed concern about the potential negative impacts on recycling and 
waste reduction efforts, while other commenters asserted that waste-to-
energy practices encourage recycling programs. Some commenters also 
expressed concern about what treatment would be approvable for 
emissions from waste-to-energy practices. As discussed above, potential 
negative impacts from waste-to-energy production on recycling, waste 
reduction, and composting programs should be evaluated and efforts to 
mitigate negative impacts must be discussed in the supporting 
documentation of state plans.
    (4) DSM.
    Avoided MWh that result from DSM may be used to adjust a 
CO2 emission rate. Eligible DSM actions are those that are 
zero-emitting and avoid, rather than shift, the use of electricity by 
an electricity end-user.\957\ The MWh that may be used for such an 
adjustment are determined based on the MW of demand reduction 
multiplied by the hours during which such a demand reduction is 
achieved (MW of demand reduction x hours = MWh avoided). DSM measures 
must be appropriately quantified and verified, in accordance with 
requirements in the emission guidelines, as discussed in section 
VIII.K.3.
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    \957\ An example is a utility direct load control program, such 
as those where customer air conditioning units are cycled during 
periods of peak electricity demand. Actions that shift electricity 
demand from one time of day to another, without reducing net 
electricity use, are not eligible, as these measures do not avoid 
electricity use from the grid. Use of emitting generators as a DSM 
measure is also not eligible.
---------------------------------------------------------------------------

    (5) Energy storage.
    Energy storage may not be directly recognized as an eligible 
measure that can be used to adjust a CO2 emission rate, 
because storage does not directly substitute for electric generation 
from the grid or avoid electricity use from the grid.\958\ The electric 
generation that is input to an energy storage unit may be used to 
adjust a CO2 emission rate, but the output from the energy 
storage unit may not.\959\ However, energy storage can be used as an 
enabling measure that facilitates greater use of RE, which can be used 
to adjust a CO2 emission rate. For example, utility scale 
energy storage may be used to facilitate greater grid penetration of RE 
generating capacity and can also be used to store RE generation that 
may have otherwise been shed in times of excess generating capacity. 
Likewise, on-site energy storage at an electricity end-user can

[[Page 64901]]

enable greater use of RE to meet on-site electricity demand.\960\
---------------------------------------------------------------------------

    \958\ Energy storage depends on a generation source, either from 
a utility-scale EGU (e.g., a fossil EGU, a wind turbine, etc.) or a 
distributed generation source at an electricity end-user (e.g., a PV 
system installed at a building).
    \959\ This approach focuses on counting the qualifying electric 
generation, which may be an input to an energy storage unit. 
Counting both the generation input to energy storage and the output 
from the energy storage unit would be a form of double counting. The 
electric generation that is stored may be counted; the subsequent 
output from the storage unit may not.
    \960\ For example, battery storage at a building with solar PV 
can enable the PV system to meet the building's entire electrical 
load, by storing energy during times of peak PV system output for 
later use when the sun is not shining.
---------------------------------------------------------------------------

    The EPA received multiple comments regarding the overall merits of 
energy storage. Consistent with the discussion above, the majority of 
commenters observed that storage technology enables greater grid 
penetration of RE and supports more efficient and effective operations 
of both RE and fossil-fuel plants. Commenters further noted that energy 
storage can provide RE to the grid when it is most needed, while 
simultaneously taking pressure off fossil-fuel plants to respond to 
sudden shifts in demand. Despite broad acknowledgment of the benefits 
of storage, public comments underscore its indirect and supporting role 
in providing zero-emission MWh to the grid (consistent with the EPA's 
decision to exclude energy storage as an eligible measure that can be 
used to adjust a CO2 emission rate).
    (6) Transmission and distribution (T&D) measures.
    Electricity T&D measures that improve the efficiency of the T&D 
system and/or reduce electricity use may be used to adjust a 
CO2 emission rate. This includes T&D measures that reduce 
losses of electricity during delivery from a generator to an end-user 
(sometimes referred to as ``line losses'' \961\) and T&D measures that 
reduce electricity use at the end-user, such as conservation voltage 
reduction (CVR).\962\ The EPA received many comments in support of 
advanced energy technologies, including energy storage and transmission 
and distribution upgrades, and including these technologies in the 
suite of potential measures that states could consider for emission 
rate adjustments in their state plans. Comments pointed out that in 
addition to helping achieve emission standards, T&D efficiency 
improvements make the grid more robust and flexible, as well as 
delivering environmental benefits. In many parts of the country, grid 
operators, transmission planners, transmission owners and regulators 
are already taking steps to expand and modernize T&D networks. 
Commenters suggested that the EPA clarify the eligibility and criteria 
under which such measures would be permitted in a state plan.
---------------------------------------------------------------------------

    \961\ T&D system losses (or ``line losses'') are typically 
defined as the difference between electricity generation to the grid 
and electricity sales. These losses are the fraction of electricity 
lost to resistance along the T&D lines, which varies depending on 
the specific conductors, the current, and the length of the lines. 
The Energy Information Administration (EIA) estimates that national 
electricity T&D losses average about 6 percent of the electricity 
that is transmitted and distributed in the U.S. each year.
    \962\ Volt/VAR optimization (VVO) refers to coordinated efforts 
by utilities to manage and improve the delivery of power in order to 
increase the efficiency of electricity distribution. VVO is 
accomplished primarily through the implementation of smart grid 
technologies that improve the real-time response to the demand for 
power. Technologies for VVO include load tap changers and voltage 
regulators, which can help manage voltage levels, as well as 
capacitor banks that achieve reductions in transmission line loss. 
VVO efforts are often closely related to CVR, which are actions 
taken to reduce initial delivered voltage levels in feeder 
transmission lines while remaining within the 114 volt to 126 volt 
range (for normal 120-volt service) required at the customer meter, 
per the ANSI C84.1 standards.
---------------------------------------------------------------------------

    To be eligible, T&D measures must be installed after 2012. This 
general eligibility requirement is discussed above in section 
VIII.K.1.a. The MWh of avoided losses or reduction in end-use that 
result from T&D measures must be appropriately quantified and verified, 
as discussed in section VIII.K.3.
    (7) Demand-side EE, including water system efficiency.
    Demand-side EE measures may be used to adjust a CO2 
emission rate, provided they meet the general eligibility requirements 
outlined above and the MWh electricity savings are properly quantified 
and verified.\963\ As used in this section, demand-side EE may include 
a range of eligible measures, provided that the measures can be 
quantified and verified in accordance with the EM&V requirements in the 
emission guidelines, which are addressed in section VIII.K.3. Examples 
of demand-side EE measures include, but are not limited to, EE measures 
that reduce electricity use in residential and commercial buildings, 
industrial facilities, and other grid-connected equipment. Water 
efficiency programs that improve EE at water and wastewater treatment 
facilities also provide demand-side EE savings opportunities. EE 
measures, for the purposes of this section, may consist of EE measures 
installed as the result of individual EE projects, such as those 
implemented by energy service companies, as well as multiple EE 
measures installed through an EE deployment program (e.g. appliance 
replacement and recycling programs, and behavioral programs) 
administered by electric utilities, state entities, and other private 
and non-profit entities.\964\ EE measures, for the purposes of this 
section, may also consist of state or local requirements that result in 
electricity savings, such as building energy codes and state appliance 
and equipment standards. Other interventions that result in electricity 
savings may also be considered an EE measure for the purposes of this 
section, provided the intervention can be specified and quantified and 
verified in accordance with EM&V requirements in the emission 
guidelines.
---------------------------------------------------------------------------

    \963\ All state plans must demonstrate that measures included in 
the plan are quantifiable and verifiable. See section VIII.K.2 for 
discussion of requirements for the issuance of ERCs, and section 
VIII.K.3 for discussion of EM&V requirements for use of demand-side 
EE relied on in a state plan.
    \964\ EE programs may also be implemented by other entities. 
Eligible EE measures that are deployed through EE programs are not 
limited to those EE measures deployed through EE programs 
administered by the types of entities listed here.
---------------------------------------------------------------------------

    Numerous commenters expressed support for including demand-side EE 
as an eligible measure states and affected EGUs can use to meet the 
emission guidelines. Commenters touted the value of demand-side EE as a 
resource that delivers energy savings, lowers bills, creates jobs and 
reduces CO2 emissions. Commenters called for the EPA to 
allow for the use of a broad range of demand-side EE measures to meet 
the emission guidelines, including, but not limited to, utility and 
non-utility EE deployment programs; energy savings performance 
contracts; measures that reduce electricity use in residential and 
commercial buildings, industrial facilities and other grid-connected 
equipment; state and local requirements that result in electricity 
savings, such as building energy codes and state appliance and 
equipment standards; appliance replacement and recycling programs; and 
behavioral programs. The EPA also received comments supporting the use 
of water sector EE programs and projects. Commenters identified water 
and wastewater utilities as particularly well-suited for participating 
in EE programs and providing a source of electricity savings. 
Investments such as replacing pumps and other aging equipment and 
repairing leaks can result in greater EE. The EPA agrees that these 
electricity savings should be eligible for adjustments to 
CO2 emission rates at affected EGUs.
    (8) Nuclear power.
    As is discussed in section V.A.3, upon consideration of comments 
received, the EPA has not included nuclear generation from either 
existing or under construction units in the determination of the BSER. 
In addition to comments received on the provisions for determining the 
BSER, the EPA also received comments requesting that the EPA allow all 
generation from nuclear generating units to be recognized as an

[[Page 64902]]

eligible measure that can be used to adjust a CO2 emission 
rate. Commenters also recommended that the EPA consider nuclear 
generating units and RE generating units in a consistent manner for 
CO2 emission rate adjustments in state plans. We agree with 
comments that nuclear generation and RE should be treated consistently 
when it comes to CO2 emission rate adjustments.
    The EPA has determined that generation from new nuclear units and 
capacity uprates at existing nuclear units will be eligible for use in 
adjusting a CO2 emission rate, just like new and uprated 
capacity RE. However, consistent with the reasons discussed for not 
including the preservation of existing nuclear capacity in the BSER--
namely, that such preservation does not actually reduce existing levels 
of CO2 emissions from affected EGUs--preserving generation 
from existing nuclear capacity is not eligible for use in adjusting a 
CO2 emission rate.
    In contrast, any incremental zero-emitting generation from new 
nuclear capacity would be expected to replace generation from affected 
EGUs and, thereby, reduce CO2 emissions; and the continued 
commitment of the owner/operators to completion of the new units and 
improving the efficiency of existing units through uprates can play a 
key role in state plans. Therefore, consistent with treatment of other 
low- and zero-emitting generation, new nuclear power generating 
capacity installed after 2012 and incremental generation resulting from 
nuclear uprates after 2012 are measures eligible for adjusting a 
CO2 emission rate. However, existing nuclear units (i.e., 
those that originally commenced operation in 2012 or earlier years) 
that receive operating license extensions are not eligible for use in 
adjusting a CO2 emission rate, except where such units 
receive a capacity uprate as a result of the relicensing process. Only 
the incremental capacity from the uprate is eligible for use to adjust 
a CO2 emission rate.
    Applicable generation (in MWh) from incremental nuclear power is 
determined in the same manner as that described for incremental RE 
above.
    (9) Combined heat and power (CHP) units.
    Electric generation from non-affected CHP units \965\ may be used 
to adjust the CO2 emission rate of an affected EGU, as CHP 
units are low-emitting electric generating resources that can replace 
generation from affected EGUs. Electrical generation from non-affected 
CHP units that meet the eligibility criteria under section VIII.K.1.a 
can be used to adjust the reported CO2 emission rate of an 
affected EGU.
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    \965\ The accounting considerations described in this section 
are for a ``topping cycle'' CHP unit. A topping cycle CHP unit 
refers to a configuration where fuel is first used to generate 
electricity and then heat is recovered from the electric generation 
process to provide additional useful thermal and/or mechanical 
energy. A CHP unit can also be configured as a ``bottoming cycle'' 
unit. In a bottoming cycle CHP unit, fuel is first used to provide 
thermal energy for an industrial process and the waste heat from 
that process is then used to generate electricity. Some waste heat 
power (WHP) units are also bottoming cycle units and the accounting 
treatment for bottoming cycle CHP units is provided with the WHP 
description below.
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    Where a state plan provides for the use of electrical generation 
from eligible non-affected CHP units to adjust the reported 
CO2 emission rate of an affected EGU, the state plan must 
provide a required calculation method for determining the MWh that may 
be used to adjust the CO2 emission rate. This proposed 
accounting method must adequately address the considerations discussed 
below. The EPA will review whether a state's proposed accounting method 
for electric generation from eligible non-affected CHP units is 
approvable per the requirements of the final emission guidelines, as 
part of its overall plan review of the rate-based emission standards 
and implementing and enforcing measures in the state plan. The EPA 
notes that the proposed model rule for a rate-based emission trading 
program includes a proposed accounting method for non-affected CHP 
units. The accounting method provided in a final model rule could be a 
presumptively approvable accounting approach.
    The proposed accounting method in a state plan must address the 
following considerations. The accounting approach proposed in a state 
plan must take into account the fact that a non-affected CHP unit is a 
fossil fuel-fired emission source, as well as the fact that the 
incremental CO2 emissions related to electrical generation 
from a non-affected CHP unit are typically very low. In accordance with 
these considerations, a non-affected CHP unit's electrical MWh output 
that can be used to adjust the reported CO2 emission rate of 
an affected EGU should be prorated based on the CO2 emission 
rate of the electrical output associated with the CHP unit (a CHP 
unit's ``incremental CO2 emission rate'') compared to a 
reference CO2 emission rate. This ``incremental 
CO2 emission rate'' related to the electric generation from 
the CHP unit would be relative to the applicable CO2 
emission rate for affected EGUs in the state and would be limited to a 
value between 0 and 1.
    This low CO2 emission rate for electrical generation 
from a non-affected CHP unit is a product of both the fact that CHP 
units are typically very thermally efficient and the fact that a 
portion of the CO2 emissions from a non-affected CHP unit 
would have occurred anyway from an industrial boiler used to meet the 
thermal load in the absence of the CHP unit. In contrast, the CHP unit 
also provides the benefit of electricity generation while resulting in 
very low incremental CO2 emissions beyond what would have 
been emitted by an industrial boiler. As a result, the accounting 
method proposed in a state plan should not presume that CO2 
emission reductions occur outside the electric power sector, but 
instead only would account for the CO2 emissions related to 
the electrical production from a CHP unit that is used to substitute 
for electrical generation from affected EGUs.
    Non-affected CHP units can use qualified biomass fuels. As 
described in section VIII.I.2.c, states must submit state plan 
requirements regarding qualified biomass feedstocks and treatment of 
biogenic CO2 emissions in state plans, along with supporting 
analysis and quality control measures, and the EPA would review the 
appropriateness and basis for such determinations in the course of its 
review of the approvability of a state plan. Considerations for 
qualified biomass included in state plans are discussed in section 
VIII.I.2.c, while accounting requirements for RE using biomass are 
provided in section VIII.K.1.a.(3)(b).
    Most comments received on CHP recommended that the EPA explicitly 
describe how CHP can be accounted for in a state plan. Commenters 
described the CO2 emission reductions achieved through CHP's 
thermal efficiency and the precedent set in other federal and state 
rules that have included CHP as a compliance option. Some commenters 
pointed out that without such a description, states would not be able 
to readily take advantage of the CO2 emission reductions 
that result from the use of CHP.
    (10) WHP.
    WHP units that meet the eligibility criteria under section VIII.K.1 
may be used to adjust the CO2 emission rate of an affected 
EGU. There are several types of WHP units. There are units, also 
referred to as bottoming cycle CHP units, where the fuel is first used 
to provide thermal energy for an industrial process and the waste heat 
from that process is then used to generate

[[Page 64903]]

electricity.\966\ There are also WHP facilities where the waste heat 
from the initial combustion process is used to generate additional 
power. Under both configurations, unless the WHP unit supplements waste 
heat with fossil fuel use, there is no additional fossil fuel used to 
generate this additional power. As a result, there are no incremental 
CO2 emissions associated with that additional power 
generation. As a result, the incremental electric generation output 
from the WHP facilities could be considered zero-emitting, for the 
purposes of meeting the emission guidelines, and the MWh of electrical 
output could be used to adjust the CO2 emission rate of an 
affected EGU.\967\ The MWh of electrical output from a WHP unit that 
can be recognized may not exceed the MWh of industrial or other thermal 
load that is being met by the WHP unit, prior to the generation of 
electricity.\968\ Most commenters that addressed WHP noted the benefits 
of WHP at the same time that they discussed the benefits of CHP. The 
commenters reflected that WHP is another potential compliance option 
and requested it be discussed explicitly as a compliance option that 
can be used to meet the emission guidelines. The comments discussed WHP 
benefits but did not elaborate on a preferred accounting method for MWh 
of electrical generation from WHP that could be used to adjust the 
CO2 emission rate of an affected EGU.
---------------------------------------------------------------------------

    \966\ In such a configuration, the waste heat stream could also 
be generated from a mechanical process, such as at natural gas 
pipeline compressors.
    \967\ This only applies where no additional fossil fuel is used 
to supplement the use of waste heat in a WHP facility. Where fossil 
fuel is used to supplement waste heat in a WHP application, MWh of 
electrical generation that can be used to adjust the CO2 
emission rate of an affected EGU must be prorated based on the 
proportion of fossil fuel heat input to total heat input that is 
used by the WHP unit to generate electricity.
    \968\ This limitation prevents oversizing the thermal output of 
a WHP unit to exceed the useful industrial or other thermal load it 
is meeting, prior to generation of electricity.
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    b. Measures that may not be used to adjust a CO2 
emission rate.
    This section addresses measures that may not be used to adjust a 
CO2 emission rate. New, modified, and reconstructed EGUs 
covered under the CAA section 111(b) final Standards of Performance for 
Greenhouse Gas Emissions from New Stationary Sources: Electric Utility 
Generating Units rule are not approvable sources of electric generation 
for adjusting the CO2 emission rate of an affected EGU under 
a rate-based state plan. As discussed earlier in section VII.D of this 
preamble, a key concern under this rule is leakage to new units that 
are not covered by the emission guidelines. Emissions leakage, or 
increased CO2 emissions due to increased utilization of 
unaffected sources, is contradictory to objectives of this rule and 
should, therefore, be minimized. Allowing affected EGUs to adjust their 
emission rates as a result of lower-emitting new NGCC units not covered 
under this section 111(d) rule would not mitigate leakage concerns, and 
could even exacerbate the situation. Consequently, new EGUs covered 
under the CAA section 111(b) rule are not allowable measures in state 
plans because the EPA believes it would result in increased emission 
leakage.
    The EPA received comments both supporting and opposing the use of 
new NGCC units in state plans. In addition to leakage concerns, 
commenters expressed concern with the potential incentives created by 
including new NGCC capacity in the BSER or as a compliance mechanism in 
state plans. Some commenters suggested that including new NGCC capacity 
in the BSER or for compliance would distort market incentives to build 
new NGCC units, particularly if new units were allowed to generate ERCs 
that could be sold to affected EGUs. These commenters suggested that 
the additional incentive for new NGCC units could make existing NGCC 
units less competitive. Other commenters suggested that including new 
NGCC capacity in state plans would promote generation from new 
CO2-emitting units at the expense of new zero-emitting 
units, increasing overall emissions within a state. This effect would 
be exacerbated if state plans allowed new NGCC units to be treated as 
``zero-emitting'' for purposes of compliance--as suggested by other 
commenters. In addition, commenters expressed concern that the EPA's 
inclusion of new NGCC capacity in setting the BSER or in compliance 
could negatively impact ratepayers over the long-term by sending the 
wrong signal to industry and resulting in stranded assets if, in the 
future, carbon emissions become more expensive or the EPA proposes to 
incorporate sources built under the forthcoming section 111(b) standard 
into the section 111(d) program. Commenters also expressed concern that 
including generation from new NGCC units could create unreasonable 
uncertainty, given limitations on the ability to accurately project new 
NGCC builds, could create undue pressure on natural gas prices, and 
could create unfair disparities in the compliance opportunities 
afforded different states. In light of the emissions leakage concerns, 
and in consideration of these comments, the EPA is not allowing 
shifting generation to new NGCC units to be used as a measure for 
adjusting CO2 emission rates for affected EGUs in rate-based 
state plans.
    In addition, other new and existing non-affected fossil fuel-fired 
EGUs that are not subject to CAA section 111(b) or 111(d), such as 
simple cycle combustion turbines, may not be used to adjust the 
CO2 emission rate of an affected EGU. While generation from 
such units could substitute for generation from affected EGUs, the EPA 
has determined that additional incentives for such generation, in the 
form of an explicit adjustment to the CO2 rate of an 
affected EGU, are not necessary or warranted. Providing for such an 
adjustment could create perverse incentives for the construction of new 
simple cycle combustion turbines that are not subject to the 
applicability criteria of the final Standards of Performance for 
Greenhouse Gas Emissions from New Stationary Sources: Electric Utility 
Generating Units rule. These units could provide only limited 
adjustment credit, as operation beyond a certain capacity factor 
threshold would trigger applicability under CAA section 111(b). 
Further, providing for the ability to generate adjustment credits would 
provide incentives for construction of less efficient fossil generating 
capacity than would likely otherwise be constructed (e.g., addition of 
a simple cycle combustion turbine rather than a NGCC unit). In 
addition, providing for the ability to generate adjustment credits 
could create perverse incentives for the continued operation of less 
efficient existing fossil generating capacity. Such outcomes run 
counter to the objectives of this final rule.
    c. Measures that reduce CO2 emissions outside the 
electric power sector.
    Measures that reduce CO2 emissions outside the electric 
power sector may not be counted toward meeting a CO2 
emission performance level for affected EGUs or a state CO2 
goal, under either a rate-based or mass-based approach, because all of 
the emission reduction measures included in the EPA's determination of 
the BSER reduce CO2 emissions from affected EGUs. Examples 
of measures that may not be counted toward meeting a CO2 
emission performance level for affected EGUs or a state CO2 
goal include GHG offset projects representing emission reductions that 
occur in the forestry and agriculture sectors,\969\ direct air capture,

[[Page 64904]]

and crediting of CO2 emission reductions that occur in the 
transportation sector as a result of vehicle electrification.
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    \969\ We note, however, that the final emission guidelines allow 
state measures like emission budget trading programs to include out-
of-sector GHG offsets. For example, both the California and RGGI 
programs allow for the use of allowances awarded to GHG offset 
projects to be used to meet a specified portion of an affected 
emission source's compliance obligation. The RGGI program contains a 
cost containment allowance reserve that makes available additional 
allowances up to a certain amount, at specified allowance price 
triggers.
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2. Requirements for Rate-Based Emission Trading Approaches
    As made clear in the proposal,\970\ all emission standards in a 
state plan must be quantifiable, verifiable, enforceable, non-
duplicative and permanent.\971\ This requirement is applicable to 
emission standards that include a rate-based emission trading program. 
The State Plan Considerations TSD for the proposal also explained that 
in order to ensure a plan is enforceable, a state plan must: identify 
in its plan the entity or entities responsible for meeting compliance 
and other enforceable obligations under the plan; include mechanisms 
for demonstrating compliance with plan requirements or demonstrating 
that other binding obligations are met; and provide a mechanism(s) for 
legal action if affected EGUs are not in compliance with plan 
requirements or if other entities fail to meet enforceable plan 
obligations. A state plan using a rate-based emission trading approach 
must therefore include rate-based emission standards for affected EGUs 
along with related implementation and compliance requirements and 
mechanisms.\972\ These related requirements include those applicable to 
rate-based emission standards more broadly: CO2 emission 
monitoring, reporting, and recordkeeping requirements for affected 
EGUs, including requirements for monitoring and reporting of useful 
energy output. By satisfactorily addressing these requirements, state 
plans including a rate-based emission trading program will be able to 
meet the statutory requirements of CAA section 111(d) regarding the 
need for state plans to provide for the implementation and enforcement 
of emission standards, as well as meet the requirement that each 
emission standard be quantifiable, verifiable, non-duplicative, 
permanent, and enforceable with respect to each affected EGU.
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    \970\ 79 FR 34830, 34913.
    \971\ These requirements are described in detail in section 
VIII.D.2.
    \972\ As described below, these requirements would likely be 
provided in a state plan in the form of state regulations, but could 
potentially be provided in another form.
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    The EPA also specifically proposed that for state plans that rely 
on measures that avoid EGU CO2 emissions, such as RE and 
demand-side EE measures, the state will also need to include 
quantification, monitoring, and verification provisions in its plan for 
these measures. The EPA is finalizing requirements specific to rate-
based emission trading programs as requirements the EPA has determined 
are necessary to assure the integrity of a rate-based approach that 
includes an emission trading program, and therefore assures a state 
plan using such an approach appropriately provides for the 
implementation and enforcement of rate-based emission standards in 
accordance with CAA section 111(d).\973\ These specific requirements 
for a rate-based emission trading program include provisions for 
issuance of ERCs by the state and/or its designated agent; provisions 
for tracking ERCs, from issuance through submission for compliance; and 
the administrative process for submission of ERCs by the owner or 
operator of an affected EGU to the state, in order to adjust its 
reported CO2 emission rate when demonstrating compliance 
with a rate-based emission standard.\974\ These requirements must be 
submitted for inclusion in the federally enforceable plan, per the 
statutory requirement that states provide for the implementation and 
enforcement of emission standards. A rate-based trading program would 
provide for the implementation and enforcement of rate-based emission 
standards for a state plan that allows its affected EGUs to adjust a 
rate by the use of an ERC.
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    \973\ By ``integrity of a rate-based emission trading program'', 
the EPA is referring to elements in the design and administration of 
a program necessary to assure that emission standards implemented 
using a rate-based emission trading approach are quantifiable, 
verifiable, enforceable, non-duplicative, and permanent.
    \974\ See section VIII.K.1 for a discussion of the accounting 
method used to adjust a CO2 emission rate.
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    The EPA will review a state plan submittal including a rate-based 
emission trading program to assure that the plan contains the 
requirements necessary to assure the integrity of a rate-based 
approach, and therefore provide for the implementation and enforcement 
of rate-based emission standards. These requirements are discussed in 
more detail in this section.
    The EPA also notes it is proposing model rules for both mass-based 
and rate-based emission trading programs. State plans that include the 
finalized model rule for a rate-based emission trading program could be 
presumptively approvable as meeting the requirements of CAA section 
111(d) and these emission guidelines. The EPA would evaluate the 
approvability of such plans through independent notice and comment 
rulemaking.
    A state may issue ERCs to an affected EGU that performs at a 
CO2 emission rate below a specified CO2 emission 
rate, as well as to providers of qualifying measures that provide 
substitute generation for affected EGUs or avoid the need for 
generation from affected EGUs. This latter category includes providers 
of qualifying RE and demand-side EE measures, as well as other types of 
measures, as discussed in section VIII.K.1.a.\975\
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    \975\ As used in this section, the term ``EE program'' refers to 
an EE deployment program. An EE program involves deployment of 
multiple EE measures or EE projects, such as utility- or state-
administered EE incentive programs that accelerate the deployment of 
EE technologies and practices. As used in this section, the term 
``EE/RE project'' refers to a discrete EE project (e.g., an EE 
upgrade to a commercial building or set of buildings) or a RE 
generator (e.g., a single wind turbine or group of turbines).
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    ERCs may be used by an affected EGU to adjust its reported 
CO2 emission rate when demonstrating compliance with a rate-
based emission standard. This adjustment is made by adding MWh to the 
denominator of an affected EGU's reported CO2 emission rate, 
in the amount of submitted ERCs, resulting in a lower adjusted rate. To 
demonstrate compliance with a rate-based emission standard, an affected 
EGU would report its CO2 lb/MWh emission rate to the state 
regulatory body, and would also surrender to the state any ERCs it 
wishes to use to adjust its reported emission rate. The state regulator 
would then cancel the submitted ERCs. The affected EGU would add the 
MWh the ERCs represent to the denominator of its reported 
CO2 lb/MWh emission rate to demonstrate compliance with its 
emission standard. The state regulator could facilitate its evaluation 
of the affected EGU's compliance (as well as evaluation by the affected 
EGU, the EPA, and others) by providing functionality in its tracking 
system to run such compliance calculations. If the affected EGU's 
adjusted CO2 emission rate is equal to or lower than its 
applicable emission rate standard, the affected EGU would be in 
compliance.
    a. Issuance of ERCs to affected EGUs.
    ERCs may be issued to affected EGUs that emit below a specified 
CO2 emission rate, as discussed below. For issuance of ERCs 
to affected EGUs, the state plan must specify the accounting method and 
administrative process for ERC issuance. This includes the

[[Page 64905]]

calculation method for determining the number of ERCs to be issued to 
an affected EGU, based on reported CO2 emissions and MWh 
energy output, in comparison to a reference CO2 emission 
rate. The reference rate is a specified CO2 lb/MWh emission 
rate that an affected EGU's reported CO2 emission rate is 
compared to, when determining the amount of ERCs that may be issued to 
an affected EGU.
    Following determination of the number of ERCs an affected EGU is 
eligible to receive, based on an affected EGU's reported CO2 
emission rate compared to a specified reference rate, the state 
regulatory body would issue those ERCs into a tracking system account 
held by the owner or operator of the affected EGU. Tracking system 
requirements are addressed below at section VIII.K.2.c.
    The accounting method that may be applied in a state plan differs 
depending on whether a state plan includes a single rate-based emission 
standard that applies to all affected EGUs (e.g., if a plan is designed 
to meet a state rate-based CO2 goal) or separate rate-based 
emission standards that apply to subcategories of affected EGUs, namely 
fossil fuel-fired electric utility steam generating units and 
stationary combustion turbines. In both cases, ERCs are issued in MWh, 
based on the difference between an affected EGU's reported 
CO2 emission rate (in CO2 lb/MWh) and a specified 
CO2 lb/MWh emission rate that the reported rate is compared 
to (referred to as a ``reference rate''). The reference rate may be an 
affected EGU's assigned CO2 emission limit rate or another 
CO2 emission rate, as described below. Where an affected 
EGU's reported CO2 emission rate is lower than the specified 
reference CO2 emission rate, ERCs may be issued.
    Where a state plan includes emission standards in the form of a 
single rate-based emission standard that applies to all affected EGUs, 
the reference rate is the CO2 emission rate limit for 
affected EGUs. In this instance, ERCs may be issued based on an 
affected EGU's reported CO2 emission rate as a proportion of 
the emission limit rate. For example, if the emission rate limit is 
2,000 lb CO2/MWh and the affected EGU emits at a rate of 
1,000 lb CO2/MWh, 0.5 MWh would be awarded for every MWh 
generated by the affected EGU. ERCs would be issued to affected EGUs in 
whole MWh increments. The calculation method is as follows:
    ERCs \976\ = reported MWh by affected EGU \977\ x ((CO2 
emission rate limit for affected EGUs \978\--affected EGU reported 
CO2 emission rate \979\)/CO2 emission rate limit 
for affected EGUs)
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    \976\ For all calculations in this section, where the result is 
a negative value, no ERCs would be issued.
    \977\ This term represents the reported MWh by the affected EGU 
on an annual basis.
    \978\ This term represents the ``reference rate.''
    \979\ This term represents the annual reported CO2 
emission rate of the affected EGU.
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    For the example above, the calculation is as follows:

    ERCs = MWh reported x (2,000-1,000)/2,000 = MWh reported x 0.5

    If the affected EGU in this example generated 1,000,000 MWh, 
500,000 ERCs would be issued.
    Where a state plan includes separate emission standards for 
subcategories of affected EGUs, specifically affected fossil fuel-fired 
electric utility steam generating units and stationary combustion 
turbines, the reference rate differs for affected fossil fuel-fired 
electric utility steam generating units and stationary combustion 
turbines. Additionally, if the state plan applies emission standards 
for its affected EGUs that are equal to the subcategorized 
CO2 emission performance rates there is a unique opportunity 
for the adjustment of an affected EGU's emission rate using ERCs that 
are generated as a result of building block 2 incremental NGCC unit 
operation. The EPA is requiring state plans to account for incremental 
NGCC generation in ERC generation if a state plan applies the 
subcategorized CO2 emission performance rates to its 
affected EGUs as emission standards. Additionally, the EPA is requiring 
that a NGCC unit is not able to use ERCs generated by it or any other 
NGCC unit's building block 2 incremental generation.
    For affected steam generating units, the reference CO2 
emission rate is the assigned CO2 emission rate limit for 
steam generating units, and the following accounting method for 
generating ERCs applies:
    ERCs \980\ = reported MWh x ((steam generating unit CO2 
emission rate limit \981\--steam generating unit reported 
CO2 emission rate)/steam generating unit CO2 
emission rate limit).
---------------------------------------------------------------------------

    \980\ For all calculations in this section, where the result is 
a negative value, no ERCs would be issued.
    \981\ The ``reference rate.''
---------------------------------------------------------------------------

    For an affected NGCC stationary combustion turbine in a 
subcategorized rate-based emission trading program, the following 
equation provides a required accounting method for generating ERCs 
based on operation with respect to the NGCC unit's emission standard:
    ERCs = NGCC unit's reported MWh--((NGCC unit's CO2 
emission standard \982\--NGCC unit's reported CO2 emission 
rate)/NGCC unit's CO2 emission standard)
---------------------------------------------------------------------------

    \982\ The ``reference rate.''
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    According to this equation, ERC issuance is assessed based on the 
difference between the CO2 emission rate standard for the 
NGCC unit \983\ and the reported CO2 emission rate of the 
affected NGCC unit. In other words, affected NGCC stationary combustion 
turbines earn ERCs for generation when they perform at an emission rate 
better than the reference rate for stationary combustion turbines, 
similarly to how affected steam units can earn ERCs.
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    \983\ This is the CO2 emission performance rate for 
affected stationary combustion turbines in the emission guidelines.
---------------------------------------------------------------------------

    In a subcategorized rate-based emission trading program, a state 
must use the incremental operation of an affected NGCC unit quantified 
for building block 2 to allow a NGCC unit to generate ERCs based on its 
expected incremental generation.
    A state plan that provides for the use of ERCs issued based on 
incremental affected NGCC generation must provide a required 
calculation method that allows for issuance of ERCs based on the 
ability of incremental generation from affected stationary combustion 
turbines to substitute for generation from affected steam generating 
units (as represented in building block 2), while also respecting the 
fact that affected stationary combustion turbines must also meet an 
assigned CO2 emission rate limit for the entirety of its MWh 
energy output. This accounting method must reflect the application of 
the BSER, as described in section V, and the accounting method must not 
create incentives to rearrange dispatch between existing NGCC units to 
generate additional ERCs without changing the overall level of NGCC 
generation.
    The EPA will review whether a state's accounting method is 
approvable per the requirements of the statute and this final rule as 
part of its overall plan review of the rate-based emission standards 
and implementing and enforcing measures in the state plan. The EPA 
notes that the proposed model rule for a rate-based emission trading 
program includes a proposed accounting method and takes comments on 
alternatives. The accounting method provided in a final model rule 
could be a presumptively approvable approach for issuance of ERCs based 
on the ability of incremental generation from affected stationary 
combustion turbines to

[[Page 64906]]

substitute for generation from affected steam generating units. A 
state's accounting requirements for generation of ERCs based on 
incremental affected NGCC generation must maintain consistency with the 
EPA's application of the BSER when calculating CO2 emission 
performance rates for affected stationary combustion turbine and steam 
generating units. In particular, a state's accounting method must 
maintain consistency of accounting in a state rate-based CO2 
emission standard with the EPA's application of building block 2 in 
calculating CO2 emission performance rates for affected 
fossil fuel-fired electric utility steam generating units and 
stationary combustion turbines, which is based on use of incremental 
generation from affected stationary combustion turbine to replace 
generation from affected steam generating units.
    b. Issuance of ERCs for RE, demand-side EE, and other measures.
    ERCs may be issued for qualifying measures.\984\ For issuance of 
ERCs for qualifying measures, state plan requirements for ERC issuance 
must include a two-step process. In the first step of the process, a 
potential ERC provider submits an eligibility application for a 
qualifying program or project \985\ to the administering state 
regulator (or its agent \986\). The state regulator reviews the 
application to determine whether, in this example, an EE/RE program or 
project meets eligibility requirements for the issuance of ERCs.\987\ 
An eligibility application must include a description of the program or 
project, a projection of the MWh generation or energy savings 
anticipated over the life of the program or project, and an EM&V plan 
that meets state plan requirements. The EM&V plan must describe how MWh 
of RE generation or energy savings resulting from the program or 
project will be quantified and verified.\988\ A state, in its emission 
standard regulations, must include requirements for EM&V plans that are 
consistent with the requirements in the emission guidelines for EE/RE 
measures and other eligible measures, as discussed in sections VIII.K.1 
and VIII.K.3.
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    \984\ Qualifying measures that can be used to adjust the 
CO2 emission rate of an affected EGU are discussed at 
section VIII.K.1, and include incremental NGCC, RE, demand-side EE, 
and other measures, such as DSM, CHP and incremental nuclear 
generation.
    \985\ For example, for an EE/RE program or project, as described 
in this section for illustrative purposes. The requirements 
described in this section for EE/RE programs and projects also apply 
for all other eligible qualifying measures discussed in section 
VIII.K.1.
    \986\ As used here, an agent is a party acting on behalf of the 
state, based on authority vested in it by the state, pursuant to the 
legal authority of the state. A state could designate an agent to 
provide certain limited administrative services, or could choose to 
vest an agent with greater authority. Where an agent issues an ERC 
on behalf of the state, such issuance would have the same legal 
effect as issuance of an ERC by the state.
    \987\ The entity implementing the EE/RE program or project 
(referred to in the preamble as a ``provider'') would submit the 
application. This is the identified entity to which ERCs would 
ultimately be issued, to a tracking system account held by the 
entity. Such entities could include a wide variety of parties that 
implement EE/RE programs and projects, including owners or operators 
of affected EGUs, electric distribution companies, independent power 
producers, energy service companies, administrators of state EE 
programs, and administrators of industrial EE programs, among 
others.
    \988\ The verification process includes confirmation that 
quantified MWh are non-duplicative and permanent (i.e., are not 
being used in any other state plan to demonstrate compliance with an 
emission standard or achievement of an emission performance rate or 
state CO2 emission goal).
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    The EPA has determined that state requirements for an eligibility 
application must include review of the application by an independent 
verifier, approved by the state as eligible per the requirements of the 
final emission guidelines to provide such verification, prior to 
submittal. This requirement builds on the approach used for assessing 
GHG offset projects, both in international emission trading programs 
and the GHG emission budget trading programs implemented by California 
and the RGGI participating states.\989\ An assessment by an independent 
verifier would be included as a component of an eligibility 
application.
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    \989\ Information about the verification process for GHG offsets 
under the RGGI program, including verifier accreditation 
requirements and access to relevant documents, is available at 
http://www.rggi.org/market/offsets/verification. Similar information 
about the verification process for GHG offsets under the California 
program is available at http://www.arb.ca.gov/cc/capandtrade/offsets/verification/verification.htm.
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    The EPA has determined that independent verification requirements 
are necessary to ensure the integrity of state rate-based emission 
trading programs included in a state plan, given the wide range of 
eligible measures that may generate ERCs and the broad geographic 
locations in which those measures may occur. Inclusion of an 
independent verification component provides technical support for state 
regulatory bodies to ensure that eligibility applications and M&V 
reports are thoroughly reviewed prior to issuance of ERCs. Inclusion of 
an independent verification component is also consistent with similar 
approaches required by state PUCs for the review of demand-side EE 
program results and GHG offset provisions included in state GHG 
emission budget trading programs.
    State plans with rate-based emission trading programs must include 
requirements regarding the qualification status of an independent 
verifier. An independent verifier is a person (including any company, 
any corporate parent or subsidiary, any contractors or subcontractors, 
and the actual person) who has the appropriate technical and other 
qualifications to provide verification reports. The independent 
verifier must not have, or have had, any direct or indirect financial 
or other interest in the subject of its verification report or ERCs 
that could impact its impartiality in performing verification services. 
State plans must require that a person be approved by the state as an 
independent verifier, as defined by this final rule, as eligible to 
perform the verifications required under the approved state plan. State 
plans must also include a mechanism to temporarily or permanently 
revoke the qualification status of an independent verifier, such that 
it can no longer provide verification services related to an 
eligibility application or M&V report for at least the duration of the 
period it does not meet the qualification requirements for independent 
verifiers in an approved state plan. The EPA's proposed model rate-
based emission trading rule contains provisions addressing 
accreditation and conflicts of interest for independent verifiers. 
State plans that adopt the finalized model rule could be presumptively 
approvable with respect to these requirements regarding independent 
verifiers.
    The state's eligibility requirements and application procedures 
must ensure that only eligible actions may generate ERCs and that 
documentation is submitted only once for each program or project, and 
to only one state program.\990\ These provisions will ensure that 
actions that are eligible for the issuance of ERCs are ``non-
duplicative.'' \991\ The tracking system used to administer a state's 
rate-based emission trading system must provide transparent, 
electronic, public access to information about program and project 
eligibility applications, including EM&V plans, and regulatory approval 
status.
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    \990\ This includes ensuring that multiple parties do not submit 
an eligibility application for the same EE program or project, or 
for the same RE generator.
    \991\ Emission standards must be ``non-duplicative'' as 
described in section VIII.D.2.
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    In the second step of the process, following implementation of the 
RE/EE program or project (as described in this example) that was 
approved in step one, the RE/EE provider periodically submits a M&V 
report to the state regulatory body documenting the results of the

[[Page 64907]]

program or project in MWh of electric generation or energy 
savings.\992\ These results are quantified according to the EM&V plan 
that was approved as part of step one. These results are verified by an 
accredited independent verifier, and its verification assessment must 
be included as part of the M&V report submitted to the state regulatory 
body. The administering state regulator (or its agent) then reviews the 
M&V report, and determines the number of ERCs (if any) that should be 
issued, based on the report. Finally, the state regulatory body (or its 
agent) issues ERCs to the provider of the approved program or project. 
These ERCs are issued to the tracking system account held by the 
program or project provider.
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    \992\ State rate-based emission trading program regulations must 
specify the frequency for submission of M&V reports for approved 
qualified measures that have been deemed eligible to generate ERCs. 
These reporting periods should be annual, but a state could consider 
shorter or longer periods, depending on the type of ERC resource.
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    State plan requirements must ensure that only one ERC is issued for 
each verified MWh. This is addressed through registration in the 
tracking system of programs and projects that have been qualified for 
the issuance of ERCs, to ensure that documentation is submitted only 
once for each RE/EE action, and to only one state program.\993\ The 
tracking system must provide transparent electronic public access to 
submitted M&V reports and regulatory approvals related to such 
reports.\994\ Such reports are the basis for issuance of ERCs.
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    \993\ EE/RE programs and projects, and other eligible measures, 
with an approved eligibility application would be designated in a 
tracking system as qualified programs or projects. Qualified 
programs and projects may be issued ERCs, based on approved M&V 
reports.
    \994\ This must include electronic Internet access to such 
information in the tracking system.
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    c. Tracking system requirements.
    State requirements must include provisions to ensure that ERCs 
issued to any eligible entity are properly tracked from issuance to 
submission by affected EGUs for compliance (where ERCs are 
``surrendered'' by the owner or operator of an affected EGU and 
``retired'' or ``cancelled''), to ensure they are only used once to 
meet a regulatory obligation. This is addressed through specified 
requirements for tracking system account holders, ERC issuance, ERC 
transfers among accounts, compliance true-up for affected EGUs,\995\ 
and an accompanying tracking system that meets requirements specified 
in the emission trading program regulations. Each issued ERC must have 
a unique identifier (e.g., serial number) and the tracking system must 
provide for traceability of issued ERCs back to the program or project 
for which they were issued.
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    \995\ ``Compliance true-up'' refers to ERC submission by an 
owner or operator of an affected EGU to adjust a reported 
CO2 emission rate, and determination of whether the 
adjusted rate is equal to or lower than the applicable rate-based 
emission standard.
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    The EPA received a number of comments from states and stakeholders 
about the value of the EPA's support in developing and/or administering 
tracking systems to support state administration of rate-based emission 
trading systems. This could include regional systems and/or a national 
system. The EPA is exploring options for providing such support and is 
conducting an initial scoping assessment of tracking system support 
needs and functionality.
    d. Effect of improperly issued ERCs.
    Because the goal of this rulemaking is the actual reduction of 
CO2 emissions, it is fundamental that ERCs represent the MWh 
of energy generation or savings they purport to represent. To this end, 
only valid ERCs that actually meet the standards articulated in this 
rule may be used to satisfy any aspect of compliance by an affected EGU 
with emission standards. Despite safeguards included in the structure 
of ERC issuance and tracking systems, such as the review of eligibility 
applications and M&V reports, and state issuance of ERCs, ERCs may be 
issued that do not, in fact, represent eligible zero-emission MWh as 
required in the emission guidelines. A variety of situations may result 
in such improper ERC issuance, ranging from simple paperwork errors to 
outright fraud.
    An approvable state plan that allows affected EGUs to comply with 
their emission standards in part through reliance on ERCs must include 
provisions making clear that an affected EGU may only demonstrate 
compliance with an ERC that represents the one MWh of actual energy 
generation or savings that it purports to represent and otherwise meets 
the emission guidelines.
    e. Banking of ERCs.
    ERCs issued in 2022 or a subsequent year may be carried forward (or 
``banked'') and used for demonstrating compliance in a future 
year.\996\ For example, an ERC issued for a MWh of RE generation that 
occurs in 2022 may be applied to adjust a CO2 emission rate 
in 2023 or future years without limitation. ERCs may be banked from the 
interim plan performance period to the final plan performance period. 
Banking provides a number of advantages while ensuring that the same 
output-weighted average CO2 emission rates of the interim 
and final state CO2 goals are achieved over the course of a 
state plan. Banking provisions have been used extensively in rate-based 
environmental programs and mass-based emission budget trading 
programs.\997\ This is because banking reduces the cost of attaining 
the requirements of the regulation. The EPA has determined that the 
same rationale and outcomes apply under a CO2 emission rate 
approach, in that allowing banking will reduce compliance costs. 
Banking encourages additional emission reductions in the near-term if 
economic to meet a long-term emission rate constraint, which is 
beneficial due to social preferences for environmental improvements 
sooner rather than later.\998\ State plans must specify whether the 
state is allowing or restricting the banking of ERCs between compliance 
periods for affected EGUs. State plans must also prohibit borrowing of 
any ERCs from future compliance periods by affected EGUs or eligible 
resources.
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    \996\ States also have the option to participate in the CEIP, 
under which they can issue ERCs for MWh generation or savings that 
occur in 2020-2021 for measures implemented following submission of 
a final state plan, and receive matching ERCs from a federal pool. 
See section VIII.B.2 for a detailed discussion. The ERCs issued 
under this program can also be banked during and between the interim 
and final compliance period.
    \997\ Banking under mass-based emission budget trading programs, 
and the rationale for banking provisions, is addressed below in 
section VIII.J.2.c.
    \998\ The absence of banking creates an incentive to defer both 
relatively low-cost and higher-cost CO2 emission 
reduction actions until a later period when emission rate limits 
become more stringent, rather than incentives to undertake the low-
cost activities sooner in order to further delay the high cost 
actions. Under a rate-based emission trading program, banking will 
encourage ERC providers to generate larger numbers of ERCs in early 
years of a plan performance period, in anticipation of rising ERC 
prices over time, when demand for ERCs is expected to increase as 
rate-based CO2 emission standards become more stringent.
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    f. Considerations for ERC issuance.
    The EPA notes that state-administered and state-overseen EE 
programs, such as those administered by state-regulated electric 
distribution utilities, could play a key role in supplying energy 
savings to a rate-based emission trading system in the form of ERCs. 
These programs have been the primary means for delivering EE programs 
and energy savings at scale, and also allow for a state to conduct a 
portfolio planning process to guide EE program design and focus in a 
manner that best provides multiple benefits to electricity ratepayers 
in a state. Such portfolio planning processes typically treat EE as an 
energy resource comparable to electricity generation.

[[Page 64908]]

    The EPA also notes that non-ERC certificates may be issued by 
states and other bodies for MWh of energy generation and energy savings 
that are used to meet other state regulatory requirements, such as 
state RPS and EERS, or by individuals to make environmental or other 
claims in voluntary markets.
    The EPA defines an ERC in the emission guidelines as a tradable 
compliance instrument that represents a zero-emission MWh (for the 
purposes of meeting the emission guidelines) from a qualifying measure 
that may be used to adjust the reported CO2 emission rate of 
an affected EGU subject to a rate-based emission standard in an 
approved state plan under CAA section 111(d). The sole purpose of an 
ERC is for use by an affected EGU in demonstrating compliance with a 
rate-based emission standard in such an approved state plan.
    An ERC is issued separately from any other instruments that may be 
issued for a MWh of energy generation or energy savings from a 
qualifying measure. Such other instruments may be issued for use in 
meeting other regulatory requirements (e.g., such as state RPS and EERS 
requirements) or for use in voluntary markets. An ERC may be issued 
based on the same data and verification requirements used by existing 
REC and EEC tracking systems for issuance of RECs and EECs.
    The EPA notes that the definitions of other instruments, such as 
RECs, differ (as established under state statute, regulations, and PUC 
orders) and that requirements under state regulatory programs that use 
such instruments, such as state RPS, also differ. As a result, states 
may want to assess, when developing their state plan, how such existing 
instruments may interact with ERCs. For example, a state may want to 
assess how issuance of ERCs pursuant to a state plan may interact with 
compliance with a state RPS by entities affected under relevant state 
RPS regulations or PUC orders. The interaction of other instruments and 
ERCs may also impact existing or future arrangements in the private 
marketplace. Actions taken by states, separate from the design of their 
state plan, could address a number of these potential interactions. For 
example, state RPS regulations that specify a REC for a MWh of RE 
generation, and the attributes related to that MWh, may or may not 
explicitly or implicitly recognize that the holder of the REC is also 
entitled to the issuance of an ERC for a MWh of electricity generation 
from the eligible RE resource. This could impact existing and future RE 
power purchase agreements or REC purchase agreements. Such interactions 
among existing instruments and ERCs could also impact how marketing 
claims are made in the voluntary RE market. How a state might choose to 
address these potential interactions will depend on a number of 
factors, including the utility regulatory structure in the state, 
existing statutory and regulatory requirements for state RPS, and 
existing RE power purchase agreements and REC contracts.
    g. Program review.
    The EPA is requiring that states periodically review the 
administration of their rate-based emission trading programs. The 
results of these program reviews must be submitted by states to the EPA 
as part of their required reports on the implementation of their state 
plans, as described in sections VIII.D.a.(5) and VIII.D.2.b.(4), and 
must be made publicly available. Such a review submitted as part of a 
required state report provides for the implementation of rate-based 
emission standards per the requirements of CAA section 111(d)(2). For a 
rate-based emission trading program, the review must cover the 
reporting period addressed in the state's periodic reports to the EPA 
on plan implementation.
    The program review must address all aspects of the administration 
of a state's rate-based emission trading program, including the state's 
evaluations and regulatory decisions regarding eligibility applications 
for ERC resources and M&V reports (and associated EM&V activities), and 
the state's issuance of ERCs. The program review must assess whether 
the program is being administered properly in accordance with the 
state's approved plan; whether ERC eligibility applications and M&V 
reports are being properly evaluated and acted upon (i.e., approved or 
disapproved); whether reported annual MWh of generation and savings 
from qualified ERC resources are being properly quantified, verified, 
and reported in accordance with approved EM&V plans, and whether 
appropriate records are being maintained. The program review must also 
address determination of the eligibility of verifiers by the state and 
the conduct of verifiers, including the quality of verifier reviews. 
Where significant deficiencies are identified by the state's program 
review, those deficiencies must be rectified by the state in a timely 
manner.
    States must collect, compile, and maintain sufficient data in an 
appropriate format to support the periodic program review. The EPA will 
review the results of each program review. The EPA may also audit a 
state's administration of its rate-based emission trading program and 
pursue appropriate remedies where significant deficiencies are 
identified.
3. EM&V Requirements for RE, Demand-Side EE, and Other Measures Used To 
Adjust a CO2 Rate
    This section discusses EM&V for RE, demand-side EE, and other 
measures that are used to generate ERCs or otherwise adjust an emission 
rate.\999\ EM&V is applied for purposes of quantifying and verifying 
MWh in rate-based state plans, as described below. Rate-based state 
plans must require that eligible resources document in EM&V plans and 
M&V reports how all MWh saved and generated from eligible measures will 
be quantified and verified. Additionally, with respect to EM&V, the 
EPA's proposed model rule identifies certain industry best practices 
that, upon finalization, could be adopted as presumptively approvable 
components of a state plan.\1000\
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    \999\ EM&V is defined to mean the set of procedures, methods, 
and analytic approaches used to quantify the MWh from demand-side EE 
and RE and other measures, and thereby ensure that the resulting 
savings and generation are quantifiable and verifiable.
    \1000\ The EPA recognizes that EM&V best practices are routinely 
evolving to reflect changes in markets, technologies and data 
availability. Therefore the agency is providing draft EM&V guidance 
with the proposed model rule, which can be updated over time to 
address any such changes to best practices. The guidance can also 
identify and describe alternative quantification approaches that may 
be approved for use, provided that such approaches meet the 
requirements of the finalized EM&V requirements.
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    As discussed in section VIII.K.1, quantified and verified MWh of RE 
generation, EE savings,\1001\ and other eligible measures may be used 
to adjust a CO2 emission rate when demonstrating compliance 
with the emission guidelines. In states implementing emission standard 
type plans with rate-based trading, affected EGUs adjust their reported 
emission rate using ERCs, which represent MWh that are quantified and 
verified according to the EM&V requirements described in this section. 
The EPA will evaluate the overall approvability of the state plan 
taking into consideration whether the state's submitted EM&V 
requirements satisfy these final emission guidelines.
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    \1001\ In the context of demand-side EE, ``measure'' refers to 
an installed piece of equipment or system at an end-use energy 
consumer facility, a strategy intended to affect consumer energy use 
behaviors, or a modification of equipment, systems or operations 
that reduces the amount of electricity that would have delivered an 
equivalent or improved level of end-use service in the absence of 
EE.
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    a. Discussion of proposed EM&V approach and public comment.
    The EPA proposed that a state plan that incorporates RE and demand-
side

[[Page 64909]]

EE measures must include an EM&V plan that explains how the effect of 
these measures will be determined in the course of plan implementation. 
The proposal sought comment on the suitability of current state and 
utility EM&V approaches for RE and demand-side EE programs in the 
context of an approvable state plan, and on whether harmonization of 
state approaches, or supplemental actions and procedures, should be 
required in an approvable state plan, provided that supporting EM&V 
documentation meets applicable minimum requirements. In the proposal, 
the EPA also indicated that it would issue guidance to help states, 
sources, and project providers quantify and verify MWh savings and 
generation resulting from zero-emitting RE and demand-side EE efforts.
    The proposal and associated ``State Plans Considerations'' TSD 
\1002\ suggested that the EPA's EM&V requirements could leverage 
existing industry practices, protocols, and tracking mechanisms 
currently utilized by the majority of states implementing RE and 
demand-side EE. The EPA further noted that many state regulatory bodies 
and other entities already have significant EM&V infrastructure in 
place and have been applying, refining, and enhancing their evaluation 
and quality assurance approaches for over 30 years, particularly with 
regard to the quantification and verification of energy savings 
resulting from utility-administered EE programs. The proposal also 
observed that the majority of RE generation is typically quantified and 
verified using readily available, reliable, and transparent methods 
such as direct metering of MWh.
---------------------------------------------------------------------------

    \1002\ See discussion beginning on p. 34 of the State Plan 
Considerations TSD for the Clean Power Plan Proposed Rule: http://www2.epa.gov/carbon-pollution-standards/clean-power-plan-proposed-rule-state-plan-considerations.
---------------------------------------------------------------------------

    As a result, the agency took comment on whether this infrastructure 
is appropriate in the context of approvable state plans for use in 
rate-based state plans that include RE, demand-side EE, and other 
measures. The majority of commenters addressing this question responded 
affirmatively, indicating that existing EM&V infrastructure is 
appropriate to assure quality, credibility, and integrity. However, 
commenters also noted that EM&V methods are routinely improving and 
changing over time, and that the EPA's requirements and guidance should 
be responsive to such changes, should avoid locking in outdated 
methods, and should be updated to maintain relevance.
    Another point made by commenters is that, despite the observed 
improvements in EM&V over time, quantification knowledge is more robust 
for some EE program and policy types than for others. Additionally, 
there is relatively limited experience applying EM&V protocols and 
procedures to emission trading programs, where each MWh of replaced 
generation can be bought and sold by a regulated source. As a result, 
the EPA's final emission guidelines and proposed model rule include a 
number of safeguards and quality-control features that are intended to 
ensure the accuracy and reliability of quantified EE savings.
    b. Requirements for EM&V and M&V submittals.
    As discussed in section VIII.K.2, these final guidelines require 
that state plans include a requirement that EM&V plans and M&V reports 
be submitted to the state for rate-based emission trading programs. 
States must require that at the initiation of an eligible measure, 
project providers must develop and submit to the state an EM&V plan 
that documents how requirements for quantification and verification 
will be carried out over the period that MWh generation or savings are 
produced. States must also require that after a project or program is 
implemented, the provider must submit periodic M&V reports to confirm 
and describe how each of the requirements was applied. These reports 
must also specify the actual MWh savings or generation results, as 
quantified by applying EM&V methods on a retrospective (ex-post) basis. 
States may not allow MWh values that are quantified using ex-ante (pre-
implementation) estimates of savings. As previously described, the EPA 
took comment on the suitability of current state and utility EM&V 
approaches for RE and demand-side EE programs in the context of an 
approvable state plan. These final requirements regarding EM&V plans 
and M&V reports are intended to leverage and closely resemble those 
already in routine use.
    For energy generating resources, including RE resources, states may 
leverage the programs and infrastructure they have in place for 
achievement of their RPS and take advantage of registries in place for 
the issuance and tracking of RECs. Many existing REC tracking systems 
already include well-established safeguards, documentation 
requirements, and procedures for registry operations that could be 
adapted to serve similar functions in relation to the final emission 
guidelines. For example, a key element of RPS compliance in many states 
that parallels the final rule's requirements is that each generating 
unit must be uniquely identified and recorded in a specified registry 
to avoid the double counting of credits at the time of issuance and 
retirement. In addition, the existing reports and documentation from 
tracking systems may, together with eligible independent third party 
verification reports, serve as the substantive basis for eligibility 
applications, EM&V plans and M&V reports for the issuance of ERCs to 
energy generating resources for affected EGUs to meet their obligations 
under the final rule. With respect to actual monitoring requirements, 
many existing REC registries include provisions for the monitoring of 
MWh of generation that would be appropriate to meet state plan 
requirements pursuant to the final rule, such as requirements to use a 
revenue quality meter.
    For demand-side EE, states must require that EM&V plans that are 
developed for purposes of adjusting an emission rate under this final 
rule include several specific components. The EPA notes these 
components reflect existing provisions in a wide range of publicly or 
rate-payer funded EE programs and energy service company projects. One 
of these components state plans must require is a demonstration of how 
savings will be quantified and verified by applying industry best-
practice protocols and guidelines, as well as an explanation of the key 
assumptions and data sources used. State plans must require EM&V plans 
to include and address the following:

     A baseline that represents what would have happened in 
the absence of the EE intervention, such as the equipment that would 
most likely have been installed--or that a typical consumer or 
building owner would have continued using--in a given circumstance 
at the time of EE implementation
     The effects of changes in independent factors affecting 
energy consumption and savings; that is, factors not directly 
related to the EE action, such as weather, occupancy, or production 
levels
     The length of time the EE action is anticipated to 
continue to remain in place and operable, effectively providing 
savings (in years)

    Examples and discussion of industry best-practices for executing 
each of the above-listed components is provided in the EPA's draft EM&V 
guidance for demand-side EE, which is being released in conjunction 
with the proposed model rule. The model trading rule defines certain 
EM&V provisions for demand-side EE, as well as specific provisions for 
non-affected CHP and RE resources, including incremental hydroelectric 
power, biomass RE facilities, and waste-to-energy facilities,

[[Page 64910]]

that may be presumptively approvable upon finalization.
    The EPA notes that state plans incorporating the finalized model 
rule for rate-based emission trading programs could be presumptively 
approvable as meeting the requirements of CAA section 111(d) and the 
EM&V provisions in these emission guidelines. The EPA will evaluate the 
approvability of such state plans through independent notice and 
comment rulemaking.
    c. Skill certification standards.
    Using a skilled workforce to implement demand-side EE and RE 
projects and other measures intended to reduce CO2 
emissions, and to evaluate, measure, quantify and verify the savings 
associated with EE projects or the additional generation from 
performance improvements at existing RE projects are both important in 
existing best industry practices. Several commenters pointed out that 
skill certification standards can help to assure quality and 
credibility of demand-side EE, RE, and other CO2 emission 
reduction projects. The EPA also recognizes that a skilled workforce 
performing the EM&V is important to substantiate the authenticity of 
emissions reductions.
    The EPA is therefore recommending in conjunction with the EM&V 
requirements discussed in this section, that states are encouraged to 
include in their plans a description of how states will ensure that the 
skills of workers installing demand-side EE and RE projects or other 
measures intended to reduce CO2 emissions as well as the 
skills of workers who perform the EM&V of demand-side EE and RE 
performance will be certified by a third party entity that:

    (1) Develops a competency based program aligned with a job task 
analysis and certification scheme;
    (2) Engages with subject matter experts in the development of 
the job task analysis and certification schemes that represent 
appropriate qualifications, categories of the jobs, and levels of 
experience;
    (3) Has clearly documented the process used to develop the job 
task analysis and certification schemes, covering such elements as 
the job description, knowledge, skills, and abilities;
    (4) Has pursued third-party accreditation aligned with 
consensus-based standards, for example ISO/IEC 17024.

    Examples of such entities include: Parties aligned with the 
Department of Energy's (DOE) Better Building Workforce Guidelines and 
validated by a third party accrediting body recognized by DOE; or by an 
apprenticeship program that is registered with the federal Department 
of Labor (DOL), Office of Apprenticeship; or with a state 
apprenticeship program approved by the DOL, or by another skill 
certification validated by a third party accrediting body. This can 
help to substantiate the authenticity of emission reductions due to 
demand-side EE and RE and other CO2 emission reduction 
measures.
4. Multi-State Coordination: Rate-Based Emission Trading Programs
    Individual rate-based state plans may provide for the interstate 
transfer of ERCs, which would enable an ERC issued by one state to be 
used for compliance by an affected EGU with a rate-based emission 
standard in another state. Such plans would include regulatory 
provisions in each state's emission standard requirements that indicate 
that ERCs issued in other partner states may be used by affected EGUs 
for compliance. Such plans must indicate how ERCs will be tracked from 
issuance through use for compliance, through either a joint tracking 
system, interoperable tracking systems, or an EPA-administered tracking 
system.\1003\
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    \1003\ The emission standards in each individual state plan must 
include regulatory provisions that address the issuance of ERCs and 
tracking of ERCs from issuance through use for compliance, as 
described in section VIII.K.2. The description here addresses how 
those regulatory provisions will be implemented through the use of a 
joint tracking system, interoperable tracking systems, or an EPA-
administered tracking system.
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    The approaches described in this section are only allowed for 
states that impose rate-based emission limits for affected EGUs that 
are equal to the CO2 emission performance levels in the 
emission guidelines. This approach is necessary to ensure that each 
state that is allowing for the interstate transfer of ERCs is 
implementing rate-based emission standards for affected EGUs at the 
same lb CO2/MWh level.\1004\ This assures that all the 
participating states are issuing ERCs to affected fossil steam and NGCC 
units that emit below their assigned emission standards on the same 
basis.
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    \1004\ States also have the option of implementing a multi-state 
plan with a single rate-based emission standard that applies to all 
affected EGUs in the participating states. This approach would also 
allow for interstate transfers of ERCs. Under this approach, a rate-
based multi-state plan would include emission standards for affected 
EGUs based on a weighted average rate-based emission goal, derived 
by calculating a weighted average CO2 emission rate based 
on the individual rate-based goals for each of the participating 
states and 2012 generation from affected EGUs.
---------------------------------------------------------------------------

    This approach avoids providing different incentives, in the form of 
issued ERCs, to affected steam generating units and NGCC units in 
different states that have comparable CO2 emission rates. 
Providing different incentives to similar affected EGUs across states 
could create distortionary effects that lead to shifts in generation 
among states based on the different CO2 emission rate 
standards applied by states to similar types of affected EGUs. 
Providing for the interstate trading of ERCs in this instance would 
exacerbate these distortionary effects by providing arbitrage 
opportunities.
    When demonstrating that a state's CO2 emission goal is 
achieved as a result of plan implementation, a state with linkages to 
other states would be required to demonstrate that any ERCs issued by 
another state that are used by affected EGUs in the state for 
compliance with its rate-based CO2 emission standards were 
issued by states with an EPA-approved state plan.\1005\
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    \1005\ This could be done by reference to data in the tracking 
system used to implement a state's rate-based emission trading 
program that identifies the origin of each ERC (e.g., by serial 
identifier).
---------------------------------------------------------------------------

    States could implement these linkages among state plans with rate-
based emission trading systems through three different implementation 
approaches: (1) Plans that are ``ready-for-interstate-trading;'' (2) 
plans that include specified bilateral or multilateral linkages; and 
(3) plans that provide for joint ERC issuance among states with 
materially consistent regulations. These approaches are summarized 
below:

     Ready-for-interstate-trading plans: A state plan 
recognizes ERCs issued by any state with an EPA-approved plan that 
also uses a specified EPA-approved \1006\ or EPA-administered 
tracking system. Plans are approved individually. A state plan need 
not designate the individual states by name from which it would 
accept issued ERCs. States can join such a coordinated approach over 
time, without the need for plan revisions.\1007\
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    \1006\ The EPA would designate tracking systems that it has 
determined adequately address the integrity elements necessary for 
the issuance and tracking of ERCs, as described in section VIII.K.2. 
Under this approach, a state could include in its plan such a 
designated tracking system, which has already been reviewed by the 
EPA.
    \1007\ The EPA notes that it is proposing a model rule for a 
rate-based emission trading program that could be used by states 
interested in implementing a ready-for-interstate-trading plan 
approach. A state plan that included the finalized rate-based model 
rule could be presumptively approvable as meeting the requirements 
of CAA section 111(d) and the emission guidelines. If a state plan 
also met the requirements described in this section for ready-for-
interstate-trading plans, it could be approved as ready-for-
interstate trading.
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     Specified bilateral linkage: States recognize ERCs 
issued by named partner states. Partner states must demonstrate that 
they use a shared tracking system, interoperable tracking systems, 
or an EPA-administered tracking system. Plans are approved 
individually, including review of the shared tracking system or 
interoperable tracking systems.
     Joint ERC issuance: States implement materially 
consistent rate-based emission

[[Page 64911]]

trading program regulations and share a tracking system. States 
coordinate their review of submissions for ERC issuance \1008\ and 
their issuance of ERCs to the shared tracking system. Issued ERCs 
are recognized as usable for compliance in all states using the 
shared tracking system. Plans are approved individually, including 
review of the shared tracking system.
---------------------------------------------------------------------------

    \1008\ This refers to eligibility applications and M&V reports, 
which are required submittals for non-affected EGU entities seeking 
the issuance of ERCs. Where affected EGUs are issued ERCs for 
emission performance below a specified CO2 emission rate, 
these ERCs are issued by the individual state in which they are 
subject to a rate-based emission standard. Requirements for ERC 
issuance are discussed in section VIII.K.2.

    These implementation approaches are designed to streamline the 
process for linking emission trading programs, avoid or limit the need 
for plan revisions as new states join a collaborative emission trading 
approach, and facilitate the development of regional or broader multi-
state markets for ERCs.\1009\
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    \1009\ The EPA also notes that individual state plans may 
utilize RE and demand-side EE (and other eligible measures), that 
occur in other states, as described in section VIII.L addressing 
interstate effects. Under an individual state plan, ERCs could be 
issued for RE and demand-side EE measures that occur in other 
states, provided the EE/RE provider submits the measures to the 
state and the measures meet requirements in the state plan's rate-
based emission trading program requirements. The multi-state 
approaches described above provide additional flexibility for states 
to informally and formally coordinate their implementation of rate-
based plans across states while retaining individual rate-based 
state goals.
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L. Treatment of Interstate Effects

    This section discusses how differing characteristics across states 
and sources could create risks of increased emissions under this rule 
through double counting of emission reduction measures or through 
foregone emission reductions due to movement of generation from source 
to source. The section also discusses how the final rule addresses 
these concerns: First, through the characteristics of goal-setting and 
the framework of state plans, and second, through specific requirements 
intended to minimize the risk of double counting and increased 
emissions.\1010\
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    \1010\ This section does not discuss emission leakage and how it 
is addressed by this final rule. See section VII.D for a discussion 
of emission leakage and its impact on state goal equivalence. See 
section VIII.J for a discussion of requirements for mass-based plans 
to address leakage.
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    The section is structured as follows. First, this section discusses 
the dynamics that cause these risks to potentially arise. Second, it 
provides a discussion of how the risks of double counting and foregone 
reductions are minimized through the following provisions: The nature 
of the final emission performance rates, multi-state plan options that 
limit distortionary effects, the structure of mass-based plan and rate-
based plan accounting for emission reductions measures, and specified 
restrictions on the counting in a rate-based plan of emission reduction 
measures located in a mass-based state. Finally, the section discusses 
how the rate-based accounting framework minimizes incentives to develop 
emission reduction measures in particular states due to differences in 
rates.
    In the June 2014 proposal, the EPA acknowledged that emission 
reduction measures implemented under a state plan will likely have 
impacts across many affected sources both within and across state 
boundaries due to the dynamic and interstate nature of the electric 
grid. These interactions may be driven in part due to differences in 
power sector dynamics across states, including the types of affected 
EGUs in a state, the availability of eligible zero-emitting resources, 
and the costs of different compliance options and existing policies in 
states. These state-level characteristics play out across dynamic 
regional grids that provide electricity across states. EGUs are 
dispatched both within and across state borders and are constantly 
adjusting behavior in response to available generation and electricity 
demand on the regional grid. Whenever CO2 emission reduction 
measures, such as RE or demand-side EE, are implemented, the measure 
can affect EGU generation and CO2 emissions across the 
regional grid. These impacts can change across multiple affected EGUs 
on a minute-to-minute, hour-to-hour, and day-to-day basis as 
electricity demand changes and different generating resources are 
dispatched. These impacts will also change in the long-term, as the 
generating fleet and load behavior change over a period of years. 
Interactions among EGUs across states may be further driven by the plan 
types (i.e., rate-based or mass-based) and the individual 
characteristics of the plans that states choose to adopt.
    In the context of this complex environment of federal and state 
policies and interstate grids, commenters expressed concern about the 
risk of double-counting of measure impacts, particularly across state 
plans. Commenters stated that there is potential for distortionary 
incentives that could undermine overall CO2 emission 
reductions (often termed emissions ``leakage''). Commenters requested 
that the EPA ensure that states avoid double-counting and minimize 
leakage effects when demonstrating achievement of state goals.
    The EPA acknowledges that some amount of shifts in generation 
between sources within and across state borders will inevitably be 
present and unavoidable in the context of this rule and may affect how 
affected EGUs achieve the applicable CO2 performance rates 
or state goals under a state plan. In fact, the definition of the BSER 
is premised upon shifts in generation across sources, particularly 
shifts from higher- to lower-emitting units that result in overall 
emission reductions. However, in the context of these shifts, the 
extent to which the movement of generation may be driven not by the 
potential to capture lower-cost emission reduction but by arbitrage 
across different emission rates, causing inefficiencies in the power 
markets and possibly eroding overall emission reductions, should be 
minimized.
    In particular, the EPA has determined final emission performance 
rates that serve to reduce relative differences between state goals, 
and thus also focus the potential for generation shifting between 
affected EGUs on achieving the emission reductions quantified in the 
BSER. In the proposal, goals differed more substantially between states 
based upon an assessment of what emission reduction potential units 
could access located within their state. Commenters observed that due 
to the interconnected nature of the power sector, units are not limited 
to such emission reduction measures within their state, and indeed any 
operational decisions that units take necessarily influence operational 
decisions at other units throughout the interconnected grid. As a 
result, in the final rule, we are finalizing CO2 emission 
performance rates, informed by regional emission reduction potential, 
for fossil fuel-fired electric utility steam generating units and 
stationary combustion turbines that are applied consistently across all 
affected EGUs. As the same source category-specific performance rates 
are applied to all units in the contiguous U.S. regardless of the state 
in which they are located, any differences between state goals in this 
final rule stem only from the relative prevalence in each state of 
fossil fuel-fired electric utility steam generating units and 
stationary combustion turbines. Consequently, there is substantially 
less incentive in this final rule for units to shift generation across 
state lines based solely on differences in state goals, since there is 
substantially less difference between the final rule's state goals, and 
since those state goals are themselves premised on nationally 
consistent

[[Page 64912]]

source category-specific performance rates.
    The EPA has also incorporated elements into the rule that seek to 
minimize double-counting and the distortionary effects that could 
potentially increase emissions. First, states have the option to adopt 
multi-state plans that reflect regional interactions while eliminating 
chances for double counting and providing a level playing field for 
trading of rate-based ERCs or mass-based allowances. Second, in the 
method for rate-based plan compliance, the rule provides a general 
accounting approach for adjusting an affected EGU's or state's 
CO2 rate that inherently acts to minimize state differences. 
These points are further discussed below.
    For both rate-based and mass-based approaches, the rule provides 
states with the option of creating either ``ready-for-interstate-
trading'' plans or multi-state plans. These options for states working 
together provide opportunities to enable protections against double 
counting and minimize the presence of distortionary effects.
    ``Ready-for-interstate-trading'' and multi-state plans engage 
multiple states in the same system for the purpose of trading mass-
based allowances or issuing and trading rate-based ERCs. This allows 
for efficient implementation of protections against double counting 
provided in state plan requirements, as multiple states are 
participating in the same tracking systems. This is particularly useful 
in the context of rate-based ERC issuance and tracking, where it must 
be ensured that the ERCs being generated are unique across rate-based 
plans.
    This final rule also reduces distortionary effects within the 
context of multi-state plans. It does so by restricting states to 
interstate trading with equivalently denominated mass-based allowances 
or rate-based ERCs. In a mass-based context, all affected EGUs will 
trade uniform mass-based allowances, whether in a ``ready-for-
interstate-trading'' plan or multi-state plan. In a rate-based plan 
context, ``ready-for-interstate-trading'' states must all adopt as 
their goal the CO2 emission performance rates as their joint 
goal. This assures that all the participating states are issuing ERCs 
using the same subcategorized performance rates, and that the sources 
in each state have equivalent incentives for trading ERCs. Similarly, 
under multi-state plans, the relevant states must choose to adopt 
identical rates, either the CO2 emission performance rates 
or a weighted average goal rate based on the rate-based goals of all 
the states involved. These requirements along with a method for 
calculating a weighted average goal rate are specified in section 
VIII.C.5.
    Under all types of state plans, states must ensure that the 
emission reduction measures counted as part of meeting their plan 
requirements are not duplicative of any measures that are counted by 
another state, in order to avoid double counting of the MWhs of 
generation or energy savings that these measure produce. Depending on 
the accounting method used to reflect these measures in state goals, 
interstate effects could still allow for the double counting of the 
emission reductions resulting from these measures, particularly if 
mathematical adjustments were made to stack emissions to reflect these 
reductions. Depending on how these measures are accounted for, the 
reductions could be counted by both the state that deployed the 
measure, and the state that reports a reduction in fossil generation or 
reported emissions. In this final rule, the accounting approaches for 
both mass-based and rate-based plans have been specifically designed to 
eliminate the risk of double counting of reductions, because emission 
reduction measures are accounted for only through their inherent impact 
on stack emissions for affected EGUs.
    Mass-based plans rely exclusively on reported stack emissions for 
determining whether a mass-based CO2 emission goal is 
achieved. This means that under a mass-based plan any emission 
reduction measures that are implemented are automatically accounted for 
in reduced stack emissions of CO2 from affected EGUs, which 
avoids concerns about counting the same mass reductions in two 
different mass-based states.
    In a rate-based plan, there needs to be an explicit adjustment of 
reported CO2 emission rates from affected EGUs, to reflect 
the measures that substitute low- or zero-emitting generation or energy 
savings for affected EGU generation. States with rate-based plans must 
demonstrate that measures used to adjust their CO2 emission 
rate, such as RE and demand-side EE, are non-duplicative. The proposal 
attempted to address this issue in part by limiting demand-side EE that 
states could claim to in-state measures. In fact, those in-state 
measures still have an impact outside of the state and under the 
proposal's approach, states would have been restricted from taking 
credit for all the measures they have put in place that reduce 
CO2 emissions. Therefore, the EPA is finalizing a treatment 
that allows states to count all in-state and out-of-state measures, 
while addressing interstate effects through the structure of the rule's 
accounting approach for adjusting the CO2 emission rate of 
an affected EGU, detailed in section VIII.K.1 above, used to show that 
the state has met its obligation under its state plan.
    The general accounting approach for adjusting the CO2 
emission rate of an affected EGU inherently accounts for the regional 
nature of how substitute generation and energy savings will impact 
affected EGU generation and CO2 emissions. The following 
discussions refer to the substituting generation and energy savings in 
question as RE and demand-side EE, but this method can apply to other 
measures that were not included in the determination of the BSER that 
substitute for affected EGU generation. The adjusted CO2 
emission rate gives credit to the affected EGU or state for the MWhs of 
RE and demand-side EE it is responsible for deploying, by allowing 
those MWhs to be added to the denominator of the CO2 rate, 
but makes no adjustment to the numerator. Instead, the numerator 
reflects reported stack emissions, which will reflect the extent to 
which RE and demand-side EE reduced the affected EGU's generation and 
emissions, without needing to account for the state in which the RE or 
demand-side EE originated, or approximating exactly how it impacted the 
regional grid. Double-counting of CO2 emission reductions is 
prevented because the reported emissions from each unit are represented 
in the numerator of each of those units' emission rates, and those real 
emissions capture whatever emission reduction impact occurred with 
regard to any particular MWh of RE or demand-side EE. Because the 
general accounting approach disallows any adjustment to any EGU's 
reported emissions, it is not possible for the real emission reductions 
prompted by any particular measure to be double-counted.
    Double-counting of MWhs in the denominator can be avoided because 
it is relatively straightforward to quantify the MWhs that the affected 
EGU is responsible for deploying and add them to the denominator, and 
this method aligns well with the MWh-denominated trading system 
described in this final rule. As long as it is assured that the MWhs of 
RE and demand-side EE are only being claimed by one affected EGU or 
state, as is outlined in section VIII.K, then there is no double-
counting of MWh. Therefore, the accounting method avoids double 
counting of both CO2 emission reductions and MWhs, the two 
characteristics of RE and demand-side EE measures that affect 
CO2 emission rates. For further discussion of the

[[Page 64913]]

MWh-based accounting method, including a calculation example, see 
section VIII.K.1.
    There may also be interactions between mass-based and rate-based 
plans regarding counting measures, specifically where measures that 
provide substitute or avoided generation, such as RE and demand-side 
EE, are located in a mass-based state and can also be used by a rate-
based state in meeting the CO2 performance rates or state 
goals. The EPA received comments on this particular issue, and many 
expressed concerns that this use of mass-based resources in a rate-
based state would result in double-counting of emission reductions.
    Commenters provided analyses specifying how two states can benefit 
from the same RE and demand-side EE measures as a result of rate- and 
mass-based plan interactions. Some commenters considered this double-
counting of emission reductions, and requested specific mathematical 
adjustments of reported generation or CO2 emissions from 
affected EGUs under either rate-based or mass-based state plans in 
order to eliminate double-counting.
    The EPA has determined that, in the context of interactions among 
rate-based and mass-based plans, there is not explicit double-counting 
of the CO2 emission reductions associated with counting 
measures located in mass-based states, considering the accounting 
methods outlined in this final rule. First, as discussed above, the 
accounting method for adjusting the CO2 emission rate only 
counts the MWhs generated by a measure to adjust the MWh in the 
denominator of the reported CO2 emission rate. The 
CO2 emissions impacts of the measures will be reflected in 
the rate-based state only to the extent that the MWhs resulted in lower 
reported CO2 emissions from an affected EGU in the rate-
based state. To the extent that measures that provide substitute or 
avoided generation reduce generation from affected EGUs in a mass-based 
state, the effect of those measures is reflected in lower reported 
CO2 emissions of the mass-based EGUs. The CO2 
emission reductions reflected in the rate and the mass state will 
necessarily be mutually exclusive, because both are based on reported 
stack emissions. Additionally, the mechanism in the mass-based state 
that is assuring CO2 emission reductions is the mass budget, 
which is met by affected EGUs adjusting their generation. Low- or zero-
emitting MWhs from resources like RE and demand-side EE can serve load 
in the mass-based state and play a role in lowering compliance costs, 
but they play no direct role in mass-based compliance. As a result, no 
double-counting of emission reductions can take place.
    Though there is no risk of double-counting emissions, some 
commenters expressed the concern that overall CO2 emissions 
reductions would be foregone in situations where a source in a rate-
based state counts the MWh from measures in a mass-based state, but the 
generation from that measure acts solely to serve load in the mass-
based state. In that scenario, expected CO2 emission 
reduction actions in the rate-based state are foregone as a result of 
counting MWh that resulted in CO2 emission reductions in a 
mass-based state. Therefore the EPA is restricting the ability of rate-
based states to claim emission reduction measures, such as RE and 
demand-side EE, located in mass-based states.
    While the EPA understands this concern regarding foregone 
reductions, we do not believe it is appropriate to restrict RE 
crediting unilaterally between rate-based and mass-based states. Such a 
restriction could cut some states off from regional RE supplies that 
are assumed in the BSER building block 3 and incorporated in the 
CO2 emission performance rates and state CO2 
goals. Allowing crediting between rate- and mass-based states, as long 
as the risk of foregone CO2 emission reduction actions in 
rate-based states are minimized, will assure a supply of eligible RE 
MWhs that will further enable affected EGUs and states to meet 
obligations under the final rule. Therefore, the EPA has determined 
that it is appropriate for rate-based states to count MWhs from RE 
located in mass-based states, subject to the condition that the 
generation in question was intended to meet electricity load in a state 
with a rate-based plan.\1011\ This may apply to some or all of the 
generation from an individual RE installation. To assure that the RE 
generation in question meets this condition, the EPA is requiring that 
RE generation from RE installations located in a mass-based state can 
only be counted in a rate-based state if the electricity generated is 
delivered with the intention to meet load in a state with a rate-based 
plan, and was treated as a generation resource used to serve regional 
load that included the rate-based state. This can be demonstrated 
through, for example, the provision of a power delivery contract or 
power purchase agreement in which an entity in the rate-based state 
contracts for the supply of the MWhs in question. The EPA is providing 
flexibility to states regarding the nature of the required 
demonstration, though the state must specify eligible demonstrations 
for approval in state plans. Under an emission standards plan, this 
demonstration would be made by the provider of the measure seeking ERC 
issuance to the rate-based state.
---------------------------------------------------------------------------

    \1011\ This does not need to necessarily be the state where the 
MWh of energy generation from the RE measure is used to adjust the 
CO2 emission rate of an affected EGU.
---------------------------------------------------------------------------

    The following are examples of how requirements for a demonstration 
could be established in state plans and used to allow RE in a mass-
based state to be counted in a rate-based state. For an emission 
standards state plan, a state could specify in the regulations for the 
rate-based emission standards included in its state plan that it will 
require an RE provider that seeks the issuance of ERCs to show that 
load-serving entities in the rate-based state have contracted for the 
delivery of the RE generation that occurs in a mass-based state to meet 
load in a rate-based state. Under this approach, an RE provider in a 
mass-based state could submit as part of an eligibility application a 
delivery contract or power purchase agreement showing that the 
generation was procured by the utility, and was treated as a generation 
resource used to serve regional load that included the rate-based 
state. This documentation would be sufficient demonstration to allow 
the RE generating resource to meet this additional geographic 
eligibility requirement for the amount of generation in question. All 
quantified and verified RE MWhs submitted for ERC issuance would need 
to be associated with that power purchase contract or agreement, and 
this fact would need to be demonstrated in the M&V reports submitted 
for issuance of ERCs.
    The ability for a rate-based state to count MWhs located in a mass-
based state under the above conditions is limited to RE. Rate-based 
states are not allowed to claim demand-side EE or any other emission 
reduction measures that were not included in the determination of the 
BSER located in mass-based states for ERC issuance. While this limits 
rate-based sources' access to additional resources, providing that 
access would result in a risk of foregone reductions. Further, unlike 
RE, there is no obligation related to demand-side EE and other measures 
that were not included in the determination of the BSER incorporated in 
the CO2 emission performance rates or state rate-based goals 
which would necessitate facilitating access to those resources. This 
treatment also does not apply to

[[Page 64914]]

fossil-fuel fired EGUs, such as NGCC units. If a mass-based emission 
standard has been applied to an affected EGU, there is no valid way to 
calculate whether it has MWh that are eligible for crediting, as is 
possible under a rate-based plan.
    Finally, as stated earlier, commenters also expressed concern about 
the potential for relative increases in emissions to occur given 
relative differences between sources and states. These differences 
could include states' goals under either the rate- or mass-based 
approaches, or states' accounting of new sources. These differences 
could induce increased generation in one state over another because the 
costs of compliance and relative costs of generation would vary between 
states. There was particular concern regarding how these differences 
would provide incentives for increasing generation at new fossil 
sources and expanding utilization of existing affected EGU generation 
in states that have less stringent goals, and that this movement of 
generation would result in increased emissions overall. This could 
potentially result in the achievement of performance rates but with 
fewer overall CO2 emissions reductions than projected 
nationally under the proposal.
    Commenters suggested that the issuance and trading of emission 
credits across states under a rate-based approach would result in 
incentives to create credits, through the development of RE for 
example, in certain states with higher state goals, and this could also 
be a source of increased overall emissions. They noted that RE siting 
would thus not occur in the most optimal locations. The commenters 
assumed that zero-emitting credits are denominated in mass units by 
multiplying the number of MWh by some emission rate: Either the state 
goal rate, the current state emission rate, a regional emission rate, 
or a calculated marginal rate. If those rates were higher in any 
states, zero-emitting MWhs would create more mass-denominated credits 
in those states, and thus RE and demand-side EE would be more valuable.
    The incentive to target the location of zero-emitting generation or 
energy savings between states based on variation in its emission 
reduction value has been minimized by the fact that states 
participating in rate-based interstate trading must adopt the same 
emission performance rates or rate-based state goals. It is further 
minimized, even outside of an interstate trading framework, by the 
nature of the accounting method finalized in this rule. As explained 
above regarding the general accounting approach and the trading 
framework, we are adjusting rates using calculated MWhs, not based upon 
an emission reduction approximation as commenters outlined above. Not 
only does the method allow emission reductions to be accounted for as 
they occur across the grid, but it means the ERCs being traded across 
states represent one MWh of zero-emitting generation in whatever state 
it originated, and its value is unaffected by any emission rate 
associated with its state of origin. Thus, the finalized accounting and 
trading methods minimize the relative incentives for generating zero-
emitting ERCs in a particular state based upon the rates that apply to 
that state.

IX. Community and Environmental Justice Considerations

    In this section we provide an overview of the actions that the 
agency is taking to help ensure that vulnerable communities are not 
disproportionately impacted by this rulemaking.\1012\As described in 
the Executive Summary, climate change is an environmental justice 
issue. Low-income communities and communities of color already 
overburdened with pollution are likely to be disproportionately 
affected by, and less resilient to, the impacts of climate change. This 
rulemaking will provide broad benefit to communities across the nation, 
as its purpose is to reduce GHGs, the most significant driver of 
climate change. While addressing climate change will provide broad 
benefits, it is particularly beneficial to low-income populations and 
some communities of color (in particular, populations defined jointly 
by ethnic/racial characteristics and geographic location) where people 
are most vulnerable to the impacts of climate change (a more robust 
discussion of the impacts of climate change on vulnerable communities 
is provided in the Executive Order 12898 section XII.J of this 
preamble). While climate change is a global phenomenon, the adverse 
effects of climate change can be very localized, as impacts such as 
storms, flooding, droughts, and the like are experienced in individual 
communities.
---------------------------------------------------------------------------

    \1012\ In this preamble, the EPA discusses environmental justice 
in two sections. Section XI.J specifically addresses how the agency 
has met the directives under Executive Order 12898. The EPA defines 
environmental justice as the fair treatment and meaningful 
involvement of all people regardless of race, color, national origin 
or income with respect to the development, implementation, and 
enforcement of environmental laws, regulations, and policies. This 
section of the preamble addresses actions that the agency is taking 
related to environmental justice and other issues (e.g., increased 
electricity costs) that may affect communities covered by Executive 
Order 12898 as well as other communities.
---------------------------------------------------------------------------

    Vulnerable communities also often receive more than their fair 
share of conventional air pollution, with the attendant adverse health 
impacts. The changes in electricity generation that will result from 
this rule will further benefit communities by reducing existing air 
pollution that directly contributes to adverse localized health 
effects. These air quality improvements will be achieved through this 
rule because the electric generating units that emit the most GHGs also 
have the highest emissions of conventional pollutants, such as 
SO2, NOX, fine particles, and HAP. These 
pollutants are known to contribute to adverse health outcomes, 
including the development of heart or lung diseases, such as asthma and 
bronchitis, increased susceptibility to respiratory and cardiac 
symptoms, greater numbers of emergency room visits and hospital 
admissions, and premature deaths.\1013\ The EPA expects that the 
reductions in utilization of higher-emitting units likely to occur 
during the implementation of state plans will produce significant 
reductions in emissions of conventional pollutants, particularly in 
those communities already overburdened by pollution, which are often 
low-income communities, communities of color, and indigenous 
communities. These reductions will have beneficial effects on air 
quality and public health both locally and regionally. Further, this 
rulemaking complements other actions already taken by the EPA to reduce 
conventional pollutant emissions and improve health outcomes for 
overburdened communities.
---------------------------------------------------------------------------

    \1013\ Six Common Air Pollutants. http://www.epa.gov/oaqps001/urbanair/.
---------------------------------------------------------------------------

    By reducing millions of tons of CO2 emissions that are 
contributing to global GHG levels and providing strong leadership to 
encourage meaningful reductions by countries across the globe, this 
rule is a significant step to address health and economic impacts of 
climate change that will fall disproportionately on vulnerable 
communities. By reducing millions of tons of conventional air 
pollutants, the rule will lead to better air quality and improved 
health in those communities. We heard from many commenters who 
recognize and welcome those benefits.
    There are other ways in which the actions that result from this 
rulemaking may affect communities in positive or potentially adverse 
ways and we also heard about these from commenters.
    While the agency expects overall emission decreases as a result of 
this

[[Page 64915]]

rulemaking, we recognize that some EGUs may operate more frequently, as 
a result of this rulemaking. To the extent that we project increases in 
utilization as a result of this rulemaking, we expect these increases 
to occur generally in lower-emitting NGCC units, which have minimal or 
no emissions of SO2 and HAP, lower emissions of particulate 
matter, and much lower emissions of NOX compared to higher-
emitting steam units. We acknowledge the concerns that have been raised 
on this point but also the difficulty in anticipating prior to plan 
implementation where those impacts might occur. In addition to 
providing for a robust state planning process with opportunity for 
meaningful input, the EPA is encouraging states to evaluate the actual 
impacts of their plans once implemented and, as described below, the 
EPA intends to conduct an assessment of whether and where emission 
increases may that may result from plan implementation and to work with 
states to mitigate adverse impacts, if any, in overburdened 
communities.
    In addition to the many positive anticipated health benefits of 
this rulemaking, it also will increase the use of clean energy and will 
encourage EE. These changes in the electricity generation system, which 
are already occurring but may be accelerated by this program, are 
expected to have other positive benefits for communities. The 
electricity sector is, and will continue to be, investing more in RE 
and EE. The construction of renewable generation and the implementation 
of EE programs such as residential weatherization will bring investment 
and employment opportunities to the communities where they take place. 
We recognize that certain communities whose economies may be affected 
by changes in the utility and related sectors may be particularly 
impacted by the final rule. The EPA encourages states to make an effort 
to engage with these communities, including workers and their 
representatives in these sectors, including EE. It is important to 
ensure that all communities share in the benefits of this program. And 
while we estimate that its benefits will greatly exceed its costs (as 
noted in the RIA for this rulemaking), it is also important to ensure 
that to the extent there are increases in electricity costs, that those 
do not fall disproportionately on those least able to afford them.
    The EPA has engaged with community groups throughout this 
rulemaking, and we received many comments on the issues outlined above 
from community groups, environmental justice organizations, faith-based 
organizations, public health organizations, and others.\1014\ This 
input has informed this final rulemaking and prompted the EPA to 
consider other steps that the agency can take in the short and long 
term to assist states and stakeholders to consider environmental 
justice and impacts to communities in plan development and 
implementation.
---------------------------------------------------------------------------

    \1014\ Detailed information on the outreach conducted as part of 
this rulemaking is provided in section I of this preamble.
---------------------------------------------------------------------------

    It has also prompted us to work with our federal partners to make 
sure that states and communities have information on federal resources 
available to assist communities. We describe these resources below, as 
well as resources that the EPA will be providing to assist communities 
in accessing EE/RE and financial assistance programs. In our discussion 
below we also provide models of programs that other states are 
currently using to assist communities in accessing available resources 
that states could use when developing their plans.
    Finally, and importantly, we recognize that communities must be 
able to participate meaningfully in state plan development. In this 
section, we discuss the requirements in the final rule for states, as 
they develop their plans, to provide opportunities for public 
involvement, and resources available to states and communities to 
enhance the success of the public process.

A. Proximity Analysis

    The EPA is committed to assisting states and communities to develop 
plans that ensure there are no disproportionate, adverse impacts on 
overburdened communities. To provide information fundamental to 
beginning that process, the EPA has conducted a proximity analysis for 
this final rulemaking that summarizes demographic data on the 
communities located near power plants.\1015\ The EPA understands that, 
in order to prevent disproportionately, high and adverse human health 
or environmental effects on these communities, both states and 
communities must have information on the communities living near 
facilities, including demographic data, and that accessing and using 
census data files requires expertise that some community groups may 
lack. Therefore, the EPA used census data from the American Community 
Survey (ACS) 2008-2012 to conduct a proximity analysis that can be used 
by states and communities as they develop state plans and as they later 
assess the final plans' impacts. The analysis and its results are 
presented in the EJ Screening Report for the Clean Power Plan, which is 
located in the docket for this rulemaking at EPA-HQ-OAR-2013-0602.
---------------------------------------------------------------------------

    \1015\ The proximity analysis was conducted using the EPA's 
environmental justice mapping and screening tool, EJSCREEN.
---------------------------------------------------------------------------

    The proximity analysis provides detailed demographic information on 
the communities located within a 3-mile radius of each affected power 
plant in the U.S. Included in the analysis is the breakdown by 
percentage of community characteristics such as income and minority 
status. The analysis shows a higher percentage of communities of color 
and low-income communities living near power plants than national 
averages. It is important to note that the impacts of power plant 
emissions are not limited to a 3-mile radius and the impacts of both 
potential increases and decreases in power plant emissions can be felt 
many miles away. Still, being aware of the characteristics of 
communities closest to power plants is a starting point in 
understanding how changes in the plant's air emissions may affect the 
air quality experienced by some of those already experiencing 
environmental burdens.
    Although overall there is a higher fraction of communities of color 
and low-income populations living near power plants than national 
averages, there are differences between rural and urban power plants. 
There are many rural power plants that are located near small 
communities with high percentages of low-income populations and lower 
percentages of communities of color. In urban areas, nearby communities 
tend to be both low-income communities and communities of color. In 
light of this difference between rural and urban communities proximate 
to power plants and in order to adequately capture both the low-income 
and minority aspects central to environmental justice considerations, 
we use the terms ``vulnerable'' or ``overburdened'' when referring to 
these communities. Our intent is for these terms to be understood in an 
expansive sense, in order to capture the full scope of communities, 
including indigenous communities most often located in rural areas, 
that are central to our environmental justice and community 
considerations.
    As stated in the Executive Order 12898 discussion located in 
section XII.J of this preamble, the EPA believes that all communities 
will benefit from this final rulemaking because this action directly 
addresses the impacts of climate change by limiting GHG emissions 
through the establishment of CO2 emission guidelines for existing 
affected fossil fuel-fired power plants.

[[Page 64916]]

The EPA also believes that the information provided in the proximity 
analysis will promote engagement between vulnerable communities and 
their states and will be useful for states as they begin developing 
their plans. In addition to providing the proximity analysis in the 
docket of this rulemaking, the EPA will disseminate the proximity 
analysis to states and will make it publicly available on its Clean 
Power Plan (CPP) Community Portal. Furthermore, the EPA has also 
created an interactive mapping tool that illustrates where power plants 
are located and provides information on a state level. This tool is 
available at: http://cleanpowerplanmaps.epa.gov/CleanPowerPlan/.
    Additionally, the EPA encourages states to conduct their own 
analyses of community considerations when developing their plans. Each 
state is uniquely knowledgeable about its own communities and well-
positioned to consider the possible impacts of plans on vulnerable 
communities within its state. Conducting state-specific analyses would 
not only help states assess possible impacts of plan options, but it 
would also enhance a state's understanding of the means to engage these 
communities that would most effectively reach them and lead to valuable 
exchanges of information and concerns. A state analysis, together with 
the proximity analysis conducted by the EPA, would provide a solid 
foundation for engagement between a state and its communities.
    Such state-specific analyses need not be exhaustive. An examination 
of the options a state is considering for its plan, and any projections 
of likely resulting increases in power plant emissions affecting low-
income populations, communities of color populations, or indigenous 
communities, would be informative for communities. The analyses could 
include available air quality monitoring data and information from air 
quality models, and, if available, take into account information about 
local health vulnerabilities such as asthma rates or access to 
healthcare. Alternatively, a simple analysis may consider expected EGU 
utilization in geographic proximity to overburdened communities. The 
EPA will provide states with information on its publicly available 
environmental justice screening and mapping tool, EJ SCREEN, which they 
may use in conducting a state-specific analysis. The EPA will also 
provide states with resources containing examples of analyses that 
other states have conducted to examine the impacts of their programs on 
overburdened communities. Additionally, the EPA encourages states to 
submit a copy of their analysis if they choose to conduct one, with 
their initial and final plan submittals.

B. Community Engagement in State Plan Development

    In sections VIII.D-E of this preamble, the EPA explains that states 
need to engage meaningfully with communities and other stakeholders 
during the initial and final plan submittal processes. Meaningful 
engagement includes outreach to vulnerable communities, sharing 
information and soliciting input on state plan development and on any 
accompanying assessments such as those described above, and selecting 
methods for engagement to support communities' involvement at critical 
junctures in plan formulation and implementation. This engagement also 
includes providing the public the opportunity to comment on the state's 
initial submittal and responding to significant comments received, 
including comments from vulnerable communities, as well as conducting a 
public hearing and responding to comments before a final state plan is 
submitted. Additionally, the EPA expects that states will conduct 
outreach meetings, which could include public hearings or listening 
sessions, before the initial submittal is made. The EPA also encourages 
states to provide background information about their proposed final 
state plan or their initial state plan in the appropriate languages in 
advance of their public hearing and at their public hearing. The EPA 
recommends that states provide translators and other resources at their 
public hearings, to ensure that members of the public can provide oral 
feedback.
    In the initial submittal, the final rule requires that states 
provide information to the agency about the community engagement they 
have undertaken and the means by which they intend to involve 
vulnerable communities and other stakeholders as they develop their 
final plan. Furthermore, as noted in section VIII.E of this preamble, 
in determining if states are eligible for a 2-year extension for 
submission of final plans, the rule requires that states demonstrate 
how they are meaningfully engaging vulnerable communities and other 
interested stakeholders as part of their public participation process. 
The EPA consulted its May 2015, Guidance on Considering Environmental 
Justice During the Development of Regulatory Actions, when crafting 
this rulemaking and recommends that states consult it to assist them in 
engaging meaningfully with vulnerable communities.\1016\ Additionally, 
states in their initial submittal and 2017 update must show how they 
identified the communities with whom they are engaging as they develop 
their plans. Some suggested actions that states could take to engage 
actively with the public, including conducting meaningful engagement 
with vulnerable communities, are outlined in section VIII.E of this 
preamble. Additionally, as outlined in section VIII.D, the final plan 
submitted by states must include an overview of the public hearing(s) 
conducted and information on how the state ensured that the hearing(s) 
were accessible to stakeholders including vulnerable communities.
---------------------------------------------------------------------------

    \1016\ Guidance on Considering Environmental Justice During the 
Development of Regulatory Actions. http://epa.gov/environmentaljustice/resources/policy/considering-ej-in-rulemaking-guide-final.pdf. May 2015.
---------------------------------------------------------------------------

    The EPA is committed to supporting states in effectively engaging 
with communities as they develop and implement their plans. The EPA 
will provide training and other resources throughout the implementation 
process that will assist states and communities in understanding plan 
requirements and options for plan development. These trainings will be 
a continuation of those that the EPA has already conducted with 
communities and states both pre- and post-proposal. The EPA will reach 
out to a wide variety of community stakeholders, including groups 
representing environmental justice communities, faith-based 
organizations, academic organizations working with vulnerable and 
overburdened communities, affordable housing advocates, public health 
professionals, public health organizations, and other community 
stakeholders.

C. Providing Communities With Access to Additional Resources

    In addition to providing resources to states, the EPA encourages 
states to be aware of existing efforts undertaken by other states aimed 
at providing low-income communities access to financial and technical 
assistance programs for EE and RE, and to consider similar approaches 
that may make sense for their own states. The EPA encourages states to 
consider targeting economic development resources to communities that 
are likely to be negatively affected by ongoing changes in the utility 
and related sectors in support of efforts to diversify their economies, 
attract new sources of investment, and create new jobs.
    One example of a program targeted at low-income communities is the

[[Page 64917]]

Maryland EmPOWER Low Income Energy Efficiency Program (LIEEP).\1017\ 
The LIEEP program administered by the Maryland Department of Housing 
and Community Development (DHCD) helps low-income households through 
free installation of energy conservation materials (i.e., installation, 
hot water system improvements, lighting retrofits, furnace cleaning, 
tuning and safety repairs, refrigerator retrofits, etc.).\1018\ Funding 
for this program is provided by EmPOWER Maryland partners: Baltimore 
Gas and Electric, Southern Maryland Electric Cooperative, Delmarva 
Power, Allegheny Energy and Pepco.\1019\ This program is available to 
both homeowners and renters.\1020\ Additionally, the Maryland 
Department of Housing provides low-income families with home heating 
bill assistance and furnace repairs and replacements through the 
Maryland Energy Assistance Program (MEAP).\1021\ Maryland's Electric 
Universal Service Program (EUSP) helps low-income electric customers 
with their electric bills.\1022\
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    \1017\ EmPOWER Maryland Low Income Energy Efficiency Programs 
(LIEEP). http://www.mdhousing.org/Website/Programs/lieep/Default.aspx.
    \1018\ Ibid.
    \1019\ Ibid.
    \1020\ Ibid.
    \1021\ Energy Assistance. http://www.dhr.state.md.us/blog/?page_id=4326.
    \1022\ Ibid.
---------------------------------------------------------------------------

    Another example of a program is EmPower New York, which provides 
no-cost energy solutions to low-income populations.\1023\ Currently 
there are about 100,000 people who are receiving assistance. Both 
homeowners and renters are eligible to receive assistance under this 
program. The types of assistance available include EE upgrades 
(plugging leaks, adding insulation, replacing inefficient refrigerators 
and freezers and new energy-efficient lighting). Other states, like the 
State of Colorado's Energy Outreach Colorado program, offer similar 
resources for low-income populations.\1024\
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    \1023\ EmPower New York. http://www.nyserda.ny.gov/All-Programs/Programs/EmPower-New-York.
    \1024\ Energy Outreach Colorado. http://www.energyoutreach.org/about.
---------------------------------------------------------------------------

    In 2013, the New York State Energy and Research Development 
Authority (NYSERDA) was able to secure a triple-A rated financial 
guarantee from the state's Clean Water State Revolving Fund (SRF) for a 
$24 million bond issue. Proceeds funded residential EE loans that were 
available to all utility customers, including low-income households. 
SRF eligibility was based on the beneficial impact of EE investment in 
reducing atmospheric deposition on impaired water bodies consistent 
with Section 319 of the Clean Water Act.
    As discussed below, there are also many federal programs that can 
help low-income populations access the benefits of RE, EE, and the 
economic benefits of a cleaner energy economy.
    In the coming months, the EPA will continue to provide information 
and resources for communities and states on existing federal, state, 
local, and other financial assistance programs to encourage EE/RE 
opportunities that are already available to communities. For example 
the EPA will provide a catalog of current or recent state and local 
programs that have successfully helped communities adopt EE/RE 
measures. The goal of these resources is to help vulnerable communities 
gain the benefits of this rulemaking by encouraging that states use 
these types of tools in their state plans. The use of these RE/EE tools 
can also help low-income households reduce their electricity 
consumption and bills.
    The EPA recognizes the potential impacts that this rulemaking could 
have on jobs in communities. Therefore, in section VIII.G of this 
preamble, the EPA has outlined that states, in designing their state 
plans, should consider the effects of their plans on employment and 
overall economic development to realize the opportunities for economic 
growth and jobs that the plans offer. To the extent possible, states 
should try to assure that communities that may be expected to 
experience job losses can also take advantage of the opportunities for 
job growth or otherwise transition to healthy, sustainable economic 
growth (e.g., with regard to delivering EE measures and installing 
rooftop solar panels). Additionally, as part of the resources that we 
will be providing to states and low-income communities, the EPA will 
provide information on the Administration's Partnerships for 
Opportunity and Workforce and Economic Revitalization (POWER) 
Initiative and other programs that specifically target economic 
development assistance to communities affected by changes in the coal 
industry and the utility power sector.\1025\
---------------------------------------------------------------------------

    \1025\ http://www.eda.gov/power.
---------------------------------------------------------------------------

D. Federal Programs and Resources Available to Communities

    Federal agencies have a history of bringing EE and RE to low-income 
communities. Earlier this summer, the Administration announced a new 
initiative to scale up access to solar energy and cut energy bills for 
all Americans, in particular low- and moderate-income communities, and 
to create a more inclusive solar workforce. As part of this new 
initiative, the U.S. Department of Energy (DOE), the U.S. Department of 
Housing and Urban Development (HUD), U.S. Department of Agriculture 
(USDA), and the EPA launched a National Community Solar Partnership to 
unlock access to solar energy for the nearly 50 percent of households 
and businesses that are renters or do not have adequate roof space to 
install solar systems, with a focus on low- and moderate-income 
communities. The Administration also set a goal to install 300 
megawatts (MW) of RE in federally subsidized housing by 2020 and plants 
to provide technical assistance to make it easier to install solar 
energy on affordable housing, including clarifying how to use federal 
funding for EE and RE. To continue enhancing employment opportunities 
in the solar industry for all Americans, AmeriCorps is providing 
funding to deploy solar energy and create jobs in underserved 
communities, and DOE is working to expand solar energy education and 
opportunities for job training.
    These recent announcements build on the many existing federal 
programs and resources available to improve EE and accelerate the 
deployment of RE in vulnerable communities. Some examples of these 
resources include: the Department of Energy's Weatherization Assistance 
Program, Health and Human Service's Low Income Home Energy Assistance 
Program, the Department of Agriculture's Energy Efficiency and 
Conservation Loan Program, High Cost Energy Grant Program, and the 
Rural Housing Service's Multi-Family Housing Program.
    HUD supports EE improvements and the deployment of RE on affordable 
housing through its Energy Efficient Mortgage Program, Multifamily 
Property Assessed Clean Energy Pilot with the State of California, 
PowerSaver Program, and the use of Section 108 Community Development 
Block Grants. The Department of Treasury provides several tax credits 
to support RE development and EE in low-income communities, including 
the New Markets Tax Credit Program and the Low-Income Housing Tax 
Credit. The EPA's RE-Powering America's Land Initiative promotes the 
reuse of potentially contaminated lands, landfills and mine sites--many 
of which are in low-income communities--for RE through a combination of 
tailored redevelopment tools for communities and developers, as well as 
site-specific technical support. The EPA's Green

[[Page 64918]]

Power Partnership is increasing community use of renewable electricity 
across the country and in low-income communities. The EPA partners with 
EE programs throughout the country that leverage ENERGY STAR to deliver 
broad consumer energy-saving benefits, of particular value to low-
income households who can least afford high energy bills. ENERGY STAR 
also works with houses of worship to reduce energy costs--savings that 
can then be repurposed to their community mission, including programs 
and assistance to residents in low-income communities. The EPA will be 
working with these federal partners and others to ensure that states 
and vulnerable communities have access to information on these programs 
and their resources.
    The federal government also has a number of programs to expand 
employment opportunities in the energy sector, including for 
underserved populations. Examples of these include HUD, DOE, and the 
Department of Education's ``STEM, Energy, and Economic Development'' 
program; DOE's Diversity in Science and Technology Advances National 
Clean Energy in Solar (DISTANCE-Solar) Program; Grid Engineering for 
Accelerated Renewable Energy Deployment (GEARED); the Department of 
Labor's Trade Adjustment Assistance Community College and Career 
Training (TAACCCT), Apprenticeship USA Advancing Apprenticeships in the 
Energy Field, Job Corps Green Training and Greening of Centers, and 
YouthBuild; and the EPA's Environmental Workforce Development and Job 
Training (EWDJT) program.

E. Multi-Pollutant Planning and Co-Pollutants

    As outlined in the final Clean Power Plan, states and sources have 
continued obligations to meet all other CAA requirements addressing 
conventional pollutants. Because the CAA envisions control of these 
other pollutants as a continuous process (through provisions such as 
periodic review of the NAAQS and residual risk requirements under the 
MACT program), the EPA believes that the Clean Power Plan provides an 
opportunity for states to consider strategies for meeting future CAA 
planning obligations as they develop their plans under this rulemaking. 
Multi-pollutant strategies that incorporate criteria pollutant 
reductions over the planning horizons specific to particular states, 
jointly with strategies for reducing CO2 emissions from 
affected EGUs needed to meet Clean Power Plan requirements over the 
time horizon of this rule, may accomplish greater environmental results 
with lower long-term costs. Such strategies may also provide 
opportunities for states, communities, and affected facilities to 
consider the most effective means of meeting these obligations while 
limiting or eliminating localized emission increases that would 
otherwise affect overburdened communities. Furthermore, this type of 
multi-pollutant approach has been suggested by states and regulated 
sources in past rulemakings as a tool to determine the best system of 
emission reductions. The EPA recommends that states consider such 
strategies in consultation with their communities, affected facilities, 
and other stakeholders.
    Air quality in a given area is affected by emissions from nearby 
sources and may be influenced by emissions that travel hundreds of 
miles and mix with emissions from other sources.\1026\ In the Cross-
State Air Pollution Rule the EPA used its authority to reduce emissions 
that significantly contribute to downwind exposures. The RIA for the 
final Cross-State Air Pollution Rule anticipates substantial health 
benefits for the population across a wide region. Similarly, the EPA 
believes that, like the Cross-State Air Pollution Rule, this rulemaking 
will result in significant health benefits because it will reduce co-
pollutant emissions of SO2 and NOX on a regional 
and national basis.\1027\ Thus, localized increases in NOX 
emissions may well be more than offset by NOX decreases 
elsewhere in the region that produce a net improvement in ozone and 
particulate concentrations across the area.
---------------------------------------------------------------------------

    \1026\ 76 FR 48348.
    \1027\ 76 FR 48347.
---------------------------------------------------------------------------

    Another effect of the final CO2 emission guidelines for 
affected existing fossil fuel-fired EGUs may be increased utilization 
of other, unmodified EGUs--in particular, high efficiency gas-fired 
EGUs--with relatively low GHG emissions per unit of electrical output. 
These plants may operate more hours during the year and could emit 
pollutants, including pollutants whose environmental effects would be 
localized and regional rather than global as is the case with GHG 
emissions. Changes in utilization already occur in response to energy 
demands and evolving energy sources, but the final CO2 
emission guidelines for affected existing fossil fuel-fired EGUs can be 
expected to cause more such changes. Increased utilization of solid 
fossil fuel-fired units generally would not increase peak 
concentrations of PM2.5, NOX, or ozone around 
such EGUs to levels higher than those that are already occurring 
because peak hourly or daily emissions generally would not change; 
however, increased utilization may make periods of relatively high 
concentrations more frequent. It should be noted that the gas-fired 
sources likely to be dispatched more frequently have very low emissions 
of primary PM, SO2, and HAP per unit of electrical output 
and that they must continue to comply with other CAA requirements that 
directly address the conventional pollutants, including federal 
emission standards, rules included in SIPs, and conditions in Title V 
operating permits, in addition to the guidelines in this final 
rulemaking. Therefore, local (or regional) air quality for these 
pollutants is not likely to be significantly affected.
    For natural gas-fired EGUs, the EPA found that regulation of HAP 
emissions ``is not appropriate or necessary because the impacts due to 
HAP emissions from such units are negligible based on the results of 
the study documented in the utility RTC.'' \1028\ Because gas-fired 
EGUs emit essentially no mercury, increased utilization will not 
increase methyl mercury concentrations in water bodies near these 
affected EGUs. In studies done by DOE/NETL comparing cost and 
performance of coal- and NGCC-fired generation, they assumed 
SO2, NOX, PM (and Hg) emissions to be 
``negligible.'' Their studies predict NOX emissions from a 
NGCC unit to be approximately 10 times lower than a subcritical or 
supercritical coal-fired boiler.\1029\ Many, although not all, NGCC 
units are also very well controlled for emissions of NOX 
through the application of after combustion controls such as selective 
catalytic reduction.
---------------------------------------------------------------------------

    \1028\ 65 FR 79831.
    \1029\ ``Cost and Performance Baseline for Fossil Energy Plants 
Volume 1: Bituminous Coal and Natural Gas to Electricity'' Rev 2a, 
September 2013 Revision 2, November 2010 DOE/NETL-2010/1397.
---------------------------------------------------------------------------

F. Assessing Impacts of State Plan Implementation

    It is important to the EPA that the implementation of state plans 
be assessed in order to identify whether they cause any adverse impacts 
on communities already overburdened by disproportionate environmental 
harms and risks. The EPA will conduct its own assessment during the 
implementation phase of this rulemaking to determine whether the 
implementation of state plans developed pursuant to this rulemaking and 
other air quality rules are, in fact, reducing emissions and improving 
air quality in all areas or whether there are localized air quality 
impacts that need to be addressed under other CAA authorities. 
Furthermore, the

[[Page 64919]]

EPA recommends that states conduct evaluations of their own to 
determine the impacts of their plans on overburdened communities. An 
example of one such approach to assessing a state plan for reducing 
GHGs is the California Air Resources Board's (CARB), First Update on 
the Climate Change Scoping Plan: Building on the Framework Pursuant to 
AB32: The California Global Warming Solutions Act of 2006, which 
outlines ongoing evaluations that it will conduct to determine the 
impacts of its programs (throughout the implementation stages) on 
overburdened communities.\1030\ CARB's Adaptive Management Plan for the 
Cap-and-Trade Program is one particular evaluation, which is intended 
to assess any localized emissions increases resulting from the program 
so that the state can appropriately respond.\1031\ The EPA recommends 
that states consider CARB's approaches and other programs as models for 
conducting ongoing assessments of the impacts of their state plans on 
overburdened communities. The EPA will provide training for states and 
communities on resources that they can use to assess options for plan 
development and implementation that appropriately consider localized 
impacts, especially effects of co-pollutants, as well as training on 
how to develop and carry out these evaluations.
---------------------------------------------------------------------------

    \1030\ First Update on the Climate Change Scoping Plan: Building 
on the Framework Pursuant to AB32: The California Global Warming 
Solutions Act of 2006. http://www.arb.ca.gov/cc/scopingplan/2013_update/first_update_climate_change_scoping_plan.pdf. May 2014.
    \1031\ Adaptive Management Plan for the Cap-and-Trade 
Regulation. http://www.arb.ca.gov/cc/capandtrade/adaptive_management/plan.pdf. October 2011.
---------------------------------------------------------------------------

    This training will include guidance in accessing the publicly 
available information that sources and states currently report that can 
help with ongoing assessments of state plan impacts. For example, unit-
specific emissions data and air quality monitoring data are readily 
available. This information, together with the assessment that the EPA 
will conduct in the implementation phase of this rulemaking and other 
analyses that states may develop, will enable states and communities to 
monitor any disproportionate emissions that may result in adverse 
impacts and to address them.

G. EPA Continued Engagement

    The EPA is committed to helping ensure that this action will not 
have disproportionate adverse human health or environmental effects on 
vulnerable communities. Throughout the implementation phase of this 
rulemaking, the agency will continue to provide trainings and resources 
to assist communities and states as they engage with one another. 
Additionally, we will provide states with recommendations on best 
practices for engaging with vulnerable communities. The EPA, through 
its outreach efforts during implementation, will continue to solicit 
feedback from communities and states on topics for which they would 
like additional trainings and resources.
    The EPA will also provide states with resources containing examples 
of analyses that other states have conducted to examine the impacts of 
their programs on vulnerable communities, as well as information on its 
publicly available environmental justice screening and mapping tool, EJ 
SCREEN. States are encouraged to use this preliminary information as 
well as other available information to conduct their own analyses. As 
described above, the EPA will assess the impacts of this rulemaking 
during its implementation. The EPA will house this assessment, along 
with the proximity analysis and other information generated throughout 
the implementation process, on its Clean Power Plan (CPP) Community 
Portal that will be linked to this rulemaking's Web site (www.epa.gov/cleanpowerplan). In addition, the EPA has expanded its set of resources 
that are being developed to help states and communities understand the 
breadth of policy options and programs that have successfully brought 
EE/RE to overburdened communities. The EPA is committed to continuing 
its engagement with states and communities from the beginning of plan 
development through plan implementation.
    A more detailed discussion concerning the application of Executive 
Order 12898 in this rulemaking can be found in section XI.J of this 
preamble. A summary of the EPA's interactions with communities is in 
the EJ Screening Report for the Clean Power Plan, available in the 
docket of this rulemaking. Furthermore, the EPA's responses to public 
comments, including comments received from communities, are provided in 
the response to comments documents located in the docket for this 
rulemaking.
    In summary, the EPA in this final rulemaking has designed an 
integrative approach that helps to ensure that vulnerable communities 
are not disproportionately impacted by this rulemaking. The proximity 
analysis that the agency has conducted for this rulemaking is a central 
component of this approach. Not only is the proximity analysis a useful 
tool to help identify overburdened communities that may be impacted by 
this rulemaking, states can use this tool as they engage with 
communities in the development of their plans, consider a multi-
pollutant approach, help low-income communities access EE/RE and 
financial assistance programs and assess the impacts of their state 
plans. Additionally, in order to continue to ensure that vulnerable 
communities are not disproportionately impacted by this rulemaking, the 
EPA will also be conducting its own assessment during the 
implementation phase. Furthermore, the EPA will continue to engage with 
communities and states throughout the implementation phase of this 
rulemaking to help ensure that vulnerable communities are not 
disproportionately impacted.

X. Interactions With Other EPA Programs and Rules

A. Implications for the New Source Review Program

    The new source review (NSR) program is a preconstruction permitting 
program that requires major stationary sources of air pollution to 
obtain permits prior to beginning construction. The requirements of the 
NSR program apply both to new construction and to modifications of 
existing major sources. Generally, a source triggers these permitting 
requirements as a result of a modification when it undertakes a 
physical or operational change that results in a significant emission 
increase and a net emissions increase. NSR regulations define what 
constitutes a significant net emissions increase, and the concept is 
pollutant-specific. As a result of the decision in Utility Air 
Regulatory Group (UARG) v. Environmental Protection Agency (EPA), 134 
S. Ct. 2427 (2014), a modification that increases only GHG emissions 
above the applicable level will not trigger the requirement to obtain a 
PSD permit. Under existing EPA regulations, a modifying major 
stationary source would trigger PSD permitting requirements for GHGs if 
it undergoes a change or change in the method of operation 
(modification) that results in a significant increase in the emissions 
of a pollutant other than GHGs and results in a GHG emissions increase 
of 75,000 tons per year CO2e as well as a GHG emissions 
increase on a mass basis. Once it has been determined that a change 
triggers the requirements of the NSR program, the source must obtain a 
permit prior to making the change. The pollutant(s) at issue and the 
air quality designation of the area where the

[[Page 64920]]

facility is located or proposed to be built determine the specific 
permitting requirements.
    As part of its CAA section 111(d) plan, a state may impose 
requirements that require an affected EGU to undertake a physical or 
operational change to improve the unit's efficiency that results in an 
increase in the unit's dispatch and an increase in the unit's annual 
emissions. If the emissions increase associated with the unit's changes 
exceeds the thresholds in the NSR regulations for one or more regulated 
NSR pollutants, including the netting analysis, the changes would 
trigger NSR.
    While there may be instances in which an NSR permit would be 
required, we expect those situations to be few. As previously discussed 
in this preamble, states have considerable flexibility in selecting 
varied measures as they develop their plans to meet the goals of the 
emission guidelines. One of these flexibilities is the ability of the 
state to establish emission standards in their CAA section 111(d) plans 
in such a way so that their affected sources, in complying with those 
standards, in fact would not have emissions increases that trigger NSR. 
To achieve this, the state would need to conduct an analysis consistent 
with the NSR regulatory requirements that supports its determination 
that as long as affected sources comply with the emission standards in 
their CAA section 111(d) plan, the source's emissions would not 
increase in a way that trigger NSR requirements.
    For example, a state could decide to use demand-side measures or 
increase reliance on RE as a way of reducing the future emissions of an 
affected source initially predicted (without such alterations) to 
increase its emissions as a result of a CAA section 111(d) plan 
requirement. In other words, a state plan's incorporation of expanded 
use of cleaner generation or demand-side measures could yield the 
result that units that would otherwise be projected to trigger NSR 
through a physical change that might result in increased dispatch would 
not, in fact, increase their emissions, due to reduced demand for their 
operation. The state could also, as part of its CAA section 111(d) 
plan, develop conditions for a source expected to trigger NSR that 
would limit the unit's ability to move up in the dispatch enough to 
result in a significant net emissions increase that would trigger NSR 
(effectively establishing a synthetic minor limit).\1032\
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    \1032\ Certain stationary sources that emit or have the 
potential to emit a pollutant at a level that is equal to or greater 
than specified thresholds are subject to major source requirements. 
See, e.g., CAA sections 165(a)(1), 169(1), 501(2), 502(a). A 
synthetic minor limitation is a legally and practicably enforceable 
restriction that has the effect of limiting emissions below the 
relevant level and that a source voluntarily obtains to avoid major 
stationary source requirements, such as the PSD or Title V 
permitting programs. See, e.g., 40 CFR 52.21(b)(4), 51.166(b)(4), 
70.2 (definition of ``potential to emit'').
---------------------------------------------------------------------------

    In addition, in this final rule, we have also adjusted the date of 
the period for mandatory reductions to 2022, instead of 2020, and 
provided states with flexibility with respect to the glide path. This 
obviates concerns that there is insufficient time for sources that may 
need permits to obtain them and allows additional planning time for 
these changes to be undertaken in a manner that does not trigger PSD. 
As a result of such flexibility and anticipated state involvement, we 
expect that a limited number of affected sources would trigger NSR when 
states implement their plans.

B. Implications for the Title V Program

    In the preamble to the June 18, 2014 proposal, the EPA discussed 
the issue of excessive title V fees resulting inadvertently as a 
consequence of the promulgation of the first section 111 standard to 
regulate GHGs. Specifically, the EPA explained that when the first 
section 111 standard is promulgated for GHGs, if we do not revise 40 
CFR parts 70 and 71 (the operating permit rule), then certain 
permitting authorities would be required to charge emissions-based fees 
for GHGs, resulting in fees that would be far in excess of what is 
required to cover the reasonable costs of the permitting programs. To 
avoid this situation, the EPA proposed as part of the re-proposed 
carbon pollution standards for newly constructed fossil fuel-fired 
power plants (70 FR 1429-1519; January 8, 2014) to exempt GHGs from the 
list of air pollutants that are subject to fee calculation requirements 
under the operating permit rules. Also, we proposed several options to 
impose a smaller fee adjustment for GHGs that would be reasonable and 
designed to recover the costs of addressing GHGs in permitting without 
being excessive.
    In a separate action in this issue of the Federal Register, the EPA 
is finalizing changes to the operating permits rules to address the 
title V fee issue. In particular, we are taking final action to exempt 
GHGs from emissions-based fee calculation requirements under the 
operating permit rules. In addition, we are also finalizing a modest 
GHG fee adjustment to recover the costs of addressing GHGs in 
permitting. The GHG adjustments we are finalizing are based on 
accounting for the number of permit actions that require a GHG 
assessment in a given period, rather than accounting for emissions 
levels of GHGs. Finally, the EPA is also finalizing the addition of 
text within 40 CFR part 60, subpart TTTT, to clarify that the fee 
pollutant for operating permit purposes is GHG (as defined in 40 CFR 
70.2 and 71.2) to add clarity to our regulations and to avoid the 
potential need for possible future rulemakings to adjust the title V 
fee regulations if any constituent of GHG, other than CO2, 
becomes subject to regulation under CAA section 111 for the first time.
    This title V fee issue is a one-time occurrence resulting from the 
promulgation of the first CAA section 111 standard to regulate GHGs 
(the standards of performance for new, modified, and reconstructed 
EGUs, also promulgated in this issue of the Federal Register). The 
title V fee issue is not an issue for any other subsequent CAA section 
111 regulations, such as this section 111(d) standard; thus, there is 
no need to address any title V fee issues in this final rule as part of 
this action.
    In the proposal, the EPA discussed that the section 111 rules would 
have no effect on the applicability thresholds for GHG under the 
operating permit rules. After the proposal for this rulemaking was 
published, the U.S. Supreme Court issued its opinion in UARG v. EPA, 
134 S.Ct. 2427 (June 23, 2014), and in accordance with that decision, 
the D.C. Circuit subsequently issued an amended judgment in Coalition 
for Responsible Regulation, Inc. v. Environmental Protection Agency, 
Nos. 09-1322, 10-073, 10-1092 and 10-1167 (D.C. Cir., April 10, 2015). 
Those decisions support the same overall conclusion, as the EPA 
discussed in the proposal, with respect to the effect of this final 
section 111 rule on the applicability thresholds for GHGs under the 
operating permits rules, though for different reasons.
    With respect to title V, the Supreme Court said that EPA may not 
treat GHGs as an air pollutant for purposes of determining whether a 
source is a major source required to obtain a title V operating permit. 
In accordance with that decision, the D.C. Circuit's amended judgment 
vacated the title V regulations under review in that case to the extent 
that they require a stationary source to obtain a title V permit solely 
because the source emits or has the potential to emit GHGs above the 
applicable major source thresholds. The D.C. Circuit also directed the 
EPA to consider whether any further revisions to its regulations are 
appropriate in light of UARG v. EPA, and, if so, to undertake to make 
such revisions. These court

[[Page 64921]]

decisions make clear that promulgation of CAA section 111 requirements 
for GHGs will not result in EPA imposing a requirement that stationary 
sources obtain a title V permit solely because such sources emit or 
have the potential to emit GHGs above the applicable major source 
thresholds.

C. Interactions With Other EPA Rules

    Fossil fuel-fired EGUs are, or potentially will be, impacted by 
several other recently finalized or proposed EPA rules.\1033\ The EPA 
recognizes the importance of assuring that each of the rules described 
below can achieve its intended environmental objectives in a 
commonsense, cost-effective manner, consistent with underlying 
statutory requirements, and while assuring a reliable power system. 
Executive Order 13563, ``Improving Regulation and Regulatory Review,'' 
issued on January 18, 2011, states that ``[i]n developing regulatory 
actions and identifying appropriate approaches, each agency shall 
attempt to promote . . . coordination, simplification, and 
harmonization. Each agency shall also seek to identify, as appropriate, 
means to achieve regulatory goals that are designed to promote 
innovation.'' Within the EPA, we are paying careful attention to the 
interrelatedness and potential impacts on the industry, reliability and 
cost that these various rulemakings can have.
---------------------------------------------------------------------------

    \1033\ We discuss other rulemakings solely for background 
purposes. The effort to coordinate rulemakings is not a defense to a 
violation of the CAA. Sources cannot defer compliance with existing 
requirements because of other upcoming regulations.
---------------------------------------------------------------------------

1. Mercury and Air Toxics Standards (MATS)
    On February 16, 2012, the EPA issued the MATS rule (77 FR 9304) to 
reduce emissions of toxic air pollutants from new and existing coal- 
and oil-fired EGUs. The MATS rule will reduce emissions of heavy 
metals, including mercury, arsenic, chromium, and nickel; and acid 
gases, including hydrochloric acid and hydrofluoric acid. These toxic 
air pollutants, also known as hazardous air pollutants or air toxics, 
are known to cause, or suspected of causing, damage nervous system 
damage, cancer, and other serious health effects. The MATS rule will 
also reduce SO2 and fine particle pollution, which will 
reduce particle concentrations in the air and prevent thousands of 
premature deaths and tens of thousands of heart attacks, bronchitis 
cases and asthma episodes.
    New or reconstructed EGUs (i.e., sources that commence construction 
or reconstruction after May 3, 2011) subject to the MATS rule are 
required to comply by April 16, 2012 or upon startup, whichever is 
later.
    Existing sources subject to the MATS rule were required to begin 
meeting the rule's requirements on April 16, 2015. Controls that will 
achieve the MATS performance standards are being installed on many 
units. Certain units, especially those that operate infrequently, may 
be considered not worth investing in given today's electricity market, 
and are closing. The final MATS rule provided a foundation on which 
states and other permitting authorities could rely in granting an 
additional, fourth year for compliance provided for by the CAA. States 
report that these fourth year extensions are being granted. In 
addition, the EPA issued an enforcement policy that provides a clear 
pathway for reliability-critical units to receive an administrative 
order that includes a compliance schedule of up to an additional year, 
if it is needed to ensure electricity reliability.
2. Cross-State Air Pollution Rule (CSAPR)
    The CSAPR requires states to take action to improve air quality by 
reducing SO2 and NOX emissions that cross state 
lines. These pollutants react in the atmosphere to form fine particles 
and ground-level ozone and are transported long distances, making it 
difficult for other states to attain and maintain the NAAQS. The first 
phase of CSAPR became effective on January 1, 2015, for SO2 
and annual NOX, and May 1, 2015, for ozone season 
NOX. The second phase will become effective on January 1, 
2017, for SO2 and annual NOX, and May 1, 2017, 
for ozone season NOX. Many of the power plants participating 
in CSAPR have taken actions to reduce hazardous air pollutants for MATS 
compliance that will also reduce SO2 and/or NOX. 
In this way these two rules are complementary. Compliance with one 
helps facilities comply with the other.
3. Requirements for Cooling Water Intake Structures at Power Plants 
(316(b) Rule)
    On May 19, 2014, the EPA issued a final rule under section 316(b) 
of the Clean Water Act (CWA) (33 U.S.C. 1326(b)) (referred to 
hereinafter as the 316(b) rule.) The rule was published on August 15, 
2014 (79 FR 48300; August 15, 2014), and became effective October 14, 
2014. The 316(b) rule establishes new standards to reduce injury and 
death of fish and other aquatic life caused by cooling water intake 
structures at existing power plants and manufacturing facilities.\1034\ 
The 316(b) rule subjects existing power plants and manufacturing 
facilities that withdraw in excess of 2 million gallons per day) of 
cooling water, and use at least 25 percent of that water for cooling 
purposes, to a national standard designed to reduce the number of fish 
destroyed through impingement and a national standard for establishing 
entrainment reduction requirements. All facilities subject to the rule 
must submit information on their operations for use by the permit 
authority in determining 316(b) permit conditions. Certain plants that 
withdraw very large volumes of water will also be required to conduct 
additional studies for use by the permit authority in determining the 
site-specific entrainment reduction measures for such facilities. The 
rule provides significant flexibility for compliance with the 
impingement standards and, as a result, is not projected to impose a 
substantial cost burden on affected facilities. With respect to 
entrainment, the rule calls upon the permitting authority to establish 
appropriate entrainment reduction measures, taking into account, among 
other factors, remaining useful plant life and quantified and 
qualitative social benefits and cost. The permit writer may also 
consider impacts on the reliability of energy delivery within the 
facility's immediate area. Existing sources subject to the 316(b) rule 
are required to comply with the impingement requirements as soon as 
practicable after the entrainment requirements are determined. They 
must comply with applicable site-specific entrainment reduction 
controls based on the schedule of requirements established by the 
permitting authority.
---------------------------------------------------------------------------

    \1034\ CWA section 316(b) provides that standards applicable to 
point sources under sections 301 and 306 of the Act must require 
that the location, design, construction and capacity of cooling 
water intake structures reflect the best technology available for 
minimizing adverse environmental impacts.
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4. Disposal of Coal Combustion Residuals From Electric Utilities (CCR 
Rule)
    On December 19, 2014, the EPA issued the final rule for the 
disposal of coal combustion residuals from electric utilities. The rule 
provides a comprehensive set of requirements for the safe disposal of 
coal combustion residuals (CCRs), commonly known as coal ash, from 
coal-fired power plants. The CCR rule is the culmination of extensive 
study on the effects of coal ash on the environment and public health. 
The CCR rule establishes technical requirements for existing and

[[Page 64922]]

new CCR landfills and surface impoundments under the Resource 
Conservation and Recovery Act, Subtitle D (42 U.S.C. 6941-6949a), the 
nation's primary law for regulating solid waste.
    These regulations address the risks from coal ash disposal--leaking 
of contaminants into ground water, blowing of contaminants into the air 
as dust, and the catastrophic failure of coal ash surface impoundments 
by establishing requirements for where CCR landfills and surface 
impoundments may be located, how they must be designed, operated and 
monitored, when they must be inspected, and how they must be closed and 
cared for after closure. Additionally, the CCR rule sets out 
recordkeeping and reporting requirements, as well as the requirement 
for each facility to establish and post specific information to a 
publicly-accessible Web site. The final rule also supports the 
responsible recycling of CCRs by distinguishing safe, beneficial use 
from disposal.
5. Steam Electric Effluent Limitation Guidelines and Standards (SE ELG 
Rule)
    The EPA is reviewing public comments and working to finalize the 
proposed SE ELG rule which will impact existing fossil fuel-fired EGUs. 
In 2013, the EPA proposed the SE ELG rule (78 FR 34432; June 7, 2013) 
to strengthen the controls on discharges from certain steam electric 
power plants by revising technology-based effluent limitations 
guidelines and standards for the steam electric power generating point 
source category. The current regulations, which were last updated in 
1982, do not adequately address the toxic pollutants discharged from 
the electric power industry, nor have they kept pace with process 
changes that have occurred over the last three decades. Existing steam 
electric power plants currently contribute 50-60 percent of all toxic 
pollutants discharged to surface waters by all industrial categories 
regulated in the U.S. under the CWA. Furthermore, power plant 
discharges to surface waters are expected to increase as pollutants are 
increasingly captured by air pollution controls and transferred to 
wastewater discharges. The proposed regulation, which includes new 
requirements for both existing and new generating units, would reduce 
impacts to human health and the environment by reducing the amount of 
toxic metals and other pollutants currently discharged to surface 
waters from power plants. The EPA intends to take final action on the 
proposed rule by September 30, 2015.
    The EPA is endeavoring to enable EGUs to comply with applicable 
obligations under other power sector rules as efficiently as possible 
(e.g., by facilitating their ability to coordinate planning and 
investment decisions with respect to those rules) and, where possible, 
implement integrated compliance strategies. For example, in the 
proposed SE ELG rule, the EPA describes its thinking on how it might 
effectively harmonize the potential requirements of that rule with the 
requirements of the final CCR rule. Because these two rules affect 
similar units and may be met with similar compliance strategies, 
common-sense implementation timeframes were established in the CCR 
final rule so that utilities would not be required to make major 
decisions about CCR units without first understanding the implications 
that such decisions would have for meeting the surface water protection 
requirements of the final ELG rule. The EPA is taking into account 
these new CCR requirements for coal ash as it develops the final SE ELG 
rule. The EPA's goal in harmonizing the SE ELG and CCR rules is to 
minimize the overall complexity of the two regulatory structures and 
avoid creating unnecessary burden.
6. Other EPA Rules
    In addition to the power sector rules discussed above, the 
development of SIPs for criteria pollutants (ozone, PM2.5, 
and SO2) and regional haze may also have implications for 
existing fossil-fired EGUs.
    Regarding ozone, the proposal included a discussion of the June 6, 
2013, proposed implementation rule for the 2008 ozone National Ambient 
Air Quality Standards (NAAQS), addressing the statutory requirements 
for areas EPA has designated as nonattainment for the 2008 ozone NAAQS. 
The final implementation rule for the 2008 ozone NAAQS was signed on 
February 13, 2015, and published on March 6, 2015, with an effective 
date of April 6, 2015. In general, the 2008 ozone NAAQS implementation 
rule interprets applicable statutory requirements and provides 
flexibility to states to minimize administrative burdens associated 
with developing and implementing plans to meet and maintain the NAAQS. 
The rule establishes due dates for attainment plans and clarifies 
attainment dates for each ozone nonattainment area according to its 
classification based on air quality thresholds, with attainment dates 
starting in July 2015 through July 2032 depending on an area's 
classification.
    On November 25, 2014, the EPA Administrator signed the proposed 
rulemaking for the 2015 revisions to the ozone NAAQS. The proposal was 
published in the Federal Register on December 17, 2014 (79 FR 75234). 
The Administrator proposed to revise the primary ozone standard to a 
level in the range of 0.065 to 0.070 ppm and took comment on lower 
levels including 0.060 ppm and on retaining the current standard of 
0.075 ppm. Among other things, the ozone NAAQS proposal also proposed 
to retain the current indicator, averaging time, and form of the 
standard and included a proposed secondary ozone NAAQS in the 0.065 to 
0.070 ppm range.
    The proposal also outlined the key implementation milestones 
requiring revised SIPs, with due dates starting in October 2018 for 
infrastructure and interstate transport SIPs, attainment plans due 
2020-21, and attainment dates of 2020-37. The EPA is under a court 
order to finalize its review of the ozone NAAQS by October 1, 2015.
    Some commenters expressed concern with the potential impact 
proposed revisions to the ozone NAAQS could have on state planning 
efforts and affected entities' ability to comply with any potentially 
new requirements associated with a revised ozone NAAQS and those 
related to the 111(d) emission guidelines. In particular, commenters 
raised issues with a potentially more stringent ozone standard and the 
permitting and state planning implications this may create. While there 
was no discussion of the proposed revisions to the ozone NAAQS in the 
111(d) emission guidelines proposal, commenters expressed a desire for 
the EPA to coordinate promulgation of the final 111(d) emission 
guidelines (and any other climate regulations) with the potential 
revision to the ozone standard to provide certainty and flexibility for 
states and affected sources.
    While it is premature to speculate about the outcome of the ozone 
NAAQS review and how a more stringent ozone NAAQS may impact sources of 
ozone precursor emissions, including EGUs, we believe the planning and 
compliance timeframes that would follow from a revised ozone NAAQS and 
the timeframes we are finalizing today for submittal of the CAA section 
111(d) state plans will allow considerable time for coordination by 
states in the development of their respective plans, as needed. As 
stated in the proposal, the EPA is prepared to work with states to 
assist them in coordinating their efforts across these planning 
processes.
    Regarding PM2.5 NAAQS implementation, the proposal 
stated that

[[Page 64923]]

the EPA was developing a proposed implementation rule to provide 
guidance to states on the development of SIPs for the 2012 
PM2.5 NAAQS. The proposed PM2.5 SIP requirements 
rule was signed on March 10, 2015, and published on March 23, 2015 (80 
FR 15340). The proposal addresses a number of requirements including 
attainment plan due dates, attainment dates and attainment date 
extension criteria for Moderate and Serious nonattainment areas; 
determination criteria for Reasonably Available Control Measures (RACM) 
for Moderate areas and Best Available Control Measures (BACM) for 
Serious areas; plans for demonstrating reasonable further progress and 
for meeting periodic quantitative milestones; and criteria for 
reclassifying a Moderate nonattainment area to Serious. The EPA is 
planning to finalize the PM2.5 implementation rule in early 
2016.
    There are currently only 9 areas designated nonattainment for the 
2012 PM2.5 NAAQS, with an effective date of April 15, 2015. 
Since the attainment plans for these areas must be completed and 
submitted to the EPA in September 2016, we expect that the four states 
with such areas should have already decided on their approach to 
implementing the 2012 PM2.5 NAAQS when they begin to develop 
their plans for implementing the 111(d) guidelines, and will be able to 
coordinate the two.
    Related to the SO2 NAAQS, and as stated in the proposal, 
the SO2 NAAQS was revised in June 2010 to protect public 
health from the short-term effects of SO2 exposure. In July 
2013, the EPA designated 29 areas in 16 states as nonattainment for the 
SO2 NAAQS. The EPA based these nonattainment designations on 
the most recent set of certified air quality monitoring data as well as 
an assessment of nearby emission sources and weather patterns that 
contribute to the monitored levels. The date for attainment plans for 
these areas to be completed and submitted to the EPA was April 2015. As 
such, we expect states with such areas to have already decided on their 
approach to implementing the SO2 NAAQS as they start 
planning for implementation of the 111(d) guidelines, which should 
allow for coordination and consideration of SO2 related air 
quality measures into their 111(d) planning. The EPA intends to address 
the designations for all other areas in three separate actions in the 
future.\1035\ These designations must be completed by no later than 
July 2, 2016, December 31, 2017, and December 31, 2020 with attainment 
plans due between 2018 and 2022.
---------------------------------------------------------------------------

    \1035\ The EPA has developed a comprehensive implementation 
strategy for these future actions that focuses resources on 
identifying and addressing unhealthy levels of SO2 in 
areas where people are most likely to be exposed to violations of 
the standard. The strategy is available at http://www.epa.gov/airquality/sulfurdioxide/implement.html, and the associated area 
designations schedule is at http://www.epa.gov/airquality/sulfurdioxide/designations/pdfs/201503Schedule.pdf.
---------------------------------------------------------------------------

    Regarding requirements under the regional haze program, several 
affected EGUs have deadlines in the 2016-2021 timeframe to install 
controls to comply with the Best Available Retrofit Technology (BART) 
and reasonable progress requirements of the Regional Haze Rule. Soon 
after these deadlines, some of the same affected EGUs may be required 
to reduce their utilization, convert into natural gas-fired facilities, 
or shut down entirely as a result of state 111(d) plans. Some 
commenters have expressed concern that for these affected EGUs, 
specifically those that choose to retire, the capital equipment 
installed to comply with the Regional Haze Rule would likely become 
stranded assets.
    While the EPA is providing considerable flexibility for states and 
sources under the final 111(d) emission guidelines, the EPA 
acknowledges the possibility that some sources could ultimately be 
faced with the potential for stranded assets as a result of state 
111(d) plans. For these sources, however, states have the option of 
developing BART alternatives that replace control requirements that 
would otherwise result in stranded assets at a particular EGU with the 
aggregate emission reductions that will result from retirements, fuel 
switching, reduced utilization, or lesser controls at multiple EGUs.
    In fact, the EPA already has experience working with states to 
account for these very types of changed circumstances.\1036\ The EPA 
will continue to work with states to explore options for integrating 
compliance requirements across multiple regulatory programs, as 
warranted.
---------------------------------------------------------------------------

    \1036\ For example, Oregon replaced its BART determination for 
the Boardman Coal Plant with a new requirement that accounted for a 
planned shutdown before the EPA took action on the state's SIP 
submission (76 FR 12661). Washington similarly replaced its BART 
determination for the TransAlta Centralia Power Plant before the EPA 
took action on the state's SIP submission (77 FR 72742). Oklahoma 
submitted a SIP revision with a new BART determination for the AEP/
PSO Northeastern Power Station, which included enforceable 
requirements for reduced utilization and early unit retirements, to 
replace a FIP that had been promulgated by the EPA (79 FR 12944). 
Finally, the EPA finalized a BART determination for Unit 3 at the 
Dave Johnston Power Plant in Wyoming that included two compliance 
options, one of which included a federally enforceable retirement 
date and less costly controls.
---------------------------------------------------------------------------

    The EPA believes that CAA section 111(d) efforts and actions will 
tend to contribute to overall air quality improvements and thus should 
be complementary to criteria pollutant and regional haze SIP efforts.
7. Final Rule Flexibilities
    As discussed in Section VIII of this preamble, the EPA is providing 
states flexibility in developing approvable plans under CAA section 
111(d), including the ability to impose source-by-source limitations 
reflecting the BSER performance rates to each affected EGU or to adopt 
rate-based or mass-based emission performance goals, and to rely on a 
wide range of CO2 emission reduction measures, including 
measures that are not part of the BSER. The EPA is also providing 
states considerable flexibility with respect to the timeframes for plan 
development and implementation, with up to 3 years permitted for final 
plans to be submitted after the GHG emission guidelines are finalized, 
and up to 15 years for all emission reduction measures to be fully 
implemented. The EPA is establishing an 8-year interim period over 
which to achieve the full required reductions to meet the 
CO2 performance rates, and this begins in 2022, more than 
seven years from the June 18, 2014 date of proposal of the rulemaking. 
The 8-year interim period from 2022 through 2029, is separated into 
three steps, 2022-2024, 2025-2027, and 2028-2029, each associated with 
its own interim CO2 emission performance rates.
    In light of these broad flexibilities, we believe that states will 
have ample opportunity, when developing and implementing their CAA 
section 111(d) plans, to coordinate their response to this requirement 
with source and state responses to any obligations that may be 
applicable to affected EGUs as a result of the MATS, CSAPR, 316(b), SE 
ELG and CCR rules, all of which are or soon will be final rules. In 
addition, we believe that states will be able to design CAA section 
111(d) plans that use innovative, cost-effective regulatory strategies, 
that spark investment and innovation across a wide variety of clean 
energy technologies, and that will help reduce cost and ensure 
reliability, while also ensuring that all applicable environmental 
requirements are met.\1037\ We also believe that the broad

[[Page 64924]]

flexibilities in this action will enable states and affected EGUs to 
build on their longstanding, successful records of complying with 
multiple CAA, CWA, and other environmental requirements, while assuring 
an adequate, affordable, and reliable supply of electricity.
---------------------------------------------------------------------------

    \1037\ It should be noted that regulatory obligations imposed 
upon states and sources operate independently under different 
statutes and sections of statutes; the EPA expects that states and 
sources will take advantage of available flexibilities as 
appropriate, but will comply with all relevant legal requirements.
---------------------------------------------------------------------------

XI. Impacts of This Action 1038
---------------------------------------------------------------------------

    \1038\ The impacts presented in this section of the preamble 
represent an illustrative implementation of the guidelines. As 
states implement the final guidelines, they have sufficient 
flexibility to adopt different state-level or regional approaches 
that may yield different costs, benefits, and environmental impacts. 
For example, states may use the flexibilities described in these 
guidelines to find approaches that are more cost-effective for their 
particular state or choose approaches that shift the balance of co-
benefits and impacts to match broader state priorities.
---------------------------------------------------------------------------

A. What are the air impacts?

    The EPA anticipates significant emission reductions under the final 
guidelines for the utility power sector. In the final emission 
guidelines, the EPA has translated the source category-specific 
CO2 emission performance rates into equivalent state-level 
rate-based and mass-based CO2 goals in order to maximize the 
range of choices that states will have in developing their plans. 
Because of the range of choices available to states and the lack of a 
priori knowledge about the specific choices states will make in 
response to the final goals, the Regulatory Impact Analysis (RIA) for 
this final action presents two scenarios designed to achieve these 
goals, which we term the ``rate-based'' illustrative plan approach and 
the ``mass-based'' illustrative plan approach.\1039\
---------------------------------------------------------------------------

    \1039\ It is important to note that the differences between the 
analytical results for the rate-based and mass-based illustrative 
plan approaches presented in the RIA may not be indicative of likely 
differences between the approaches if implemented by states and 
affected EGUs in response to the final guidelines. If one approach 
performs differently than the other on a given metric during a given 
time period, this does not imply this will apply in all instances.
---------------------------------------------------------------------------

    Under the rate-based approach, when compared to 2005, 
CO2 emissions are projected to be reduced by approximately 
22 percent in 2020, 28 percent in 2025, and 32 percent in 2030. Under 
the mass-based approach, when compared to 2005, CO2 
emissions are projected to be reduced by approximately 23 percent in 
2020, 29 percent in 2025, and 32 percent in 2030. The final guidelines 
are projected to result in substantial co-benefits through reductions 
of SO2, NOX and PM2.5 that will have 
direct public health benefits by lowering ambient levels of these 
pollutants and ozone. Tables 15 and 16 show expected CO2 and 
other air pollutant emissions in the base case and reductions under the 
final guidelines for 2020, 2025, and 2030 for the rate-based and mass-
based approaches, respectively.

    Table 15--Summary of CO2 and Other Air Pollutant Emission Reductions From the Base Case Under Rate-Based
                                           Illustrative Plan Approach
----------------------------------------------------------------------------------------------------------------
                                                CO2  (millions short  SO2  (thousand short  NOX  (thousand short
                                                        tons)                 tons)                 tons)
----------------------------------------------------------------------------------------------------------------
2020 Final Guidelines:
    Base Case.................................                 2,155                 1,311                 1,333
    Final Guidelines..........................                 2,085                 1,297                 1,282
    Emissions Reductions......................                    69                    14                    50
2025 Final Guidelines:
    Base Case.................................                 2,165                 1,275                 1,302
    Final Guidelines..........................                 1,933                 1,097                 1,138
    Emissions Reductions......................                   232                   178                   165
2030 Final Guidelines:
    Base Case.................................                 2,227                 1,314                 1,293
    Final Guidelines..........................                 1,812                   996                 1,011
    Emissions Reductions......................                   415                   318                   282
----------------------------------------------------------------------------------------------------------------
Source: Integrated Planning Model, 2015.
Note: Emissions may not sum due to rounding.


    Table 16--Summary of CO2 and Other Air Pollutant Emission Reductions From the Base Case Under Mass-Based
                                           Illustrative Plan Approach
----------------------------------------------------------------------------------------------------------------
                                                 CO2  (million short  SO2  (thousand short  NOX  (thousand short
                                                        tons)                 tons)                 tons)
----------------------------------------------------------------------------------------------------------------
2020 Final Guidelines:
    Base Case.................................                 2,155                 1,311                 1,333
    Final Guidelines..........................                 2,073                 1,257                 1,272
    Emissions Reductions......................                    81                    54                    60
2025 Final Guidelines:
    Base Case.................................                 2,165                 1,275                 1,302
    Final Guidelines..........................                 1,901                 1,090                 1,100
    Emissions Reductions......................                   265                   185                   203
2030 Final Guidelines:
    Base Case.................................                 2,227                 1,314                 1,293
    Final Guidelines..........................                 1,814                 1,034                 1,015
    Emissions Reductions......................                   413                   280                   278
----------------------------------------------------------------------------------------------------------------
Source: Integrated Planning Model, 2015.
Note: Emissions may not sum due to rounding.


[[Page 64925]]

    The reductions in Tables 15 and 16 do not account for reductions in 
hazardous air pollutants (HAPs) that may occur as a result of this 
rule. For instance, the fine particulate reductions presented above do 
not reflect all of the reductions in many heavy metal particulates.

B. Endangered Species Act

    As explained in the preamble to the proposed rule (79 FR at 34933-
934), the EPA has carefully considered the requirements of section 
7(a)(2) of the Endangered Species Act (ESA) and applicable ESA 
regulations, and reviewed relevant ESA case law and guidance, to 
determine whether consultation with the U.S. Fish and Wildlife Service 
(FWS) and/or National Marine Fisheries Service (together, the Services) 
is required by the ESA. The EPA proposed to conclude that the 
requirements of ESA section 7(a)(2) would not be triggered by 
promulgation of the rule, and we now finalize that determination.
    Section 7(a)(2) of the ESA requires federal agencies, in 
consultation with one or both of the Services (depending on the species 
at issue), to ensure that actions they authorize, fund, or carry out 
are not likely to jeopardize the continued existence of federally 
listed endangered or threatened species or result in the destruction or 
adverse modification of designated critical habitat of such species. 16 
U.S.C. 1536(a)(2). Under relevant implementing regulations, section 
7(a)(2) applies only to actions where there is discretionary federal 
involvement or control. 50 CFR 402.03. Further, under the regulations 
consultation is required only for actions that ``may affect'' listed 
species or designated critical habitat. 50 CFR 402.14. Consultation is 
not required where the action has no effect on such species or habitat. 
Under this standard, it is the federal agency taking the action that 
evaluates the action and determines whether consultation is required. 
See 51 FR 19926, 19949 (June 3, 1986). Effects of an action include 
both the direct and indirect effects that will be added to the 
environmental baseline. 50 CFR 402.02. Direct effects are the direct or 
immediate effects of an action on a listed species or its 
habitat.\1040\ Indirect effects are those that are ``caused by the 
proposed action and are later in time, but still are reasonably certain 
to occur.'' Id. To trigger the consultation requirement, there must 
thus be a causal connection between the federal action, the effect in 
question, and the listed species, and if the effect is indirect, it 
must be reasonably certain to occur.
---------------------------------------------------------------------------

    \1040\ See Endangered Species Consultation Handbook, U.S. Fish & 
Wildlife Service and National Marine Fisheries Service at 4-25 
(March 1998) (providing examples of direct effects: e.g., driving an 
off road vehicle through the nesting habitat of a listed species of 
bird and destroying a ground nest; building a housing unit and 
destroying the habitat of a listed species). Available at https://www.fws.gov/ENDANGERED/esa-library/pdf/esa_section7_handbook.pdf.
---------------------------------------------------------------------------

    The EPA notes that the projected environmental effects of this rule 
are positive: Reductions in overall GHG emissions, and reductions in PM 
and ozone-precursor emissions (SO2 and NOX). The 
EPA recognizes that beneficial effects to listed species can, as a 
general matter, result in a ``may affect'' determination under the ESA. 
However, the EPA's assessment that the rule will have an overall net 
positive environmental effect by virtue of reducing emissions of 
certain air pollutants does not address whether the rule may affect any 
listed species or designated critical habitat for ESA section 7(a)(2) 
purposes and does not constitute any finding of effects for that 
purpose. The fact that the rule will have overall positive effects on 
the national and global environment does not mean that the rule may 
affect any listed species in its habitat or the designated critical 
habitat of such species within the meaning of ESA section 7(a)(2) or 
the implementing regulations or require ESA consultation. The EPA has 
considered various types of potential effects in reaching the 
conclusion that ESA consultation is not required for this rule.
    With respect to the projected GHG emission reductions, the EPA 
considered in detail in the proposal why such reductions do not trigger 
ESA consultation requirements under section 7(a)(2). As explained in 
the proposal, in reaching this conclusion the EPA was mindful of 
significant legal and technical analysis undertaken by FWS and the U.S. 
Department of the Interior (DOI) in the context of listing the polar 
bear as a threatened species under the ESA. In that context, in 2008, 
FWS and DOI expressed the view that the best scientific data available 
were insufficient to draw a causal connection between GHG emissions and 
effects on the species in its habitat.\1041\ The DOI Solicitor 
concluded that where the effect at issue is climate change, proposed 
actions involving GHG emissions cannot pass the ``may affect'' test of 
the section 7 regulations and thus are not subject to ESA consultation.
---------------------------------------------------------------------------

    \1041\ See, e.g., 73 FR 28212, 28300 (May 15, 2008); Memorandum 
from David Longly Bernhardt, Solicitor, U.S. Department of the 
Interior re: ``Guidance on the Applicability of the Endangered 
Species Act's Consultation Requirements to Proposed Actions 
Involving the Emission of Greenhouse Gases'' (Oct. 3, 2008). 
Available at http://www.doi.gov/solicitor/opinions/M-37017.pdf.
---------------------------------------------------------------------------

    As described in the proposal, the EPA has also previously 
considered issues relating to GHG emissions in connection with the 
requirements of ESA section 7(a)(2) and has supplemented DOI's analysis 
with additional consideration of GHG modeling tools and data regarding 
listed species. Although the GHG emission reductions projected for this 
final rule are large (estimated reductions of about 415 million short 
tons of CO2 in 2030 relative to the base case under the 
rate-based illustrative plan approach--see Table 14 above), the EPA 
evaluated larger reductions in assessing this same issue in the context 
of the light-duty vehicle GHG emission standards for model years 2012-
2016 and 2017-2025. There the agency projected emission reductions over 
the lifetimes of the model years in question \1042\ which are roughly 
five to six times those projected above and, based on air quality 
modeling of potential environmental effects, concluded that ``EPA knows 
of no modeling tool which can link these small, time-attenuated changes 
in global metrics to particular effects on listed species in particular 
areas. Extrapolating from global metric to local effect with such small 
numbers, and accounting for further links in a causative chain, remain 
beyond current modeling capabilities.'' \1043\ The EPA reached this 
conclusion after evaluating issues relating to potential improvements 
relevant to both temperature and oceanographic pH outputs. The EPA's 
ultimate finding was that ``any potential for a specific impact on 
listed species in their habitats associated with these very small 
changes in average global temperature and ocean pH is too remote to 
trigger the threshold for ESA section 7(a)(2).'' Id. The EPA believes 
that the same conclusion applies to the present rule. See, e.g., Ground 
Zero Center for Non-Violent Action v. U.S. Dept. of Navy, 383 F. 3d 
1082, 1091-92 (9th Cir. 2004) (where the likelihood of jeopardy to a 
species from a federal action is extremely remote, ESA does not require 
consultation). The EPA's conclusion is entirely consistent with DOI's 
analysis regarding ESA requirements in the

[[Page 64926]]

context of federal actions involving GHG emissions.\1044\
---------------------------------------------------------------------------

    \1042\ See 75 FR at 25438 Table I.C 2-4 (May 7, 2010); 77 FR at 
62894 Table III-68 (Oct. 15, 2012).
    \1043\ EPA, Light-Duty Vehicle Greenhouse Gas Emission Standards 
and Corporate Average Fuel Economy Standards, Response to Comment 
Document for Joint Rulemaking at 4-102 (Docket ID EPA-OAR-HQ-2010-
0799). Available at http://www.epa.gov/otaq/climate/regulations/420r10012a.pdf.
    \1044\ The EPA has received correspondence from a U.S. Senator 
and a Member of the U.S. House of Representatives noting that the 
Services have identified several listed species affected by global 
climate change. See Letter from Rob Bishop, Chairman, House 
Committee on Natural Resources, to Gina McCarthy, Administrator, 
U.S. Environmental Protection Agency, dated June 11, 2015; Letter 
from Rob Bishop, Chairman, House Committee on Natural Resources, and 
James M. Inhofe, Chairman, Senate Committee on Environment and 
Public Works, to Gina McCarthy, Administrator, U.S. Environmental 
Protection Agency, dated June 15, 2015. EPA's assessment of ESA 
requirements in connection with the present rule does not address 
whether global climate change may, as a general matter, be a 
relevant consideration in the status of certain listed species. 
Rather, the requirements of ESA section 7(a)(2) must be considered 
and applied to the specific action at issue. As explained above, 
EPA's conclusion that ESA section 7(a)(2) consultation is not 
required here is premised on the specific facts and circumstances of 
the present rule and is fully consistent with prior relevant 
analyses conducted by DOI, FWS, and EPA.
---------------------------------------------------------------------------

    With regard to non-GHG air emissions, the EPA also projects 
substantial reductions of SO2 and NOX as a 
collateral consequence of this final action. However, CAA section 
111(d)(1) standards cannot directly control emissions of criteria 
pollutants. See CAA section 111(d)(1)(i). Consequently, CAA section 
111(d) provides no discretion to adjust the standard based on potential 
impacts to endangered species of reduced criteria pollutant emissions. 
Section 7(a)(2) consultation thus is not required with respect to the 
projected reductions of criteria pollutant emissions. See 50 CFR 
402.03; see also, WildEarth Guardians v. U.S. Envt'l Protection Agency, 
759 F.3d 1196, 1207-10 (10th Cir. 2014) (EPA has no duty to consult 
under section 7(a)(2) of the ESA regarding hazardous air pollutant 
controls that it did not require--and likely lacked authority to 
require--in a federal implementation plan for regional haze controls 
under section 169A of the CAA).
    Finally, the EPA has also considered other potential effects of the 
rule (beyond reductions in air pollutants) and whether any such effects 
are ``caused by'' the rule and ``reasonably certain to occur'' within 
the meaning of the ESA regulatory definition of the effects of an 
action. 50 CFR 402.02. As the EPA noted in the proposal, there are 
substantial questions as to whether any potential for relevant effects 
results from any element of the rule or would result instead from 
separate decisions and actions made in connection with the development, 
implementation, and enforcement of a plan to implement the standards 
established in the rule. Cf. American Trucking Assn's v. EPA, 175 F. 3d 
1027, 1043-45 (D.C. Cir. 1999), rev'd on different grounds sub nom., 
Whitman v. American Trucking Assn's, 531 U.S. 457 (2000) (National 
Ambient Air Quality Standards have no economic impact, for purposes of 
Regulatory Flexibility Act, because impacts result from the actions of 
states through their development, implementation and enforcement of 
SIPs).\1045\ The EPA recognized, for instance, that questions may exist 
whether decisions such as increased utilization of solar or wind power 
could have effects on listed species. The EPA received comments on the 
proposal asserting that because potential increased reliance on wind or 
solar power may be an element of building block 3, and because wind and 
solar facilities may in some cases have effects on listed species, the 
EPA must consult under the ESA on this aspect of the rule. The EPA is 
also aware of certain questions regarding potential effects of the rule 
on the Big Bend Power Station located in Florida, which discharges 
effluent that provides a warm water refuge for manatees. The Big Bend 
Power Station and another coal-fired facility located in Florida--the 
Crystal River Plant--are, for example, referenced in the June 11, 2015, 
and June 15, 2015, congressional letters to EPA cited above.
---------------------------------------------------------------------------

    \1045\ One commenter questioned the EPA's citation to American 
Trucking Assn's. As stated by the commenter, the statute at issue in 
that case--the Regulatory Flexibility Act (RFA)--is distinguishable 
from the ESA in that it addresses only direct effects and does not 
consider indirect effects. The commenter misreads the EPA's citation 
to this case. The EPA cites this case simply to reference a decision 
considering the impacts of an EPA action--the revision of a NAAQS 
under the CAA--that in certain respects provides a useful analogy to 
the present rule. A NAAQS is implemented through a series of 
subsequent planning decisions generally taken by states by means of 
adoption of SIPs. States can choose to impose or avoid the types of 
impacts at issue in the D.C. Circuit case through their planning 
decisions; thus such impacts were not viewed as having been caused--
for purposes of the RFA--by the EPA's promulgation of the revised 
NAAQS in the first instance. The standard setting and implementation 
mechanisms under section 111(d) are very similar. Under section 
111(d), the EPA is required to establish ``a procedure similar to 
that provided by section 7410''--the provision establishing the SIP 
mechanism for implementing NAAQS. Thus, the D.C. Circuit's 
discussion provides a useful analogy to the present rule and the 
various types of potential effects that may be attributable to 
future implementation planning decisions by states and other 
entities as they exercise their discretion in determining how to 
implement the federal guidelines, but not to promulgation of the 
rule itself. The EPA's citation to this case was not intended to 
address any comparison of the scope of effects covered by the RFA 
and the effects cognizable under section 7(a)(2) of the ESA. The EPA 
is aware that the ESA addresses both direct and indirect effects as 
defined by the applicable ESA regulations. The discussion supporting 
the EPA's ESA conclusion expressly acknowledges the relevance of 
indirect effects to the ESA analysis and explains why such effects 
are not present here.
---------------------------------------------------------------------------

    The EPA has carefully considered the comments and the 
correspondence from Congress as well as the case law and other 
materials cited in those documents. The EPA does not believe that the 
effects of potential future changes in the energy sector--including 
increased reliance on wind or solar power as a result of future 
potential actions by states or other implementing entities--or any 
potential alterations in the operations of any particular facility are 
caused by the current rule or sufficiently certain to occur so as to 
require ESA consultation on the rule. The EPA appreciates that the ESA 
regulations call for consultation where actions authorized, funded, or 
carried out by federal agencies may have indirect effects on listed 
species or designated critical habitat. However, as noted above, 
indirect effects must be caused by the action at issue and must be 
reasonably certain to occur. At this point, there is no reasonable 
certainty regarding implementation of any planning measures in any 
location, let alone in any location occupied by a listed species or its 
designated critical habitat. The EPA cannot predict with reasonable 
certainty where such measures may take effect or which measures may be 
adopted. It is not clear, for instance, whether a particular 
implementation plan will call, if at all, for increased reliance on 
wind power, as opposed to solar power, or on some other form of low or 
zero carbon emitting generation. It is also entirely uncertain how a 
future implementation plan for a particular state might affect, if at 
all, operations at a specific facility.\1046\ The precise steps 
included in an implementation plan cannot be determined or ordered by 
this federal action, and they are not sufficiently certain to be 
attributable to this final rule for ESA purposes. These steps will flow 
from a series of later in time decisions generally made by other 
entities--usually states--in their

[[Page 64927]]

distinct planning processes. These later decisions cannot now be 
required by the rule, are not caused by the rule, and are not 
reasonably certain to occur. The EPA also notes that the plans adopted 
for particular states may themselves provide wide degrees of 
implementation flexibility, thus further increasing the uncertainty 
that any species-impacting activity will occur in any particular 
location, if at all. The Services have explained that section 7(a)(2) 
was not intended to preclude federal actions based on potential future 
speculative effects.\1047\ These are precisely the types of speculative 
future activities and effects at issue here.\1048\ For this additional 
reason, the EPA concludes that the rule does not have effects on listed 
species that trigger the section 7(a)(2) consultation 
requirement.\1049\
---------------------------------------------------------------------------

    \1046\ A congressional letter of June 11, 2015, referenced above 
asserts that EPA's modeling suggests that the Big Bend Power Station 
and Crystal River Energy Complex in Florida will be prematurely 
retired as a result of the rule. EPA notes that any such facility-
level projections associated with the rule cannot be stated with 
sufficient certainty to qualify as potential indirect effects under 
the ESA. These projections are based on numerous assumptions 
regarding a variety of planning and business decisions yet to be 
made by the implementing governments (usually states) and facility 
owners. Given the wide degrees of discretion and flexibility and the 
numerous options available for such decision making, the potential 
for such outcomes to be realized as currently projected is at this 
point too uncertain to qualify as an effect under the ESA.
    \1047\ See 51 FR at 19933 (describing effects that are 
``reasonably certain to occur'' in the context of consideration of 
cumulative effects and distinguishing broader consideration that may 
be appropriate in applying a procedural statute such as the National 
Environmental Policy Act, as opposed to a substantive provision such 
as ESA section 7(a)(2) that may prohibit certain federal actions); 
Endangered Species Consultation Handbook, U.S. Fish & Wildlife 
Service and National Marine Fisheries Service at 4-30 (March 1998) 
(in the same context, describing indicators that an activity is 
reasonably certain to occur as including governmental approvals of 
the action or indications that such approval is imminent, project 
sponsors' assurance that the action will proceed, obligation of 
venture capital, or initiation of contracts; and noting that the 
more governmental administrative discretion remains to be exercised, 
the less there is reasonable certainty the action will proceed). 
Available at https://www.fws.gov/ENDANGERED/esa-library/pdf/esa_section7_handbook.pdf.
    \1048\ EPA also notes that some of the future implementing 
activities may involve federal actions that are subject to ESA 
consultation, thus providing consideration of any impacts on listed 
species at the appropriate point when particular activities have 
become reasonably certain. Several commenters on the proposal 
specifically noted that such future activities--e.g., development of 
additional RE facilities such as wind farms--may call for ESA 
consultation. Further, EPA notes that section 9 of the ESA, which 
prohibits the take of individuals of most listed species, provides 
an additional protection for listed species as future implementing 
activities become reasonably certain.
    \1049\ The commenters cite certain cases that they assert 
support consulting under ESA section 7(a)(2). The EPA has considered 
these cases, each of which is distinguishable from the present rule. 
By way of example, a commenter cites two cases involving EPA 
actions: Defenders of Wildlife v. EPA, 420 F.3d 946 (9th Cir. 2005), 
rev'd, National Association of Homebuilders v. Defenders of 
Wildlife, 551 U.S. 644 (2007); and Washington Toxics Coalition v. 
EPA, 413 F.3d 1024 (9th Cir. 2005). In Defenders of Wildlife (a 
decision that was reversed by the U.S. Supreme Court), a principal 
relevant impact of the federal action at issue--the EPA's approval 
of a state's permitting program under the Clean Water Act--was that 
following the action, the relevant permitted activities would no 
longer be subject to consultation under the ESA. By contrast, 
promulgation of the present rule will result in no change to any ESA 
requirements applicable to any future activities directed by plans 
(either state or federal) implementing the rule. The action at issue 
in Washington Toxics Coalition involved the EPA's registration of 
certain pesticide active ingredients under the Federal Insecticide, 
Fungicide, and Rodenticide Act. Such actions provide authorization 
for the sale and distribution of those products, consistent with 
applicable labelling requirements. The EPA also notes that under the 
EPA's regulations, registered pesticide labels must, among other 
things, specify the product ingredients and the methods and sites of 
product application. 40 CFR 156.10. By contrast, the present rule 
only sets goals and describes potential pathways to meeting those 
goals, all of which are subject to future considerations and 
decisions involved in the implementation of plans (generally by 
states). The rule neither authorizes, nor directs, any of the future 
measures to meet the rule's goals. Those activities remain subject 
to the full range of future decision making addressing which types 
of measures to implement, what emitting entities will be affected, 
how much, and when.
---------------------------------------------------------------------------

C. What are the energy impacts?

    The final guidelines have important energy market implications. 
Table 17 presents a variety of important energy market impacts for 
2020, 2025, and 2030 under both the rate-based and mass-based 
illustrative plan approaches.

   Table 17--Summary Table of Important Energy Market Impacts for Rate-Based and Mass-Based Illustrative Plan
                                                   Approaches
                                         [Percent change from base case]
----------------------------------------------------------------------------------------------------------------
                                                  Rate-based                             Mass-based
                                   -----------------------------------------------------------------------------
                                        2020         2025         2030         2020         2025         2030
----------------------------------------------------------------------------------------------------------------
Retail electricity prices.........            3            1            1            3            2            0
Price of coal at minemouth........           -1           -5           -4           -1           -5           -3
Coal production for power sector             -5          -14          -25           -7          -17          -24
 use..............................
Price of natural gas delivered to             5           -8            2            4           -3           -2
 power sector.....................
Natural gas use for electricity               3           -1           -1            5            0           -4
 generation.......................
----------------------------------------------------------------------------------------------------------------

    These figures reflect the EPA's illustrative modeling that presumes 
policies that lead to generation shifts and growing use of demand-side 
EE and renewable electricity generation out to 2029. If states make 
different policy choices, impacts could be different. For instance, if 
states implement renewable and/or demand-side EE policies on a more 
aggressive time-frame, impacts on natural gas and electricity prices 
would likely be less. Implementation of other measures not included in 
the BSER calculation or compliance modeling, such as nuclear uprates, 
transmission system improvements, use of energy storage technologies or 
retrofit CCS, could also mitigate gas price and/or electricity price 
impacts.
    Energy market impacts from the guidelines are discussed more 
extensively in the RIA found in the docket for this rulemaking.

D. What are the compliance costs?

    The compliance costs of this final action are represented in this 
analysis as the change in electric power generation costs between the 
base case and the final rule in which states pursue a distinct set of 
strategies beyond the strategies taken in the base case to meet the 
terms of the final guidelines. The compliance costs estimates include 
cost estimates for demand-side EE. The compliance assumptions--and, 
therefore, the projected compliance costs--set forth in this analysis 
are illustrative in nature and do not represent the full suite of 
compliance flexibilities states may ultimately pursue. The illustrative 
analysis is designed to reflect, to the extent possible, the scope and 
the nature of the final guidelines. However, there is considerable 
uncertainty with regards to the precise measures that states will adopt 
to meet the final requirements, because there are considerable 
flexibilities afforded to the states in developing their state plans.
    The incremental cost is the projected additional cost of complying 
with the guidelines in the year analyzed and includes the amortized 
cost of capital investment, needed new capacity, shifts between or 
amongst various fuels, deployment of demand-side EE programs, and other 
actions associated with compliance. These important

[[Page 64928]]

dynamics are discussed in more detail in the RIA in the rulemaking 
docket.
    The EPA estimates the annual incremental compliance cost for the 
rate-based approach for final emission guidelines to be $2.5 billion in 
2020, $1.0 billion in 2025 and $8.4 billion in 2030, including the 
costs associated with monitoring, reporting, and recordkeeping 
(MR&R).\1050\ The EPA estimates the annual incremental compliance cost 
for the mass-based approach for final emission guidelines to be $1.4 
billion in 2020, $3.0 billion in 2025 and $5.1 billion in 2030, 
including the costs associated with MR&R.
---------------------------------------------------------------------------

    \1050\ The MR&R costs estimates are $65 million in 2020, $15 
million in 2025 and $15 million in 2030 and are assumed to be the 
same for both rate-based and mass-based illustrative plan 
approaches.
---------------------------------------------------------------------------

    More detailed cost estimates are available in the RIA included in 
the rulemaking docket.

E. What are the economic and employment impacts?

    The final standards are projected to result in certain changes to 
power system operation as a compliance with the standards. See Table 16 
above for a variety of important energy market impacts for 2020, 2025, 
and 2030 under both the rate-based and mass-based illustrative plan 
approaches.
    It is important to note that the EPA's modeling does not 
necessarily account for all of the factors that may influence business 
decisions regarding future coal-fired capacity. Many power companies 
already factor a potential financial liability associated with carbon 
emissions into their long term capacity planning that would further 
influence business decisions to replace these aging assets with modern, 
and significantly cleaner, generation.
    The compliance modeling done to support the final rule assumes that 
overall electric demand will decrease as states ramp up programs that 
result in lower overall demand. Demand-side EE levels are expected to 
increase such that they achieve about a 7.8 percent reduction on 
overall electricity demand levels in 2030 under the final guidelines.
    Changes in price or demand for electricity, natural gas, and coal 
can impact markets for goods and services produced by sectors that use 
these energy inputs in the production process or supply those sectors. 
Changes in the cost of production may result in changes in prices, 
quantities produced, and profitability of affected firms. The EPA 
recognizes that these guidelines provide significant flexibilities and 
states implementing the guidelines may choose to mitigate impacts to 
some markets outside the utility power sector. Similarly, demand for 
new generation or demand-side EE as a result of states implementing the 
guidelines can result in shifts in production and profitability for 
firms that supply those goods and services.
    Executive Order 13563 directs federal agencies to consider the 
effect of regulations on job creation and employment. According to the 
Executive Order, ``our regulatory system must protect public health, 
welfare, safety, and our environment while promoting economic growth, 
innovation, competitiveness, and job creation. It must be based on the 
best available science.'' (Executive Order 13563, 2011) Although 
standard benefit-cost analyses have not typically included a separate 
analysis of regulation-induced employment impacts, we typically conduct 
employment analyses. While the economy continues moving toward full-
employment, employment impacts are of particular concern and questions 
may arise about their existence and magnitude.
    States have the responsibility and flexibility to implement 
policies and practices for compliance with the final guidelines. 
Quantifying the associated employment impacts is complicated by the 
wide range of approaches that states may use. As such, the EPA's 
employment analysis includes projected employment impacts associated 
with illustrative plan approaches for these guidelines for the electric 
power industry, coal and natural gas production, and demand-side EE 
activities. These projections are derived, in part, from a detailed 
model of the utility power sector used for this regulatory analysis, 
and U.S government data on employment and labor productivity. In the 
electricity, coal, and natural gas sectors, the EPA estimates that 
these guidelines could result in a net decrease of approximately 25,000 
job-years in 2025 for the final guidelines under the rate-based 
illustrative plan approach and approximately 26,000 job-years in 2025 
under the mass-based approach. For 2030, the estimates of the net 
decrease in job-years are 31,000 under the rate-based approach and 
34,000 under the mass-based approach. The agency is also offering an 
illustrative calculation of potential employment effects due to demand-
side EE programs. Employment impacts from demand-side energy EE 
programs in 2030 could range from approximately 52,000 to 83,000 jobs 
under the final guidelines.
    By its nature, demand-side EE reduces overall demand for electric 
power. The EPA recognizes as more efficiency is built into the U.S. 
power system over time, lower fuel requirements may lead to fewer jobs 
in the coal and natural gas extraction sectors, as well as in fossil-
fuel fired EGU construction and operation than would otherwise have 
been expected. The EPA also recognizes the fact that, in many cases, 
employment gains and losses that might be attributable to this rule 
would be expected to affect different sets of people. Moreover, workers 
who lose jobs in these sectors may find employment elsewhere just as 
workers employed in new jobs in these sectors may have been previously 
employed elsewhere. Therefore, the employment estimates reported in 
these sectors may include workers previously employed elsewhere. This 
analysis also does not capture potential economy-wide impacts due to 
changes in prices (of fuel, electricity, labor, for example) or other 
factors such as improved labor productivity and reduced health care 
expenditures resulting from cleaner air. For these reasons, the numbers 
reported here should not be interpreted as a net national employment 
impact.

F. What are the benefits of the final goals?

    Implementing the final standards will generate benefits by reducing 
emissions of CO2 and criteria pollutant precursors, 
including SO2, NOX, and directly-emitted 
particles. SO2 and NOX are precursors to 
PM2.5 (particles smaller than 2.5 microns), and 
NOX is a precursor to ozone. The estimated benefits 
associated with these emission reductions are beyond those achieved by 
previous EPA rulemakings including the Mercury and Air Toxics Standards 
rule. The health and welfare benefits from reducing air pollution are 
considered co-benefits for these standards. For this rulemaking, we 
were only able to quantify the climate benefits from reduced emissions 
of CO2 and the health co-benefits associated with reduced 
exposure to PM2.5 and ozone. There are many additional 
benefits which we are not able to quantify, leading to an underestimate 
of monetized benefits. In summary, we estimate the total combined 
climate benefits and health co-benefits for the rate-based approach to 
be $3.5 to $4.6 billion in 2020, $18 to $28 billion in 2025, and $34 to 
$54 billion in 2030 (3 percent discount rate, 2011$). Total combined 
climate benefits and health co-benefits for the mass-based approach are 
estimated to be $5.3 to $8.1 billion in 2020, $19 to $29 billion in 
2025, and

[[Page 64929]]

$32 to $48 billion in 2030 (3 percent discount rate, 2011$). A summary 
of the emission reductions and monetized benefits estimated for this 
rule at all discount rates is provided in Tables 15 through 22 of this 
preamble.

               Table 18--Summary of the Monetized Global Climate Benefits for the Final Guidelines
                                             [Billions of 2011$] \a\
----------------------------------------------------------------------------------------------------------------
                                                                            Monetized climate benefits
                 Year                         Discount rate      -----------------------------------------------
                                               (statistic)             2020            2025            2030
----------------------------------------------------------------------------------------------------------------
                                               Rate-based Approach
----------------------------------------------------------------------------------------------------------------
CO2 Reductions (million short tons)...  ........................              69             232             415
                                        5 percent (average SC-             $0.80            $3.1            $6.4
                                         CO2).
                                        3 percent (average SC-              $2.8             $10             $20
                                         CO2).
                                        2.5 percent (average SC-            $4.1             $15             $29
                                         CO2).
                                        3 percent (95th                     $8.2             $31             $61
                                         percentile SC-CO2).
----------------------------------------------------------------------------------------------------------------
                                               Mass-based Approach
----------------------------------------------------------------------------------------------------------------
CO2 Reductions (million short tons)...  ........................              81             265             413
                                        5 percent (average SC-             $0.94            $3.6            $6.4
                                         CO2).
                                        3 percent (average SC-              $3.3             $12             $20
                                         CO2).
                                        2.5 percent (average SC-            $4.9             $17             $29
                                         CO2).
                                        3 percent (95th                     $9.7             $35             $60
                                         percentile SC-CO2).
----------------------------------------------------------------------------------------------------------------
\a\ Climate benefit estimates reflect impacts from CO2 emission changes in the analysis years presented in the
  table and do not account for changes in non-CO2 GHG emissions. These estimates are based on the global social
  cost of carbon (SC-CO2) estimates for the analysis years and are rounded to two significant figures.


 Table 19--Summary of the Monetized Health Co-Benefits in the U.S. for the Final Guidelines, Rate-based Approach
                                             [Billions of 2011$] \a\
----------------------------------------------------------------------------------------------------------------
                                         National
                                         emission         Monetized health  co-         Monetized Health  Co-
              Pollutant                 reductions        benefits  (3 percent          benefits  (7 percent
                                       (thousands of            discount)                     discount)
                                        short tons)
----------------------------------------------------------------------------------------------------------------
                                   Final Guidelines, Rate-based Approach, 2020
----------------------------------------------------------------------------------------------------------------
PM2.5 precursors: \b\
    SO2.............................              14  $0.44 to $0.99..............  $0.39 to $0.89
    NOX.............................              50  $0.14 to $0.33..............  $0.13 to $0.30
Ozone precursor: \c\
    NOX (ozone season only).........              19  $0.12 to $0.52..............  $0.12 to $0.52
                                     ---------------------------------------------------------------------------
        Total Monetized Health Co-    ..............  $0.70 to $1.8...............  $0.64 to $1.7
         benefits.
        Total Monetized Health Co-    ..............  $3.5 to $4.6................  $3.5 to $4.5
         benefits combined with
         Monetized Climate Benefits
         \d\.
----------------------------------------------------------------------------------------------------------------
                                   Final Guidelines, Rate-based Approach, 2025
----------------------------------------------------------------------------------------------------------------
PM2.5 precursors: \b\
    SO2.............................             178  $6.4 to $14.................  $5.7 to $13
    NOX.............................             165  $0.56 to $1.3...............  $0.50 to $1.1
Ozone precursor: \c\
    NOX (ozone season only).........              70  $0.49 to $2.1...............  $0.49 to $2.1
                                     ---------------------------------------------------------------------------
        Total Monetized Health Co-                    $7.4 to $18.................  $6.7 to $16
         benefits.
        Total Monetized Health Co-                    $18 to $28..................  $17 to $26
         benefits combined with
         Monetized Climate Benefits
         \d\.
----------------------------------------------------------------------------------------------------------------
                                   Final Guidelines, Rate-based Approach, 2030
----------------------------------------------------------------------------------------------------------------
PM2.5 precursors: \b\
    SO2.............................             318  $12 to $28..................  $11 to $25
    NOX.............................             282  $1.0 to $2.3................  $0.93 to $2.1
Ozone precursor: \c\
    NOX (ozone season only).........             118  $0.86 to $3.7...............  $0.86 to $3.7
                                     ---------------------------------------------------------------------------
        Total Monetized Health Co-                    $14 to $34..................  $13 to $31
         benefits.
        Total Monetized Health Co-                    $34 to $54..................  $33 to $51
         benefits combined with
         Monetized Climate Benefits.
         \d\.
----------------------------------------------------------------------------------------------------------------
\a\ All estimates are rounded to two significant figures, so estimates may not sum. It is important to note that
  the monetized co-benefits do not include reduced health effects from direct exposure to SO2, direct exposure
  to NO2, exposure to mercury, ecosystem effects or visibility impairment. Air pollution health co-benefits are
  estimated using regional benefit-per-ton estimates for the contiguous U.S.

[[Page 64930]]

 
\b\ The monetized PM2.5 co-benefits reflect the human health benefits associated with reducing exposure to PM2.5
  through reductions of PM2.5 precursors, such as SO2 and NOX. The co-benefits do not include the benefits of
  reductions in directly emitted PM2.5. These additional benefits would increase overall benefits by a few
  percent based on the analyses conducted for the proposed rule. PM co-benefits are shown as a range reflecting
  the use of two concentration-response functions, with the lower end of the range based on a function from
  Krewski et al. (2009) and the upper end based on a function from Lepeule et al. (2012). These models assume
  that all fine particles, regardless of their chemical composition, are equally potent in causing premature
  mortality because the scientific evidence is not yet sufficient to allow differentiation of effect estimates
  by particle type.
\c\ The monetized ozone co-benefits reflect the human health benefits associated with reducing exposure to ozone
  through reductions of NOX during the ozone season. Ozone co-benefits are shown as a range reflecting the use
  of several different concentration-response functions, with the lower end of the range based on a function
  from Bell, et al. (2004) and the upper end based on a function from Levy, et al. (2005). Ozone co-benefits
  occur in the analysis year, so they are the same for all discount rates.
\d\ We estimate climate benefits associated with four different values of a one ton CO2 reduction (model average
  at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent). Referred to as the
  social cost of carbon, each value increases over time. For the purposes of this table, we show the benefits
  associated with the model average at 3 percent discount rate, however we emphasize the importance and value of
  considering the full range of social cost of carbon values. We provide combined climate and health estimates
  based on additional discount rates in the RIA.


 Table 20--Summary of the Monetized Health Co-Benefits in the U.S. for the Final Guidelines, Mass-based Approach
                                             [Billions of 2011$] \a\
----------------------------------------------------------------------------------------------------------------
                                                                     National        Monetized       Monetized
                                                                     emission       health  co-     health  co-
                            Pollutant                               reductions     benefits  (3    benefits  (7
                                                                   (thousands of      percent         percent
                                                                    short tons)      discount)       discount)
----------------------------------------------------------------------------------------------------------------
                                   Final Guidelines, Mass-based Approach, 2020
----------------------------------------------------------------------------------------------------------------
PM2.5 precursors: \ b\
    SO2.........................................................              54    $1.7 to $3.8    $1.5 to $3.4
    NOX.........................................................              60  $0.17 to $0.39  $0.16 to $0.36
Ozone precursor: \c\
    NOX (ozone season only).....................................              23  $0.14 to $0.61  $0.14 to $0.61
                                                                 -----------------------------------------------
        Total Monetized Health Co-benefits......................  ..............    $2.0 to $4.8    $1.8 to $4.4
        Total Monetized Health Co-benefits combined with          ..............    $5.3 to $8.1    $5.1 to $7.7
         Monetized Climate Benefits \d\.........................
----------------------------------------------------------------------------------------------------------------
                                   Final Guidelines, Mass-based Approach, 2025
----------------------------------------------------------------------------------------------------------------
PM2.5 precursors: \ b\
    SO2.........................................................             185     $6.0 to $13     $5.4 to $12
    NOX.........................................................             203   $0.58 to $1.3   $0.52 to $1.2
Ozone precursor: \c\
    NOX (ozone season only).....................................              88   $0.56 to $2.4   $0.56 to $2.4
                                                                 -----------------------------------------------
        Total Monetized Health Co-benefits......................  ..............     $7.1 to $17     $6.5 to $16
        Total Monetized Health Co-benefits combined with          ..............      $19 to $29      $18 to $27
         Monetized Climate Benefits \d\.........................
----------------------------------------------------------------------------------------------------------------
                                   Final Guidelines, Mass-based Approach, 2030
----------------------------------------------------------------------------------------------------------------
PM2.5 precursors: \b\
    SO2.........................................................             280      $10 to $23     $9.0 to $20
    NOX.........................................................             278   $0.87 to $2.0   $0.79 to $1.8
Ozone precursor: \c\
NOX (ozone season only).........................................             121   $0.82 to $3.5   $0.82 to $3.5
                                                                 -----------------------------------------------
        Total Monetized Health Co-benefits......................  ..............      $12 to $28      $11 to $26
        Total Monetized Health Co-benefits combined with          ..............      $32 to $48      $31 to $46
         Monetized Climate Benefits \d\.........................
----------------------------------------------------------------------------------------------------------------
\a\ All estimates are rounded to two significant figures, so estimates may not sum. It is important to note that
  the monetized co-benefits do not include reduced health effects from direct exposure to SO2, direct exposure
  to NO2, exposure to mercury, ecosystem effects or visibility impairment. Air pollution health co-benefits are
  estimated using regional benefit-per-ton estimates for the contiguous U.S.
\b\ The monetized PM2.5 co-benefits reflect the human health benefits associated with reducing exposure to PM2.5
  through reductions of PM2.5 precursors, such as SO2 and NOX. The co-benefits do not include the benefits of
  reductions in directly emitted PM2.5. These additional benefits would increase overall benefits by a few
  percent based on the analyses conducted for the proposed rule. PM co-benefits are shown as a range reflecting
  the use of two concentration-response functions, with the lower end of the range based on a function from
  Krewski et al. (2009) and the upper end based on a function from Lepeule et al. (2012). These models assume
  that all fine particles, regardless of their chemical composition, are equally potent in causing premature
  mortality because the scientific evidence is not yet sufficient to allow differentiation of effect estimates
  by particle type.
\c\ The monetized ozone co-benefits reflect the human health benefits associated with reducing exposure to ozone
  through reductions of NOX during the ozone season. Ozone co-benefits are shown as a range reflecting the use
  of several different concentration-response functions, with the lower end of the range based on a function
  from Bell, et al. (2004) and the upper end based on a function from Levy, et al. (2005). Ozone co-benefits
  occur in the analysis year, so they are the same for all discount rates.
\d\ We estimate climate benefits associated with four different values of a one ton CO2 reduction (model average
  at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent). Referred to as the
  social cost of carbon, each value increases over time. For the purposes of this table, we show the benefits
  associated with the model average at 3 percent discount rate, however we emphasize the importance and value of
  considering the full range of social cost of carbon values. We provide combined climate and health estimates
  based on additional discount rates in the RIA.


[[Page 64931]]

    The EPA has used the social cost of carbon (SC-CO2) 
estimates presented in the Technical Support Document: Technical Update 
of the Social Cost of Carbon for Regulatory Impact Analysis Under 
Executive Order 12866 (May 2013, Revised June 2015) (``current TSD'') 
to analyze CO2 climate impacts of this rulemaking.\1051\ We 
refer to these estimates, which were developed by the U.S. Government, 
as ``SC-CO2 estimates.'' The SC-CO2 is a metric 
that estimates the monetary value of impacts associated with marginal 
changes in CO2 emissions in a given year. It includes a wide 
range of anticipated climate impacts, such as net changes in 
agricultural productivity and human health, property damage from 
increased flood risk, and changes in energy system costs, such as 
reduced costs for heating and increased costs for air conditioning. It 
is typically used to assess the avoided damages as a result of 
regulatory actions (i.e., benefits of rulemakings that lead to an 
incremental reduction in cumulative global CO2 emissions).
---------------------------------------------------------------------------

    \1051\ Docket ID EPA-HQ-OAR-2013-0495, Technical Support 
Document: Technical Update of the Social Cost of Carbon for 
Regulatory Impact Analysis Under Executive Order 12866, Interagency 
Working Group on Social Cost of Carbon, with participation by 
Council of Economic Advisers, Council on Environmental Quality, 
Department of Agriculture, Department of Commerce, Department of 
Energy, Department of Transportation, Domestic Policy Council, 
Environmental Protection Agency, National Economic Council, Office 
of Management and Budget, Office of Science and Technology Policy, 
and Department of the Treasury (May 2013, Revised July 2015). 
Available at: http://www.whitehouse.gov/sites/default/files/omb/inforeg/scc-tsd-final-july-2015.pdf.
---------------------------------------------------------------------------

    The SC-CO2 estimates used in this analysis were 
developed over many years, using the best science available, and with 
input from the public. Specifically, an interagency working group (IWG) 
that included the EPA and other executive branch agencies and offices 
used three integrated assessment models (IAMs) to develop the SC-
CO2 estimates and recommended four global values for use in 
regulatory analyses. The SC-CO2 estimates were first 
released in February 2010 and updated in 2013 using new versions of 
each IAM. The 2010 SC-CO2 Technical Support Document (2010 
TSD) \1052\ provides a complete discussion of the methods used to 
develop these estimates and the current TSD presents and discusses the 
2013 update (including two recent minor corrections to the 
estimates).\1053\
---------------------------------------------------------------------------

    \1052\ Docket ID EPA-HQ-OAR-2009-0472-114577, Technical Support 
Document: Social Cost of Carbon for Regulatory Impact Analysis Under 
Executive Order 12866, Interagency Working Group on Social Cost of 
Carbon, with participation by the Council of Economic Advisers, 
Council on Environmental Quality, Department of Agriculture, 
Department of Commerce, Department of Energy, Department of 
Transportation, Environmental Protection Agency, National Economic 
Council, Office of Energy and Climate Change, Office of Management 
and Budget, Office of Science and Technology Policy, and Department 
of Treasury (February 2010). Also available at: http://www.whitehouse.gov/sites/default/files/omb/inforeg/for-agencies/Social-Cost-of-Carbon-for-RIA.pdf.
    \1053\ The current version of the TSD is available at: https://www.whitehouse.gov/sites/default/files/omb/inforeg/scc-response-to-comments-final-july-2015.pdf, Docket ID EPA-HQ-OAR-2013-0495, 
Technical Support Document: Technical Update of the Social Cost of 
Carbon for Regulatory Impact Analysis Under Executive Order 12866, 
Interagency Working Group on Social Cost of Carbon, with 
participation by Council of Economic Advisers, Council on 
Environmental Quality, Department of Agriculture, Department of 
Commerce, Department of Energy, Department of Transportation, 
Domestic Policy Council, Environmental Protection Agency, National 
Economic Council, Office of Management and Budget, Office of Science 
and Technology Policy, and Department of Treasury (May 2013, Revised 
July 2015).
---------------------------------------------------------------------------

    The EPA received numerous comments on the SC-CO2 
estimates as part of this rulemaking. The comments covered a wide range 
of topics including the technical details of the modeling conducted to 
develop the SC-CO2 estimates, the aggregation and 
presentation of the SC-CO2 estimates, and the process by 
which the SC-CO2 estimates were derived. Many but not all 
commenters were supportive of the SC-CO2 and its application 
to this rulemaking. Commenters also provided constructive 
recommendations for potential opportunities to improve the SC-
CO2 estimates in future updates. Many of these comments were 
similar to those that OMB's Office of Information and Regulatory 
Affairs received in response to a separate request for public comment 
on the approach used to develop the estimates. After careful evaluation 
of the full range of comments submitted to OMB, the IWG continues to 
recommend the use of the SC-CO2 estimates in regulatory 
impact analysis.\1054\ With the release of the response to comments, 
the IWG announced plans to obtain expert independent advice from the 
National Academies of Sciences, Engineering, and Medicine (Academies) 
to ensure that the SC-CO2 estimates continue to reflect the 
best available scientific and economic information on climate change. 
The Academies review will be informed by the public comments received 
and focus on the technical merits and challenges of potential 
approaches to improving the SC-CO2 estimates in future 
updates. See the EPA Response to Comments document for the complete 
response to comments received on SC-CO2 as part of this 
rulemaking.
---------------------------------------------------------------------------

    \1054\ See https://www.whitehouse.gov/omb/oira/social-cost-of-carbon for additional details, including the OMB Response to 
Comments and the SC-CO2 TSDs.
---------------------------------------------------------------------------

    Concurrent with OMB's publication of the response to comments on 
SC-CO2 and announcement of the Academies process, OMB posted 
a revised TSD that includes two minor technical corrections to the 
current estimates. One technical correction addressed an inadvertent 
omission of climate change damages in the last year of analysis (2300) 
in one model and the second addressed a minor indexing error in another 
model. On average the revised SC-CO2 estimates are one 
dollar less than the mean SC-CO2 estimates reported in the 
November 2013 revision to the May 2013 TSD. The change in the estimates 
associated with the 95th percentile estimates when using a 3 percent 
discount rate is slightly larger, as those estimates are heavily 
influenced by the results from the model that was affected by the 
indexing error.
    The EPA, as a member of the IWG on the SC-CO2, has 
carefully examined and evaluated the minor technical corrections in the 
revised TSD and the public comments submitted to OMB's separate SC-
CO2 comment process. Additionally, the EPA has carefully 
examined and evaluated all comments received regarding the SC-
CO2 through this rulemaking process. The EPA concurs with 
the IWG's conclusion that it is reasonable, and scientifically 
appropriate, to use the current SC-CO2 estimates for 
purposes of regulatory impact analysis, including for this proceeding.
    The four SC-CO2 estimates are as follows: $12, $40, $60, 
and $120 per short ton of CO2 emissions in the year 2020 
(2011$).\1055\ The first three values are based on the average SC-
CO2 from the three IAMs, at discount rates of 5, 3, and 2.5 
percent, respectively. The SC-CO2 value at several discount 
rates are included because the literature shows that the SC-
CO2 is quite sensitive to assumptions about the discount 
rate, and because no consensus exists on the appropriate rate to use in 
an intergenerational context (where costs and benefits are incurred by 
different generations). The fourth value is the 95th percentile of the 
SC-CO2 from all three models at a 3 percent discount

[[Page 64932]]

rate. It is included to represent higher-than-expected impacts from 
temperature change further out in the tails of the SC-CO2 
distribution (representing less likely, but potentially catastrophic, 
outcomes).
---------------------------------------------------------------------------

    \1055\ The current version of the TSD is available at: https://www.whitehouse.gov/sites/default/files/omb/inforeg/scc-tsd-final-july-2015.pdf. The 2010 and 2013 TSDs present SC-CO2 in 
2007$ per metric ton. The estimates were adjusted to (1) short tons 
for using conversion factor 0.90718474 and (2) 2011$ using GDP 
Implicit Price Deflator, http://www.gpo.gov/fdsys/pkg/ECONI-2013-02/pdf/ECONI-2013-02-Pg3.pdf.
---------------------------------------------------------------------------

    There are limitations in the estimates of the benefits from the 
final emission guidelines, including the omission of climate and other 
CO2 related benefits that could not be monetized. The 2010 
TSD discusses a number of limitations to the SC-CO2 
analysis, including the incomplete way in which the IAMs capture 
catastrophic and non-catastrophic impacts, their incomplete treatment 
of adaptation and technological change, uncertainty in the 
extrapolation of damages to high temperatures, and assumptions 
regarding risk aversion. Currently, IAMs do not assign value to all of 
the important impacts of CO2 recognized in the literature, 
such as ocean acidification or potential tipping points, for various 
reasons, including the inherent difficulties in valuing non-market 
impacts and the fact that the science incorporated into these models 
understandably lags behind the most recent research. Nonetheless, these 
estimates and the discussion of their limitations represent the best 
available information about the social benefits of CO2 
emission reductions to inform the benefit-cost analysis. As previously 
noted, the IWG plans to seek independent expert advice on technical 
opportunities to improve the SC-CO2 estimates from the 
Academies. The Academies process will help to ensure that the SC-
CO2 estimates used by the federal government continue to 
reflect the best available science and methodologies. Additional 
details are provided in the TSDs.
    The health co-benefits estimates represent the total monetized 
human health benefits for populations exposed to reduced 
PM2.5 and ozone resulting from emission reductions from the 
illustrative compliance strategy for the final standards. Unlike the 
global SC-CO2 estimates, the air pollution health co-
benefits are estimated for the contiguous U.S. only. We used a 
``benefit-per-ton'' approach to estimate the benefits of this 
rulemaking. To create the PM2.5 benefit-per-ton estimates, 
we conducted air quality modeling for an illustrative scenario 
reflecting the proposed standards to convert precursor emissions into 
changes in ambient PM2.5 and ozone concentrations. We then 
used these air quality modeling results in BenMAP \1056\ to calculate 
average regional benefit-per-ton estimates using the health impact 
assumptions used in the PM NAAQS RIA \1057\ and Ozone NAAQS 
RIAs.1058 1059 The three regions were the Eastern U.S., 
Western U.S., and California. To calculate the co-benefits for the 
final standards, we multiplied the regional benefit-per-ton estimates 
generated from modeling of the proposed standards by the corresponding 
regional emission reductions for the final standards.\1060\ All 
benefit-per-ton estimates reflect the geographic distribution of the 
modeled emissions for the proposed standards, which may not exactly 
match the emission reductions in this final rulemaking, and thus they 
may not reflect the local variability in population density, 
meteorology, exposure, baseline health incidence rates, or other local 
factors for any specific location. More information regarding the 
derivation of the benefit-per-ton estimates is available in the RIA.
---------------------------------------------------------------------------

    \1056\ http://www.epa.gov/airquality/benmap/index.html.
    \1057\ U.S. Environmental Protection Agency (U.S. EPA). 2012. 
Regulatory Impact Analysis for the Final Revisions to the National 
Ambient Air Quality Standards for Particulate Matter. Research 
Triangle Park, NC: Office of Air Quality Planning and Standards, 
Health and Environmental Impacts Division. (EPA document number EPA-
452/R-12-003, December). Available at: <http://www.epa.gov/pm/2012/finalria.pdf>.
    \1058\ U.S. Environmental Protection Agency (U.S. EPA). 2008b. 
Final Ozone NAAQS Regulatory Impact Analysis. Research Triangle 
Park, NC: Office of Air Quality Planning and Standards, Health and 
Environmental Impacts Division, Air Benefit and Cost Group Research. 
(EPA document number EPA-452/R-08-003, March). Available at: <http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=194645>.
    \1059\ U.S. Environmental Protection Agency (U.S. EPA). 2010. 
Section 3: Re-analysis of the Benefits of Attaining Alternative 
Ozone Standards to Incorporate Current Methods. Available at: 
<http://www.epa.gov/ttnecas1/regdata/RIAs/s3-supplemental_analysis-updated_benefits11-5.09.pdf>.
    \1060\ U.S. Environmental Protection Agency. 2013. Technical 
support document: Estimating the benefit per ton of reducing PM2.5 
precursors from 17 sectors. Research Triangle Park, NC: Office of 
Air and Radiation, Office of Air Quality Planning and Standards, 
January. Available at: <http://www.epa.gov/airquality/benmap/models/Source_Apportionment_BPT_TSD_1_31_13.pdf>.
---------------------------------------------------------------------------

    PM benefit-per-ton values are generated using two concentration-
response functions, Krewski et al. (2009) \1061\ and Lepeule et al. 
(2012).\1062\ These models assume that all fine particles, regardless 
of their chemical composition, are equally potent in causing premature 
mortality because the scientific evidence is not yet sufficient to 
allow differentiation of effect estimates by particle type. Even though 
we assume that all fine particles have equivalent health effects, the 
benefit-per-ton estimates vary between PM2.5 precursors 
depending on the location and magnitude of their impact on 
PM2.5 concentrations, which drive population exposure.
---------------------------------------------------------------------------

    \1061\ Krewski D.; M. Jerrett; R.T. Burnett; R. Ma; E. Hughes; 
Y. Shi, et al. 2009. Extended Follow-up and Spatial Analysis of the 
American Cancer Society Study Linking Particulate Air Pollution and 
Mortality. Health Effects Institute. (HEI Research Report number 
140). Boston, MA: Health Effects Institute. Available at http://www.healtheffects.org/Pubs/RR140-Krewski.pdf.
    \1062\ Lepeule, J.; F. Laden; D. Dockery; J. Schwartz. 2012. 
``Chronic Exposure to Fine Particles and Mortality: An Extended 
Follow-Up of the Harvard Six Cities Study from 1974 to 2009.'' 
Environmental Health Perspective, 120(7), July, pp. 965-970.
---------------------------------------------------------------------------

    It is important to note that the magnitude of the PM2.5 
and ozone co-benefits is largely driven by the concentration response 
functions for premature mortality and the value of a statistical life 
used to value reductions in premature mortality. For PM2.5, 
we use two key empirical studies, one based on the American Cancer 
Society cohort study (Krewski et al., 2009) and one based on the 
extended Six Cities cohort study (Lepuele et al., 2012). We present the 
PM2.5 co-benefits results as a range based on benefit-per-
ton estimates calculated using the concentration-response functions 
from these two epidemiology studies, but this range does not capture 
the full range of uncertainty inherent in the co-benefits estimates. In 
the RIA for this rule, which is available in the docket, we also 
include PM2.5 co-benefits estimates using benefit-per-ton 
estimates based on expert judgments of the effect of PM2.5 
on premature mortality (Roman et al., 2008) \1063\ as a 
characterization of uncertainty regarding the PM2.5-
mortality relationship.
---------------------------------------------------------------------------

    \1063\ Roman, H., et al. 2008. ``Expert Judgment Assessment of 
the Mortality Impact of Changes in Ambient Fine Particulate Matter 
in the U.S.'' Environmental Science & Technology, Vol. 42, No. 7, 
February, pp. 2268-2274.
---------------------------------------------------------------------------

    For the ozone co-benefits, we present the results as a range 
reflecting benefit-per-ton estimates which use several different 
concentration-response functions for mortality, with the lower end of 
the range based on a benefit-per-ton estimate using the function from 
Bell et al. (2004) \1064\ and the upper end based on a benefit-per-ton 
estimate using the function from Levy et al. (2005).\1065\ Similar to 
PM2.5, the range of ozone co-benefits does not capture the 
full range of inherent uncertainty.
---------------------------------------------------------------------------

    \1064\ Bell, M.L., et al. 2004. ``Ozone and Short-Term Mortality 
in 95 U.S. Urban Communities, 1987-2000.'' Journal of the American 
Medical Association, 292(19), pp. 2372-8.
    \1065\ Levy, J.I., S.M. Chemerynski, and J.A. Sarnat. 2005. 
``Ozone exposure and mortality: An empiric Bayes metaregression 
analysis.'' Epidemiology. 16(4): p. 458-68.
---------------------------------------------------------------------------

    In this analysis, in estimating the benefits-per-ton for 
PM2.5 precursors,

[[Page 64933]]

the EPA assumes that the health impact function for fine particles is 
without a threshold. This is based on the conclusions of EPA's 
Integrated Science Assessment for Particulate Matter,\1066\ which 
evaluated the substantial body of published scientific literature, 
reflecting thousands of epidemiology, toxicology, and clinical studies 
that documents the association between elevated PM2.5 
concentrations and adverse health effects, including increased 
premature mortality. This assessment, which was twice reviewed by the 
EPA's independent Science Advisory Board, concluded that the scientific 
literature consistently finds that a no-threshold model most adequately 
portrays the PM-mortality concentration-response relationship.
---------------------------------------------------------------------------

    \1066\ U.S. Environmental Protection Agency. 2009. Integrated 
Science Assessment for Particulate Matter (Final Report). Research 
Triangle Park, NC: National Center for Environmental Assessment, RTP 
Division. (EPA document number EPA-600-R-08-139F, December). 
Available at: http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546.
---------------------------------------------------------------------------

    In general, we are more confident in the magnitude of the risks we 
estimate from simulated PM2.5 concentrations that coincide 
with the bulk of the observed PM concentrations in the epidemiological 
studies that are used to estimate the benefits. Likewise, we are less 
confident in the risk we estimate from simulated PM2.5 
concentrations that fall below the bulk of the observed data in these 
studies.
    For this analysis, policy-specific air quality data are not 
available,\1067\ and thus, we are unable to estimate the percentage of 
premature mortality associated with this specific rule that is above 
the lowest measured PM2.5 levels (LML) for the two 
PM2.5 mortality epidemiology studies that form the basis for 
our analysis. As a surrogate measure of mortality impacts above the 
LML, we provide the percentage of the population exposed above the 
lowest measured PM2.5 level (LML) in each of the two 
studies, using the estimates of baseline projected PM2.5 
from the air quality modeling for the proposed guidelines used to 
calculate the benefit-per-ton estimates for the EGU sector. Using the 
Krewski et al. (2009) study, 88 percent of the population is exposed to 
annual mean PM2.5 levels at or above the LML of 5.8 
micrograms per cubic meter ([mu]g/m\3\). Using the Lepeule et al. 
(2012) study, 46 percent of the population is exposed above the LML of 
8 [mu]g/m\3\. It is important to note that baseline exposure is only 
one parameter in the health impact function, along with baseline 
incidence rates, population, and change in air quality.
---------------------------------------------------------------------------

    \1067\ In addition, site-specific emission reductions will 
depend upon how states implement the guidelines.
---------------------------------------------------------------------------

    Every benefit analysis examining the potential effects of a change 
in environmental protection requirements is limited, to some extent, by 
data gaps, model capabilities (such as geographic coverage) and 
uncertainties in the underlying scientific and economic studies used to 
configure the benefit and cost models. Despite these uncertainties, we 
believe the air quality co-benefit analysis for this rule provides a 
reasonable indication of the expected health benefits of the air 
pollution emission reductions for the illustrative analysis of the 
final standards under a set of reasonable assumptions. This analysis 
does not include the type of detailed uncertainty assessment found in 
the 2012 PM2.5 National Ambient Air Quality Standard (NAAQS) 
RIA (U.S. EPA, 2012) because we lack the necessary air quality input 
and monitoring data to conduct a complete benefits assessment. In 
addition, using a benefit-per-ton approach adds another important 
source of uncertainty to the benefits estimates. The 2012 
PM2.5 NAAQS benefits analysis provides an indication of the 
sensitivity of our results to various assumptions.
    We note that the monetized co-benefits estimates shown here do not 
include several important benefit categories, including exposure to 
SO2, NOX, and hazardous air pollutants (e.g., 
mercury and hydrogen chloride), as well as ecosystem effects and 
visibility impairment. Although we do not have sufficient information 
or modeling available to provide monetized estimates for this rule, we 
include a qualitative assessment of these unquantified benefits in the 
RIA for the final guidelines. In addition, in the RIA for the final 
standards, we did not estimate changes in emissions of directly emitted 
particles. As a result, quantified PM2.5 related benefits 
are underestimated by a relatively small amount. In the RIA for the 
proposed guidelines, the benefits from reductions in directly emitted 
PM2.5 were less than 10 percent of total monetized health 
co-benefits across all scenarios and years.
    For more information on the benefits analysis, please refer to the 
RIA for this rule, which is available in the rulemaking docket.

XII. Statutory and Executive Order Reviews

    Additional information about these Statutory and Executive Orders 
can be found at http://www2.epa.gov/laws-regulations/laws-and-executive-orders.

A. Executive Order 12866: Regulatory Planning and Review, and Executive 
Order 13563: Improving Regulation and Regulatory Review

    This final action is an economically significant regulatory action 
that was submitted to the OMB for review. Any changes made in response 
to OMB recommendations have been documented in the docket. The EPA 
prepared an analysis of the potential costs and benefits associated 
with this action. This analysis, which is contained in the ``Regulatory 
Impact Analysis for Clean Power Plan Final Rule'' (EPA-452/R-15-003, 
July 2015), is available in the docket and is briefly summarized in 
section XI of this preamble.
    Consistent with Executive Order 12866 and Executive Order 13563, 
the EPA estimated the costs and benefits for illustrative compliance 
approaches of implementing the guidelines. The final rule establishes: 
(1) Carbon dioxide (CO2) emission performance rates for two 
source categories of existing fossil fuel-fired EGUs, fossil fuel-fired 
electric utility steam generating units and stationary combustion 
turbines, and (2) guidelines for the development, submittal and 
implementation of state plans that implement the CO2 
emission performance rates. Actions taken to comply with the guidelines 
will also reduce the emissions of directly-emitted PM2.5, 
SO2 and NOX. The benefits associated with these 
PM2.5, SO2 and NOX reductions are 
referred to as co-benefits, as these reductions are not the primary 
objective of this rule.
    The EPA has used the social cost of carbon estimates presented in 
the Technical Support Document: Technical Update of the Social Cost of 
Carbon for Regulatory Impact Analysis Under Executive Order 12866 (May 
2013, Revised July 2015) (``current TSD'') to analyze CO2 
climate impacts of this rulemaking. We refer to these estimates, which 
were developed by the U.S. government, as ``SC-CO2 
estimates.'' The SC-CO2 is an estimate of the monetary value 
of impacts associated with a marginal change in CO2 
emissions in a given year. The four SC-CO2 estimates are 
associated with different discount rates (model average at 2.5 percent 
discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent), 
and each increases over time. In this summary, the EPA provides the 
estimate of climate benefits associated with the SC-CO2 
value deemed to be central in the current TSD: The model average at 3 
percent discount rate.
    In the final emission guidelines, the EPA has translated the source 
category-

[[Page 64934]]

specific CO2 emission performance rates into equivalent 
state-level rate-based and mass-based CO2 goals in order to 
maximize the range of choices that states will have in developing their 
plans. Because of the range of choices available to states and the lack 
of a priori knowledge about the specific choices states will make in 
response to the final goals, the Regulatory Impact Analysis (RIA) for 
this rule analyzed two implementation scenarios designed to achieve 
these goals, which we term the ``rate-based'' illustrative plan 
approach and the ``mass-based'' illustrative plan approach.
    It is very important to note that the differences between the 
analytical results for the rate-based and mass-based illustrative plan 
approaches presented in the RIA may not be indicative of likely 
differences between the approaches if implemented by states and 
affected EGUs in response to the final guidelines. Rather, the two sets 
of analyses are intended to illustrate two different approaches to 
accomplish the emission performance rates finalized in the Clean Power 
Plan Final Rule. In other words, if one approach performs differently 
than the other on a given metric during a given time period, this does 
not imply this will apply in all instances in all time periods in all 
places.
    The EPA estimates that, in 2020, the final guidelines will yield 
monetized climate benefits (in 2011$) of approximately $2.8 billion for 
the rate-based approach and $3.3 billion for the mass-based approach (3 
percent model average). For the rate-based approach, the air pollution 
health co-benefits in 2020 are estimated to be $0.7 billion to $1.8 
billion (2011$) for a 3 percent discount rate and $0.64 billion to $1.7 
billion (2011$) for a 7 percent discount rate. For the mass-based 
approach, the air pollution health co-benefits in 2020 are estimated to 
be $2.0 billion to $4.8 billion (2011$) for a 3 percent discount rate 
and $1.8 billion to $4.4 billion (2011$) for a 7 percent discount rate. 
The annual, illustrative compliance costs estimated by IPM and 
inclusive of demand-side EE program and participant costs and MRR costs 
in 2020, are approximately $2.5 billion for the rate-based approach and 
$1.4 billion for the mass-based approach (2011$). The quantified net 
benefits (the difference between monetized benefits and compliance 
costs) in 2020 are estimated to range from $1.0 billion to $2.1 billion 
(2011$) for the rate-based approach and from $3.9 billion to 6.7 
billion (2011$) for the mass-based approach, using a 3 percent discount 
rate (model average).
    The EPA estimates that, in 2025, the final guidelines will yield 
monetized climate benefits (in 2011$) of approximately $10 billion for 
the rate-based approach and $12 billion for the mass-based approach (3 
percent model average). For the rate-based approach, the air pollution 
health co-benefits in 2025 are estimated to be $7.4 billion to $18 
billion (2011$) for a 3 percent discount rate and $6.7 billion to $16 
billion (2011$) for a 7 percent discount rate. For the mass-based 
approach, the air pollution health co-benefits in 2025 are estimated to 
be $7.1 billion to $17 billion (2011$) for a 3 percent discount rate 
and $6.5 billion to $16 billion (2011$) for a 7 percent discount rate. 
The annual, illustrative compliance costs estimated by IPM and 
inclusive of demand-side EE program and participant costs and MRR costs 
in 2025, are approximately $1.0 billion for the rate-based approach and 
$3.0 billion for the mass-based approach (2011$). The quantified net 
benefits (the difference between monetized benefits and compliance 
costs) in 2025 are estimated to range from $17 billion to $27 billion 
(2011$) for the rate-based approach and $16 billion to $26 billion 
(2011$) for the mass-based approach, using a 3 percent discount rate 
(model average).
    The EPA estimates that, in 2030, the final guidelines will yield 
monetized climate benefits (in 2011$) of approximately $20 billion for 
the rate-based approach and $20 billion for the mass-based approach (3 
percent model average). For the rate-based approach, the air pollution 
health co-benefits in 2030 are estimated to be $14 billion to $34 
billion (2011$) for a 3 percent discount rate and $13 billion to $31 
billion (2011$) for a 7 percent discount rate. For the mass-based 
approach, the air pollution health co-benefits in 2030 are estimated to 
be $12 billion to $28 billion (2011$) for a 3 percent discount rate and 
$11 billion to $26 billion (2011$) for a 7 percent discount rate. The 
annual, illustrative compliance costs estimated by IPM and inclusive of 
demand-side EE program and participant costs and MRR costs in 2030, are 
approximately $8.4 billion for the rate-based approach and $5.1 billion 
for the mass-based approach (2011$). The quantified net benefits (the 
difference between monetized benefits and compliance costs) in 2030 are 
estimated to range from $26 billion to $45 billion (2011$) for the 
rate-based approach and from $26 billion to $43 billion (2011$) for the 
mass-based approach, using a 3 percent discount rate (model average).
    Tables 20 and 21 provide the estimates of the climate benefits, 
health co-benefits, compliance costs and net benefits of the final 
emission guidelines for rate-based and mass-based illustrative plan 
approaches, respectively.

   Table 21--Summary of the Monetized Benefits, Compliance Costs, and Net Benefits for the Final Guidelines in
                       2020, 2025 and 2030 Under the Rate-Based Illustrative Plan Approach
                                             [Billions of 2011$] \a\
----------------------------------------------------------------------------------------------------------------
                                                                                Rate-based approach
                                                                 -----------------------------------------------
                                                                       2020            2025            2030
----------------------------------------------------------------------------------------------------------------
Climate Benefits \b\
    5% discount rate............................................           $0.80            $3.1            $6.4
    3% discount rate............................................            $2.8             $10             $20
    2.5% discount rate..........................................            $4.1             $15             $29
    95th percentile at 3% discount rate.........................            $8.2             $31             $61
----------------------------------------------------------------------------------------------------------------
                                      Air Quality Co-benefits Discount Rate
----------------------------------------------------------------------------------------------------------------


 
 
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                 3%.................  7%................  3%................  7%................  3%................  7%
Air Quality Health Co-benefits   $0.70 to $1.8......  $0.64 to $1.7.....  $7.4 to $18.......  $6.7 to $16.......  $14 to $34........  $13 to $31
 \c\.
--------------------------------------------------------------------------------------------------------------------------------------------------------


 
 
----------------------------------------------------------------------------------------------------------------
Compliance Costs \d\............................................            $2.5            $1.0            $8.4
----------------------------------------------------------------------------------------------------------------


[[Page 64935]]


 
 
--------------------------------------------------------------------------------------------------------------------------------------------------------
Net Benefits \e\...............  $1.0 to $2.1.......  $1.0 to $2.0......  $17 to $27........  $16 to $25........  $26 to $45........  $25 to $43
--------------------------------------------------------------------------------------------------------------------------------------------------------
Non-Monetized Benefits.........                                              Non-monetized climate benefits.
                                                                      Reductions in exposure to ambient NO2 and SO2.
                                                                            Reductions in mercury deposition.
                                                 Ecosystem benefits associated with reductions in emissions of NOX, SO2, PM, and mercury.
                                                                                  Visibility impairment.
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ All are rounded to two significant figures, so figures may not sum.
\b\ The climate benefit estimate in this summary table reflects global impacts from CO2 emission changes and does not account for changes in non-CO2 GHG
  emissions. Also, different discount rates are applied to SC-CO2 than to the other estimates because CO2 emissions are long-lived and subsequent
  damages occur over many years. The benefit estimates in this table are based on the average SC-CO2 estimated for a 3 percent discount rate. However,
  we emphasize the importance and value of considering the full range of SC-CO2 values. As shown in the RIA, climate benefits are also estimated using
  the other three SC-CO2 estimates (model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent). The SC-CO2
  estimates are year-specific and increase over time.
\c\ The air pollution health co-benefits reflect reduced exposure to PM2.5 and ozone associated with emission reductions of SO2 and NOX. The range
  reflects the use of concentration-response functions from different epidemiology studies. The co-benefits do not include the benefits of reductions in
  directly emitted PM2.5. These additional benefits would increase overall benefits by a few percent based on the analyses conducted for the proposed
  rule. The reduction in premature fatalities each year accounts for over 98 percent of total monetized co-benefits from PM2.5 and ozone. These models
  assume that all fine particles, regardless of their chemical composition, are equally potent in causing premature mortality because the scientific
  evidence is not yet sufficient to allow differentiation of effect estimates by particle type.
\d\ Total costs are approximated by the illustrative compliance costs estimated using the Integrated Planning Model for the final guidelines and a
  discount rate of approximately 5 percent. This estimate includes monitoring, recordkeeping, and reporting costs and demand-side EE program and
  participant costs.
\e\ The estimates of net benefits in this summary table are calculated using the global SC-CO2 at a 3 percent discount rate (model average). The RIA
  includes combined climate and health estimates based on additional discount rates.


   Table 22--Summary of the Monetized Benefits, Compliance Costs, and Net Benefits for the Final Guidelines in
                       2020, 2025 and 2030 Under the Mass-Based Illustrative Plan Approach
                                             [Billions of 2011$] \a\
----------------------------------------------------------------------------------------------------------------
                                                                                Mass-based approach
                                                                 -----------------------------------------------
                                                                       2020            2025            2030
----------------------------------------------------------------------------------------------------------------
Climate Benefits \b\
5% discount rate................................................            $0.9            $3.6            $6.4
3% discount rate................................................            $3.3             $12             $20
2.5% discount rate..............................................            $4.9             $17             $29
95th percentile at 3% discount rate.............................            $9.7             $35             $60
----------------------------------------------------------------------------------------------------------------
                                      Air Quality Co-benefits Discount Rate
----------------------------------------------------------------------------------------------------------------


 
 
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                3%................  7%................  3%................  7%...............  3%...............  7%
Air Quality Health Co-benefits  $2.0 to $4.8......  $1.8 to $4.4......  $7.1 to $17.......  $6.5 to $16......  $12 to $28.......  $11 to $26
 \c\.
--------------------------------------------------------------------------------------------------------------------------------------------------------


 
 
----------------------------------------------------------------------------------------------------------------
Compliance Costs \d\............................................            $1.4            $3.0            $5.1
----------------------------------------------------------------------------------------------------------------


 
 
--------------------------------------------------------------------------------------------------------------------------------------------------------
Net Benefits \e\...............  $3.9 to $6.7.......  $3.7 to $6.3......  $16 to $26........  $15 to $24........  $26 to $43........  $25 to $40
--------------------------------------------------------------------------------------------------------------------------------------------------------
Non-Monetized Benefits.........                                              Non-monetized climate benefits.
                                                                      Reductions in exposure to ambient NO2 and SO2.
                                                                            Reductions in mercury deposition.
                                                 Ecosystem benefits associated with reductions in emissions of NOX, SO2, PM, and mercury.
                                                                                 Visibility improvement.
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ All are rounded to two significant figures, so figures may not sum.
\b\ The climate benefit estimate in this summary table reflects global impacts from CO2 emission changes and does not account for changes in non-CO2 GHG
  emissions. Also, different discount rates are applied to SC-CO2 than to the other estimates because CO2 emissions are long-lived and subsequent
  damages occur over many years. The benefit estimates in this table are based on the average SC-CO2 estimated for a 3 percent discount rate. However,
  we emphasize the importance and value of considering the full range of SC-CO2 values. As shown in the RIA, climate benefits are also estimated using
  the other three SC-CO2 estimates (model average at 2.5 percent discount rate, 3 percent, and 5 percent; 95th percentile at 3 percent). The SC-CO2
  estimates are year-specific and increase over time.
\c\ The air pollution health co-benefits reflect reduced exposure to PM2.5 and ozone associated with emission reductions of SO2 and NOX. The co-benefits
  do not include the benefits of reductions in directly emitted PM2.5. These additional benefits would increase overall benefits by a few percent based
  on the analyses conducted for the proposed rule. The range reflects the use of concentration-response functions from different epidemiology studies.
  The reduction in premature fatalities each year accounts for over 98 percent of total monetized co-benefits from PM2.5 and ozone. These models assume
  that all fine particles, regardless of their chemical composition, are equally potent in causing premature mortality because the scientific evidence
  is not yet sufficient to allow differentiation of effect estimates by particle type.
\d\ Total costs are approximated by the illustrative compliance costs estimated using the Integrated Planning Model for the final guidelines and a
  discount rate of approximately 5 percent. This estimate includes monitoring, recordkeeping, and reporting costs and demand-side EE program and
  participant costs.
\e\ The estimates of net benefits in this summary table are calculated using the global SC-CO2 at a 3 percent discount rate (model average). The RIA
  includes combined climate and health estimates based on additional discount rates.

    There are additional important benefits that the EPA could not 
monetize. Due to current data and modeling limitations, our estimates 
of the benefits from reducing CO2 emissions do not include 
important impacts like ocean acidification or potential tipping points 
in natural or managed ecosystems. Unquantified

[[Page 64936]]

benefits also include climate benefits from reducing emissions of non-
CO2 GHGs (e.g., nitrous oxide and methane) and co-benefits 
from reducing direct exposure to SO2, NOX and 
hazardous air pollutants (e.g., mercury), as well as from reducing 
ecosystem effects and visibility impairment. Based upon the foregoing 
discussion, it remains clear that the benefits of this final action are 
substantial, and far exceed the costs. Additional details on benefits, 
costs, and net benefits estimates are provided in this RIA.

B. Paperwork Reduction Act (PRA)

    The information collection requirements in this rule have been 
submitted for approval to OMB under the PRA. The Information Collection 
Request (ICR) document prepared by the EPA has been assigned the EPA 
ICR number 2503.02. You can find a copy of the ICR in the docket for 
this rule, and it is briefly summarized here. The information 
collection requirements are not enforceable until OMB approves them.
    This rule does not directly impose specific requirements on EGUs 
located in states or areas of Indian country. The rule also does not 
impose specific requirements on tribal governments that have affected 
EGUs located in their area of Indian country. For areas of Indian 
country, the rule establishes CO2 emission performance goals 
that could be addressed through either tribal or federal plans. A tribe 
would have the opportunity under the Tribal Authority Rule (TAR), but 
not the obligation, to apply to the EPA for Treatment as State (TAS) 
for purposes of a CAA section 111(d) plan and, if approved by the EPA, 
to establish a CAA section 111(d) plan for its area of Indian country. 
To date, no tribe has requested or obtained TAS eligibility for 
purposes of a CAA section 111(d) plan. For areas of Indian country with 
affected EGUs where a tribe has not applied for TAS and submitted any 
needed plan, if the EPA determines that a CAA section 111(d) plan is 
necessary or appropriate, the EPA would have the responsibility to 
establish the plans. Because tribes are not required to implement 
section 111(d) plans and because no tribe has yet sought TAS 
eligibility for this purpose, this action is not anticipated to impose 
any information collection burden on tribal governments over the 3-year 
period covered by this ICR.
    This rule does impose specific requirements on state governments 
with affected EGUs. The information collection requirements are based 
on the recordkeeping and reporting burden associated with developing, 
implementing, and enforcing a plan to limit CO2 emissions 
from existing sources in the utility power sector. These recordkeeping 
and reporting requirements are specifically authorized by CAA section 
114 (42 U.S.C. 7414). All information submitted to the EPA pursuant to 
the recordkeeping and reporting requirements for which a claim of 
confidentiality is made is safeguarded according to agency policies set 
forth in 40 CFR part 2, subpart B.
    The annual burden for this collection of information for the states 
(averaged over the first 3 years following promulgation) is estimated 
to be a range of 505,000 to 821,000 hours at a total annual labor cost 
of $35.8 to $58.1 million. The lower bound estimate reflects the 
assumption that some states already have EE and RE programs in place. 
The higher bound estimate reflects the overly-conservative assumption 
that no states have EE and RE programs in place.
    The total annual burden for the federal government associated with 
the state collection of information (averaged over the first 3 years 
following promulgation) is estimated to be 54,000 hours at a total 
annual labor cost of $3.00 million. Burden is defined at 5 CFR 
1320.3(b).
    An agency may not conduct or sponsor, and a person is not required 
to respond to, a collection of information unless it displays a 
currently valid OMB control number. The OMB control numbers for the 
EPA's regulations in 40 CFR are listed in 40 CFR part 9. When OMB 
approves this ICR, the agency will announce that approval in the 
Federal Register and publish a technical amendment to 40 CFR part 9 to 
display the OMB control number for the approved information collection 
activities contained in this final rule.

C. Regulatory Flexibility Act (RFA)

    I certify that this action will not have a significant economic 
impact on a substantial number of small entities under the RFA. This 
action will not impose any requirements on small entities. 
Specifically, emission guidelines established under CAA section 111(d) 
do not impose any requirements on regulated entities and, thus, will 
not have a significant economic impact upon a substantial number of 
small entities. After emission guidelines are promulgated, states 
establish emission standards on existing sources, and it is those 
requirements that could potentially impact small entities.
    Our analysis here is consistent with the analysis of the analogous 
situation arising when the EPA establishes NAAQS, which do not impose 
any requirements on regulated entities. As here, any impact of a NAAQS 
on small entities would only arise when states take subsequent action 
to maintain and/or achieve the NAAQS through their SIPs. See American 
Trucking Assoc. v. EPA, 175 F.3d 1029, 1043-45 (D.C. Cir. 1999) (NAAQS 
do not have significant impacts upon small entities because NAAQS 
themselves impose no regulations upon small entities).
    Nevertheless, the EPA is aware that there is substantial interest 
in the rule among small entities and, as detailed in section III.A of 
the preamble to the proposed carbon pollution emission guidelines for 
existing EGUs (79 FR 34845-34847; June 18, 2014) and in section II.D of 
the preamble to the proposed carbon pollution emission guidelines for 
existing EGUs in Indian Country and U.S. Territories (79 FR 65489; 
November 4, 2014), has conducted an unprecedented amount of stakeholder 
outreach. As part of that outreach, agency officials participated in 
many meetings with individual utilities and electric utility 
associations, as well as industry leaders and trade association 
representatives from various industries. While formulating the 
provisions of the rule, the EPA considered the input provided over the 
course of the stakeholder outreach as well as the input provided in the 
many public comments.

D. Unfunded Mandates Reform Act (UMRA)

    This action does not contain an unfunded mandate of $100 million or 
more as described in UMRA, 2 U.S.C. 1531-1538, and does not 
significantly or uniquely affect small governments. The emission 
guidelines do not impose any direct compliance requirements on EGUs 
located in states or areas of Indian country. As explained in section 
XII.B above, the rule also does not impose specific requirements on 
tribal governments that have affected EGUs located in their area of 
Indian country. The rule does impose specific requirements on state 
governments that have affected EGUs. Specifically, states are required 
to develop plans to implement the guidelines under CAA section 111(d) 
for affected EGUs. The burden for states to develop CAA section 111(d) 
plans in the 3-year period following promulgation of the rule was 
estimated and is listed in section XII.B above, but this burden is 
estimated to be below $100 million in any one year. Thus, this rule is 
not subject to the requirements of section 202 or section 205 of the 
UMRA.

[[Page 64937]]

    This rule is also not subject to the requirements of section 203 of 
UMRA because it contains no regulatory requirements that might 
significantly or uniquely affect small governments. Specifically, the 
state governments to which rule requirements apply are not considered 
small governments.
    In light of the interest among governmental entities, the EPA 
conducted outreach with national organizations representing state and 
local elected officials and tribal governmental entities while 
formulating the provisions of this rule. Sections III.A and XI.F of the 
preamble to the proposed carbon pollution emission guidelines for 
existing EGUs (79 FR 34845-34847; June 18, 2014) and sections II.D and 
VI.F of the preamble to the proposed carbon pollution emission 
guidelines for existing EGUs in areas of Indian Country and U.S. 
Territories (79 FR 65489; November 4, 2014) describes the extensive 
stakeholder outreach the EPA has conducted on setting emission 
guidelines for existing EGUs. The EPA considered the input provided 
over the course of the stakeholder outreach as well as the input 
provided in the many public comments when developing the provisions of 
these emission guidelines.

E. Executive Order 13132: Federalism

    The EPA has concluded that this action may have federalism 
implications, pursuant to agency policy for implementing the Order, 
because it imposes substantial direct compliance costs on state or 
local governments, and the federal government will not provide the 
funds necessary to pay those costs. As discussed in the Supporting 
Statement found in the docket for this rulemaking, the development of 
state plans will entail many hours of staff time to develop and 
coordinate programs for compliance with the rule, as well as time to 
work with state legislatures as appropriate, to develop a plan 
submittal. Consistent with this determination, the EPA provides the 
following federalism summary impact statement.
    The EPA consulted with state and local officials early in the 
process of developing the proposed action to permit them to have 
meaningful and timely input into its development. As described in the 
Federalism discussion in the preamble to the proposed standards of 
performance for GHG emissions from new EGUs (79 FR 1501; January 8, 
2014), the EPA consulted with state and local officials in the process 
of developing the proposed standards for newly constructed EGUs. This 
outreach addressed planned actions for new, reconstructed, modified and 
existing sources. The EPA invited the following 10 national 
organizations representing state and local elected officials to a 
meeting on April 12, 2011, in Washington, DC: (1) National Governors 
Association; (2) National Conference of State Legislatures, (3) Council 
of State Governments, (4) National League of Cities, (5) U.S. 
Conference of Mayors, (6) National Association of Counties, (7) 
International City/County Management Association, (8) National 
Association of Towns and Townships, (9) County Executives of America, 
and (10) Environmental Council of States. The National Association of 
Clean Air Agencies also participated. On February 26, 2014, the EPA re-
engaged with those governmental entities to provide a pre-proposal 
update on the emission guidelines for existing EGUs and emission 
standards for modified and reconstructed EGUs. In addition, as 
described in section III.A of the preamble to the proposed carbon 
pollution emission guidelines for existing EGUs (79 FR 34845-34847; 
June 18, 2014), extensive stakeholder outreach conducted by the EPA 
allowed state leaders, including governors, state attorneys general, 
environmental commissioners, energy officers, public utility 
commissioners, and air directors, opportunities to engage with EPA 
officials and provide input regarding reducing carbon pollution from 
power plants.
    In the spirit of Executive Order 13132, and consistent with the 
EPA's policy to promote communications between the EPA and state and 
local governments, the EPA specifically solicited comment on the 
proposed action from state and local officials. The EPA received 
comments from over 400 entities representing state and local 
governments.
    Several themes emerged from state and local government comments. 
Commenters raised concerns with the building blocks that comprise the 
best system of emission reduction (BSER), including the stringency of 
the building blocks, and the timing of achieving interim CO2 
levels. They also identified the potential for electric system 
reliability issues and stranded assets due to the proposed timeframe 
for plan submittals and CO2 emission reductions. In 
addition, states commented on state plan development and implementation 
topics, including state plan approaches, early actions, trading 
programs, interstate crediting for RE, and EPA guidance and outreach.
    Commenters identified overarching concerns regarding the stringency 
of the CO2 goals and the timeframe for achieving reductions 
that encompassed the building blocks, the BSER, and associated timing 
for achievement of interim CO2 levels. State commenters, in 
particular, identified changes to the stringency of the building 
blocks, concerns with the timeframe over which reductions must be 
achieved, and concerns with the approaches and measures used for the 
BSER. For the final rule, in response to stakeholder comments, the EPA 
has made refinements to the building blocks, the period of time over 
which measures are deployed, and the stringency of emission limitations 
that those measures can achieve in a practical and reasonable cost way. 
The final BSER reflects those refinements.
    To many commenters, the proposal's 2020 compliance date, together 
with the stringency of the interim CO2 goal, bore 
significant reliability implications. In this final rule, the agency is 
addressing those concerns via adjustments to the compliance timeframe 
(an 8-year interim period that begins in 2022) and to the approach for 
meeting interim CO2 emission performance rates (a glide path 
separated into three steps, 2022-2024, 2025-2027, and 2028-2029), as 
well as a more gradual phase in of the emission reduction expectations. 
These adjustments provide more time for planning, consultation and 
decision making in the formulation of state plans and in EGUs' choices 
of compliance strategies. The final rule also retains flexibilities 
presented in the proposal and offers additional opportunities, 
including opportunities for trading within and between states, and 
other multi-state compliance approaches that will further support 
electric system reliability. The EPA is also requiring each state to 
demonstrate in its final state that it has considered electric system 
reliability issues in developing its plan--and is providing the time to 
do so. Even with this foundation of flexibility in place, these final 
guidelines further provide states with the option of proposing 
amendments to approved plans in the event that unanticipated and 
significant reliability challenges arise.
    Commenters provided compelling information indicating that it will 
take longer than the agency initially anticipated to for states to 
complete the tasks necessary to finalize a state plan, including 
administrative and potential legislative processes. Recognizing this, 
as well as the urgent need for actions to reduce GHG emissions, the EPA 
is requiring states to make an initial submittal by September 6, 2016, 
and is allowing states two additional years to

[[Page 64938]]

submit a final plan, if justified (to be submitted by September 6, 
2018).
    States commented on state plan development and implementation 
topics that included state plan approaches, early actions being taken 
into account, trading programs being allowed, interstate crediting for 
RE being allowed, and guidance and outreach being provided by the EPA. 
For the state plan approaches, commenters expressed concerns with the 
proposed ``portfolio approach'' for state plans, including concerns 
with enforceability of requirements, and identified a ``state 
commitment approach'' with backstop measures as an option for state 
plans. In this final rule, in response to stakeholder comments on the 
portfolio approach and alternative approaches, the EPA is finalizing a 
``state measures'' approach that includes a requirement for the 
inclusion of backstop measures.
    State commenters supported providing incentives for states and 
utilities to deploy CO2-reducing investments, such as RE and 
demand-side EE measures, as early as possible. The EPA recognizes the 
value of such early actions, and in this final rule is establishing the 
CEIP to provide opportunities for investment in RE and demand-side EE 
projects that deliver results in 2020 and/or 2021.
    Many state commenters supported the use of mass-based and rate-
based emission trading programs in state plans, including interstate 
emission trading programs. The EPA also received a number of comments 
from states and stakeholders about the value of EPA support in 
developing and/or administering tracking systems to support state 
administration of rate-based and mass-based emission trading programs. 
In this final rule, states may use trading or averaging approaches and 
technologies or strategies that are not explicitly mentioned in any of 
the three building blocks as part of their overall plans, as long as 
they achieve the required emission reductions from affected fossil-
fuel-fired EGUs. In addition, in response to concerns from states and 
power companies that the need for up-front interstate cooperation in 
developing multi-state plans could inhibit the development of 
interstate programs that could lower cost, the final rule provides 
additional options to allow individual EGUs to use creditable out-of-
state reductions to achieve required CO2 reductions, without 
the need for up-front interstate agreements. The EPA is committed to 
working with states to provide support for tracking of emissions and 
allowances or credits, to help implement multi-state trading or 
averaging approaches.
    In their comments, many states identified the need for the EPA to 
provide guidance, including guidance on RE and EE emission measurement 
and verification (EM&V), and to maintain regular contact/forums with 
states throughout the implementation process. To provide state and 
local governments and other stakeholders with an understanding of the 
rule requirements, and to provide efficiencies where possible and 
reduce the cost and administrative burden, the EPA will continue 
outreach throughout the plan development and submittal process. 
Outreach will include opportunities for states to participate in 
briefings, teleconferences, and meetings about the final rule. The 
EPA's 10 regional offices will continue to be the entry point for 
states and tribes to ask technical and policy questions. The agency 
will host (or partner with appropriate groups to co-host) a number of 
webinars about various components of the final rule during the first 
two months after the final rule is issued. The EPA will use information 
from this outreach process to inform the training and other tools that 
will be of most use to the states and tribes that are implementing the 
final rule. The EPA expects to issue guidance on specific topics, 
including evaluation, measurement and verification (EM&V) for RE and 
demand-side EE, state-community engagement, and resources and financial 
assistance for RE and demand-side EE. As guidance documents, tools, 
templates and other resources become available, the EPA, in 
consultation with the U.S. Department of Energy and other federal 
agencies, will continue to make these resources available via a 
dedicated Web site.
    A list of the state and local government commenters has been 
provided to OMB and has been placed in the docket for this rulemaking. 
In addition, the detailed response to comments from these entities is 
contained in the EPA's response to comments document on this final 
rulemaking, which has also been placed in the docket for this 
rulemaking.
    As required by section 8(a) of Executive Order 13132, the EPA 
included a certification from its Federalism Official stating that the 
EPA had met the Executive Order's requirements in a meaningful and 
timely manner when it sent the draft of this final action to OMB for 
review pursuant to Executive Order 12866. A copy of the certification 
is included in the public version of the official record for this final 
action.

F. Executive Order 13175: Consultation and Coordination With Indian 
Tribal Governments

    This action has tribal implications. However, it will neither 
impose substantial direct compliance costs on federally recognized 
tribal governments, nor preempt tribal law. Tribes are not required to 
develop or adopt CAA programs, but they may apply to the EPA for 
treatment in a manner similar to states (TAS) and, if approved, do so. 
As a result, tribes are not required to develop plans to implement the 
guidelines under CAA section 111(d) for affected EGUs in their areas of 
Indian country. To the extent that a tribal government seeks and 
attains TAS status for that purpose, these emission guidelines would 
require that planning requirements be met and emission management 
implementation plans be executed by the tribes. The EPA notes that this 
rule does not directly impose specific requirements on affected EGUs, 
including those located in areas of Indian country, but provides 
guidance to any tribe approved by the EPA to address CO2 
emissions from EGUs subject to section 111(d) of the CAA. The EPA also 
notes that none of the affected EGUs are owned or operated by tribal 
governments.
    As described in sections III.A and XI.F of the preamble to the 
proposed carbon pollution emission guidelines for existing EGUs (79 FR 
34845-34847; June 18, 2014) and sections II.D and VI.F of the preamble 
to the proposed carbon pollution emission guidelines for existing EGUs 
in Indian Country and U.S. Territories (79 FR 65489; November 4, 2014), 
the rule was developed after extensive and vigorous outreach to tribal 
governments. These tribes expressed varied points of view. Some tribes 
raised concerns about the impacts of the regulations on EGUs located in 
their areas of Indian country and the subsequent impact on jobs and 
revenue for their tribes. Other tribes expressed concern about the 
impact the regulations would have on the cost of water covered under 
treaty to their communities as a result of increased costs to the EGU 
that provide energy to transport the water to the tribes. Other tribes 
raised concerns about the impacts of climate change on their 
communities, resources, ways of life and hunting and treaty rights. The 
tribes were also interested in the scope of the guidelines being 
considered by the agency (e.g., over what time period, relationship to 
state and multi-state plans) and how tribes will participate in these 
planning activities.

[[Page 64939]]

    The EPA consulted with tribal officials under the EPA Policy on 
Consultation and Coordination with Indian Tribes early in the process 
of developing this action to permit them to have meaningful and timely 
input into its development. A summary of that consultation follows.
    Prior to issuing the supplemental proposal on November 4, 2014, the 
EPA consulted with tribes as follows. The EPA held a consultation with 
the Ute Tribe, the Crow Nation, and the Mandan, Hidatsa, Arikara (MHA) 
Nation on July 18, 2014. On August 22, 2014, the EPA held a 
consultation with the Fort Mojave Tribe. On September 15, 2014, the EPA 
held a consultation with the Navajo Nation. The Navajo Nation sent a 
letter to the EPA on September 18, 2014, summarizing the information 
presented at the consultation and the Navajo Nation's position on the 
supplemental proposal. One issue raised by tribal officials was the 
potential impacts of the June 18, 2014 proposal and the supplemental 
proposal on tribes with budgets that are dependent on revenue from coal 
mines and power plants, as well as employment at the mines and power 
plants. The tribes noted the high unemployment rates and lack of access 
to basic services on their lands. Tribal officials also asked whether 
the rules will have any impact on a tribe's ability to seek TAS. Tribal 
officials also expressed interest in agency actions with regard to 
facilitating power plant compliance with regulatory requirements. The 
Navajo Nation made the following recommendations in their letter of 
September 18, 2014: The Navajo Nation supports a mass-based 
CO2 emission standard based on the highest historical 
CO2 emissions since 1996; the Navajo Nation requests that 
the EPA grant the Navajo Nation carbon credits and that the Navajo 
Nation retains ownership and control of such credits; building block 2 
is not appropriate for the Navajo Nation because there are no NGCC 
plants located on the Navajo Nation; building block 3 is not 
appropriate for the Navajo Nation because the Navajo people already 
receive virtually all of their electricity from carbon-free sources 
(mostly hydroelectric power) and their use of electricity is negligible 
compared to the generation at the power plants; building block 4 is not 
appropriate for the Navajo Nation because of the inadequate access to 
electricity, and the goal should allow for an increase in energy 
consumption on the Navajo Nation; the supplemental proposal should 
consider the useful life of the power plants located on the Navajo 
Nation; and the supplemental proposal should clarify that RE projects 
located within the Navajo Nation that provide electricity outside the 
Navajo Nation should be counted toward meeting the relevant state's RE 
goals under the Clean Power Plan.
    After issuing the supplemental proposal, the EPA held additional 
consultation with tribes. On November 18, 2014, the EPA held 
consultations with the following tribes: Fort McDowell Yavapai Nation, 
Fort Mojave Tribe, Hopi Tribe, Navajo Nation, and Ak-Chin Indian 
Community. A consultation with the Ute Indian Tribe of the Uintah and 
Ouray Reservation was held on December 16, 2014 and with the Gila River 
Indian Community on January 15, 2015. The Navajo Nation reiterated the 
concerns raised during the previous consultation. Several tribes also 
again indicated that they wanted to ensure they would be included in 
the development of any tribal or federal plans for areas of Indian 
country. The Fort Mojave Tribe and the Navajo Nation expressed concern 
with using data from 2012 as the basis for the goal for their areas of 
Indian country; in their view, that year was not representative for the 
affected EGU. On April 28, 2015, the EPA held an additional 
consultation with the Navajo Nation. The issues raised by the Navajo 
Nation during the consultation included whether the EPA has the 
authority to set less stringent standards on a case-by-case basis, and 
a suggested ``parity glide path'' that would account and adjust for the 
very low electricity usage by the Navajo Nation and promote Navajo 
Nation economic growth and demand. Furthermore, on July 7, 2015 the EPA 
conducted an additional consultation with the Navajo Nation. One of the 
goals of the consultation was for the new government of the Navajo 
Nation to deepen their understanding of the rulemaking. The questions 
raised by the nation had to do with goal setting and carbon credits, 
the timing of the rulemaking, and the proposed federal plan. 
Additionally, on July 14, 2015 the EPA conducted an additional 
consultation with the Fort Mojave Tribe. The Fort Mojave tribes 
expressed concerns that 2012 is not a representative year, that natural 
gas-fired combined cycle power plants should be treated differently 
from coal-fired power plants, and that the proposed goal for Fort 
Mojave was not appropriate. Additionally, they also expressed interest 
in being engaged in the federal plan process. Responses to these 
comments and others received are available in the Response to Comment 
Document that is in the docket for this rulemaking. As required by 
section 7(a), the EPA's Tribal Consultation Official has certified that 
the requirements of the executive order have been met in a meaningful 
and timely manner. A copy of the certification is included in the 
docket for this action.

G. Executive Order 13045: Protection of Children From Environmental 
Health Risks and Safety Risks

    This action is subject to Executive Order 13045 (62 FR 19885, April 
23, 1997) because it is an economically significant regulatory action 
as defined by Executive Order 12866, and the EPA believes that the 
environmental health or safety risk addressed by this action has a 
disproportionate effect on children. Accordingly, the agency has 
evaluated the environmental health and welfare effects of climate 
change on children.
    CO2 is a potent GHG that contributes to climate change 
and is emitted in significant quantities by fossil fuel-fired power 
plants. The EPA believes that the CO2 emission reductions 
resulting from implementation of these final guidelines, as well as 
substantial ozone and PM2.5 emission reductions as a co-
benefit, will further improve children's health.
    The assessment literature cited in the EPA's 2009 Endangerment 
Finding concluded that certain populations and lifestages, including 
children, the elderly, and the poor, are most vulnerable to climate-
related health effects. The assessment literature since 2009 
strengthens these conclusions by providing more detailed findings 
regarding these groups' vulnerabilities and the projected impacts they 
may experience.
    These assessments describe how children's unique physiological and 
developmental factors contribute to making them particularly vulnerable 
to climate change. Impacts to children are expected from heat waves, 
air pollution, infectious and waterborne illnesses, and mental health 
effects resulting from extreme weather events. In addition, children 
are among those especially susceptible to most allergic diseases, as 
well as health effects associated with heat waves, storms, and floods. 
Additional health concerns may arise in low income households, 
especially those with children, if climate change reduces food 
availability and increases prices, leading to food insecurity within 
households.
    More detailed information on the impacts of climate change to human 
health and welfare is provided in section II.A of this preamble.

[[Page 64940]]

H. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use

    This action, which is a significant regulatory action under EO 
12866, is likely to have a significant effect on the supply, 
distribution, or use of energy. The EPA has prepared a Statement of 
Energy Effects for this action as follows. We estimate a 1 to 2 percent 
change in retail electricity prices on average across the contiguous 
U.S. in 2025, and a 22 to 23 percent reduction in coal-fired 
electricity generation as a result of this rule. The EPA projects that 
utility power sector delivered natural gas prices will increase by up 
to 2.5 percent in 2030. For more information on the estimated energy 
effects, please refer to the economic impact analysis for this 
proposal. The analysis is available in the RIA, which is in the public 
docket.

I. National Technology Transfer and Advancement Act (NTTAA)

    This rulemaking does not involve technical standards.

J. Executive Order 12898: Federal Actions To Address Environmental 
Justice in Minority Populations and Low-Income Populations

    Executive Order 12898 (59 FR 7629; February 16, 1994) establishes 
federal executive policy on environmental justice. Its main provision 
directs federal agencies, to the greatest extent practicable and 
permitted by law, to make environmental justice part of their mission 
by identifying and addressing, as appropriate, disproportionately high 
and adverse human health or environmental effects of their programs, 
policies, and activities on minority populations and low-income 
populations in the U.S. The EPA defines environmental justice as the 
fair treatment and meaningful involvement of all people regardless of 
race, color, national origin, or income with respect to the 
development, implementation, and enforcement of environmental laws, 
regulations, and policies. The EPA has this goal for all communities 
and persons across this Nation. It will be achieved when everyone 
enjoys the same degree of protection from environmental and health 
hazards and equal access to the decision-making process to have a 
healthy environment in which to live, learn, and work.
    Leading up to this rulemaking the EPA summarized the public health 
and welfare effects of GHG emissions in its 2009 Endangerment Finding. 
See, section VIII.A of this preamble where the EPA summarizes the 
public health and welfare impacts from GHG emissions that were detailed 
in the 2009 Endangerment Finding under CAA section 202(a)(1).\1068\ As 
part of the Endangerment Finding, the Administrator considered climate 
change risks to minority populations and low-income populations, 
finding that certain parts of the population may be especially 
vulnerable based on their characteristics or circumstances. Populations 
that were found to be particularly vulnerable to climate change risks 
include the poor, the elderly, the very young, those already in poor 
health, the disabled, those living alone, and/or indigenous populations 
dependent on one or a few resources. See sections XII.F and XII.G, 
above, where the EPA discusses Consultation and Coordination with 
Tribal Governments and Protection of Children. The Administrator placed 
weight on the fact that certain groups, including children, the 
elderly, and the poor, are most vulnerable to climate-related health 
effects.
---------------------------------------------------------------------------

    \1068\ ``Endangerment and Cause or Contribute Findings for 
Greenhouse Gases Under Section 202(a) of the Clean Air Act,'' 74 FR 
66496 (Dec. 15, 2009) (``Endangerment Finding'').
---------------------------------------------------------------------------

    The record for the 2009 Endangerment Finding summarizes the strong 
scientific evidence in the major assessment reports by the U.S. Global 
Change Research Program (USGCRP), the Intergovernmental Panel on 
Climate Change (IPCC), and the National Research Council (NRC) of the 
National Academies that the potential impacts of climate change raise 
environmental justice issues. These reports concluded that poor 
communities can be especially vulnerable to climate change impacts 
because they tend to have more limited adaptive capacities and are more 
dependent on climate-sensitive resources such as local water and food 
supplies. In addition, Native American tribal communities possess 
unique vulnerabilities to climate change, particularly those impacted 
by degradation of natural and cultural resources within established 
reservation boundaries and threats to traditional subsistence 
lifestyles. Tribal communities whose health, economic well-being, and 
cultural traditions that depend upon the natural environment will 
likely be affected by the degradation of ecosystem goods and services 
associated with climate change. The 2009 Endangerment Finding record 
also specifically noted that Southwest native cultures are especially 
vulnerable to water quality and availability impacts. Native Alaskan 
communities are already experiencing disruptive impacts, including 
coastal erosion and shifts in the range or abundance of wild species 
crucial to their livelihoods and well-being.
    The most recent assessments continue to strengthen scientific 
understanding of climate change risks to minority populations and low-
income populations in the U.S.\1069\ The new assessment literature 
provides more detailed findings regarding these populations' 
vulnerabilities and projected impacts they may experience. In addition, 
the most recent assessment reports provide new information on how some 
communities of color (more specifically, populations defined jointly by 
ethnic/racial characteristics and geographic location) may be uniquely 
vulnerable to climate change health impacts in the U.S. These reports 
find that certain climate change related impacts--including heat waves, 
degraded air quality, and extreme weather events--have disproportionate 
effects on low-income populations and some communities of color, 
raising environmental justice concerns. Existing health disparities and 
other inequities in these communities increase their vulnerability to 
the health effects of climate change. In addition, assessment reports 
also find that climate change poses particular threats to health, well-
being, and ways of life of indigenous peoples in the U.S.
---------------------------------------------------------------------------

    \1069\ Melillo, Jerry M., Terese (T.C.) Richmond, and Gary W. 
Yohe, Eds., 2014: Climate Change Impacts in the United States: The 
Third National Climate Assessment. U.S. Global Change Research 
Program, 841 pp.
    IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and 
Vulnerability. Part A: Global and Sectoral Aspects. Contribution of 
Working Group II to the Fifth Assessment Report of the 
Intergovernmental Panel on Climate Change [Field, C.B., V.R. Barros, 
D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E. Bilir, M. Chatterjee, 
K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. 
Levy, S. MacCracken, P.R. Mastrandrea, and L.L. White (eds.)]. 
Cambridge University Press, 1132 pp. https://www.ipcc.ch/report/ar5/wg2/.
    IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and 
Vulnerability. Part B: Regional Aspects. Contribution of Working 
Group II to the Fifth Assessment Report of the Intergovernmental 
Panel on Climate Change [Barros, V.R., C.B. Field, D.J. Dokken, M.D. 
Mastrandrea, K.J. Mach, T.E. Bilir, M. Chatterjee, K.L. Ebi, Y.O. 
Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. Levy, S. 
MacCracken, P.R. Mastrandrea, and L.L. White (eds.)]. Cambridge 
University Press, 688 pp. https://www.ipcc.ch/report/ar5/wg2/.
---------------------------------------------------------------------------

    As the scientific literature presented above and as the 2009 
Endangerment Finding illustrates, low income populations and some 
communities of color are especially vulnerable to the health and other 
adverse impacts of climate change. The EPA believes that communities 
will benefit from this final rulemaking because this action directly 
addresses the impacts of climate change

[[Page 64941]]

by limiting GHG emissions through the establishment of CO2 
emission guidelines for existing affected fossil fuel-fired EGUs.
    In addition to reducing CO2 emissions, the guidelines 
finalized in this rulemaking would reduce other emissions from affected 
EGUs that reduce generation due to higher adoption of EE and RE. These 
emission reductions will include SO2 and NOX, 
which form ambient PM2.5 and ozone in the atmosphere, and 
HAP, such as mercury and hydrochloric acid. In the final rule revising 
the annual PM2.5 NAAQS,\1070\ the EPA identified low-income 
populations as being a vulnerable population for experiencing adverse 
health effects related to PM exposures. Low-income populations have 
been generally found to have a higher prevalence of pre-existing 
diseases, limited access to medical treatment, and increased 
nutritional deficiencies, which can increase this population's 
susceptibility to PM-related effects.\1071\ In areas where this 
rulemaking reduces exposure to PM2.5, ozone, and 
methylmercury, low-income populations will also benefit from such 
emissions reductions. The RIA for this rulemaking, included in the 
docket for this rulemaking, provides additional information regarding 
the health and ecosystem effects associated with these emission 
reductions.
---------------------------------------------------------------------------

    \1070\ ``National Ambient Air Quality Standards for Particulate 
Matter, Final Rule,'' 78 FR 3086 (Jan. 15, 2013).
    \1071\ U.S. Environmental Protection Agency (U.S. EPA). 2009. 
Integrated Science Assessment for Particulate Matter (Final Report). 
EPA-600-R-08-139F. National Center for Environmental Assessment--RTP 
Division. December. Available on the Internet at <http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546>.
---------------------------------------------------------------------------

    Additionally, as outlined in the community and environmental 
justice considerations section IX of this preamble, the EPA has taken a 
number of actions to help ensure that this action will not have 
potential disproportionately high and adverse human health or 
environmental effects on overburdened communities. The EPA consulted 
its May 2015, Guidance on Considering Environmental Justice During the 
Development of Regulatory Actions, when determining what actions to 
take.\1072\ As described in the community and environmental justice 
considerations section of this preamble the EPA also conducted a 
proximity analysis, which is available in the docket of this rulemaking 
and is discussed in section IX. Additionally, as outlined in sections I 
and IX of this preamble, the EPA has engaged with communities 
throughout this rulemaking and has devised a robust outreach strategy 
for continual engagement throughout the implementation phase of this 
rulemaking.
---------------------------------------------------------------------------

    \1072\ Guidance on Considering Environmental Justice During the 
Development of Regulatory Actions. http://epa.gov/environmentaljustice/resources/policy/considering-ej-in-rulemaking-guide-final.pdf. May 2015.
---------------------------------------------------------------------------

K. Congressional Review Act (CRA)

    This final action is subject to the CRA, and the EPA will submit a 
rule report to each House of the Congress and to the Comptroller 
General of the United States. This action is a ``major rule'' as 
defined by 5 U.S.C. 804(2).

XIII. Statutory Authority

    The statutory authority for this action is provided by sections 
111, 301, 302, and 307(d)(1)(C) of the CAA as amended (42 U.S.C. 7411, 
7601, 7602, 7607(d)(1)(C)). This action is also subject to section 
307(d) of the CAA (42 U.S.C. 7607(d)).

List of Subjects in 40 CFR Part 60

    Environmental protection, Administrative practice and procedure, 
Air pollution control, Intergovernmental relations, Reporting and 
recordkeeping requirements.

    Dated: August 3, 2015.
Gina McCarthy,
Administrator.
    For the reasons stated in the preamble, title 40, chapter I, part 
60 of the Code of the Federal Regulations is amended as follows:

PART 60--STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES

0
1. The authority citation for Part 60 continues to read as follows:

    Authority:  42 U.S.C. 7401 et seq.


0
2. Add subpart UUUU to read as follows:

Subpart--UUUU Emission Guidelines for Greenhouse Gas Emissions and 
Compliance Times for Electric Utility Generating Units

Sec.

Introduction

60.5700 What is the purpose of this subpart?
60.5705 Which pollutants are regulated by this subpart?
60.5710 Am I affected by this subpart?
60.5715 What is the review and approval process for my State plan?
60.5720 What if I do not submit a plan or my plan is not approvable?
60.5725 In lieu of a State plan submittal, are there other 
acceptable option(s) for a State to meet its CAA section 111(d) 
obligations?
60.5730 Is there an approval process for a negative declaration 
letter?
60.5735 What authorities will not be delegated to State, local, or 
tribal agencies?
60.5736 Will the EPA impose any sanctions?
60.5737 What is the Clean Energy Incentive Program and how do I 
participate?

State and Multi-State Plan Requirements

60.5740 What must I include in my federally enforceable State or 
multi-State plan?
60.5745 What must I include in my final plan submittal?
60.5750 Can I work with other States to develop a multi-State plan?
60.5760 What are the timing requirements for submitting my plan?
60.5765 What must I include in an initial submittal if requesting an 
extension for a final plan submittal?
60.5770 What schedules, performance periods, and compliance periods 
must I include in my plan?
60.5775 What emission standards must I include in my plan?
60.5780 What State measures may I rely upon in support of my plan?
60.5785 What is the procedure for revising my plan?
60.5790 What must I do to meet my plan obligations?

Emission Rate Credit Requirements

60.5795 What affected EGUs qualify for generation of ERCs?
60.5800 What other resources qualify for issuance of ERCs?
60.5805 What is the process for the issuance of ERCs?
60.5810 What applicable requirements are there for an ERC tracking 
system?

Mass Allocations Requirements

60.5815 What are the requirements for State allocation of allowances 
in a mass-based program?
60.5820 What are my allowance tracking requirements?
60.5825 What is the process for affected EGUs to demonstrate 
compliance in a mass-based program?

Evaluation Measurement and Verification Plans and Monitoring and 
Verification Reports

60.5830 What are the requirements for EM&V plans for eligible 
resources?
60.5835 What are the requirements for M&V reports for eligible 
resources?

Applicability of Plans to Affected EGUs

60.5840 Does this subpart directly affect EGU owners and operators 
in my State?
60.5845 What affected EGUs must I address in my State plan?
60.5850 What EGUs are excluded from being affected EGUs?
60.5855 What are the CO2 emission performance rates for 
affected EGUs?
60.5860 What applicable monitoring, recordkeeping, and reporting

[[Page 64942]]

requirements do I need to include in my plan for affected EGUs?

Recordkeeping and Reporting Requirements

60.5865 What are my recordkeeping requirements?
60.5870 What are my reporting and notification requirements?
60.5875 How do I submit information required by these emission 
guidelines to the EPA?

Definitions

60.5880 What definitions apply to this subpart?
Table 1 to Subpart UUUU of Part 60--CO2 Emission 
Performance Rates (Pounds of CO2 per Net MWh)
Table 2 to Subpart UUUU of Part 60--Statewide Rate-based 
CO2 Emission Goals (Pounds of CO2 per Net MWh)
Table 3 to Subpart UUUU of Part 60--Statewide Mass-based 
CO2 Emission Goals (Short Tons of CO2)
Table 4 to Subpart UUUU of Part 60--Statewide Mass-based 
CO2 Emission Goals plus New Source CO2 
Emission Complement (Short Tons of CO2)

Introduction


Sec.  60.5700  What is the purpose of this subpart?

    This subpart establishes emission guidelines and approval criteria 
for State or multi-State plans that establish emission standards 
limiting greenhouse gas (GHG) emissions from an affected steam 
generating unit, integrated gasification combined cycle (IGCC), or 
stationary combustion turbine. An affected steam generating unit, IGCC, 
or stationary combustion turbine shall, for the purposes of this 
subpart, be referred to as an affected EGU. These emission guidelines 
are developed in accordance with section 111(d) of the Clean Air Act 
and subpart B of this part. To the extent any requirement of this 
subpart is inconsistent with the requirements of subparts A or B of 
this part, the requirements of this subpart will apply.


Sec.  60.5705  Which pollutants are regulated by this subpart?

    (a) The pollutants regulated by this subpart are greenhouse gases. 
The emission guidelines for greenhouse gases established in this 
subpart are expressed as carbon dioxide (CO2) emission 
performance rates and equivalent statewide CO2 emission 
goals.
    (b) PSD and Title V Thresholds for Greenhouse Gases.
    (1) For the purposes of Sec.  51.166(b)(49)(ii), with respect to 
GHG emissions from facilities, the ``pollutant that is subject to the 
standard promulgated under section 111 of the Act'' shall be considered 
to be the pollutant that otherwise is subject to regulation under the 
Act as defined in Sec.  51.166(b)(48) and in any State Implementation 
Plan (SIP) approved by the EPA that is interpreted to incorporate, or 
specifically incorporates, Sec.  51.166(b)(48) of this chapter.
    (2) For the purposes of Sec.  52.21(b)(50)(ii), with respect to GHG 
emissions from facilities regulated in the plan, the ``pollutant that 
is subject to the standard promulgated under section 111 of the Act'' 
shall be considered to be the pollutant that otherwise is subject to 
regulation under the Act as defined in Sec.  52.21(b)(49) of this 
chapter.
    (3) For the purposes of Sec.  70.2 of this chapter, with respect to 
greenhouse gas emissions from facilities regulated in the plan, the 
``pollutant that is subject to any standard promulgated under section 
111 of the Act'' shall be considered to be the pollutant that otherwise 
is ``subject to regulation'' as defined in Sec.  70.2 of this chapter.
    (4) For the purposes of Sec.  71.2, with respect to greenhouse gas 
emissions from facilities regulated in the plan, the ``pollutant that 
is subject to any standard promulgated under section 111 of the Act'' 
shall be considered to be the pollutant that otherwise is ``subject to 
regulation'' as defined in Sec.  71.2 of this chapter.


Sec.  60.5710  Am I affected by this subpart?

    If you are the Governor of a State in the contiguous United States 
with one or more affected EGUs that commenced construction on or before 
January 8, 2014, you must submit a State or multi-State plan to the 
U.S. Environmental Protection Agency (EPA) that implements the emission 
guidelines contained in this subpart. If you are the Governor of a 
State in the contiguous United States with no affected EGUs for which 
construction commenced on or before January 8, 2014, in your State, you 
must submit a negative declaration letter in place of the State plan.


Sec.  60.5715  What is the review and approval process for my plan?

    The EPA will review your plan according to Sec.  60.27 except that 
under Sec.  60.27(b) the Administrator will have 12 months after the 
date the final plan or plan revision (as allowed under Sec.  60.5785) 
is submitted, to approve or disapprove such plan or revision or each 
portion thereof. If you submit an initial submittal under Sec.  
60.5765(a) in lieu of a final plan submittal the EPA will follow the 
procedure in Sec.  60.5765(b).


Sec.  60.5720  What if I do not submit a plan or my plan is not 
approvable?

    (a) If you do not submit an approvable plan the EPA will develop a 
Federal plan for your State according to Sec.  60.27. The Federal plan 
will implement the emission guidelines contained in this subpart. 
Owners and operators of affected EGUs not covered by an approved plan 
must comply with a Federal plan implemented by the EPA for the State.
    (b) After a Federal plan has been implemented in your State, it 
will be withdrawn when your State submits, and the EPA approves, a 
final plan.


Sec.  60.5725  In lieu of a State plan submittal, are there other 
acceptable option(s) for a State to meet its CAA section 111(d) 
obligations?

    A State may meet its CAA section 111(d) obligations only by 
submitting a final State or multi-State plan submittal or a negative 
declaration letter (if applicable).


Sec.  60.5730  Is there an approval process for a negative declaration 
letter?

    No. The EPA has no formal review process for negative declaration 
letters. Once your negative declaration letter has been received, the 
EPA will place a copy in the public docket and publish a notice in the 
Federal Register. If, at a later date, an affected EGU for which 
construction commenced on or before January 8, 2014 is found in your 
State, you will be found to have failed to submit a final plan as 
required, and a Federal plan implementing the emission guidelines 
contained in this subpart, when promulgated by the EPA, will apply to 
that affected EGU until you submit, and the EPA approves, a final State 
plan.


Sec.  60.5735  What authorities will not be delegated to State, local, 
or tribal agencies?

    The authorities that will not be delegated to State, local, or 
tribal agencies are specified in paragraphs (a) and (b) of this 
section.
    (a) Approval of alternatives, not already approved by this subpart, 
to the CO2 emission performance rates in Table 1 to this 
subpart established under Sec.  60.5855.
    (b) Approval of alternatives, not already approved by this subpart, 
to the CO2 emissions goals in Tables 2, 3 and 4 to this 
subpart established under Sec.  60.5855.


Sec.  60.5736  Will the EPA impose any sanctions?

    No. The EPA will not withhold any existing federal funds from a 
State on account of a State's failure to submit, implement, or enforce 
an approvable plan or plan revision, or to meet any other requirements 
under this subpart or subpart B of this part.

[[Page 64943]]

Sec.  60.5737  What is the Clean Energy Incentive Program and how do I 
participate?

    (a) This subpart establishes the Clean Energy Incentive Program 
(CEIP). Participation in this program is optional. The program enables 
States to award early action emission rate credits (ERCs) and 
allowances to eligible renewable energy (RE) or demand-side energy 
efficiency (EE) projects that generate megawatt hours (MWh) or reduce 
end-use energy demand during 2020 and/or 2021. Eligible projects are 
those that:
    (1) Are located in or benefit a state that has submitted a final 
state plan that includes requirements establishing its participation in 
the CEIP; and
    (2) Commence construction in the case of RE, or commence operation 
in the case of demand-side EE, following the submission of a final 
state plan to the EPA, or after September 6, 2018 for a state that 
chooses not to submit a final state plan by that date; and either
    (3) Generate metered MWh from any type of wind or solar resources; 
or
    (4) Result in quantified and verified electricity savings (MWh) 
through demand-side EE implemented in low-income communities.
    (b) The EPA will award matching ERCs or allowances to States that 
award early action ERCs or allowances, up to a match limit equivalent 
to 300 million tons of CO2 emissions. The awards will be 
executed as follows:
    (1) For RE projects that generate metered MWh from wind or solar 
resources: For every two MWh generated, the project will receive one 
early action ERC (or the equivalent number of allowances) from the 
State, and the EPA will provide one matching ERC (or the equivalent 
number of allowances) to the State to award to the project.
    (2) For EE projects implemented in low-income communities: For 
every two MWh in end-use demand savings achieved, the project will 
receive two early action ERCs (or the equivalent number of allowances) 
from the State, and the EPA will provide two matching ERCs (or the 
equivalent number of allowances) to the State to award to the project.
    (c) You may participate in this program by including in your State 
plan a mechanism that enables issuance of early action ERCs or 
allowances by the State to parties effectuating reductions in the 
calendar years 2020 and/or 2021 in a manner that would have no impact 
on the emission performance of affected EGUs required to meet rate-
based or mass-based emission standards during the performance periods. 
This mechanism is not required to account for matching ERCs or 
allowances that may be issued to the State by the EPA.
    (d) If you are submitting an initial submittal by September 6, 
2016, and you intend to participate in the CEIP, you must include a 
non-binding statement of intent to participate in the program. If you 
are submitting a final plan by September 6, 2016, and you intend to 
participate in the CEIP, your State plan must either include 
requirements establishing the necessary infrastructure to implement 
such a program and authorizing your affected EGUs to use early action 
allowances or ERCs as appropriate, or you must include a non-binding 
statement of intent as part of your supporting documentation and revise 
your plan to include the appropriate requirements at a later date.
    (e) If you intend to participate in the CEIP, your final State 
plan, or plan revision if applicable, must require that projects 
eligible under this program be evaluated, monitored, and verified, and 
that resulting ERCs or allowances be issued, per applicable 
requirements of the State plan approved by the EPA as meeting Sec.  
60.5805 through Sec.  60.5835.

State and Multi-State Plan Requirements


Sec.  60.5740  What must I include in my federally enforceable State or 
multi State plan?

    (a) You must include the components described in paragraphs (a)(1) 
through (5) of this section in your plan submittal. The final plan must 
meet the requirements and include the information required under Sec.  
60.5745.
    (1) Identification of affected EGUs. Consistent with Sec.  
60.25(a), you must identify the affected EGUs covered by your plan and 
all affected EGUs in your State that meet the applicability criteria in 
Sec.  60.5845. In addition, you must include an inventory of 
CO2 emissions from the affected EGUs during the most recent 
calendar year for which data is available prior to the submission of 
the plan.
    (2) Emission standards. You must include an identification of all 
emission standards for each affected EGU according to Sec.  60.5775, 
compliance periods for each emission standard according to Sec.  
60.5770, and a demonstration that the emission standards, when taken 
together, achieve the applicable CO2 emission performance 
rates or CO2 emission goals described in Sec.  60.5855. 
Allowance systems are an acceptable form of emission standards under 
this subpart.
    (i) Your plan does not need to include corrective measures 
specified in paragraph (a)(2)(ii) of this section if your plan:
    (A) Imposes emission standards on all affected EGUs that, assuming 
full compliance by all affected EGUs, mathematically assure achievement 
of the CO2 emission performance rates in the plan for each 
plan period;
    (B) Imposes emission standards on all affected EGUS that, assuming 
full compliance by all affected EGUs, mathematically assure achievement 
of the CO2 emission goals; or
    (C) Imposes emission standards on all affected EGUs that, assuming 
full compliance by all affected EGUs, in conjunction with applicable 
requirements under state law for EGUs subject to subpart TTTT of this 
subpart, assuming the applicable requirements under state law are met 
by all EGUs subject to subpart TTTT of this subpart, achieve the 
applicable mass-based CO2 emission goals plus new source 
CO2 emission complement allowed for in Sec.  60.5790(b)(5).
    (ii) If your plan does not meet the requirements of (a)(2)(i) or 
(iii) of this section, your plan must include the requirement for 
corrective measures to be implemented if triggered. Upon triggering 
corrective measures, if you do not already have them included in your 
approved State plan, you must submit corrective measures to EPA for 
approval as a plan revision per the requirements of Sec.  60.5785(c). 
These corrective measures must ensure that the interim period and final 
period CO2 emission performance rates or CO2 
emission goals are achieved by your affected EGUs, as applicable, and 
must achieve additional emission reductions to offset any emission 
performance shortfall. Your plan must include the requirement that 
corrective measures be triggered and implemented according to 
paragraphs (a)(2)(ii)(A) through (H) of this section.
    (A) Your plan must include a trigger for an exceedance of an 
interim step 1 or interim step 2 CO2 emission performance 
rate or CO2 emission goal by 10 percent or greater, either 
on average or cumulatively (if applicable).
    (B) Your plan must include a trigger for an exceedance of an 
interim step 1 goal or interim step 2 goal of 10 percent or greater 
based on either reported CO2 emissions with applied plus or 
minus net allowance export or import adjustments (if applicable), or 
based on the adjusted CO2 emission rate (if applicable).
    (C) Your plan must include a trigger for a failure to meet an 
interim period goal based on reported CO2 emissions with 
applied plus or minus net allowance export or import adjustments

[[Page 64944]]

(if applicable), or based on the adjusted CO2 emission rate 
(if applicable).
    (D) Your plan must include a trigger for a failure to meet the 
interim period or any final reporting period CO2 emission 
performance rate or CO2 emission goal, either on average or 
cumulatively (as applicable).
    (E) Your plan must include a trigger for a failure to meet any 
final reporting period goal based on reported CO2 emissions 
with applied plus or minus net allowance export or import adjustments 
(if applicable).
    (F) Your plan must include a trigger for a failure to meet the 
interim period CO2 emission performance rate or 
CO2 emission goal based on the adjusted CO2 
emission rate (if applicable).
    (G) Your plan must include a trigger for a failure to meet any 
final reporting period CO2 emission performance rate or 
CO2 emission goal based on the adjusted CO2 
emission rate (if applicable).
    (H) A net allowance import adjustment represents the CO2 
emissions (in tons) equal to the number of net imported CO2 
allowances. This adjustment is subtracted from reported CO2 
emissions. Under this adjustment, such allowances must be issued by a 
state with an emission budget trading program that only applies to 
affected EGUs (or affected EGUs plus EGUs covered by subpart TTTT of 
this part as applicable). A net allowance export adjustment represents 
the CO2 emissions (in tons) equal to the number of net 
exported CO2 allowances. This adjustment is added to 
reported CO2 emissions.
    (iii) If your plan relies upon State measures, in addition to or in 
lieu of emission standards on your affected EGUs, then the final State 
plan must include the requirements in paragraph (a)(3) of this section 
and the submittal must include the information listed in Sec.  
60.5745(a)(6).
    (iv) If your plan requires emission standards in addition to 
relying upon State measures, then you must demonstrate that the 
emission standards and State measures, when taken together, result in 
the achievement of the applicable mass-based CO2 emission 
goal described in Sec.  60.5855 by your State's affected EGUs.
    (3) State measures backstop. If your plan relies upon State 
measures, you must submit, as part of the plan in lieu of the 
requirements in paragraph (a)(2)(i) and (ii) of this section, a 
federally enforceable backstop that includes emission standards for 
affected EGUs that will be put into place, if there is a triggering 
event listed in paragraph (a)(3)(i) of this section, within 18 months 
of the due date of the report required in Sec.  60.5870(b). The 
emission standards on the affected EGUs as part of the backstop must be 
able to meet either the CO2 emission performance rates or 
mass-based or rate-based CO2 emission goal for your State 
during the interim and final periods. You must either submit, along 
with the backstop emission standards, provisions to adjust the emission 
standards to make up for the prior emission performance shortfall, such 
that no later plan revision to modify the emission standards is 
necessary in order to address the emission performance shortfall, or 
you must submit, as part of the final plan, backstop emission standards 
that assure affected EGUs would achieve your State's CO2 
emission performance rates or emission goals during the interim and 
final periods, and then later submit appropriate revisions to the 
backstop emission standards adjusting for the shortfall through the 
State plan revision process described in Sec.  60.5785. The backstop 
must also include the requirements in paragraphs (a)(3)(i) through 
(iii) of this section, as applicable.
    (i) You must include a trigger for the backstop to go into effect 
upon:
    (A) A failure to meet a programmatic milestone;
    (B) An exceedance of 10 percent or greater of an interim step 1 
goal or interim step 2 goal based on reported CO2 emissions, 
with applied plus or minus net allowance export or import adjustments 
(if applicable);
    (C) A failure to meet the interim period goal based on reported 
CO2 emissions, with applied plus or minus net allowance 
export or import adjustments (if applicable); or
    (D) A failure to meet any final reporting period goal based on 
reported CO2 emissions, with applied plus or minus net 
allowance export or import adjustments (if applicable).
    (ii) You may include in your plan any additional triggers so long 
as they do not reduce the stringency of the triggers required under 
paragraph (a)(3)(i) of this section.
    (iii) You must include a schedule for implementation of the 
backstop once triggered, and you must identify all necessary State 
administrative and technical procedures for implementing the backstop.
    (4) Identification of applicable monitoring, reporting, and 
recordkeeping requirements for each affected EGU. You must include in 
your plan all applicable monitoring, reporting and recordkeeping 
requirements for each affected EGU and the requirements must be 
consistent with or no less stringent than the requirements specified in 
Sec.  60.5860.
    (5) State reporting. You must include in your plan a description of 
the process, contents, and schedule for State reporting to the EPA 
about plan implementation and progress, including information required 
under Sec.  60.5870.
    (i) You must include in your plan a requirement for a report to be 
submitted by July 1, 2021, that demonstrates that the State has met, or 
is on track to meet, the programmatic milestone steps indicated in the 
timeline required in Sec.  60.5770.
    (b) You must follow the requirements of subpart B of this part and 
demonstrate that they were met in your State plan. However, the 
provisions of Sec.  60.24(f) shall not apply.


Sec.  60.5745  What must I include in my final plan submittal?

    (a) In addition to the components of the plan listed in Sec.  
60.5740, a final plan submittal to the EPA must include the information 
in paragraphs (a)(1) through (13) of this section. This information 
must be submitted to the EPA as part of your final plan submittal but 
will not be codified as part of the federally enforceable plan upon 
approval by EPA.
    (1) You must include a description of your plan approach and the 
geographic scope of the plan (i.e., State or multi-State, geographic 
boundaries related to the plan elements), including, if applicable, 
identification of multi-State plan participants.
    (2) You must identify CO2 emission performance rates or 
equivalent statewide CO2 emission goals that your affected 
EGUs will achieve. If the geographic scope of your plan is a single 
State, then you must identify CO2 emission performance rates 
or emission goals according to Sec.  60.5855. If your plan includes 
multiple States and you elect to set CO2 emission goals, you 
must identify CO2 emission goals calculated according to 
Sec.  60.5750.
    (i) You must specify in the plan submittal the CO2 
emission performance rates or emission goals that affected EGUs will 
meet for the interim period, each interim step, and the final period 
(including each final reporting period) pursuant to Sec.  60.5770.
    (ii) [Reserved]
    (3) You must include a demonstration that the affected EGUs covered 
by the plan are projected to achieve the CO2 emission 
performance rates or CO2 emission goals described in Sec.  
60.5855.
    (4) You must include a demonstration that each affected EGU's 
emission standard is quantifiable, non-

[[Page 64945]]

duplicative, permanent, verifiable, and enforceable according to Sec.  
60.5775.
    (5) If your plan includes emission standards on your affected EGUs 
sufficient to meet either the CO2 emission performance rates 
or CO2 emission goals, you must include in your plan 
submittal the information in paragraphs (a)(5)(i) through (v) of this 
section as applicable.
    (i) If your plan applies separate rate-based CO2 
emission standards for affected EGUs (in lbs CO2/MWh) that 
are equal to or lower than the CO2 emission performance 
rates listed in Table 1 of this subpart or uniform rate-based 
CO2 emission standards equal to or lower than the rate-based 
CO2 emission goals listed in Table 2 of this subpart, then 
no additional demonstration is required beyond inclusion of the 
emission standards in the plan.
    (ii) If a plan applies rate-based emission standards to individual 
affected EGUs at a lbs CO2/MWh rate that differs from the 
CO2 emission performance rates in Table 1 of this subpart or 
the State's rate-based CO2 emission goal in Table 2 of this 
subpart, then a further demonstration is required that the application 
of the CO2 emission standards will achieve the 
CO2 emission performance rates or State rate-based 
CO2 emission goal. You must demonstrate through a projection 
that the adjusted weighted average CO2 emission rate of 
affected EGUs, when weighted by generation (in MWh), will be equal to 
or less than the CO2 emission performance rates or the rate-
based CO2 emission goal. This projection must address the 
interim period and the final period. The projection in the plan 
submittal must include the information listed in paragraph (a)(5)(v) of 
this section and in addition the following:
    (A) An analysis of the change in generation of affected EGUs given 
the compliance costs and incentives under the application of different 
emission rate standards across affected EGUs in a State;
    (B) A projection showing how generation is expected to shift 
between affected EGUs and across affected EGUs and non-affected EGUs 
over time;
    (C) Assumptions regarding the availability and anticipated use of 
the MWh of electricity generation or electricity savings from eligible 
resources that can be issued ERCs;
    (D) The specific calculation (or assumption) of how eligible 
resource MWh of electricity generation or savings are being used in the 
projection to adjust the reported CO2 emission rate of 
affected EGUs;
    (E) If a state plan provides for the ability of renewable energy 
resources located in states with mass-based plans to be issued ERCs, 
consideration in the projection that such resources must meet 
geographic eligibility requirements, consistent with Sec.  60.5800(a); 
and
    (F) Any other applicable assumptions used in the projection.
    (iii) If a plan establishes mass-based emission standards for 
affected EGUs that cumulatively do not exceed the State's EPA-specified 
mass CO2 emission goal, then no additional demonstration is 
required beyond inclusion of the emission standards in the plan.
    (iv) If a plan applies mass-based emission standards to individual 
affected EGUs that cumulatively exceed the State's EPA-specified mass 
CO2 emission goal, then you must include a demonstration 
that your mass-based emission program will be designed such that 
compliance by affected EGUs would achieve the State mass-based 
CO2 emission goals. This demonstration includes the 
information listed in paragraph (a)(5)(v) of this section.
    (v) Your plan demonstration to be included in your plan submittal, 
if applicable, must include the information listed in paragraphs 
(a)(5)(v)(A) through (L) of this section.
    (A) A summary of each affected EGU's anticipated future operation 
characteristics, including:
    (1) Annual generation;
    (2) CO2 emissions;
    (3) Fuel use, fuel prices (when applicable), fuel carbon content;
    (4) Fixed and variable operations and maintenance costs (when 
applicable);
    (5) Heat rates; and
    (6) Electric generation capacity and capacity factors.
    (B) An identification of any planned new electric generating 
capacity.
    (C) Analytic treatment of the potential for building unplanned new 
electric generating capacity.
    (D) A timeline for implementation of EGU-specific actions (if 
applicable).
    (E) All wholesale electricity prices.
    (F) A geographic representation appropriate for capturing impacts 
and/or changes in the electric system.
    (G) A time period of analysis, which must extend through at least 
2031.
    (H) An anticipated electricity demand forecast (MWh load and MW 
peak demand) at the State and regional level, including the source and 
basis for these estimates, and, if appropriate, justification and 
documentation of underlying assumptions that inform the development of 
the demand forecast (e.g., annual economic and demand growth rate or 
population growth rate).
    (I) A demonstration that each emission standard included in your 
plan meets the requirements of Sec.  60.5775.
    (J) Any ERC or emission allowance prices, when applicable.
    (K) An identification of planning reserve margins.
    (L) Any other applicable assumptions used in the projection.
    (6) If your plan relies upon State measures, in addition to or in 
lieu of the emission standards required by paragraph Sec.  
60.5740(a)(2), the final State plan submittal must include the 
information under paragraphs (a)(5)(v) and (a)(6)(i) through (v) of 
this section.
    (i) You must include a description of all the State measures the 
State will rely upon to achieve the applicable CO2 emission 
goals required under Sec.  60.5855(e), the projected impacts of the 
State measures over time, the applicable State laws or regulations 
related to such measures, and identification of parties or entities 
subject to or implementing such State measures.
    (ii) You must include the schedule and milestones for the 
implementation of the State measures. If the State measures in your 
plan submittal rely upon measures that do not have a direct effect on 
the CO2 emissions measured at an affected EGU's stack, you 
must also demonstrate how the minimum emission, monitoring and 
verification (EM&V) requirements listed under Sec.  60.5795 that apply 
to those programs and projects will be met.
    (iii) You must demonstrate that federally enforceable emission 
standards for affected EGUs in conjunction with any State measures 
relied upon for your plan, are sufficient to achieve the mass-based 
CO2 emission goal for the interim period, each interim step 
in that interim period, the final period, and each final reporting 
period. In addition, you must demonstrate that each emission standard 
included in your plan meets the requirements of Sec.  60.5775 and each 
State measure included in your plan submittal meets the requirements of 
Sec.  60.5780.
    (iv) You must include a CO2 performance projection of 
your State measures that shows how the measures, whether alone or in 
conjunction with any federally enforceable CO2 emission 
standards for affected EGUs, will result in the achievement of the 
future CO2 performance at affected EGUs. Elements of this 
projection must include those specified in paragraph (a)(5)(v) of this 
section, as applicable, and the following for the interim period and 
the final period:

[[Page 64946]]

    (A) A baseline demand and supply forecast as well as the underlying 
assumptions and data sources of each forecast;
    (B) The magnitude of energy and emission impacts from all measures 
included in the plan and applicable assumptions;
    (C) An identification of State-enforceable measures with 
electricity savings and RE generation, in MWh, expected for individual 
and collective measures and any assumptions related to the 
quantification of the MWh, as applicable.
    (7) Your plan submittal must include a demonstration that the 
reliability of the electrical grid has been considered in the 
development of your plan.
    (8) Your plan submittal must include a timeline with all the 
programmatic milestone steps the State intends to take between the time 
of the State plan submittal and January 1, 2022 to ensure the plan is 
effective as of January 1, 2022.
    (9) Your plan submittal must adequately demonstrate that your State 
has the legal authority (e.g., through regulations or legislation) and 
funding to implement and enforce each component of the State plan 
submittal, including federally enforceable emission standards for 
affected EGUs, and State measures as applicable.
    (10) Your State plan submittal must demonstrate that each interim 
step goal required under Sec.  60.5855(c), will be met and include in 
its supporting documentation, if applicable, a description of the 
analytic process, tools, methods, and assumptions used to make this 
demonstration.
    (11) Your plan submittal must include certification that a hearing 
required under Sec.  60.23(c)(1) on the State plan was held, a list of 
witnesses and their organizational affiliations, if any, appearing at 
the hearing, and a brief written summary of each presentation or 
written submission, pursuant to the requirements of Sec.  60.23(d) and 
(f).
    (12) Your plan submittal must include documentation of any 
conducted community outreach and community involvement, including 
engagement with vulnerable communities.
    (13) Your plan submittal must include supporting material for your 
plan including:
    (i) Materials demonstrating the State's legal authority and funding 
to implement and enforce each component of its plan, including 
emissions standards and/or State measures that the plan relies upon;
    (ii) Materials supporting that the CO2 emission 
performance rates or CO2 emission goals will be achieved by 
affected EGUs identified under the plan, according to paragraph (a)(3) 
of this section;
    (iii) Materials supporting any calculations for CO2 
emission goals calculated according to Sec.  60.5855, if applicable; 
and
    (iv) Any other materials necessary to support evaluation of the 
plan by the EPA.
    (b) You must submit your final plan to the EPA electronically 
according to Sec.  60.5875.


Sec.  60.5750  Can I work with other States to develop a multi-State 
plan?

    A multi-State plan must include all the required elements for a 
plan specified in Sec.  60.5740(a). A multi-State plan must meet the 
requirements of paragraphs (a) and (b) of this section.
    (a) The multi-State plan must demonstrate that all affected EGUs in 
all participating States will meet the CO2 emission 
performance rates listed in Table 1 of this subpart or an equivalent 
CO2 emission goal according to paragraphs (a)(1) or (2) of 
this section. States may only follow the procedures in (a)(1) or (2) if 
they have functionally equivalent requirements meeting Sec.  60.5775 
and Sec.  60.5790 included in their plans.
    (1) For States electing to demonstrate performance with a 
CO2 emission rate-based goal, the CO2 emission 
goals identified in the plan according to Sec.  60.5855 will be an 
adjusted weighted (by net energy output) average lbs CO2/MWh 
emission rate to be achieved by all affected EGUs in the multi-State 
area during the plan periods; or
    (2) For States electing to demonstrate performance with a 
CO2 emission mass-based goal, the CO2 emission 
goals identified in the multi-State plan according to Sec.  60.5855 
will be total mass CO2 emissions by all affected EGUs in the 
multi-State area during the plan periods, representing the sum of all 
individual mass CO2 goals for states participating in the 
multi-state plan.
    (b) Options for submitting a multi-State plan include the 
following:
    (1) States participating in a multi-State plan may submit one 
multi-State plan submittal on behalf of all participating States. The 
joint submittal must be signed electronically, according to Sec.  
60.5875, by authorized officials for each of the States participating 
in the multi-State plan. In this instance, the joint submittal will 
have the same legal effect as an individual submittal for each 
participating State. The joint submittal must address plan components 
that apply jointly for all participating States and components that 
apply for each individual State in the multi-State plan, including 
necessary State legal authority to implement the plan, such as State 
regulations and statutes.
    (2) States participating in a multi-State plan may submit a single 
plan submittal, signed by authorized officials from each participating 
State, which addresses common plan elements. Each participating State 
must, in addition, provide individual plan submittals that address 
State-specific elements of the multi-State plan.
    (3) States participating in a multi-State plan may separately make 
individual submittals that address all elements of the multi-State 
plan. The plan submittals must be materially consistent for all common 
plan elements that apply to all participating States, and also must 
address individual State-specific aspects of the multi-State plan. Each 
individual State plan submittal must address all required plan 
components in Sec.  60.5740.
    (c) A State may elect to participate in more than one multi-State 
plan. If your State elects to participate in more than one multi-State 
plan then you must identify in the State plan submittal required under 
Sec.  60.5745, the subset of affected EGUs that are subject to the 
specific multi-State plan or your State's individual plan. An affected 
EGU can only be subject to one plan.
    (d) A State may elect to allow its affected EGUs to interact with 
affected EGUs in other States through mass-based trading programs or a 
rate-based trading program without entering into a formal multi-State 
plan allowed for under this section, so long as such programs are part 
of an EPA-approved state plan and meet the requirements of paragraphs 
(d)(1) and (2) of this section, as applicable.
    (1) For States that elect to do mass-based trading under this 
option the State must indicate in its plan that its emission budget 
trading program will be administered using an EPA-approved (or EPA-
administered) emission and allowance tracking system.
    (2) For States that elect to use a rate-based trading program which 
allows the affected EGUs to use ERCs from other State rate-based 
trading programs, the plan must require affected EGUs within their 
State to comply with emission standards equal to the sub-category 
CO2 emission performance rates in Table 1 of this subpart.


Sec.  60.5760  What are the timing requirements for submitting my plan?

    (a) You must submit a final plan with the information required 
under Sec.  60.5745 by September 6, 2016, unless you are submitting an 
initial submittal,

[[Page 64947]]

allowed under Sec.  60.5765, in lieu of a final State plan submittal, 
according to paragraph (b) of this section.
    (b) For States seeking a two year extension for a final plan 
submittal, you must include the information in Sec.  60.5765(a) in an 
initial submittal by September 6, 2016, to receive an extension to 
submit your final State plan submittal by September 6, 2018.
    (c) You must submit all information required under paragraphs (a) 
and (b) of this section according to the electronic reporting 
requirements in Sec.  60.5875.


Sec.  60.5765  What must I include in an initial submittal if 
requesting an extension for a final plan submittal?

    (a) You must sufficiently demonstrate that your State is able to 
undertake steps and processes necessary to timely submit a final plan 
by the extended date of September 6, 2018, by addressing the following 
required components in an initial submittal by September 6, 2016, if 
requesting an extension for a final plan submittal:
    (1) An identification of final plan approach or approaches under 
consideration and a description of progress made to date on the final 
plan components;
    (2) An appropriate explanation of why the State requires additional 
time to submit a final plan by September 6, 2018; and
    (3) A demonstration or description of the opportunity for public 
comment on the initial submittal and meaningful engagement with 
stakeholders, including vulnerable communities, during the time in 
preparation of the initial submittal and the plans for engagement 
during development of the final plan.
    (b) You must submit an initial submittal allowed in paragraph (a) 
of this section, information required under paragraph (c) of this 
section (only if a State elects to submit an initial submittal to 
request an extension for a final plan submittal), and a final State 
plan submittal according to Sec.  60.5870. If a State submits an 
initial submittal, an extension for a final State plan submittal is 
considered granted and a final State plan submittal is due according to 
Sec.  60.5760(b) unless a State is notified within 90 days of the EPA 
receiving the initial submittal that the EPA finds the initial 
submittal does not meet the requirements listed in paragraph (a) of 
this section. If the EPA notifies the State that the initial submittal 
does not meet such requirements, the EPA will also notify the State 
that it has failed to submit the final plan required by September 6, 
2016.
    (c) If an extension for submission of a final plan has been 
granted, you must submit a progress report by September 6, 2017. The 
2017 report must include the following:
    (1) A summary of the status of each component of the final plan, 
including an update from the 2016 initial submittal and a list of which 
final plan components are not complete.
    (2) A commitment to a plan approach (e.g., single or multi-State, 
rate-based or mass-based emission performance level, rate-based or 
mass-based emission standards), including draft or proposed legislation 
and/or regulations.
    (3) An updated comprehensive roadmap with a schedule and milestones 
for completing the final plan, including any updates to community 
engagement undertaken and planned.


Sec.  60.5770  What schedules, performance periods, and compliance 
periods must I include in my plan?

    (a) The affected EGUs covered by your plan must meet the 
CO2 emission requirements required under Sec.  60.5855 for 
the interim period, interim steps, and the final reporting periods 
according to paragraph (b) of this section. You must also include in 
your plan compliance periods for each affected EGU regulated under the 
plan according to paragraphs (c) and (d) of this section.
    (b) Your plan must require your affected EGUs to achieve each 
CO2 emission performance rate or CO2 emission 
goal, as applicable, required under Sec.  60.5855 over the periods 
according to paragraphs (b)(1) through (3) of this section.
    (1) The interim period.
    (2) Each interim step.
    (3) Each final reporting period.
    (c) The emission standards for affected EGUs regulated under the 
plan must include the following compliance periods:
    (1) For the interim period, affected EGUs must have emission 
standards that have compliance periods that are no longer than each 
interim step and are imposed for the entirety of the interim step 
either alone or in combination.
    (2) For the final period, affected EGUs must have emission 
standards that have compliance periods that are no longer than each 
final reporting period and are imposed for the entirety of the final 
reporting period either alone or in combination.
    (3) Compliance periods for each interim step and each final 
reporting period may take forms shorter than specified in this 
regulation, provided the schedules of compliance collectively end on 
the same schedule as each interim step and final reporting period.
    (d) If your plan relies upon State measures in lieu of or in 
addition to emission standards for affected EGUs regulated under the 
plan, then the performance periods must be identical to the compliance 
periods for affected EGUs listed in paragraphs (c)(1) through (3) of 
this section.


Sec.  60.5775  What emission standards must I include in my plan?

    (a) Emission standard(s) for affected EGUs included under your plan 
must be demonstrated to be quantifiable, verifiable, non-duplicative, 
permanent, and enforceable with respect to each affected EGU. The plan 
submittal must include the methods by which each emission standard 
meets each of the following requirements in paragraphs (b) through (f) 
of this section.
    (b) An affected EGU's emission standard is quantifiable if it can 
be reliably measured in a manner that can be replicated.
    (c) An affected EGU's emission standard is verifiable if adequate 
monitoring, recordkeeping and reporting requirements are in place to 
enable the State and the Administrator to independently evaluate, 
measure, and verify compliance with the emission standard.
    (d) An affected EGU's emission standard is non-duplicative with 
respect to a State plan if it is not already incorporated as an 
emission standard in another State plan unless incorporated in multi-
State plan.
    (e) An affected EGU's emission standard is permanent if the 
emission standard must be met for each compliance period, unless it is 
replaced by another emission standard in an approved plan revision, or 
the State demonstrates in an approvable plan revision that the emission 
reductions from the emission standard are no longer necessary for the 
State to meet its State level of performance.
    (f) An affected EGU's emission standard is enforceable if:
    (1) A technically accurate limitation or requirement and the time 
period for the limitation or requirement are specified;
    (2) Compliance requirements are clearly defined;
    (3) The affected EGUs responsible for compliance and liable for 
violations can be identified;
    (4) Each compliance activity or measure is enforceable as a 
practical matter; and
    (5) The Administrator, the State, and third parties maintain the 
ability to enforce against violations (including if an affected EGU 
does not meet its emission standard based on its

[[Page 64948]]

emissions, its allowances if it is subject to a mass-based emission 
standard, or its ERCs if it is subject to a rate-based emission 
standard) and secure appropriate corrective actions, in the case of the 
Administrator pursuant to CAA sections 113(a)-(h), in the case of a 
State, pursuant to its plan, State law or CAA section 304, as 
applicable, and in the case of third parties, pursuant to CAA section 
304.


Sec.  60.5780  What State measures may I rely upon in support of my 
plan?

    You may rely upon State measures in support of your plan that are 
not emission standard(s) on affected EGUs, provided those State 
measures meet the requirements in paragraph (a) of this section.
    (a) Each State measure is quantifiable, verifiable, non-
duplicative, permanent, and enforceable with respect to each affected 
entity (e.g., entities other than affected EGUs with no federally 
enforceable obligations under a State plan), and your plan supporting 
materials include the methods by which each State measure meets each of 
the following requirements in paragraphs (a)(1) through (5) of this 
section.
    (1) A State measure is quantifiable with respect to an affected 
entity if it can be reliably measured in a manner that can be 
replicated.
    (2) A State measure is verifiable with respect to an affected 
entity if adequate monitoring, recordkeeping and reporting requirements 
are in place to enable the State to independently evaluate, measure, 
and verify compliance with the State measure.
    (3) A State measure is non-duplicative with respect to an affected 
entity if it is not already incorporated as a State measure or an 
emission standard in another State plan or State plan supporting 
material unless incorporated in a multi-State plan.
    (4) A State measure is permanent with respect to an affected entity 
if the State measure must be met for at least each compliance period, 
or unless either it is replaced by another State measure in an approved 
plan revision, or the State demonstrates in an approved plan revision 
that the emission reductions from the State measure are no longer 
necessary for the State's affected EGUs to meet their mass-based 
CO2 emission goal.
    (5) A State measure is enforceable against an affected entity if:
    (i) A technically accurate limitation or requirement and the time 
period for the limitation or requirement are specified;
    (ii) Compliance requirements are clearly defined;
    (iii) The affected entities responsible for compliance and liable 
for violations can be identified;
    (iv) Each compliance activity or measure is enforceable as a 
practical matter; and
    (v) The State maintains the ability to enforce violations and 
secure appropriate corrective actions.
    (b) [Reserved]


Sec.  60.5785  What is the procedure for revising my plan?

    (a) EPA-approved plans can be revised only with approval by the 
Administrator. The Administrator will approve a plan revision if it is 
satisfactory with respect to the applicable requirements of this 
subpart and any applicable requirements of subpart B of this part, 
including the requirement in Sec.  60.5745(a)(3) to demonstrate 
achievement of the CO2 emission performance rates or 
CO2 emission goals in Sec.  60.5855. If one (or more) of the 
elements of the plan set in Sec.  60.5740 require revision with respect 
to achieving the CO2 emission performance rates or 
CO2 emission goals in Sec.  60.5855, a request must be 
submitted to the Administrator indicating the proposed revisions to the 
plan to ensure the CO2 emission performance rates or 
CO2 emission goals are met. In addition, the following 
provisions in paragraphs (b) through (d) of this section may apply.
    (b) You may submit revisions to a plan to adjust CO2 
emission goals according to Sec.  60.5855(d).
    (c) If your State is required to submit a notification according to 
Sec.  60.5870(d) indicating a triggering of corrective measures as 
described in Sec.  60.5740(a)(2)(i) and your plan does not already 
include corrective measures to be implemented if triggered, you must 
revise your State plan to include corrective measures to be 
implemented. The corrective measures must ensure achievement of the 
CO2 emission performance rates or State CO2 
emission goal. Additionally, the corrective measures must achieve 
additional CO2 emission reductions to offset any 
CO2 emission performance shortfall relative to the overall 
interim period or final period CO2 emission performance rate 
or State CO2 emission goal. The State plan revision 
submission must explain how the corrective measures both make up for 
the shortfall and address the State plan deficiency that caused the 
shortfall. The State must submit the revised plan and explanation to 
the EPA within 24 months after submitting the State report required in 
Sec.  60.5870(a) indicating the CO2 emission performance 
deficiency in lieu of the requirements of Sec.  60.28(a). The State 
must implement corrective measures within 6 months of the EPA's 
approval of a plan revision adding them. The shortfall must be made up 
as expeditiously as practicable.
    (d) If your plan relies upon State measures, your backstop is 
triggered under Sec.  60.5740(a)(3)(i), and your State measures plan 
backstop does not include a mechanism to make up the shortfall, you 
must revise your backstop emission standards to make up the shortfall. 
The shortfall must be made up as expeditiously as practicable.
    (e) Reliability Safety Valve:
    (1) In order to trigger a reliability safety valve, you must notify 
the EPA within 48 hours of an unforeseen, emergency situation that 
threatens reliability, such that your State will need a short-term 
modification of emission standards under a State plan for a specified 
affected EGU or EGUs. The EPA will consider the notification in Sec.  
60.5870(g)(1) to be an approved short-term modification to the State 
plan without needing to go through the full State plan revision process 
if the State provides a second notification to the EPA within seven 
days of the first notification. The short-term modification under a 
reliability safety valve allows modification to emission standards 
under the State plan for an affected EGU or EGUs for an initial period 
of up to 90 days. During that period of time, the affected EGU or EGUs 
will need to comply with the modified emission standards identified in 
the initial notification required under Sec.  60.5870(g)(1) or amended 
in the second notification required under Sec.  60.5870(g)(2). For the 
duration of the up to 90-day short-term modification, the 
CO2 emissions of the affected EGU or EGUs that exceed their 
obligations under the originally approved State plan will not be 
counted against the State's CO2 emission performance rate or 
CO2 emission goal. The EPA reserves the right to review any 
such notification required under Sec.  60.5870(g), and, in the event 
that the EPA finds such notification is improper, the EPA may disallow 
the short-term modification and affected EGUs must continue to operate 
under the approved State plan emission standards. As described more 
fully in Sec.  60.5870(g)(3), at least seven days before the end of the 
initial 90-day reliability safety valve period, the State must notify 
the appropriate EPA regional office whether the reliability concern has 
been addressed and the affected EGU or EGUs can resume meeting the 
original emission standards established in the State plan prior to the 
short-term modification or whether a

[[Page 64949]]

serious, ongoing reliability issue necessitates the affected EGU or 
EGUs emitting beyond the amount allowed under the State plan.
    (2) Plan revisions submitted pursuant to Sec.  60.5870(g)(3) must 
meet the requirements for State plan revisions under Sec.  60.5785(a).


Sec.  60.5790  What must I do to meet my plan obligations?

    (a) To meet your plan obligations, you must demonstrate that your 
affected EGUs are complying with their emission standards as specified 
in Sec.  60.5740, and you must demonstrate that the emission standards 
on affected EGUs, alone or in conjunction with any State measures, are 
resulting in achievement of the CO2 emission performance 
rates or statewide CO2 emission goals by affected EGUs using 
the procedures in paragraphs (b) through (d) of this section. If your 
plan requires the use of allowances for your affected EGUs to comply 
with their mass-based emission standards, you must follow the 
requirements under paragraph (b) of this section and Sec.  60.5830. If 
your plan requires the use of ERCs for your affected EGUs to comply 
with their rate-based emission standards, you must follow the 
requirements under paragraphs (c) and (d) of this section and 
Sec. Sec.  60.5795 through 60.5805.
    (b) If you submit a plan that sets a mass-based emission trading 
program for your affected EGUs, the State plan must include emission 
standards and requirements that specify the allowance system, related 
compliance requirements and mechanisms, and the emission budget as 
appropriate. These requirements must include those listed in paragraphs 
(b)(1) through (5) of this section.
    (1) CO2 emission monitoring, reporting, and 
recordkeeping requirements for affected EGUs.
    (2) Requirements for State allocation of allowances consistent with 
Sec.  60.5815.
    (3) Requirements for tracking of allowances, from issuance through 
submission for compliance, consistent with Sec.  60.5820.
    (4) The process for affected EGUs to demonstrate compliance 
(allowance ``true-up'' with reported CO2 emissions) 
consistent with Sec.  60.5825.
    (5) Requirements that address potential increased CO2 
emissions from new sources, beyond the emissions expected from new 
sources if affected EGUs were given emission standards in the form of 
the subcategory-specific CO2 emission performance rates. You 
may meet this requirement by requiring one of the options under 
paragraphs (b)(5)(i) through (iii) of this section.
    (i) You may include, as part of your plan's supporting 
documentation, requirements enforceable as a matter of State law 
regulating CO2 emissions from EGUs covered by subpart TTTT 
of this part under the mass-based CO2 goal plus new source 
CO2 emission complement applicable to your State in Table 4 
of this subpart. If you choose this option, the term ``mass-based 
CO2 goal plus new source CO2 emission 
complement'' shall apply rather than ``CO2 mass-based goal'' 
and the term ``CO2 emission goal'' shall include ``mass-
based CO2 goal plus new source CO2 emission 
complement'' in these emission guidelines.
    (ii) You may include requirements in your State plan for emission 
budget allowance allocation methods that align incentives to generate 
to affected EGUs or EGUs covered by subpart TTTT of this part that 
result in the affected EGUs meeting the mass-based CO2 
emission goal;
    (iii) You may submit for the EPA's approval, an equivalent method 
which requires affected EGUs to meet the mass-based CO2 
emission goal. The EPA will evaluate the approvability of such an 
alternative method on a case by case basis.
    (c) If you submit a plan that sets rate-based emission standards on 
your affected EGUs, to meet the requirements of Sec.  60.5775, you must 
follow the requirements in paragraphs (c)(1) through (4) of this 
section.
    (1) You must require the owner or operator of each affected EGU 
covered by your plan to calculate an adjusted CO2 emission 
rate to demonstrate compliance with its emission standard by factoring 
stack emissions and any ERCs into the following equation:
[GRAPHIC] [TIFF OMITTED] TR23OC15.005


Where:
CO2 emission rate = An affected EGU's adjusted 
CO2 emission rate that will be used to determine 
compliance with the applicable CO2 emission standard.
MCO2 = Measured CO2 mass in units of pounds 
(lbs) summed over the compliance period for an affected EGU.
MWhop = Total net energy output over the compliance 
period for an affected EGU in units of MWh.
MWhERC = ERC replacement generation for an affected EGU 
in units of MWh (ERCs are denominated in whole integers as specified 
in paragraph (d) of this section).

    (2) Your plan must specify that an ERC qualifies for the compliance 
demonstration specified in paragraph (c)(1) of this section if the ERC 
meets the requirements of paragraphs (c)(2)(i) through (iv) of this 
section.
    (i) An ERC must have a unique serial number.
    (ii) An ERC must represent one MWh of actual energy generated or 
saved with zero associated CO2 emissions.
    (iii) An ERC must only be issued to an eligible resource that meets 
the requirements of Sec.  60.5800 or to an affected EGU that meets the 
requirements of Sec.  60.5795 and must only be issued by a State or its 
State agent through an EPA-approved ERC tracking system that meets the 
requirements of Sec.  60.5810, or by the EPA through an EPA-
administered tracking system.
    (iv) An ERC must be surrendered and retired only once for purpose 
of compliance with this regulation through an EPA-approved ERC tracking 
system that meets the requirements of Sec.  60.5810, or by the EPA 
through an EPA-administered tracking system.
    (3) Your plan must specify that an ERC does not qualify for the 
compliance demonstration specified in paragraph (c)(1) of this section 
if it does not meet the requirements of paragraph (c)(2) of this 
section or if any State has used that same ERC for purposes of 
demonstrating achievement of a CO2 emission performance rate 
or CO2 emission goal. The plan must additionally include 
provisions that address requirements for revocation or adjustment that 
apply if an ERC issued by the State is subsequently found to have been 
improperly issued.
    (4) Your plan must include provisions either allowing for or 
restricting banking of ERCs between compliance periods for affected 
EGUs, and provisions not allowing any borrowing of any ERCs from future 
compliance periods by affected EGUs or eligible resources.

[[Page 64950]]

Emission Rate Credit Requirements


Sec.  60.5795  What affected EGUs qualify for generation of ERCs?

    (a) For issuance of ERCs to the affected EGUs that generate them, 
the plan must specify the accounting method and process for ERC 
issuance. For plans that require that affected EGUs meet a rate-based 
CO2 emission goal, where all affected EGUs have identical 
emission standards, you must specify the accounting method listed in 
paragraph (a)(1) of this section for generating ERCs. For plans that 
require affected EGUs to meet the CO2 emission performance 
rates or CO2 emission goals where affected EGUs have 
emission standards that are not equal for all affected EGUs, you must 
specify the accounting methods listed in paragraphs (a)(1) and (2) of 
this section for generating ERCs.
    (1) You must include the calculation method for determining the 
number of ERCs, denominated in MWh, that may be generated by and issued 
to an affected EGU that is in compliance with its emission standard, 
based on the difference between its emission standard and its reported 
CO2 emission rate for the compliance period; and
    (2) You must include the calculation method for determining the 
number of ERCs, denominated in MWh, that may be issued to affected EGUs 
that meet the definition of a stationary combustion turbine based on 
the displaced emissions from affected EGUs not meeting the definition 
of a stationary combustion turbine, resulting from the difference 
between its annualized net energy output in MWh for the calendar 
year(s) in the compliance period and its net energy output in MWh for 
the 2012 calendar year (January 1, 2012, through December 31, 2012).
    (b) Any ERCs generated through the method described as required by 
paragraph (a)(2) of this section must not be used by any affected EGUs 
other than steam generating units or IGCCs to demonstrate compliance as 
prescribed under Sec.  60.5790(c)(1).
    (c) Any states in a multi-State plan that requires the use of ERCs 
for affected EGUs to comply with their emission standards must have 
functionally equivalent requirements pursuant to paragraphs (a)(1) and 
(2) of this section for generating ERCs.


Sec.  60.5800  What other resources qualify for issuance of ERCs?

    (a) ERCs may only be issued for generation or savings produced on 
or after January 1, 2022, to a resource that qualifies as an eligible 
resource because it meets each of the requirements in paragraphs (a)(1) 
through (4) of this section.
    (1) Resources qualifying for eligibility only include resources 
that increased installed electrical generation nameplate capacity, or 
implemented new electrical savings measures, on or after January 1, 
2013. If a resource had a nameplate capacity uprate, ERCs may be issued 
only for the difference in generation between its uprated nameplate 
capacity and its nameplate capacity prior to the uprate. ERCs must not 
be issued for generation for an uprate that followed a derate that 
occurred on or after January 1, 2013. A resource that is relicensed or 
receives a license extension is considered existing capacity and is not 
an eligible resource, unless it receives a capacity uprate as a result 
of the relicensing process that is reflected in its relicensed permit. 
In such a case, only the difference in nameplate capacity between its 
relicensed permit and its prior permit is eligible to be issued ERCs.
    (2) The resource must be connected to, and deliver energy to or 
save electricity on, the electric grid in the contiguous United States.
    (3) The resource must be located in either:
    (i) A State whose affected EGUs are subject to rate-based emission 
standards pursuant to this regulation; or
    (ii) A State with a mass-based CO2 emission goal, and 
the resource can demonstrate (e.g., through a power purchase agreement 
or contract for delivery) that the electricity generated is delivered 
with the intention to meet load in a State with affected EGUs which are 
subject to rate-based emission standards pursuant to this regulation, 
and was treated as a generation resource used to serve regional load 
that included the State whose affected EGUs are subject to rate-based 
emission standards. Notwithstanding any other provision of paragraph 
(a)(4) of this section, the only type of eligible resource in the State 
with mass-based emission standards is renewable generating technologies 
listed in (a)(4)(i) of this section.
    (4) The resource falls into one of the following categories of 
resources:
    (i) Renewable electric generating technologies using one of the 
following renewable energy resources: Wind, solar, geothermal, hydro, 
wave, tidal;
    (ii) Qualified biomass;
    (iii) Waste-to-energy (biogenic portion only);
    (iv) Nuclear power;
    (v) A non-affected combined heat and power (CHP) unit, including 
waste heat power;
    (vi) A demand-side EE or demand-side management measure that saves 
electricity and is calculated on the basis of quantified ex post 
savings, not ``projected'' or ``claimed'' savings; or
    (vii) A category identified in a State plan and approved by the EPA 
to generate ERCs.
    (b) Any resource that does not meet the requirements of this 
subpart or an approved State plan cannot be issued ERCs for use by an 
affected EGU with its compliance demonstration required under Sec.  
60.5790(c).
    (c) ERCs may not be issued to or for any of the following:
    (1) New, modified, or reconstructed EGUs that are subject to 
subpart TTTT of this part, except CHP units that meet the requirements 
of a CHP unit under paragraph (a);
    (2) EGUs that do not meet the applicability requirements of 
Sec. Sec.  60.5845 and 60.5850, except CHP units that meet the 
requirements of a CHP unit under paragraph (a);
    (3) Measures that reduce CO2 emissions outside the 
electric power sector, including, for example, GHG offset projects 
representing emission reductions that occur in the forestry and 
agriculture sectors, direct air capture, and crediting of 
CO2 emission reductions that occur in the transportation 
sector as a result of vehicle electrification; and
    (4) Any measure not approved by the EPA for issuance of ERCs in 
connection with a specific State plan.
    (d) You must include the appropriate requirements in paragraphs 
(d)(1) through (3) of this section for an applicable eligible resource 
in your plan.
    (1) If qualified biomass is an eligible resource, the plan must 
include a description of why the proposed feedstocks or feedstock 
categories should qualify as an approach for controlling increases of 
CO2 levels in the atmosphere as well as the proposed 
valuation of biogenic CO2 emissions. In addition, for 
sustainably-derived agricultural and forest biomass feedstocks, the 
state plan must adequately demonstrate that such feedstocks 
appropriately control increases of CO2 levels in the 
atmosphere and methods for adequately monitoring and verifying these 
feedstock sources and related sustainability practices. For all 
qualified biomass feedstocks, plans must specify how biogenic 
CO2 emissions will be monitored and reported, and identify 
specific EM&V, tracking and auditing approaches.
    (2) If waste-to-energy is an eligible resource, the plan must 
assess both the

[[Page 64951]]

capacity to strengthen existing or implement new waste reduction, 
reuse, recycling and composting programs, and measures to minimize any 
potential negative impacts of waste-to-energy operations on such 
programs. Additionally the plan must include a method for determining 
the proportion of total MWh generation from a waste-to-energy facility 
that is eligible for use in adjusting a CO2 emission rate 
(i.e., that which is generated from biogenic materials).
    (3) If carbon capture and utilization (CCU) is an eligible resource 
in a plan, the plan must include analysis supporting how the proposed 
qualifying CCU technology results in CO2 emission mitigation 
from affected EGUs and provide monitoring, reporting, and verification 
requirements to demonstrate the reductions.
    (e) States and areas of Indian country that do not have any 
affected EGUs, and other countries, may provide ERCs to adjust 
CO2 emissions provided they are connected to the contiguous 
U.S. grid and meet the other requirements for eligibility and eligible 
resources and the issuance of ERCs included in these emission 
guidelines, except that such States and other countries may not provide 
ERCs from resources described in Sec.  60.5800(a)(4)(vi).


Sec.  60.5805  What is the process for the issuance of ERCs?

    If your plan uses ERCs your plan must include the process and 
requirements for issuance of ERCs to affected EGUs and eligible 
resources set forth in paragraphs (a) through (f) of this section.
    (a) Eligibility application. Your plan must require that, to 
receive ERCs, the owner or operator must submit an eligibility 
application to you that demonstrates that the requirements of your 
State plan as approved by the EPA as meeting Sec.  60.5795 (for an 
affected EGU) or Sec.  60.5800 (for an eligible resource) are met, and, 
in the case of an eligible resource, includes at a minimum:
    (1) Documentation that the eligibility application has only been 
submitted to you, or pursuant to an EPA-approved multi-State 
collaborative approach;
    (2) An EM&V plan that meets the requirements of the State plan as 
approved by the EPA as meeting Sec.  60.5830; and
    (3) A verification report from an independent verifier that 
verifies the eligibility of the eligible resource to be issued an ERC 
and that the EM&V plan meets the requirements of the State plan as 
approved by the EPA of meeting Sec.  60.5805.
    (b) Registration. Your plan must require that any affected EGU or 
eligible resource register with an ERC tracking system that meets the 
requirements of Sec.  60.5810 prior to the issuance of ERCs, and your 
plan must specify that you will only register an affected EGU or 
eligible resource after you approve its eligibility application and 
determine that the requirements of paragraph (a) of this section are 
met.
    (c) M&V reports. For an eligible resource registered pursuant to 
paragraph (b) of this section, your plan must require that, prior to 
issuance of ERCs by you, the owner or operator must submit the 
following:
    (1) An M&V report that meets the requirements of your State plan as 
approved by the EPA as meeting Sec.  60.5835; and
    (2) A verification report from an independent verifier that 
verifies that the requirements for the M&V report are met.
    (e) Issuance of ERCs. Your plan must specify your procedure for 
issuance of ERCs based on your review of an M&V report and verification 
report, and must require that ERCs be issued only on the basis of 
energy actually generated or saved, and that only one ERC is issued for 
each verified MWh.
    (f) Tracking system. Your plan must require that ERCs may only be 
issued through an ERC tracking system approved as part of the State 
plan.
    (g) Error adjustment. Your plan must include a mechanism to adjust 
the number of ERCs issued if any are issued based on error (clerical, 
formula input error, etc.).
    (h) Qualification status of an eligible resource. Your plan must 
include a mechanism to temporarily or permanently revoke the 
qualification status of an eligible resource, such that it can no 
longer be issued ERCs for at least the duration that it does not meet 
the requirements for being issued ERCs in your State plan.
    (i) Qualification status of an independent verifier--(1) 
Eligibility. To be an independent verifier, a person must be approved 
by the State as:
    (A) An independent verifier, as defined by this regulation; and
    (B) Eligible to verify eligibility applications, EM&V plans, and/or 
M&V reports per the requirements of the approved State plan as meeting 
Sec. Sec.  60.5830 and 60.5835 respectively.
    (2) Revocation of qualification. Your plan must include a mechanism 
to temporarily or permanently revoke the qualification status of an 
independent verifier, such that it can no longer verify eligibility 
applications, EM&V plans or M&V reports for at least the duration of 
the period it does not meet the requirements of your State plan.


Sec.  60.5810  What applicable requirements are there for an ERC 
tracking system?

    (a) Your plan must include provisions for an ERC tracking system, 
if applicable, that meets the following requirements:
    (1) It electronically records the issuance of ERCs, transfers of 
ERCs among accounts, surrender of ERCs by affected EGUs as part of a 
compliance demonstration, and retirement or cancellation of ERCs; and
    (2) It documents and provides electronic, internet-based public 
access to all information that supports the eligibility of eligible 
resources and issuance of ERCs and functionality to generate reports 
based on such information, which must include, for each ERC, an 
eligibility application, EM&V plan, M&V reports, and independent 
verifier verification reports.
    (b) If approved in a State plan, an ERC tracking system may provide 
for transfers of ERCs to or from another ERC tracking system approved 
in a State plan, or provide for transfers of ERCs to or from an EPA-
administered ERC tracking system used to administer a Federal plan.

Mass Allocation Requirements


Sec.  60.5815  What are the requirements for State allocation of 
allowances in a mass-based program?

    (a) For a mass-based trading program, a State plan must include 
requirements for CO2 allowance allocations according to 
paragraphs (b) through (f) of this section.
    (b) Provisions for allocation of allowances for each compliance 
period prior to the beginning of the compliance period.
    (c) Provisions for allocation of set-aside allowance, if 
applicable, must be established to ensure that the eligible resources 
must meet the same requirements for the ERC eligible resource 
requirements of Sec.  60.5800, and the State must include eligibility 
application and verification provisions equivalent to those for ERCs in 
Sec.  60.5805 and EM&V plan and M&V report provisions that meet the 
requirements of Sec.  60.5830 and Sec.  60.5835.
    (d) Provisions for adjusting allocations if the affected EGUs or 
eligible resources are incorrectly allocated CO2 allowances.
    (e) Provisions allowing for or restricting banking of allowances 
between compliance periods for affected EGUs.

[[Page 64952]]

    (f) Provisions not allowing any borrowing of allowances from future 
compliance periods by affected EGUs.


Sec.  60.5820  What are my allowance tracking requirements?

    (a) Your plan must include provisions for an allowance tracking 
system, if applicable, that meets the following requirements:
    (1) It electronically records the issuance of allowances, transfers 
of allowances among accounts, surrender of allowances by affected EGUs 
as part of a compliance demonstration, and retirement of allowances; 
and
    (2) It documents and provides electronic, internet-based public 
access to all information that supports the eligibility of eligible 
resources and issuance of set aside allowances, if applicable, and 
functionality to generate reports based on such information, which must 
include, for each set aside allowance, an eligibility application, EM&V 
plan, M&V reports, and independent verifier verification reports.
    (b) If approved in a State plan, an allowance tracking system may 
provide for transfers of allowances to or from another allowance 
tracking system approved in a State plan, or provide for transfers of 
allowances to or from an EPA-administered allowance tracking system 
used to administer a Federal plan.


Sec.  60.5825  What is the process for affected EGUs to demonstrate 
compliance in a mass-based program?

    (a) A plan must require an affected EGU's owners or operators to 
demonstrate compliance with emission standards in a mass based program 
by holding an amount of allowances not less than the tons of total 
CO2 emissions for such compliance period from the affected 
EGUs in the account for the affected EGU's emissions in the allowance 
tracking system required under Sec.  60.5820 during the applicable 
compliance period.
    (b) In a mass-based trading program a plan may allow multiple 
affected EGUs co-located at the same facility to demonstrate that they 
are meeting the applicable emission standards on a facility-wide basis 
by the owner or operator holding enough allowances to cover the 
CO2 emissions of all the affected EGUs at the facility.
    (1) If there are not enough allowances to cover the facility's 
affected EGUs' CO2 emissions then there must be provisions 
for determining the compliance status of each affected EGU located at 
that facility.
    (2) [Reserved]

Evaluation Measurement and Verification Plans and Monitoring and 
Verification Reports


Sec.  60.5830  What are the requirements for EM&V plans for eligible 
resources?

    (a) If your plan requires your affected EGUs to meet their emission 
standards in accordance with Sec.  60.5790, your plan must include 
requirements that any EM&V plan that is submitted in accordance with 
the requirements of Sec.  60.5805, in support of the issuance of an ERC 
or set-aside allowance that can be used in accordance with Sec.  
60.5790, must meet the EM&V criteria approved as part of your State 
plan.
    (b) Your plan must require each EM&V plan to include identification 
of the eligible resource.
    (c) Your plan must require that an EM&V plan must contain specific 
criteria, as applicable to the specific eligible resource.
    (1) For RE resources, your plan must include requirements 
discussing how the generation data will be physically measured on a 
continuous basis using, for example, a revenue-quality meter.
    (2) For demand-side EE, your plan must require that each EM&V plan 
quantify and verify electricity savings on a retrospective (ex-post) 
basis using industry best-practice EM&V protocols and methods that 
yield accurate and reliable measurements of electricity savings. Your 
plan must also require each EM&V plan to include an assessment of the 
independent factors that influence the electricity savings, the 
expected life of the savings (in years), and a baseline that represents 
what would have happened in the absence of the demand-side EE activity. 
Additionally, your plan must require that each EM&V plan include a 
demonstration of how the industry best-practices protocol and methods 
were applied to the specific activity, project, measure, or program 
covered in the EM&V plan, and include an explanation of why these 
protocols or methods were selected. EM&V plans must require eligible 
resources to demonstrate how all such best-practice approaches will be 
applied for the purposes of quantifying and verifying MWh results. 
Subsequent reporting of demand-side EE savings values must demonstrate 
and explain how the EM&V plan was followed.


Sec.  60.5835  What are the requirements for M&V reports for eligible 
resources?

    (a) If your plan requires your affected EGUs to meet their emission 
standards in accordance with Sec.  60.5790, your plan must include 
requirements that any M&V report that is submitted in accordance with 
the requirements of Sec.  60.5805, in support of the issuance of an ERC 
or set-aside allocation that can be used in accordance with Sec.  
60.5790, must meet the requirements of this section.
    (b) Your plan must require that each M&V report include the 
following:
    (1) For the first M&V report submitted, documentation that the 
energy-generating resources, energy-saving measures, or practices were 
installed or implemented consistent with the description in the 
approved eligibility application required in Sec.  60.5805(a).
    (2) Each M&V report submitted must include the following:
    (i) Identification of the time period covered by the M&V report;
    (ii) A description of how relevant quantification methods, 
protocols, guidelines, and guidance specified in the EM&V plan were 
applied during the reporting period to generate the quantified MWh of 
generation or MWh of energy savings;
    (iii) Documentation (including data) of the energy generation and/
or energy savings from any activity, project, measure, resource, or 
program addressed in the EM&V plan, quantified and verified in MWh for 
the period covered by the M&V report, in accordance with its EM&V plan, 
and based on ex-post energy generation or savings; and
    (iv) Documentation of any change in the energy generation or 
savings capability of the eligible resource from the description of the 
resource in the approved eligibility application during the period 
covered by the M&V report and the date on which the change occurred, 
and/or demonstration that the eligible resource continued to meet the 
requirements of Sec.  60.5800.

Applicability of Plans to Affected EGUs


Sec.  60.5840  Does this subpart directly affect EGU owners or 
operators in my State?

    (a) This subpart does not directly affect EGU owners or operators 
in your State. However, affected EGU owners or operators must comply 
with the plan that a State or States develop to implement the emission 
guidelines contained in this subpart.
    (b) If a State does not submit a final plan to implement and 
enforce the emission guidelines contained in this subpart, or an 
initial submittal for which an extension to submit a final plan can be 
granted, by September 6, 2016, or the EPA disapproves a final plan, the 
EPA will implement and enforce a Federal plan, as provided in Sec.  
60.5720, applicable to each affected EGU within the State that 
commenced

[[Page 64953]]

construction on or before January 8, 2014.


Sec.  60.5845  What affected EGUs must I address in my State plan?

    (a) The EGUs that must be addressed by your plan are any affected 
steam generating unit, IGCC, or stationary combustion turbine that 
commenced construction on or before January 8, 2014.
    (b) An affected EGU is a steam generating unit, IGCC, or stationary 
combustion turbine that meets the relevant applicability conditions 
specified in paragraph (b)(1) through (3) of this section, as 
applicable, except as provided in Sec.  60.5850.
    (1) Serves a generator or generators connected to a utility power 
distribution system with a nameplate capacity greater than 25 MW-net 
(i.e., capable of selling greater than 25 MW of electricity);
    (2) Has a base load rating (i.e., design heat input capacity) 
greater than 260 GJ/hr (250 MMBtu/hr) heat input of fossil fuel (either 
alone or in combination with any other fuel); and
    (3) Stationary combustion turbines that meet the definition of 
either a combined cycle or combined heat and power combustion turbine.


Sec.  60.5850  What EGUs are excluded from being affected EGUs?

    EGUs that are excluded from being affected EGUs are:
    (a) EGUs that are subject to subpart TTTT of this part as a result 
of commencing construction after the subpart TTTT applicability date;
    (b) Steam generating units and IGCCs that are, and always have 
been, subject to a federally enforceable permit limiting annual net-
electric sales to one-third or less of its potential electric output, 
or 219,000 MWh or less;
    (c) Non-fossil units (i.e., units that are capable of combusting 50 
percent or more non-fossil fuel) that have always historically limited 
the use of fossil fuels to 10 percent or less of the annual capacity 
factor or are subject to a federally enforceable permit limiting fossil 
fuel use to 10 percent or less of the annual capacity factor;
    (d) Stationary combustion turbines not capable of combusting 
natural gas (e.g., not connected to a natural gas pipeline);
    (e) EGUs that are combined heat and power units that have always 
historically limited, or are subject to a federally enforceable permit 
limiting, annual net-electric sales to a utility distribution system to 
no more than the greater of either 219,000 MWh or the product of the 
design efficiency and the potential electric output;
    (f) EGUs that serve a generator along with other steam generating 
unit(s), IGCC(s), or stationary combustion turbine(s) where the 
effective generation capacity (determined based on a prorated output of 
the base load rating of each steam generating unit, IGCC, or stationary 
combustion turbine) is 25 MW or less;
    (g) EGUs that are a municipal waste combustor unit that is subject 
to subpart Eb of this part; and
    (h) EGUs that are a commercial or industrial solid waste 
incineration unit that is subject to subpart CCCC of this part.


Sec.  60.5855  What are the CO2 emission performance rates 
for affected EGUs?

    (a) You must require, in your plan, emission standards on affected 
EGUs to meet the CO2 emission performance rates listed in 
Table 1 of this subpart except as provided in paragraph (b) of this 
section. In addition, you must set CO2 emission performance 
rates for the interim steps, according to paragraph (a)(1) of this 
section, except as provided in paragraph (b) of this section.
    (1) You must set CO2 emission performance rates for your 
affected EGUs to meet during the interim step periods on average and as 
applicable for the two subcategories of affected EGUs.
    (2) [Reserved]
    (b) You may elect to require your affected EGUs to meet emission 
standards that differ from the CO2 emission performance 
rates listed in Table 1 of this subpart, provided that you demonstrate 
that the affected EGUs in your State will collectively meet their 
CO2 emission performance rate by achieving statewide 
emission goals that are equivalent and no less stringent than the 
CO2 emission performance rates listed in Table 1, and 
provided that your equivalent statewide CO2 emission goals 
take one of the following forms:
    (1) Average statewide rate-based CO2 emission goals 
listed in Table 2 of this subpart, except as provided in paragraphs (c) 
and (d); or
    (2) Cumulative statewide mass-based CO2 emission goals 
listed in Table 3 of this subpart, except as provided in paragraphs (c) 
and (d) of this section.
    (c) If your plan meets CO2 emission goals listed in 
paragraphs (b)(1) or (2) of this section you must develop your own 
interim step goals and final reporting period goal for your affected 
EGUs to meet either on average (in the case of rate-based goals) or 
cumulatively (in the case of mass-based goals). Additionally the 
following applies if you develop your own goals:
    (1) The interim period and interim steps CO2 emission 
goals must be in the same form, either both rate (in units of pounds 
per net MWh) or both mass (in tons); and
    (2) You must set interim step goals that will either on average or 
cumulatively meet the State's interim period goal, as applicable to a 
rate-based or mass-based CO2 emission goal.
    (d) Your plan's interim period and final period CO2 
emission goals required to be met pursuant to paragraph (b)(1) or (2) 
of this section, may be changed in the plan only according to 
situations listed in paragraphs (d)(1) through (3) of this section. If 
a situation requires a plan revision, you must follow the procedures in 
Sec.  60.5785 to submit a plan revision.
    (1) If your plan implements CO2 emission goals, you may 
submit a plan or plan revision, allowed in Sec.  60.5785, to make 
corrections to them, subject to EPA's approval, as a result of changes 
in the inventory of affected EGUs; and
    (2) If you elect to require your affected EGUs to meet emission 
standards to meet mass-based CO2 emission goals in your 
plan, you may elect to incorporate, as a matter of state law, the mass 
emissions from EGUs that are subject to subpart TTTT of this part that 
are considered new affected EGUs under subpart TTTT of this part.
    (e) If your plan relies upon State measures in addition to or in 
lieu of emission standards, you must only use the mass-based goals 
allowed for in paragraph (b)(2) of this section to demonstrate that 
your affected EGUs are meeting the required emissions performance.
    (f) Nothing in this subpart precludes an affected EGU from 
complying with its emission standard or you from meeting your 
obligations under the State plan.


Sec.  60.5860  What applicable monitoring, recordkeeping, and reporting 
requirements do I need to include in my plan for affected EGUs?

    (a) Your plan must include monitoring for affected EGUs that is no 
less stringent than what is described in (a)(1) through (8) of this 
section.
    (1) The owner or operator of an affected EGU (or group of affected 
EGUs that share a monitored common stack) that is required to meet 
rate-based or mass-based emission standards must prepare a monitoring 
plan in accordance with the applicable provisions in Sec.  75.53(g) and 
(h) of this chapter, unless such a plan is already in place under 
another program that requires CO2 mass emissions to be 
monitored and reported according to part 75 of this chapter.
    (2) For rate-based emission standards, each compliance period shall 
include

[[Page 64954]]

only ``valid operating hours'' in the compliance period, i.e., full or 
partial unit (or stack) operating hours for which:
    (i) ``Valid data'' (as defined in Sec.  60.5880) are obtained for 
all of the parameters used to determine the hourly CO2 mass 
emissions (lbs). For the purposes of this subpart, substitute data 
recorded under part 75 of this chapter are not considered to be valid 
data; and
    (ii) The corresponding hourly net energy output value is also valid 
data (Note: For operating hours with no useful output, zero is 
considered to be a valid value).
    (3) For rate-based emission standards, the owner or operator of an 
affected EGU must measure and report the hourly CO2 mass 
emissions (lbs) from each affected unit using the procedures in 
paragraphs (a)(3)(i) through (vi) of this section, except as otherwise 
provided in paragraph (a)(4) of this section.
    (i) The owner or operator of an affected EGU must install, certify, 
operate, maintain, and calibrate a CO2 continuous emissions 
monitoring system (CEMS) to directly measure and record CO2 
concentrations in the affected EGU exhaust gases emitted to the 
atmosphere and an exhaust gas flow rate monitoring system according to 
Sec.  75.10(a)(3)(i) of this chapter. As an alternative to direct 
measurement of CO2 concentration, provided that the affected 
EGU does not use carbon separation (e.g., carbon capture and storage), 
the owner or operator of an affected EGU may use data from a certified 
oxygen (O2) monitor to calculate hourly average 
CO2 concentrations, in accordance with Sec.  
75.10(a)(3)(iii) of this chapter. However, when an O2 
monitor is used this way, it only quantifies the combustion 
CO2; therefore, if the EGU is equipped with emission 
controls that produce non-combustion CO2 (e.g., from sorbent 
injection), this additional CO2 must be accounted for, in 
accordance with section 3 of appendix G to part 75 of this chapter. If 
CO2 concentration is measured on a dry basis, the owner or 
operator of the affected EGU must also install, certify, operate, 
maintain, and calibrate a continuous moisture monitoring system, 
according to Sec.  75.11(b) of this chapter. Alternatively, the owner 
or operator of an affected EGU may either use an appropriate fuel-
specific default moisture value from Sec.  75.11(b) or submit a 
petition to the Administrator under Sec.  75.66 of this chapter for a 
site-specific default moisture value.
    (ii) For each ``valid operating hour'' (as defined in paragraph 
(a)(2) of this section), calculate the hourly CO2 mass 
emission rate (tons/hr), either from Equation F-11 in Appendix F to 
part 75 of this chapter (if CO2 concentration is measured on 
a wet basis), or by following the procedure in section 4.2 of Appendix 
F to part 75 of this chapter (if CO2 concentration is 
measured on a dry basis).
    (iii) Next, multiply each hourly CO2 mass emission rate 
by the EGU or stack operating time in hours (as defined in Sec.  72.2 
of this chapter), to convert it to tons of CO2. Multiply the 
result by 2,000 lbs/ton to convert it to lbs.
    (iv) The hourly CO2 tons/hr values and EGU (or stack) 
operating times used to calculate CO2 mass emissions are 
required to be recorded under Sec.  75.57(e) of this chapter and must 
be reported electronically under Sec.  75.64(a)(6), if required by a 
plan. The owner or operator must use these data, or equivalent data, to 
calculate the hourly CO2 mass emissions.
    (v) Sum all of the hourly CO2 mass emissions values from 
paragraph (a)(3)(ii) of this section over the entire compliance period.
    (vi) For each continuous monitoring system used to determine the 
CO2 mass emissions from an affected EGU, the monitoring 
system must meet the applicable certification and quality assurance 
procedures in Sec.  75.20 of this chapter and Appendices A and B to 
part 75 of this chapter.
    (4) The owner or operator of an affected EGU that exclusively 
combusts liquid fuel and/or gaseous fuel may, as an alternative to 
complying with paragraph (a)(3) of this section, determine the hourly 
CO2 mass emissions according to paragraphs (a)(4)(i) through 
(a)(4)(vi) of this section.
    (i) Implement the applicable procedures in appendix D to part 75 of 
this chapter to determine hourly EGU heat input rates (MMBtu/hr), based 
on hourly measurements of fuel flow rate and periodic determinations of 
the gross calorific value (GCV) of each fuel combusted. The fuel flow 
meter(s) used to measure the hourly fuel flow rates must meet the 
applicable certification and quality-assurance requirements in sections 
2.1.5 and 2.1.6 of appendix D to part 75 (except for qualifying 
commercial billing meters). The fuel GCV must be determined in 
accordance with section 2.2 or 2.3 of appendix D, as applicable.
    (ii) For each measured hourly heat input rate, use Equation G-4 in 
Appendix G to part 75 of this chapter to calculate the hourly 
CO2 mass emission rate (tons/hr).
    (iii) For each ``valid operating hour'' (as defined in paragraph 
(a)(2) of this section), multiply the hourly tons/hr CO2 
mass emission rate from paragraph (a)(4)(ii) of this section by the EGU 
or stack operating time in hours (as defined in Sec.  72.2 of this 
chapter), to convert it to tons of CO2. Then, multiply the 
result by 2,000 lbs/ton to convert it to lbs.
    (iv) The hourly CO2 tons/hr values and EGU (or stack) 
operating times used to calculate CO2 mass emissions are 
required to be recorded under Sec.  75.57(e) of this chapter and must 
be reported electronically under Sec.  75.64(a)(6), if required by a 
plan. You must use these data, or equivalent data, to calculate the 
hourly CO2 mass emissions.
    (v) Sum all of the hourly CO2 mass emissions values (lb) 
from paragraph (a)(4)(iii) of this section over the entire compliance 
period.
    (vi) The owner or operator of an affected EGU may determine site-
specific carbon-based F-factors (Fc) using Equation F-7b in 
section 3.3.6 of appendix F to part 75 of this chapter, and may use 
these Fc values in the emissions calculations instead of 
using the default Fc values in the Equation G-4 
nomenclature.
    (5) For both rate-based and mass-based standards, the owner or 
operator of an affected EGU (or group of affected units that share a 
monitored common stack) must install, calibrate, maintain, and operate 
a sufficient number of watt meters to continuously measure and record 
on an hourly basis net electric output. Measurements must be performed 
using 0.2 accuracy class electricity metering instrumentation and 
calibration procedures as specified under ANSI Standards No. C12.20. 
Further, the owner or operator of an affected EGU that is a combined 
heat and power facility must install, calibrate, maintain and operate 
equipment to continuously measure and record on an hourly basis useful 
thermal output and, if applicable, mechanical output, which are used 
with net electric output to determine net energy output. The owner or 
operator must use the following procedures to calculate net energy 
output, as appropriate for the type of affected EGU(s).
    (i) Determine Pnet the hourly net energy output in MWh. 
For rate-based standards, perform this calculation only for valid 
operating hours (as defined in paragraph (a)(2) of this section). For 
mass-based standards, perform this calculation for all unit (or stack) 
operating hours, i.e., full or partial hours in which any fuel is 
combusted.
    (ii) If there is no net electrical output, but there is mechanical 
or useful thermal output, either for a particular valid operating hour 
(for rate-based

[[Page 64955]]

applications), or for a particular operating hour (for mass-based 
applications), the owner or operator of the affected EGU must still 
determine the net energy output for that hour.
    (iii) For rate-based applications, if there is no (i.e., zero) 
gross electrical, mechanical, or useful thermal output for a particular 
valid operating hour, that hour must be used in the compliance 
determination. For hours or partial hours where the gross electric 
output is equal to or less than the auxiliary loads, net electric 
output shall be counted as zero for this calculation.
    (iv) Calculate Pnet for your affected EGU (or group of 
affected EGUs that share a monitored common stack) using the following 
equation. All terms in the equation must be expressed in units of MWh. 
To convert each hourly net energy output value reported under part 75 
of this chapter to MWh, multiply by the corresponding EGU or stack 
operating time.
[GRAPHIC] [TIFF OMITTED] TR23OC15.006


Where:
Pnet = Net energy output of your affected EGU for each 
valid operating hour (as defined in 60.5860(a)(2)) in MWh.
(Pe)ST = Electric energy output plus mechanical energy 
output (if any) of steam turbines in MWh.
(Pe)CT = Electric energy output plus mechanical energy 
output (if any) of stationary combustion turbine(s) in MWh.
(Pe)IE = Electric energy output plus mechanical energy 
output (if any) of your affected EGU's integrated equipment that 
provides electricity or mechanical energy to the affected EGU or 
auxiliary equipment in MWh.
(Pe)A = Electric energy used for any auxiliary loads in 
MWh.
(Pt)PS = Useful thermal output of steam (measured 
relative to SATP conditions, as applicable) that is used for 
applications that do not generate additional electricity, produce 
mechanical energy output, or enhance the performance of the affected 
EGU. This is calculated using the equation specified in paragraph 
(a)(5)(v) of this section in MWh.
(Pt)HR = Non-steam useful thermal output (measured 
relative to SATP conditions, as applicable) from heat recovery that 
is used for applications other than steam generation or performance 
enhancement of the affected EGU in MWh.
(Pt)IE = Useful thermal output (relative to SATP 
conditions, as applicable) from any integrated equipment is used for 
applications that do not generate additional steam, electricity, 
produce mechanical energy output, or enhance the performance of the 
affected EGU in MWh.
TDF = Electric Transmission and Distribution Factor of 0.95 for a 
combined heat and power affected EGU where at least on an annual 
basis 20.0 percent of the total gross or net energy output consists 
of electric or direct mechanical output and 20.0 percent of the 
total net energy output consist of useful thermal output on a 12-
operating month rolling average basis, or 1.0 for all other affected 
EGUs.

    (v) If applicable to your affected EGU (for example, for combined 
heat and power), you must calculate (Pt)PS using the 
following equation:
[GRAPHIC] [TIFF OMITTED] TR23OC15.007


Where:
Qm = Measured steam flow in kilograms (kg) (or pounds 
(lbs)) for the operating hour.
H = Enthalpy of the steam at measured temperature and pressure 
(relative to SATP conditions or the energy in the condensate return 
line, as applicable) in Joules per kilogram (J/kg) (or Btu/lb).
CF = Conversion factor of 3.6 x 10\9\ J/MWh or 3.413 x 10\6\ Btu/
MWh.

    (vi) For rate-based standards, sum all of the values of 
Pnet for the valid operating hours (as defined in paragraph 
(a)(2) of this section), over the entire compliance period. Then, 
divide the total CO2 mass emissions for the valid operating 
hours from paragraph (a)(3)(v) or (a)(4)(v) of this section, as 
applicable, by the sum of the Pnet values for the valid 
operating hours plus any ERC replacement generation (as shown in Sec.  
60.5790(c)), to determine the CO2 emissions rate (lb/net 
MWh) for the compliance period.
    (vii) For mass-based standards, sum all of the values of 
Pnet for all operating hours, over the entire compliance 
period.
    (6) In accordance with Sec.  60.13(g), if two or more affected EGUs 
implementing the continuous emissions monitoring provisions in 
paragraph (a)(2) of this section share a common exhaust gas stack and 
are subject to the same emissions standard, the owner or operator may 
monitor the hourly CO2 mass emissions at the common stack in 
lieu of monitoring each EGU separately. If an owner or operator of an 
affected EGU chooses this option, the hourly net electric output for 
the common stack must be the sum of the hourly net electric output of 
the individual affected EGUs and the operating time must be expressed 
as ``stack operating hours'' (as defined in Sec.  72.2 of this 
chapter).
    (7) In accordance with Sec.  60.13(g), if the exhaust gases from an 
affected EGU implementing the continuous emissions monitoring 
provisions in paragraph (a)(2) of this section are emitted to the 
atmosphere through multiple stacks (or if the exhaust gases are routed 
to a common stack through multiple ducts and you elect to monitor in 
the ducts), the hourly CO2 mass emissions and the ``stack 
operating time'' (as defined in Sec.  72.2 of this chapter) at each 
stack or duct must be monitored separately. In this case, the owner or 
operator of an affected EGU must determine compliance with an 
applicable emissions standard by summing the CO2 mass 
emissions measured at the individual stacks or ducts and dividing by 
the net energy output for the affected EGU.
    (8) Consistent with Sec.  60.5775 or Sec.  60.5780, if two or more 
affected EGUs serve a common electric generator, you must apportion the 
combined hourly net energy output to the individual affected EGUs 
according to the fraction of the total steam load contributed by each 
EGU. Alternatively, if the EGUs are identical, you may apportion the 
combined hourly net electrical load to the individual EGUs according to 
the fraction of the total heat input contributed by each EGU.
    (b) For mass-based standards, the owner or operator of an affected 
EGU must determine the CO2 mass emissions (tons) for the 
compliance period as follows:
    (1) For each operating hour, calculate the hourly CO2 
mass (tons) according to paragraph (a)(3) or (4) of this section, 
except that a complete data record is required, i.e., CO2 
mass emissions must be reported for each operating hour. Therefore, 
substitute data values recorded under part 75 of this chapter for 
CO2 concentration, stack gas flow rate, stack gas moisture 
content, fuel flow rate and/or GCV shall be used in the calculations; 
and
    (2) Sum all of the hourly CO2 mass emissions values over 
the entire compliance period.
    (3) The owner or operator of an affected EGU must install, 
calibrate, maintain, and operate a sufficient number of watt meters to 
continuously

[[Page 64956]]

measure and record on an hourly basis net electric output. Measurements 
must be performed using 0.2 accuracy class electricity metering 
instrumentation and calibration procedures as specified under ANSI 
Standards No. C12.20. Further, the owner or operator of an affected EGU 
that is a combined heat and power facility must install, calibrate, 
maintain and operate equipment to continuously measure and record on an 
hourly basis useful thermal output and, if applicable, mechanical 
output, which are used with net electric output to determine net energy 
output (Pnet). The owner or operator must calculate net 
energy output according to paragraphs (a)(5)(i)(A) and (B) of this 
section.
    (c) Your plan must require the owner or operator of each affected 
EGU covered by your plan to maintain the records, as described in 
paragraphs (b)(1) and (2) of this section, for at least 5 years 
following the date of each compliance period, occurrence, measurement, 
maintenance, corrective action, report, or record.
    (1) The owner or operator of an affected EGU must maintain each 
record on site for at least 2 years after the date of each compliance 
period, occurrence, measurement, maintenance, corrective action, 
report, or record, whichever is latest, according to Sec.  60.7. The 
owner or operator of an affected EGU may maintain the records off site 
and electronically for the remaining year(s).
    (2) The owner or operator of an affected EGU must keep all of the 
following records, in a form suitable and readily available for 
expeditious review:
    (i) All documents, data files, and calculations and methods used to 
demonstrate compliance with an affected EGU's emission standard under 
Sec.  60.5775.
    (ii) Copies of all reports submitted to the State under paragraph 
(c) of this section.
    (iii) Data that are required to be recorded by 40 CFR part 75 
subpart F.
    (iv) Data with respect to any ERCs generated by the affected EGU or 
used by the affected EGU in its compliance demonstration including the 
information in paragraphs (c)(2)(iv)(A) and (B) of this section.
    (A) All documents related to any ERCs used in a compliance 
demonstration, including each eligibility application, EM&V plan, M&V 
report, and independent verifier verification report associated with 
the issuance of each specific ERC.
    (B) All records and reports relating to the surrender and 
retirement of ERCs for compliance with this regulation, including the 
date each individual ERC with a unique serial identification number was 
surrendered and/or retired.
    (d) Your plan must require the owner or operator of an affected EGU 
covered by your plan to include in a report submitted to you at the end 
of each compliance period the information in paragraphs (d)(1) through 
(5) of this section.
    (1) Owners or operators of an affected EGU must include in the 
report all hourly CO2 emissions, for each affected EGU (or 
group of affected EGUs that share a monitored common stack).
    (2) For rate-based standards, each report must include:
    (i) The hourly CO2 mass emission rate values (tons/hr) 
and unit (or stack) operating times, (as monitored and reported 
according to part 75 of this chapter), for each valid operating hour in 
the compliance period;
    (ii) The net electric output and the net energy output 
(Pnet) values for each valid operating hour in the 
compliance period;
    (iii) The calculated CO2 mass emissions (lb) for each 
valid operating hour in the compliance period;
    (iv) The sum of the hourly net energy output values and the sum of 
the hourly CO2 mass emissions values, for all of the valid 
operating hours in the compliance period;
    (v) ERC replacement generation (if any), properly justified (see 
paragraph (c)(5) of this section); and
    (vi) The calculated CO2 mass emission rate for the 
compliance period (lbs/net MWh).
    (3) For mass-based standards, each report must include:
    (i) The hourly CO2 mass emission rate value (tons/hr) 
and unit (or stack) operating time, as monitored and reported according 
to part 75 of this chapter, for each unit or stack operating hour in 
the compliance period;
    (ii) The calculated CO2 mass emissions (tons) for each 
unit or stack operating hour in the compliance period;
    (iii) The sum of the CO2 mass emissions (tons) for all 
of the unit or stack operating hours in the compliance period;
    (iv) The net electric output and the net energy output 
(Pnet) values for each unit or stack operating hour in the 
compliance period; and
    (v) The sum of the hourly net energy output values for all of the 
unit or stack operating hours in the compliance period.
    (vi) Notwithstanding the requirements in paragraphs (c)(3)(i) 
through (c)(3)(iii) of this section, if the compliance period is a 
discrete number of calendar years (e.g., one year, three years), in 
lieu of reporting the information specified in those paragraphs, the 
owner or operator may report:
    (A) The cumulative annual CO2 mass emissions (tons) for 
each year of the compliance period, derived from the electronic 
emissions report for the fourth calendar quarter of that year, 
submitted to EPA under Sec.  75.64(a) of this chapter; and
    (B) The sum of the cumulative annual CO2 mass emissions 
values from paragraph (c)(3)(v)(A) of this section, if the compliance 
period includes multiple years.
    (4) For each affected EGU's compliance period, the report must also 
include the applicable emission standard and demonstration that it met 
the emission standard. An owner or operator must also include in the 
report the affected EGU's calculated emission performance as a 
CO2 emission rate or cumulative mass in units of the 
emission standard required in Sec. Sec.  60.5790(b) through (c) and 
60.5855, as applicable.
    (5) If the owner or operator of an affected EGU is complying with 
an emission standard by using ERCs, they must include in the report a 
list of all unique ERC serial numbers that were retired in the 
compliance period, and, for each ERC, the date an ERC was surrendered 
and retired and eligible resource identification information sufficient 
to demonstrate that it meets the requirements of Sec.  60.5800 and 
qualifies to be issued ERCs (including location, type of qualifying 
generation or savings, date commenced generating or saving, and date of 
generation or savings for which the ERC was issued).
    (6) If the owner or operator of an affected EGU is complying with 
an emission standard by using allowances, they must include in the 
report a list of all unique allowance serial numbers that were retired 
in the compliance period, and, for each allowance, the date an 
allowance was surrendered and retired and if the allowance was a set-
aside allowance the eligible resource identification information 
sufficient to demonstrate that it meets the requirements of Sec.  
60.5815(c) and qualifies to be issued set-aside allowances (including 
location, type of qualifying generation or savings, date commenced 
generating or saving, and date of generation or savings for which the 
allowance was issued).
    (e) The owner or operator of an affected EGU must follow any 
additional requirements for monitoring, recordkeeping and reporting in 
a plan that are required under Sec.  60.5745(a)(4), if applicable.

[[Page 64957]]

    (f) If an affected EGU captures CO2 to meet the 
applicable emission limit, the owner or operator must report in 
accordance with the requirements of 40 CFR part 98 subpart PP and 
either:
    (1) Report in accordance with the requirements of 40 CFR part 98 
subpart RR, if injection occurs on-site;
    (2) Transfer the captured CO2 to an EGU or facility that 
reports in accordance with the requirements of 40 CFR part 98 subpart 
RR, if injection occurs off-site; or
    (3) Transfer the captured CO2 to a facility that has 
received an innovative technology waiver from EPA pursuant to paragraph 
(g) of this section.
    (g) Any person may request the Administrator to issue a waiver of 
the requirement that captured CO2 from an affected EGU be 
transferred to a facility reporting under 40 CFR part 98 subpart RR. To 
receive a waiver, the applicant must demonstrate to the Administrator 
that its technology will store captured CO2 as effectively 
as geologic sequestration, and that the proposed technology will not 
cause or contribute to an unreasonable risk to public health, welfare, 
or safety. In making this determination, the Administrator shall 
consider (among other factors) operating history of the technology, 
whether the technology will increase emissions or other releases of any 
pollutant other than CO2, and permanence of the 
CO2 storage. The Administrator may test the system itself, 
or require the applicant to perform any tests considered by the 
Administrator to be necessary to show the technology's effectiveness, 
safety, and ability to store captured CO2 without release. 
The Administrator may grant conditional approval of a technology, the 
approval conditioned on monitoring and reporting of operations. The 
Administrator may also withdraw approval of the waiver on evidence of 
releases of CO2 or other pollutants. The Administrator will 
provide notice to the public of any application under this provision, 
and provide public notice of any proposed action on a petition before 
the Administrator takes final action.

Recordkeeping and Reporting Requirements


Sec.  60.5865  What are my recordkeeping requirements?

    (a) You must keep records of all information relied upon in support 
of any demonstration of plan components, plan requirements, supporting 
documentation, State measures, and the status of meeting the plan 
requirements defined in the plan for each interim step and the interim 
period. After 2029, States must keep records of all information relied 
upon in support of any continued demonstration that the final 
CO2 emission performance rates or CO2 emissions 
goals are being achieved.
    (b) You must keep records of all data submitted by the owner or 
operator of each affected EGU that is used to determine compliance with 
each affected EGU emissions standard or requirements in an approved 
State plan, consistent with the affected EGU requirements listed in 
Sec.  60.5860.
    (c) If your State has a requirement for all hourly CO2 
emissions and net generation information to be used to calculate 
compliance with an annual emissions standard for affected EGUs, any 
information that is submitted by the owners or operators of affected 
EGUs to the EPA electronically pursuant to requirements in Part 75 
meets the recordkeeping requirement of this section and you are not 
required to keep records of information that would be in duplicate of 
paragraph (b) of this section.
    (d) You must keep records at a minimum for 10 years, for the 
interim period, and 5 years, for the final period, from the date the 
record is used to determine compliance with an emissions standard, plan 
requirement, CO2 emission performance rate or CO2 
emissions goal. Each record must be in a form suitable and readily 
available for expeditious review.


Sec.  60.5870  What are my reporting and notification requirements?

    (a) In lieu of the annual report required under Sec.  60.25(e) and 
(f) of this part, you must report the information in paragraphs (b) 
through (f) of this section.
    (b) You must submit a report covering each interim step within the 
interim period and each of the final 2-calendar year periods due no 
later than July 1 of the year following the end of the period. The 
interim period reporting starts with a report covering interim step 1 
due no later than July 1, 2025. The final period reports start with a 
biennial report covering the first final reporting period (which is due 
by July 1, 2032), a 2-calendar year average of emissions or cumulative 
sum of emissions used to determine compliance with the final 
CO2 emission performance rate or CO2 emission 
goal (as applicable). The report must include the information in 
paragraphs (b)(1) through (4) of this section.
    (1) The report must include the emissions performance achieved by 
all affected EGUs during the reporting period, consistent with the plan 
approach according to Sec.  60.5745(a), and identification of whether 
each affected EGU is in compliance with its emission standard and 
whether the collective of all affected EGUs covered by the State are on 
schedule to meet the applicable CO2 emission performance 
rate or emission goal during the performance periods and compliance 
periods, as specified in the plan.
    (2) The report must include a comparison of the CO2 
emission performance rate or CO2 emission goal identified in 
the State plan for the applicable interim step period versus the actual 
average, cumulative, or adjusted CO2 emission performance 
(as applicable) achieved by all affected EGUs.
    (i) For interim step 3, you do not need to include a comparison 
between the applicable interim step 3 CO2 emission 
performance rate or emission goal; you must only submit the average, 
cumulative or adjusted CO2 emission performance (as 
applicable) of your affected EGUs during that period in units of your 
applicable CO2 emission performance rate or emission goal.
    (3) The report must include all other required information, as 
specified in your State plan according to Sec.  60.5740(a)(5).
    (4) If applicable, the report must include a program review that 
your State has conducted that addresses all aspects of the 
administration of the State plan and overall program, including State 
evaluations and regulatory decisions regarding eligibility applications 
for ERC resources and M&V reports (and associated EM&V activities), and 
State issuance of ERCs. The program review must assess whether the 
program is being administered properly in accordance with the approved 
plan, whether reported annual MWh of generation and savings from 
qualified ERC resources are being properly quantified, verified, and 
reported in accordance with approved EM&V plans, and whether 
appropriate records are being maintained. The program review must also 
address determination of the eligibility of verifiers by the State and 
the conduct of independent verifiers, including the quality of verifier 
reviews.
    (c) If your plan relies upon State measures, in lieu of or in 
addition to emission standards, then you must submit an annual report 
to the EPA in addition to the reports required under paragraph (b) of 
this section for the interim period. In the final period, you must 
submit biennial reports consistent with those required under paragraph 
(b) of this section. The annual reports in the interim period must be 
submitted no later than July 1 following the end of each calendar year 
starting with 2022.

[[Page 64958]]

The annual and biennial reports must include the information in 
paragraphs (c)(1) and (2) of this section for the preceding year or two 
years, as applicable.
    (1) You must include in your report the status of implementation of 
federally enforceable emission standards (if applicable) and State 
measures.
    (2) You must include information regarding the status of the 
periodic programmatic milestones to show progress in program 
implementation. The programmatic milestones with specific dates for 
achievement must be consistent with the State measures included in the 
State plan submittal.
    (d) If your plan includes the requirement for emission standards on 
your affected EGUs, then you must submit a notification, if applicable, 
in the report required under paragraph (b) of this section to the EPA 
if your affected EGUs trigger corrective measures as described in Sec.  
60.5740(a)(2)(i). If corrective measures are required and were not 
previously submitted with your state plan, you must follow the 
requirements in Sec.  60.5785 for revising your plan to implement the 
corrective measures.
    (e) If your plan relies upon State measures, in lieu of or in 
addition to emission standards, than you must submit a notification as 
required under paragraphs (e)(1) and (2) of this section.
    (1) You must submit a notification in the report required under 
paragraph (c) of this section to the EPA if at the end of the calendar 
year your State did not meet a programmatic milestone included in your 
plan submittal. This notification must detail the implementation of the 
backstop required in your plan to be fully in place within 18 months of 
the due date of the report required in paragraph (b) of this section. 
In addition, the notification must describe the steps taken by the 
State to inform the affected EGUs in its State that the backstop has 
been triggered.
    (2) You must submit a notification in the report required under 
paragraph (b) of this section to the EPA if you trigger the backstop as 
described in Sec.  60.5740(a)(3)(i). This notification must detail the 
steps that will be taken by you to implement the backstop so that it is 
fully in place within 18 months of the due date of the report required 
in paragraph (b) of this section. In addition, the notification must 
describe the steps taken by the State to inform the affected EGUs that 
the backstop has been triggered.
    (f) You must include in your 2029 report (which is due by July 1, 
2030) the calculation of average CO2 emissions rate, 
cumulative sum of CO2 emissions, or adjusted CO2 
emissions rate (as applicable) over the interim period and a comparison 
of those values to your interim CO2 emission performance 
rate or emission goal. The calculated value must be in units consistent 
with the approach you set in your plan for the interim period.
    (g) The notifications listed in paragraphs (g)(1) through (3) of 
this section are required for the reliability safety valve allowed in 
Sec.  60.5785(e).
    (1) As required under Sec.  60.5785(e), you must submit an initial 
notification to the appropriate EPA regional office within 48 hours of 
an unforeseen, emergency situation. The initial notification must:
    (i) Include a full description, to the extent that it is known, of 
the emergency situation that is being addressed;
    (ii) Identify the affected EGU or EGUs that are required to run to 
assure reliability; and
    (iii) Specify the modified emission standards at which the 
identified EGU or EGUs will operate.
    (2) Within 7 days of the initial notification in Sec.  
60.5870(g)(1), the State must submit a second notification to the 
appropriate EPA regional office that documents the initial 
notification. If the State fails to submit this documentation on a 
timely basis, the EPA will notify the State, which must then notify the 
affected EGU(s) that they must operate or resume operations under the 
original approved State plan emission standards. This notification must 
include the following:
    (i) A full description of the reliability concern and why an 
unforeseen, emergency situation that threatens reliability requires the 
affected EGU or EGUs to operate under modified emission standards from 
those originally required in the State plan including discussion of why 
the flexibilities provided under the state's plan are insufficient to 
address the concern;
    (ii) A description of how the State is coordinating or will 
coordinate with relevant reliability coordinators and planning 
authorities to alleviate the problem in an expedited manner;
    (iii) An indication of the maximum time that the State anticipates 
the affected EGU or EGUs will need to operate in a manner inconsistent 
with its or their obligations under the State's approved plan;
    (iv) A written concurrence from the relevant reliability 
coordinator and/or planning authority confirming the existence of the 
imminent reliability threat and supporting the temporary modification 
request or an explanation of why this kind of concurrence cannot be 
provided;
    (v) The modified emission standards or levels that the affected EGU 
or EGU will be operating at for the remainder of the 90-day period if 
it has changed from the initial notification; and
    (vi) Information regarding any system-wide or other analysis of the 
reliability concern conducted by the relevant planning authority, if 
any.
    (3) At least 7 days before the end of the 90-day reliability safety 
valve period, the State must notify the appropriate EPA regional office 
that either:
    (i) The reliability concern has been addressed and the affected EGU 
or EGUs can resume meeting the original emission standards in the State 
plan approved prior to the short-term modification; or
    (ii) There still is a serious, ongoing reliability issue that 
necessitates the affected EGU or EGUs to emit beyond the amount allowed 
under the State plan. In this case, the State must provide a 
notification to the EPA that it will be submitting a State plan 
revision according to paragraph Sec.  60.5785(a) of this section to 
address the reliability issue. The notification must provide the date 
by which a revised State plan will be submitted to EPA and 
documentation of the ongoing emergency with a written concurrence from 
the relevant reliability coordinator and/or planning authority 
confirming the continuing urgent need for the affected EGU or EGUs to 
operate beyond the requirements of the State plan and that there is no 
other reasonable way of addressing the ongoing reliability emergency 
but for the affected EGU or EGUs to operate under an alternative 
emission standard than originally approved under the State plan. After 
the initial 90-day period, any excess emissions beyond what is 
authorized in the original approved State plan will count against the 
State's overall CO2 emission goal or emission performance 
rate for affected EGUs.


Sec.  60.5875  How do I submit information required by these Emission 
Guidelines to the EPA?

    (a) You must submit to the EPA the information required by these 
emission guidelines following the procedures in paragraphs (b) through 
(e) of this section.
    (b) All negative declarations, State plan submittals, supporting 
materials that are part of a State plan submittal, any plan revisions, 
and all State reports required to be submitted to the EPA by the State 
plan must be reported through EPA's State Plan Electronic Collection

[[Page 64959]]

System (SPeCS). SPeCS is a web accessible electronic system accessed at 
the EPA's Central Data Exchange (CDX) (http://www.epa.gov/cdx/). States 
who claim that a State plan submittal or supporting documentation 
includes confidential business information (CBI) must submit that 
information on a compact disc, flash drive, or other commonly used 
electronic storage media to the EPA. The electronic media must be 
clearly marked as CBI and mailed to U.S. EPA/OAQPS/CORE CBI Office, 
Attention: State and Local Programs Group, MD C539-01, 4930 Old Page 
Rd., Durham, NC 27703.
    (c) Only a submittal by the Governor or the Governor's designee by 
an electronic submission through SPeCS shall be considered an official 
submittal to the EPA under this subpart. If the Governor wishes to 
designate another responsible official the authority to submit a State 
plan, the EPA must be notified via letter from the Governor prior to 
the September 6, 2016, deadline for plan submittal so that the official 
will have the ability to submit the initial or final plan submittal in 
the SPeCS. If the Governor has previously delegated authority to make 
CAA submittals on the Governor's behalf, a State may submit 
documentation of the delegation in lieu of a letter from the Governor. 
The letter or documentation must identify the designee to whom 
authority is being designated and must include the name and contact 
information for the designee and also identify the State plan preparers 
who will need access to SPeCS. A State may also submit the names of the 
State plan preparers via a separate letter prior to the designation 
letter from the Governor in order to expedite the State plan 
administrative process. Required contact information for the designee 
and preparers includes the person's title, organization and email 
address.
    (d) The submission of the information by the authorized official 
must be in a non-editable format. In addition to the non-editable 
version all plan components designated as federally enforceable must 
also be submitted in an editable version. Following initial plan 
approval, States must provide the EPA with an editable copy of any 
submitted revision to existing approved federally enforceable plan 
components, including State plan backstop measures. The editable copy 
of any such submitted plan revision must indicate the changes made at 
the State level, if any, to the existing approved federally enforceable 
plan components, using a mechanism such as redline/strikethrough. These 
changes are not part of the State plan until formal approval by EPA.
    (e) You must provide the EPA with non-editable and editable copies 
of any submitted revision to existing approved federally enforceable 
plan components, including State plan backstop measures. The editable 
copy of any such submitted plan revision must indicate the changes made 
at the State level, if any, to the existing approved federally 
enforceable plan components, using a mechanism such as redline/
strikethrough. These changes are not part of the State plan until 
formal approval by EPA.

Definitions


Sec.  60.5880  What definitions apply to this subpart?

    As used in this subpart, all terms not defined herein will have the 
meaning given them in the Clean Air Act and in subparts A, B, and TTTT, 
of this part.
Adjusted CO2 Emission Rate Means
    (1) For an affected EGU, the reported CO2 emission rate 
of an affected EGU, adjusted as described in Sec.  60.5790(c)(1) to 
reflect any ERCs used by an affected EGU to demonstrate compliance with 
its CO2 emission standards; or
    (2) For a State (or states in a multi-state plan) calculating a 
collective CO2 emission rate achieved under the plan, the 
actual CO2 emission rate during a plan reporting period of 
the affected EGUs subject to the rate specified in the plan, adjusted 
by the ERCs used for compliance by those EGUs (total CO2 
mass divided by the sum of the total MWh and ERCs).
    Affected electric generating unit or Affected EGU means a steam 
generating unit, integrated gasification combined cycle (IGCC), or 
stationary combustion turbine that meets the relevant applicability 
conditions in section Sec.  60.5845.
    Allowance means an authorization for each specified unit of actual 
CO2 emitted from an affected EGU or a facility during a 
specified period.
    Allowance system means a control program under which the owner or 
operator of each affected EGU is required to hold an allowance for each 
specified unit of CO2 emitted from that affected EGU or 
facility during a specified period and which limits the total amount of 
such allowances for a specified period and allows the transfer of such 
allowances.
    Annual capacity factor means the ratio between the actual heat 
input to an EGU during a calendar year and the potential heat input to 
the EGU had it been operated for 8,760 hours during a calendar year at 
the base load rating.
    Base load rating means the maximum amount of heat input (fuel) that 
an EGU can combust on a steady-state basis, as determined by the 
physical design and characteristics of the EGU at ISO conditions. For a 
stationary combustion turbine, base load rating includes the heat input 
from duct burners.
    Biomass means biologically based material that is living or dead 
(e.g., trees, crops, grasses, tree litter, roots) above and below 
ground, and available on a renewable or recurring basis. Materials that 
are biologically based include non-fossilized, biodegradable organic 
material originating from modern or contemporarily grown plants, 
animals, or microorganisms (including plants, products, byproducts and 
residues from agriculture, forestry, and related activities and 
industries, as well as the non-fossilized and biodegradable organic 
fractions of industrial and municipal wastes, including gases and 
liquids recovered from the decomposition of non-fossilized and 
biodegradable organic material).
    CO2 emission goal means a statewide rate-based 
CO2 emission goal or mass-based CO2 emission goal 
specified in Sec.  60.5855.
    Combined cycle unit means an electric generating unit that uses a 
stationary combustion turbine from which the heat from the turbine 
exhaust gases is recovered by a heat recovery steam generating unit to 
generate additional electricity.
    Combined heat and power unit or CHP unit, (also known as 
``cogeneration'') means an electric generating unit that uses a steam-
generating unit or stationary combustion turbine to simultaneously 
produce both electric (or mechanical) and useful thermal output from 
the same primary energy source.
    Compliance period means a discrete time period for an affected EGU 
to comply with either an emission standard or State measure.
    Demand-side energy efficiency project means an installed piece of 
equipment or system, a modification of an existing piece of equipment 
or system, or a strategy intended to affect consumer electricity-use 
behavior, that results in a reduction in electricity use (in MWh) at an 
end-use facility, premises, or equipment connected to the electricity 
grid.
    Derate means a decrease in the available capacity of an electric 
generating unit, due to a system or equipment modification or to 
discounting a portion of a generating unit's capacity for planning 
purposes.
    Eligible resource means a resource that meets the requirements of 
Sec.  60.5800(a).

[[Page 64960]]

    Emission Rate Credit or ERC means a tradable compliance instrument 
that meets the requirements of Sec.  60.5790(c).
    EM&V plan means a plan that meets the requirements of Sec.  
60.5830.
    ERC tracking system means a system for the issuance, surrender and 
retirement of ERCs that meets the requirements of Sec.  60.5810.
    Final period means the period that begins on January 1, 2030, and 
continues thereafter. The final period is comprised of final reporting 
periods, each of which may be no longer than two calendar years (with a 
calendar year beginning on January 1 and ending on December 31).
    Final reporting period means an increment of plan performance 
within the final period, with each final reporting period being no 
longer than two calendar years (with a calendar year beginning on 
January 1 and ending on December 31), with the first final reporting 
period in the final period beginning on January 1, 2030, and ending no 
later than December 31, 2031.
    Fossil fuel means natural gas, petroleum, coal, and any form of 
solid fuel, liquid fuel, or gaseous fuel derived from such material for 
the purpose of creating useful heat.
    Heat recovery steam generating unit (HRSG) means a unit in which 
hot exhaust gases from the combustion turbine engine are routed in 
order to extract heat from the gases and generate useful output. Heat 
recovery steam generating units can be used with or without duct 
burners.
    Independent verifier means a person (including any individual, 
corporation, partnership, or association) who has the appropriate 
technical and other qualifications to provide verification reports. The 
independent verifier must not have, or have had, any direct or indirect 
financial or other interest in the subject of its verification report 
or ERCs that could impact their impartiality in performing verification 
services.
    Integrated gasification combined cycle facility or IGCC means a 
combined cycle facility that is designed to burn fuels containing 50 
percent (by heat input) or more solid-derived fuel not meeting the 
definition of natural gas plus any integrated equipment that provides 
electricity or useful thermal output to either the affected facility or 
auxiliary equipment. The Administrator may waive the 50 percent solid-
derived fuel requirement during periods of the gasification system 
construction, startup and commissioning, shutdown, or repair. No solid 
fuel is directly burned in the unit during operation.
    Interim period means the period of eight calendar years from 
January 1, 2022, to December 31, 2029. The interim period is composed 
three interim steps, interim step 1, interim step 2, and interim step 
3.
    Interim step means an increment of plan performance within the 
interim period.
    Interim step 1 means the period of three calendar years from 
January 1, 2022, to December 31, 2024.
    Interim step 2 means the period of three calendar years from 
January 1, 2025, to December 31, 2027.
    Interim step 3 means the period of two calendar years from January 
1, 2028, to December 31, 2029.
    ISO conditions means 288 Kelvin (15 [deg]C), 60 percent relative 
humidity and 101.3 kilopascals pressure.
    M&V report means a report that meets the requirements of Sec.  
60.5835.
    Mechanical output means the useful mechanical energy that is not 
used to operate the affected facility, generate electricity and/or 
thermal output, or to enhance the performance of the affected facility. 
Mechanical energy measured in horsepower hour must be converted into 
MWh by multiplying it by 745.7 then dividing by 1,000,000.
    Nameplate capacity means, starting from the initial installation, 
the maximum electrical generating output that a generator, prime mover, 
or other electric power production equipment under specific conditions 
designated by the manufacturer is capable of producing (in MWe, rounded 
to the nearest tenth) on a steady-state basis and during continuous 
operation (when not restricted by seasonal or other deratings) as of 
such installation as specified by the manufacturer of the equipment, or 
starting from the completion of any subsequent physical change 
resulting in an increase in the maximum electrical generating output 
that the equipment is capable of producing on a steady-state basis and 
during continuous operation (when not restricted by seasonal or other 
deratings), such increased maximum amount (in MWe, rounded to the 
nearest tenth) as of such completion as specified by the person 
conducting the physical change.
    Natural gas means a fluid mixture of hydrocarbons (e.g., methane, 
ethane, or propane), composed of at least 70 percent methane by volume 
or that has a gross calorific value between 35 and 41 megajoules (MJ) 
per dry standard cubic meter (950 and 1,100 Btu per dry standard cubic 
foot), that maintains a gaseous State under ISO conditions. In 
addition, natural gas contains 20.0 grains or less of total sulfur per 
100 standard cubic feet. Finally, natural gas does not include the 
following gaseous fuels: Landfill gas, digester gas, refinery gas, sour 
gas, blast furnace gas, coal-derived gas, producer gas, coke oven gas, 
or any gaseous fuel produced in a process which might result in highly 
variable sulfur content or heating value.
    Net allowance export/import means a net transfer of CO2 
allowances during an interim step, the interim period, or a final 
reporting period which represents the net number of CO2 
allowances (issued by a State) that are transferred from the compliance 
accounts of affected EGUs in that state to the compliance accounts of 
affected EGUs in another State. This net transfer is determined based 
on compliance account holdings at the end of the plan performance 
period. Compliance account holdings, as used here, refer to the number 
of CO2 allowances surrendered for compliance during a plan 
performance period, as well as any remaining CO2 allowances 
held in a compliance account as of the end of a plan performance 
period.
    Net electric output means the amount of gross generation the 
generator(s) produce (including, but not limited to, output from steam 
turbine(s), combustion turbine(s), and gas expander(s)), as measured at 
the generator terminals, less the electricity used to operate the plant 
(i.e., auxiliary loads); such uses include fuel handling equipment, 
pumps, fans, pollution control equipment, other electricity needs, and 
transformer losses as measured at the transmission side of the step up 
transformer (e.g., the point of sale).
    Net energy output means:
    (1) The net electric or mechanical output from the affected 
facility, plus 100 percent of the useful thermal output measured 
relative to SATP conditions that is not used to generate additional 
electric or mechanical output or to enhance the performance of the unit 
(e.g., steam delivered to an industrial process for a heating 
application).
    (2) For combined heat and power facilities where at least 20.0 
percent of the total gross or net energy output consists of electric or 
direct mechanical output and at least 20.0 percent of the total gross 
or net energy output consists of useful thermal output on a 12-
operating month rolling average basis, the net electric or mechanical 
output from the affected EGU divided by 0.95, plus 100 percent of the 
useful thermal output; (e.g., steam delivered to an industrial process 
for a heating application).
    Programmatic milestone means the implementation of measures 
necessary for plan progress, including specific dates associated with 
such

[[Page 64961]]

implementation. Prior to January 1, 2022, programmatic milestones are 
applicable to all state plan approaches and measures. Subsequent to 
January 1, 2022, programmatic milestones are applicable to state 
measures.
    Qualified biomass means a biomass feedstock that is demonstrated as 
a method to control increases of CO2 levels in the 
atmosphere.
    Standard ambient temperature and pressure (SATP) conditions means 
298.15 Kelvin (25 [deg]C, 77 [deg]F)) and 100.0 kilopascals (14.504 
psi, 0.987 atm) pressure. The enthalpy of water at SATP conditions is 
50 Btu/lb.
    State agent means an entity acting on behalf of the State, with the 
legal authority of the State.
    State measures means measures that are adopted, implemented, and 
enforced as a matter of State law. Such measures are enforceable only 
per State law, and are not included in and codified as part of the 
federally enforceable State plan.
    Stationary combustion turbine means all equipment, including but 
not limited to the turbine engine, the fuel, air, lubrication and 
exhaust gas systems, control systems (except emissions control 
equipment), heat recovery system, fuel compressor, heater, and/or pump, 
post-combustion emissions control technology, and any ancillary 
components and sub-components comprising any simple cycle stationary 
combustion turbine, any combined cycle combustion turbine, and any 
combined heat and power combustion turbine based system plus any 
integrated equipment that provides electricity or useful thermal output 
to the combustion turbine engine, heat recovery system or auxiliary 
equipment. Stationary means that the combustion turbine is not self-
propelled or intended to be propelled while performing its function. It 
may, however, be mounted on a vehicle for portability. If a stationary 
combustion turbine burns any solid fuel directly it is considered a 
steam generating unit.
    Steam generating unit means any furnace, boiler, or other device 
used for combusting fuel and producing steam (nuclear steam generators 
are not included) plus any integrated equipment that provides 
electricity or useful thermal output to the affected facility or 
auxiliary equipment.
    Uprate means an increase in available electric generating unit 
power capacity due to a system or equipment modification.
    Useful thermal output means the thermal energy made available for 
use in any heating application (e.g., steam delivered to an industrial 
process for a heating application, including thermal cooling 
applications) that is not used for electric generation, mechanical 
output at the affected EGU, to directly enhance the performance of the 
affected EGU (e.g., economizer output is not useful thermal output, but 
thermal energy used to reduce fuel moisture is considered useful 
thermal output), or to supply energy to a pollution control device at 
the affected EGU. Useful thermal output for affected EGU(s) with no 
condensate return (or other thermal energy input to the affected 
EGU(s)) or where measuring the energy in the condensate (or other 
thermal energy input to the affected EGU(s)) would not meaningfully 
impact the emission rate calculation is measured against the energy in 
the thermal output at SATP conditions. Affected EGU(s) with meaningful 
energy in the condensate return (or other thermal energy input to the 
affected EGU) must measure the energy in the condensate and subtract 
that energy relative to SATP conditions from the measured thermal 
output.
    Valid data means quality-assured data generated by continuous 
monitoring systems that are installed, operated, and maintained 
according to part 75 of this chapter. For CEMS, the initial 
certification requirements in Sec.  75.20 of this chapter and appendix 
A to part 75 of this chapter must be met before quality-assured data 
are reported under this subpart; for on-going quality assurance, the 
daily, quarterly, and semiannual/annual test requirements in sections 
2.1, 2.2, and 2.3 of appendix B to part 75 of this chapter must be met 
and the data validation criteria in sections 2.1.5, 2.2.3, and 2.3.2 of 
appendix B to part 75 of this chapter apply. For fuel flow meters, the 
initial certification requirements in section 2.1.5 of appendix D to 
part 75 of this chapter must be met before quality-assured data are 
reported under this subpart (except for qualifying commercial billing 
meters under section 2.1.4.2 of appendix D), and for on-going quality 
assurance, the provisions in section 2.1.6 of appendix D to part 75 of 
this chapter apply (except for qualifying commercial billing meters).
    Waste-to-Energy means a process or unit (e.g., solid waste 
incineration unit) that recovers energy from the conversion or 
combustion of waste stream materials, such as municipal solid waste, to 
generate electricity and/or heat.

   Table 1 to Subpart UUUU of Part 60--CO2 Emission Performance Rates
                       [Pounds of CO2 per net MWh]
------------------------------------------------------------------------
              Affected EGU                 Interim rate     Final rate
------------------------------------------------------------------------
Steam generating unit or integrated                1,534           1,305
 gasification combined cycle (IGCC).....
Stationary combustion turbine...........             832             771
------------------------------------------------------------------------


                   Table 2 to Subpart UUUU of Part 60--Statewide Rate-Based CO2 Emission Goals
                                           [Pounds of CO2 per net MWh]
----------------------------------------------------------------------------------------------------------------
                             State                               Interim emission goal     Final emission goal
----------------------------------------------------------------------------------------------------------------
Alabama.......................................................                    1,157                    1,018
Arizona.......................................................                    1,173                    1,031
Arkansas......................................................                    1,304                    1,130
California....................................................                      907                      828
Colorado......................................................                    1,362                    1,174
Connecticut...................................................                      852                      786
Delaware......................................................                    1,023                      916
Florida.......................................................                    1,026                      919
Georgia.......................................................                    1,198                    1,049
Idaho.........................................................                      832                      771
Illinois......................................................                    1,456                    1,245

[[Page 64962]]

 
Indiana.......................................................                    1,451                    1,242
Iowa..........................................................                    1,505                    1,283
Kansas........................................................                    1,519                    1,293
Kentucky......................................................                    1,509                    1,286
Lands of the Fort Mojave Tribe................................                      832                      771
Lands of the Navajo Nation....................................                    1,534                    1,305
Lands of the Uintah and Ouray Reservation.....................                    1,534                    1,305
Louisiana.....................................................                    1,293                    1,121
Maine.........................................................                      842                      779
Maryland......................................................                    1,510                    1,287
Massachusetts.................................................                      902                      824
Michigan......................................................                    1,355                    1,169
Minnesota.....................................................                    1,414                    1,213
Mississippi...................................................                    1,061                      945
Missouri......................................................                    1,490                    1,272
Montana.......................................................                    1,534                    1,305
Nebraska......................................................                    1,522                    1,296
Nevada........................................................                      942                      855
New Hampshire.................................................                      947                      858
New Jersey....................................................                      885                      812
New Mexico....................................................                    1,325                    1,146
New York......................................................                    1,025                      918
North Carolina................................................                    1,311                    1,136
North Dakota..................................................                    1,534                    1,305
Ohio..........................................................                    1,383                    1,190
Oklahoma......................................................                    1,223                    1,068
Oregon........................................................                      964                      871
Pennsylvania..................................................                    1,258                    1,095
Rhode Island..................................................                      832                      771
South Carolina................................................                    1,338                    1,156
South Dakota..................................................                    1,352                    1,167
Tennessee.....................................................                    1,411                    1,211
Texas.........................................................                    1,188                    1,042
Utah..........................................................                    1,368                    1,179
Virginia......................................................                    1,047                      934
Washington....................................................                    1,111                      983
West Virginia.................................................                    1,534                    1,305
Wisconsin.....................................................                    1,364                    1,176
Wyoming.......................................................                    1,526                    1,299
----------------------------------------------------------------------------------------------------------------


                   Table 3 to Subpart UUUU of Part 60--Statewide Mass-Based CO2 Emission Goals
                                               [Short tons of CO2]
----------------------------------------------------------------------------------------------------------------
                                                                                         Final emission goals (2
                             State                               Interim emission goal     year blocks starting
                                                                      (2022-2029)            with 2030-2031)
----------------------------------------------------------------------------------------------------------------
Alabama.......................................................              497,682,304              113,760,948
Arizona.......................................................              264,495,976               60,341,500
Arkansas......................................................              269,466,064               60,645,264
California....................................................              408,216,600               96,820,240
Colorado......................................................              267,103,064               59,800,794
Connecticut...................................................               57,902,920               13,883,046
Delaware......................................................               40,502,952                9,423,650
Florida.......................................................              903,877,832              210,189,408
Georgia.......................................................              407,408,672               92,693,692
Idaho.........................................................               12,401,136                2,985,712
Illinois......................................................              598,407,008              132,954,314
Indiana.......................................................              684,936,520              152,227,670
Iowa..........................................................              226,035,288               50,036,272
Kansas........................................................              198,874,664               43,981,652
Kentucky......................................................              570,502,416              126,252,242
Lands of the Fort Mojave Tribe................................                4,888,824                1,177,038
Lands of the Navajo Nation....................................              196,462,344               43,401,174
Lands of the Uintah and Ouray Reservation.....................               20,491,560                4,526,862
Louisiana.....................................................              314,482,512               70,854,046
Maine.........................................................               17,265,472                4,147,884
Maryland......................................................              129,675,168               28,695,256
Massachusetts.................................................              101,981,416               24,209,494
Michigan......................................................              424,457,200               95,088,128

[[Page 64963]]

 
Minnesota.....................................................              203,468,736               45,356,736
Missouri......................................................              500,555,464              110,925,768
Mississippi...................................................              218,706,504               50,608,674
Montana.......................................................              102,330,640               22,606,214
Nebraska......................................................              165,292,128               36,545,478
Nevada........................................................              114,752,736               27,047,168
New Hampshire.................................................               33,947,936                7,995,158
New Jersey....................................................              139,411,048               33,199,490
New Mexico....................................................              110,524,488               24,825,204
New York......................................................              268,762,632               62,514,858
North Carolina................................................              455,888,200              102,532,468
North Dakota..................................................              189,062,568               41,766,464
Ohio..........................................................              660,212,104              147,539,612
Oklahoma......................................................              356,882,656               80,976,398
Oregon........................................................               69,145,312               16,237,308
Pennsylvania..................................................              794,646,616              179,644,616
Rhode Island..................................................               29,259,080                7,044,450
South Carolina................................................              231,756,984               51,997,936
South Dakota..................................................               31,591,600                7,078,962
Tennessee.....................................................              254,278,880               56,696,792
Texas.........................................................            1,664,726,728              379,177,684
Utah..........................................................              212,531,040               47,556,386
Virginia......................................................              236,640,576               54,866,222
Washington....................................................               93,437,656               21,478,344
West Virginia.................................................              464,664,712              102,650,684
Wisconsin.....................................................              250,066,848               55,973,976
Wyoming.......................................................              286,240,416               63,268,824
----------------------------------------------------------------------------------------------------------------


   Table 4 to Subpart UUUU of Part 60-- Statewide Mass-based CO2 Goals plus New Source CO2 Emission Complement
                                               [Short tons of CO2]
----------------------------------------------------------------------------------------------------------------
                                                                                           Final emission goals
                             State                               Interim emission goal   (2 year blocks starting
                                                                      (2022-2029)            with 2030-2031)
----------------------------------------------------------------------------------------------------------------
Alabama.......................................................              504,534,496              115,272,348
Arizona.......................................................              275,895,952               64,760,392
Arkansas......................................................              272,756,576               61,371,058
California....................................................              430,988,824              105,647,270
Colorado......................................................              277,022,392               63,645,748
Connecticut...................................................               58,986,192               14,121,986
Delaware......................................................               41,133,688                9,562,772
Florida.......................................................              917,904,040              213,283,190
Georgia.......................................................              412,826,944               93,888,808
Idaho.........................................................               13,155,256                3,278,026
Illinois......................................................              604,953,792              134,398,348
Indiana.......................................................              692,451,256              153,885,208
Iowa..........................................................              228,426,760               50,563,762
Kansas........................................................              200,960,120               44,441,644
Kentucky......................................................              576,522,048              127,580,002
Lands of the Fort Mojave Tribe................................                5,186,112                1,292,276
Lands of the Navajo Nation....................................              202,938,832               45,911,608
Lands of the Uintah and Ouray Reservation.....................               21,167,080                4,788,708
Louisiana.....................................................              318,356,976               71,708,642
Maine.........................................................               17,592,128                4,219,936
Maryland......................................................              131,042,600               28,996,872
Massachusetts.................................................              103,782,424               24,606,744
Michigan......................................................              429,446,408               96,188,604
Minnesota.....................................................              205,761,008               45,862,346
Mississippi...................................................              221,990,024               51,332,926
Missouri......................................................              505,904,560              112,105,626
Montana.......................................................              105,704,024               23,913,816
Nebraska......................................................              167,021,320               36,926,888
Nevada........................................................              120,916,064               29,436,214
New Hampshire.................................................               34,519,280                8,121,182
New Jersey....................................................              141,919,248               33,752,728
New Mexico....................................................              114,741,592               26,459,850

[[Page 64964]]

 
New York......................................................              272,940,440               63,436,364
North Carolina................................................              461,424,928              103,753,712
North Dakota..................................................              191,025,152               42,199,354
Ohio..........................................................              667,812,080              149,215,950
Oklahoma......................................................              361,531,056               82,001,704
Oregon........................................................               72,774,608               17,644,106
Pennsylvania..................................................              804,705,296              181,863,274
Rhode Island..................................................               29,819,360                7,168,032
South Carolina................................................              234,516,064               52,606,510
South Dakota..................................................               31,963,696                7,161,036
Tennessee.....................................................              257,149,584               57,329,988
Texas.........................................................            1,707,356,792              396,210,498
Utah..........................................................              220,386,616               50,601,386
Virginia......................................................              240,240,880               55,660,348
Washington....................................................               97,691,736               23,127,324
West Virginia.................................................              469,488,232              103,714,614
Wisconsin.....................................................              252,985,576               56,617,764
Wyoming.......................................................              295,724,848               66,945,204
----------------------------------------------------------------------------------------------------------------

[FR Doc. 2015-22842 Filed 10-22-15; 8:45 am]
 BILLING CODE 6560-50-P


