
[Federal Register Volume 80, Number 205 (Friday, October 23, 2015)]
[Rules and Regulations]
[Pages 64509-64660]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2015-22837]



[[Page 64509]]

Vol. 80

Friday,

No. 205

October 23, 2015

Part II





Environmental Protection Agency





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40 CFR Parts 60, 70, 71, et al.





 Standards of Performance for Greenhouse Gas Emissions From New, 
Modified, and Reconstructed Stationary Sources: Electric Utility 
Generating Units; Final Rule

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

[[Page 64510]]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 60, 70, 71, and 98

[EPA-HQ-OAR-2013-0495; EPA-HQ-OAR-2013-0603; FRL-9930-66-OAR]
RIN 2060-AQ91


Standards of Performance for Greenhouse Gas Emissions From New, 
Modified, and Reconstructed Stationary Sources: Electric Utility 
Generating Units

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

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SUMMARY: The Environmental Protection Agency (EPA) is finalizing new 
source performance standards (NSPS) under Clean Air Act (CAA) section 
111(b) that, for the first time, will establish standards for emissions 
of carbon dioxide (CO2) for newly constructed, modified, and 
reconstructed affected fossil fuel-fired electric utility generating 
units (EGUs). This action establishes separate standards of performance 
for fossil fuel-fired electric utility steam generating units and 
fossil fuel-fired stationary combustion turbines. This action also 
addresses related permitting and reporting issues. In a separate 
action, under CAA section 111(d), the EPA is issuing final emission 
guidelines for states to use in developing plans to limit 
CO2 emissions from existing fossil fuel-fired EGUs.

DATES: This final rule is effective on October 23, 2015. The 
incorporation by reference of certain publications listed in the rule 
is approved by the Director of the Federal Register as of October 23, 
2015.

ADDRESSES: The EPA has established dockets for this action under Docket 
ID No. EPA-HQ-OAR-2013-0495 (Standards of Performance for Greenhouse 
Gas Emissions from New Stationary Sources: Electric Utility Generating 
Units) and Docket ID No. EPA-HQ-OAR-2013-0603 (Carbon Pollution 
Standards for Modified and Reconstructed Stationary Sources: Electric 
Utility Generating Units). All documents in the dockets are listed on 
the www.regulations.gov Web site. Although listed in the index, some 
information is not publicly available, e.g., Confidential Business 
Information or other information whose 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 www.regulations.gov or 
in hard copy at the EPA Docket Center (EPA/DC), Room 3334, EPA WJC West 
Building, 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 legal 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 FURTHER INFORMATION CONTACT: Dr. Nick Hutson, Energy Strategies 
Group, Sector Policies and Programs Division (D243-01), U.S. EPA, 
Research Triangle Park, NC 27711; telephone number (919) 541-2968, 
facsimile number (919) 541-5450; email address: hutson.nick@epa.gov or 
Mr. Christian Fellner, Energy Strategies Group, Sector Policies and 
Programs Division (D243-01), U.S. EPA, Research Triangle Park, NC 
27711; telephone number (919) 541-4003, facsimile number (919) 541-
5450; email address: fellner.christian@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:

AB Assembly Bill
AEO Annual Energy Outlook
AEP American Electric Power
ANSI American National Standards Institute
ASME American Society of Mechanical Engineers
BACT Best Available Control Technology
BDT Best Demonstrated Technology
BSER Best System of Emission Reduction
Btu/kWh British Thermal Units per Kilowatt-hour
Btu/lb British Thermal Units per Pound
CAA Clean Air Act
CAIR Clean Air Interstate Rule
CBI Confidential Business Information
CCS Carbon Capture and Storage (or Sequestration)
CDX Central Data Exchange
CEDRI Compliance and Emissions Data Reporting Interface
CEMS Continuous Emissions Monitoring System
CFB Circulating Fluidized Bed
CH4 Methane
CHP Combined Heat and Power
CO2 Carbon Dioxide
CSAPR Cross-State Air Pollution Rule
DOE Department of Energy
DOT Department of Transportation
ECMPS Emissions Collection and Monitoring Plan System
EERS Energy Efficiency Resource Standards
EGU Electric Generating Unit
EIA Energy Information Administration
EO Executive Order
EOR Enhanced Oil Recovery
EPA Environmental Protection Agency
FB Fluidized Bed
FGD Flue Gas Desulfurization
FOAK First-of-a-kind
FR Federal Register
GHG Greenhouse Gas
GHGRP Greenhouse Gas Reporting Program
GPM Gallons per Minute
GS Geologic Sequestration
GW Gigawatts
H2 Hydrogen Gas
HAP Hazardous Air Pollutant
HFC Hydrofluorocarbon
HRSG Heat Recovery Steam Generator
IGCC Integrated Gasification Combined Cycle
IPCC Intergovernmental Panel on Climate Change
IPM Integrated Planning Model
IRPs Integrated Resource Plans
kg/MWh Kilogram per Megawatt-hour
kJ/kg Kilojoules per Kilogram
kWh Kilowatt-hour
lb CO2/MMBtu Pounds of CO2 per Million British 
Thermal Unit
lb CO2/MWh Pounds of CO2 per Megawatt-hour
lb CO2/yr Pounds of CO2 per Year
lb/lb-mole Pounds per Pound-Mole
LCOE Levelized Cost of Electricity
MATS Mercury and Air Toxic Standards
MMBtu/hr Million British Thermal Units per Hour
MRV Monitoring, Reporting, and Verification
MW Megawatt
MWe Megawatt Electrical
MWh Megawatt-hour
MWh-g Megawatt-hour gross
MWh-n Megawatt-hour net
N2O Nitrous Oxide
NAAQS National Ambient Air Quality Standards
NAICS North American Industry Classification System
NAS National Academy of Sciences
NETL National Energy Technology Laboratory
NGCC Natural Gas Combined Cycle
NOAK n\th\-of-a-kind
NRC National Research Council
NSPS New Source Performance Standards
NSR New Source Review
NTTAA National Technology Transfer and Advancement Act
O2 Oxygen Gas
OMB Office of Management and Budget
PC Pulverized Coal
PFC Perfluorocarbon
PM Particulate Matter
PM2.5 Fine Particulate Matter
PRA Paperwork Reduction Act
PSD Prevention of Significant Deterioration
PUC Public Utilities Commission
RCRA Resource Conservation and Recovery Act
RFA Regulatory Flexibility Act
RGGI Regional Greenhouse Gas Initiative
RIA Regulatory Impact Analysis
RPS Renewable Portfolio Standard
RTC Response to Comments
RTP Response to Petitions
SBA Small Business Administration
SCC Social Cost of Carbon
SCR Selective Catalytic Reduction
SCPC Supercritical Pulverized Coal
SDWA Safe Drinking Water Act
SF6 Sulfur Hexafluoride
SIP State Implementation Plan

[[Page 64511]]

SNCR Selective Non-Catalytic Reduction
SO2 Sulfur Dioxide
SSM Startup, Shutdown, and Malfunction
Tg Teragram (one trillion (10\12\) grams)
Tpy Tons per Year
TSD Technical Support Document
TTN Technology Transfer Network
UIC Underground Injection Control
UMRA Unfunded Mandates Reform Act of 1995
U.S. United States
USDW Underground Source of Drinking Water
USGCRP U.S. Global Change Research Program
VCS Voluntary Consensus Standard
WGS Water Gas Shift
WWW World Wide Web

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

I. General Information
    A. Executive Summary
    B. Does this action apply to me?
    C. Where can I get a copy of this document?
    D. Judicial Review
    E. How is this preamble organized?
II. Background
    A. Climate Change Impacts From GHG Emissions
    B. GHG Emissions From Fossil Fuel-Fired EGUs
    C. The Utility Power Sector
    D. Statutory Background
    E. Regulatory Background
    F. Development of Carbon Pollution Standards for Fossil Fuel-
Fired Electric Utility Generating Units
    G. Stakeholder Engagement and Public Comments on the Proposals
III. Regulatory Authority, Affected EGUs and Their Standards, and 
Legal Requirements
    A. Authority To Regulate Carbon Dioxide From Fossil Fuel-Fired 
EGUs
    B. Treatment of Categories and Codification in the Code of 
Federal Regulations
    C. Affected Units
    D. Units Not Covered by This Final Rule
    E. Coal Refuse
    F. Format of the Output-Based Standard
    G. CO2 Emissions Only
    H. Legal Requirements for Establishing Emission Standards
    I. Severability
    J. Certain Projects Under Development
IV. Summary of Final Standards for Newly Constructed, Modified, and 
Reconstructed Fossil Fuel-Fired Electric Utility Steam Generating 
Units
    A. Applicability Requirements and Rationale
    B. Best System of Emission Reduction
    C. Final Standards of Performance
V. Rationale for Final Standards for Newly Constructed Fossil Fuel-
Fired Electric Utility Steam Generating Units
    A. Factors Considered in Determining the BSER
    B. Highly Efficient SCPC EGU Implementing Partial CCS as the 
BSER for Newly Constructed Steam Generating Units
    C. Rationale for the Final Emission Standards
    D. Post-Combustion Carbon Capture
    E. Pre-Combustion Carbon Capture
    F. Vendor Guarantees, Industry Statements, Academic Literature, 
and Commercial Availability
    G. Response to Key Comments on the Adequacy of the Technical 
Feasibility Demonstration
    H. Consideration of Costs
    I. Key Comments Regarding the EPA's Consideration of Costs
    J. Achievability of the Final Standards
    K. Emission Reductions Utilizing Partial CCS
    L. Further Development and Deployment of CCS Technology
    M. Technical and Geographic Aspects of Disposition of Captured 
CO2
    N. Final Requirements for Disposition of Captured CO2
    O. Non-Air Quality Impacts and Energy Requirements
    P. Options That Were Considered by the EPA But Were Ultimately 
Not Determined to Be the BSER
    Q. Summary
VI. Rationale for Final Standards for Modified Fossil Fuel-Fired 
Electric Utility Steam Generating Units
    A. Rationale for Final Applicability Criteria for Modified Steam 
Generating Units
    B. Identification of the Best System of Emission Reduction
    C. BSER Criteria
VII. Rationale for Final Standards for Reconstructed Fossil Fuel-
Fired Electric Utility Steam Generating Units
    A. Rationale for Final Applicability Criteria for Reconstructed 
Sources
    B. Identification of the Best System of Emission Reduction
VIII. Summary of Final Standards for Newly Constructed and 
Reconstructed Stationary Combustion Turbines
    A. Applicability Requirements
    B. Best System of Emission Reduction
    C. Final Emission Standards
    D. Significant Differences Between Proposed and Final Combustion 
Turbine Provisions
IX. Rationale for Final Standards for Newly Constructed and 
Reconstructed Stationary Combustion Turbines
    A. Applicability
    B. Subcategories
    C. Identification of the Best System of Emission Reduction
    D. Achievability of the Final Standards
X. Summary of Other Final Requirements for Newly Constructed, 
Modified, and Reconstructed Fossil Fuel-Fired Electric Utility Steam 
Generating Units and Stationary Combustion Turbines
    A. Startup, Shutdown, and Malfunction Requirements
    B. Continuous Monitoring Requirements
    C. Emissions Performance Testing Requirements
    D. Continuous Compliance Requirements
    E. Notification, Recordkeeping, and Reporting Requirements
XI. Consistency Between BSER Determinations for This Rule and the 
Rule for Existing EGUs
    A. Newly Constructed Steam Generating Units
    B. New Combustion Turbines
    C. Modified and Reconstructed Steam and NGCC Units
XII. Interactions With Other EPA Programs and Rules
    A. Overview
    B. Applicability of Tailoring Rule Thresholds Under the PSD 
Program
    C. Implications for BACT Determinations Under PSD
    D. Implications for Title V Program
    E. Implications for Title V Fee Requirements for GHGs
    F. Interactions With Other EPA Rules
XIII. Impacts of This Action
    A. What are the air impacts?
    B. Endangered Species Act
    C. What are the energy impacts?
    D. What are the water and solid waste impacts?
    E. What are the compliance costs?
    F. What are the economic and employment impacts?
    G. What are the benefits of the final standards?
XIV. 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) and 
1 CFR Part 51
    J. Executive Order 12898: Federal Actions To Address 
Environmental Justice in Minority Populations and Low-Income 
Populations
    K. Congressional Review Act (CRA)
XV. Withdrawal of Proposed Standards for Certain Modified Sources
XVI. Statutory Authority

I. General Information

A. Executive Summary

1. Purpose of the Regulatory Action
    In this final action the EPA is establishing standards that limit 
greenhouse gas (GHG) emissions from newly constructed, modified, and 
reconstructed fossil fuel-fired electric utility steam generating units 
and stationary combustion turbines, following the issuance of proposals 
for such standards and an accompanying Notice of Data Availability.
    On June 25, 2013, in conjunction with the announcement of his 
Climate Action Plan (CAP), President Obama issued a

[[Page 64512]]

Presidential Memorandum directing the EPA to issue a proposal to 
address carbon pollution from new power plants by September 30, 2013, 
and to issue ``standards, regulations, or guidelines, as appropriate, 
which address carbon pollution from modified, reconstructed, and 
existing power plants.'' Pursuant to authority in section 111(b) of the 
CAA, on September 20, 2013, the EPA issued proposed carbon pollution 
standards for newly constructed fossil fuel-fired power plants. The 
proposal was published in the Federal Register on January 8, 2014 (79 
FR 1430; ``January 2014 proposal'').\1\ In that proposal, the EPA 
proposed to limit emissions of CO2 from newly constructed 
fossil fuel-fired electric utility steam generating units and newly 
constructed natural gas-fired stationary combustion turbines.
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    \1\ The EPA previously proposed performance standards for newly 
reconstructed fossil fuel-fired EGUs in April 2012 (77 FR 22392). In 
that action, the EPA proposed standards for steam generating units 
and natural gas-fired combustion turbines based on a single Best 
System of Emission Reduction determination. On January 8, 2014, the 
EPA withdrew that proposal (79 FR 1352).
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    The EPA subsequently issued a Notice of Data Availability (NODA) in 
which the EPA solicited comment on its initial interpretation of 
provisions in the Energy Policy Act of 2005 (EPAct05) and associated 
provisions in the Internal Revenue Code (IRC) and also solicited 
comment on a companion Technical Support Document (TSD) that addressed 
these provisions' relationship to the factual record supporting the 
proposed rule. 79 FR 10750 (February 26, 2014).
    On June 2, 2014, the EPA proposed standards of performance, also 
pursuant to CAA section 111(b), to limit emissions of CO2 
from modified and reconstructed fossil fuel-fired electric utility 
steam generating units and natural gas-fired stationary combustion 
turbines. 79 FR 34960 (June 18, 2014) (``June 2014 proposal''). 
Specifically, the EPA proposed standards of performance for: (1) 
Modified fossil fuel-fired steam generating units, (2) modified natural 
gas-fired stationary combustion turbines, (3) reconstructed fossil 
fuel-fired steam generating units, and (4) reconstructed natural gas-
fired stationary combustion turbines.
    In this action, the EPA is issuing final standards of performance 
to limit emissions of GHG pollution manifested as CO2 from 
newly constructed, modified, and reconstructed fossil fuel-fired 
electric utility steam generating units (i.e., utility boilers and 
integrated gasification combined cycle (IGCC) units) and from newly 
constructed and reconstructed stationary combustion turbines. 
Consistent with the requirements of CAA section 111(b), these standards 
reflect the degree of emission limitation achievable through the 
application of the best system of emission reduction (BSER) that the 
EPA has determined has been adequately demonstrated for each type of 
unit. These final standards are codified in 40 CFR part 60, subpart 
TTTT, a new subpart specifically created for CAA 111(b) standards of 
performance for GHG emissions from fossil fuel-fired EGUs.
    In a separate action that affects the same source category, the EPA 
is issuing final emission guidelines under CAA section 111(d) for 
states to use in developing plans to limit CO2 emissions 
from existing fossil fuel-fired EGUs. Pursuant to those guidelines, 
states must submit plans to the EPA following a schedule set by the 
guidelines.
    The EPA received numerous comments and conducted extensive outreach 
to stakeholders for this rulemaking. After careful consideration of 
public comments and input from a variety of stakeholders, the final 
standards of performance in this action reflect certain changes from 
the proposals. Comments considered include written comments that were 
submitted during the public comment period and oral testimony provided 
during the public hearing for the proposed standards.
2. Summary of Major Provisions and Changes to the Proposed Standards
    The BSER determinations and final standards of performance for 
affected newly constructed, modified, and reconstructed EGUs are 
summarized in Table 1 and discussed in more detail below. The final 
standards for new, modified, and reconstructed EGUs apply to sources 
that commenced construction--or modification or reconstruction, as 
appropriate--on or after the date of publication of corresponding 
proposed standards.\2\ The final standards for newly constructed fossil 
fuel-fired EGUs apply to those sources that commenced construction on 
or after the date of publication of the proposed standards, January 8, 
2014. The final standards for modified and reconstructed fossil fuel-
fired EGUs apply to those sources that modify or reconstruct on or 
after the date of publication of the proposed standards, June 18, 2014.
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    \2\ See CAA section 111(a)(2).

     Table 1--Summary of BSER and Final Standards for Affected EGUs
------------------------------------------------------------------------
                                                      Final standards of
          Affected EGUs                  BSER             performance
------------------------------------------------------------------------
Newly Constructed Fossil Fuel-    Efficient new       1,400 lb CO2/MWh-
 Fired Steam Generating Units.     supercritical       g.
                                   pulverized coal
                                   (SCPC) utility
                                   boiler
                                   implementing
                                   partial carbon
                                   capture and
                                   storage (CCS).
Modified Fossil Fuel-Fired Steam  Most efficient      Sources making
 Generating Units.                 generation at the   modifications
                                   affected EGU        resulting in an
                                   achievable          increase in CO2
                                   through a           hourly emissions
                                   combination of      of more than 10
                                   best operating      percent are
                                   practices and       required to meet
                                   equipment           a unit-specific
                                   upgrades.           emission limit
                                                       determined by the
                                                       unit's best
                                                       historical annual
                                                       CO2 emission rate
                                                       (from 2002 to the
                                                       date of the
                                                       modification);
                                                       the emission
                                                       limit will be no
                                                       more stringent
                                                       than:
                                                      1. 1,800 lb CO2/
                                                       MWh-g for sources
                                                       with heat input
                                                       >2,000 MMBtu/h.
                                                      2. 2,000 lb CO2/
                                                       MWh-g for sources
                                                       with heat input
                                                       <=2,000 MMBtu/h.
Reconstructed Fossil Fuel-Fired   Most efficient      1. Sources with
 Steam Generating Units.           generating          heat input >2,000
                                   technology at the   MMBtu/h are
                                   affected source     required to meet
                                   (supercritical      an emission limit
                                   steam conditions    of 1,800 lb CO2/
                                   for the larger;     MWh-g.
                                   and subcritical    2. Sources with
                                   conditions for      heat input
                                   the smaller).       <=2,000 MMBtu/h
                                                       are required to
                                                       meet an emission
                                                       limit of 2,000 lb
                                                       CO2/MWh-g.

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Newly Constructed and             Efficient NGCC      1. 1,000 lb CO2/
 Reconstructed Fossil Fuel-Fired   technology for      MWh-g or 1,030 lb
 Stationary Combustion Turbines.   base load natural   CO2/MWh-n for
                                   gas-fired units     base load natural
                                   and clean fuels     gas-fired units.
                                   for non-base load  2. 120 lb CO2/
                                   and multi-fuel-     MMBtu for non-
                                   fired units.\3\     base load natural
                                                       gas-fired units.
                                                      3. 120 to 160 lb
                                                       CO2/MMBtu for
                                                       multi-fuel-fired
                                                       units.\4\
------------------------------------------------------------------------

a. Fossil Fuel-Fired Electric Utility Steam Generating Units
    This action establishes standards of performance for newly 
constructed fossil fuel-fired steam generating units \5\ based on the 
performance of a new highly efficient SCPC EGU implementing post-
combustion partial carbon capture and storage (CCS) technology, which 
the EPA determines to be the BSER for these sources. After 
consideration of a wide range of comments, technical input received on 
the availability, technical feasibility, and cost of CCS 
implementation, and publicly available information about projects that 
are implementing or planning to implement CCS, the EPA confirms its 
proposed determination that CCS technology is available and technically 
feasible to implement at fossil fuel-fired steam generating units. 
However, the EPA's final standard reflects the consideration of 
legitimate concerns regarding the cost to implement available CCS 
technology on a new steam generating unit. Accordingly, the EPA is 
finalizing an emission standard for newly constructed fossil fuel-fired 
steam generating units at 1,400 lb CO2/MWh-g, a level that 
is less stringent than the proposed limitation of 1,100 lb 
CO2/MWh-g. This final standard reflects our identification 
of the BSER for such units to be a lower level of partial CCS than we 
identified as the basis of the proposed standards--one that we conclude 
better represents the requirement that the BSER be implementable at 
reasonable cost.
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    \3\ The term ``multi-fuel-fired'' refers to a stationary 
combustion turbine that is physically connected to a natural gas 
pipeline, but that burns a fuel other than natural gas for 10 
percent or more of the unit's heat input capacity during the 12-
operating-month compliance period.
    \4\ The emission standard for combustion turbines co-firing 
natural gas with other fuels shall be determined at the end of each 
operating month based on the amount of co-fired natural gas. Units 
only burning natural gas with other fuels with a relatively 
consistent chemical composition and an emission factor of 160 lb 
CO2/MMBtu or less (e.g., natural gas, distillate oil, 
etc.) only need to maintain records of the fuels burned at the unit 
to demonstrate compliance. Units burning fuels with variable 
chemical composition or with an emission factor greater than 160 lb 
CO2/MMBtu (e.g., residual oil) must conduct periodic fuel 
sampling and testing to determine the overall CO2 
emission rate.
    \5\ Also referred to as just ``steam generating units'' or as 
``utility boilers and IGCC units''. These are units that are covered 
under 40 CFR part 60, subpart Da for criteria pollutants.
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    The EPA proposed that the BSER for newly constructed steam 
generating EGUs was highly efficient new generating technology (i.e., a 
supercritical utility boiler or IGCC unit) implementing partial CCS 
technology to achieve CO2 emission reductions resulting in 
an emission limit of 1,100 lb CO2/MWh-g.\6\
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    \6\ Using the most recent data on partial capture rates to meet 
an emission standard of 1,100 lb CO2/MWh-gross, about 35 
percent capture would be required at an SCPC unit and about 22 
percent capture would be required at an IGCC unit.
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    The BSER for newly constructed steam generating EGUs in the final 
rule is very similar to that in the January 2014 proposal. In this 
final action, the EPA finds that a highly efficient new supercritical 
pulverized coal (SCPC) utility boiler EGU implementing partial CCS to 
the degree necessary to achieve an emission of 1,400 lb CO2/
MWh-g is the BSER. Contrary to the January 2014 proposal, the EPA finds 
that IGCC technology--either with natural gas co-firing or implementing 
partial CCS--is not part of the BSER, but recognizes that IGCC 
technology can serve as an alternative method of compliance.
    The EPA finds that a highly efficient SCPC implementing partial CCS 
is the BSER because CCS technology has been demonstrated to be 
technically feasible and is in use or under construction in various 
industrial sectors, including the power generation sector. For example, 
the Boundary Dam Unit #3 CCS project in Saskatchewan, Canada is a full-
scale, fully integrated CCS project that is currently operating and is 
designed to capture more than 90 percent of the CO2 from the 
lignite-fired boiler. A newly constructed, highly efficient SCPC 
utility boiler burning bituminous coal will be able to meet this final 
standard of performance by capturing and storing approximately 16 
percent of the CO2 produced from the facility. A newly 
constructed, highly efficient SCPC utility boiler burning subbituminous 
coal or dried lignite \7\ will be able to meet this final standard of 
performance by capturing and storing approximately 23 percent of the 
CO2 produced from the facility. As an alternative compliance 
option, utilities and project developers will also be able to construct 
new steam generating units (both utility boilers and IGCC units) that 
meet the final standard of performance by co-firing with natural gas. 
This final standard of performance for newly constructed fossil fuel-
fired steam generating units provides a clear and achievable path 
forward for the construction of such sources while addressing GHG 
emissions and supporting technological innovation. The standard of 
1,400 lb CO2/MWh-g is achievable by fossil fuel-fired steam 
generating units for all fuel types, under a wide range of conditions, 
and throughout the United States.
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    \7\ For a summary of lignite drying technologies, see ``Techno-
economics of modern pre-drying technologies for lignite-fired power 
plants'' available at www.iea-coal.org.uk/documents/83436/9095/
Techno-economics-of-modern-pre-drying-technologies-for-lignite-
fired-power-plants,-CCC/241; ``Drying the lignite prior to 
combustion in the boiler is thus an effective way to increase the 
thermal efficiencies and reduce the CO2 emissions from 
lignite-fired power plants.''
---------------------------------------------------------------------------

    We note that identifying a highly efficient new SCPC EGU 
implementing partial CCS as the BSER provides a path forward for new 
fossil fuel-fired steam generation in the current market context. 
Numerous studies have predicted that few new fossil fuel-fired steam 
generating units will be constructed in the future. These analyses 
identify a range of factors unrelated to this rulemaking, including low 
electricity demand growth, highly competitive natural gas prices, and 
increases in the supply of renewable energy. The EPA recognizes that, 
in certain circumstances, there may be interest in building fossil 
fuel-fired steam generating units despite these market conditions. In 
particular, utilities and project developers may build new fossil fuel-
fired steam generating EGUs in order to achieve or maintain fuel 
diversity within generating fleets, as a hedge against the possibility 
of natural gas prices far exceeding projections, or to co-produce both 
power and chemicals, including capturing CO2 for use in 
enhanced oil

[[Page 64514]]

recovery (EOR) projects.\8\ As regulatory history has shown, 
identifying a new highly efficient SCPC EGU implementing partial CCS as 
the BSER in this rule is likely to further boost research and 
development in CCS technologies, making the implementation even more 
efficacious and cost-effective, while providing a competitive, low 
emission future for fossil fuel-fired steam generation.
---------------------------------------------------------------------------

    \8\ As the EIA has stated: Policy-related factors, such as 
environmental regulations and investment or production tax credits 
for specified generation sources, can also impact investment 
decisions. Finally, although levelized cost calculations are 
generally made using an assumed set of capital and operating costs, 
the inherent uncertainty about future fuel prices and future 
policies may cause plant owners or investors who finance plants to 
place a value on portfolio diversification. While EIA considers many 
of these factors in its analysis of technology choice in the 
electricity sector, these concepts are not included in LCOE or LACE 
calculations. http://www.eia.gov/forecasts/aeo/electricity_generation.cfm.
---------------------------------------------------------------------------

    The EPA is also issuing final standards for steam generating units 
that implement ``large modifications,'' (i.e., modifications resulting 
in an increase in hourly CO2 emissions of more than 10 
percent when compared to the source's highest hourly emissions in the 
previous 5 years).\9\ The EPA is not issuing final standards, at this 
time, for steam generating units that implement ``small modifications'' 
(i.e., modifications resulting in an increase in hourly CO2 
emissions of less than or equal to 10 percent when compared to the 
source's highest hourly emissions in the previous 5 years).
---------------------------------------------------------------------------

    \9\ 40 CFR 60.14(h) provides that no physical change, or change 
in the method of operation, at an existing electric utility steam 
generating unit will be treated as a modification provided that such 
change does not increase the maximum hourly emissions above the 
maximum hourly emissions achievable at that unit during the 5 years 
prior to the change.
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    The standards of performance for modified steam generating units 
that make large modifications are based on each affected unit's own 
best potential performance as the BSER. Specifically, such a modified 
steam generating unit will be required to meet a unit-specific 
CO2 emission limit determined by that unit's best 
demonstrated historical performance (in the years from 2002 to the time 
of the modification).\10\ The EPA has determined that this standard 
based on each unit's own best potential performance can be met through 
a combination of best operating practices and equipment upgrades and 
that these steps can be implemented cost-effectively at the time when a 
source is undertaking a large modification. To account for facilities 
that have already implemented best practices and equipment upgrades, 
the final rule also specifies that modified facilities will not have to 
meet an emission standard more stringent than the corresponding 
standard for reconstructed steam generating units (i.e., 1,800 lb 
CO2/MWh-g for units with heat input greater than 2,000 
MMBtu/h and 2,000 lb CO2/MWh-g for units with heat input 
less than or equal to 2,000 MMBtu/h).
---------------------------------------------------------------------------

    \10\ For the 2002 reporting year the EPA introduced new 
automated checks in the software that integrated automated quality 
assurance (QA) checks on the hourly data. Thus, the EPA believes 
that the data from 2002 and forward are of higher quality.
---------------------------------------------------------------------------

    The final standards for steam generating units implementing large 
modifications are similar to the proposed standards for such units. In 
the proposal, we suggested that the standard should be based on when 
the modification is undertaken (i.e., before being subject to 
requirements under a CAA section 111(d) state plan or after being 
subject to such a plan). We also suggested that for units that 
undertake modifications prior to becoming subject to an approved CAA 
section 111(d) state plan, the standard should be its best historical 
performance plus an additional two percent reduction. In response to 
comments on the proposal, we are not finalizing separate standards that 
are dependent upon when the modification takes place, nor are we 
finalizing the proposed additional two percentage reduction.
    The EPA is not promulgating final standards of performance for, and 
is withdrawing the proposed standards for steam generating sources that 
make modifications resulting in an increase of hourly CO2 
emissions of less than or equal to 10 percent (see Section XV of this 
preamble). As we indicated in the proposal, the EPA has been notified 
of very few modifications for criteria pollutant emissions from the 
power sector to which NSPS requirements have applied. As such, we 
expect that there will be few NSPS modifications for GHG emissions as 
well. Even so, we also recognize (and we discuss in this preamble) that 
the power sector is undergoing significant change and realignment in 
response to a variety of influences and incentives in the industry. We 
do not have sufficient information at this time, however, to anticipate 
the types of modifications, if any, that may result from these changes. 
In particular, we do not have sufficient information about the types of 
modifications, if any, that would result in increases in CO2 
emissions of 10 percent or less, and what the appropriate standard for 
such sources would be. Therefore, we conclude that it is prudent to 
delay issuing standards for sources that undertake small modifications 
(i.e., those resulting in an increase in CO2 emissions of 
less than or equal to 10 percent).
    For reconstructed steam generating units, the EPA is finalizing 
standards based on the performance of the most efficient generating 
technology for these types of units as the BSER (i.e., reconstructing 
the boiler if necessary to use steam with higher temperature and 
pressure, even if the boiler was not originally designed to do so).\11\ 
The emission standard for these sources is 1,800 lb CO2/MWh-
g for large sources, (i.e. those with a heat input rating of greater 
than 2,000 MMBtu/h) or 2,000 lb CO2/MWh-g for small sources 
(i.e., those with a heat input rating of 2,000 MMBtu/h or less). The 
difference in the standards for larger and smaller units is based on 
greater availability of higher pressure/temperature steam turbines 
(e.g., supercritical steam turbines) for larger units. The standards 
can also be met through other non-BSER options, such as natural gas co-
firing.
---------------------------------------------------------------------------

    \11\ Steam with higher temperature and pressure has more thermal 
energy that can be more efficiently converted to electrical energy.
---------------------------------------------------------------------------

b. Stationary Combustion Turbines
    This action also finalizes standards of performance for newly 
constructed and reconstructed stationary combustion turbines. In the 
January 2014 proposal for newly constructed EGUs, the EPA proposed that 
natural gas-fired stationary combustion turbines (i.e., turbines 
combusting over 90 percent natural gas) would be subject to a standard 
of performance for CO2 emissions if they are constructed for 
the purpose of supplying and actually annually supply to the grid (1) 
one-third or more of their potential electric output \12\ and (2) more 
than 219,000 MWh,\13\ based on a three-year rolling average. We refer 
to units that operate above the electric sales thresholds as ``base 
load units,'' and we refer to units that operate below these thresholds 
as ``non-base load units.''
---------------------------------------------------------------------------

    \12\ We refer to thresholds related to an EGU's actual annual 
electrical sales (as a fraction of potential annual output) as 
``percentage electric sales criteria.''
    \13\ We refer to thresholds related to an EGU's actual annual 
electrical sales in megawatt-hours as ``total electric sales 
criteria.''
---------------------------------------------------------------------------

    In the January 2014 proposal for newly constructed combustion 
turbines, the EPA proposed standards for two subcategories of base load 
natural gas-fired stationary combustion turbines. The proposed standard 
for small combustion turbines (units with base load ratings less than 
or equal to 850 MMBtu/h) was 1,100 lb CO2/MWh-g. The 
proposed standard for large combustion turbines (units with base

[[Page 64515]]

load ratings greater than 850 MMBtu/h) was 1,000 lb CO2/MWh-
g. The EPA did not propose standards for non-base load units.
    In the June 2014 proposal for modified and reconstructed combustion 
turbines, the EPA solicited comment on alternative approaches for 
establishing applicability and subcategorization criteria, including 
(1) eliminating the ``constructed for the purpose of supplying'' 
qualifier for the total electric sales and percentage electric sales 
criteria, (2) eliminating the 219,000 MWh total electric sales 
criterion altogether, (3) replacing the fixed percentage electric sales 
criterion with a variable percentage electric sales criterion (i.e., 
the sliding-scale approach \14\), and (4) eliminating the proposed 
small and large subcategories for base load natural gas-fired 
combustion turbines. These proposed applicability requirements were 
intended to exclude combustion turbines that are used for the purpose 
of meeting peak power demand, as opposed to those that are used to meet 
base load power demand.
---------------------------------------------------------------------------

    \14\ The sliding-scale approach determines a unit-specific 
percentage electric sales threshold equivalent to a unit's net 
design efficiency (the maximum value is capped at 50 percent).
---------------------------------------------------------------------------

    In both proposals, the EPA also solicited comment on a broad 
applicability approach that would include non-base load natural gas-
fired units (primarily simple cycle combustion turbines) and multi-
fuel-fired units (primarily distillate oil-fired combustion turbines) 
in the general applicability of subpart TTTT. As part of the broad 
applicability approach, the EPA solicited comment on imposing ``no 
emission standard'' or establishing separate numerical limits for these 
two subcategories.
    In this action, the EPA is finalizing a variation of the approaches 
put forward in the January 2014 proposal for new sources and the June 
2014 proposal for modified and reconstructed sources. Based on our 
review of public comments related to the proposed subcategories for 
small and large combustion turbines and our additional data analyses, 
we have determined that there is no need to set two separate standards 
for different sizes of combustion turbines for base load natural gas-
fired combustion turbines. The EPA has determined that all sizes of 
affected newly constructed and reconstructed stationary combustion 
turbines can achieve the final standards. For newly constructed and 
reconstructed base load natural gas-fired stationary combustion 
turbines, the EPA is finalizing a standard of 1,000 lb CO2/
MWh-g based on efficient natural gas combined cycled (NGCC) technology 
as the BSER. Alternatively, owners and operators of base load natural 
gas-fired combustion turbines may elect to comply with a standard based 
on net output of 1,030 lb CO2/MWh-n.
    The EPA is eliminating the 219,000 MWh total annual electric sales 
criterion for non-CHP units. In addition, the EPA is finalizing the 
sliding-scale approach for deriving the unit-specific, percentage 
electric sales threshold above which a combustion turbine transitions 
from the subcategory for non-base load units to the subcategory for 
base load units. For newly constructed and reconstructed non-base load 
natural gas-fired stationary combustion turbines, the EPA is finalizing 
the combustion of clean fuels (natural gas with a small allowance for 
distillate oil) as the BSER with a corresponding heat input-based 
standard of 120 lb CO2/MMBtu. This standard of performance 
will apply to the vast majority of simple cycle combustion turbines. 
The EPA is finalizing a heat input-based clean fuels standard because 
we have insufficient information at this time to set a uniform output-
based standard that can be achieved by all new and reconstructed non-
base load units.
    In addition, for newly constructed and reconstructed multi-fuel-
fired stationary combustion turbines, the EPA is finalizing an input-
based standard of 120 to 160 lb CO2/MMBtu based on the 
combustion of clean fuels as the BSER.\15\ The EPA has similarly 
determined that it has insufficient information at this time to set a 
uniform output-based standard for stationary combustion turbines that 
operate with significant quantities of a fuel other than natural gas.
---------------------------------------------------------------------------

    \15\ Combustion turbines co-firing natural gas with other fuels 
shall determine fuel-based site-specific standards at the end of 
each operating month. The site-specific standards depend on the 
amount of co-fired natural gas.
---------------------------------------------------------------------------

    We are not promulgating final standards of performance for 
stationary combustion turbines that make modifications at this time. We 
are simultaneously withdrawing the proposed standards for modifications 
(see Section XV of this preamble). As we indicated in the proposal, 
sources from the power sector have notified the EPA of very few NSPS 
modifications, and we expect that there will be few NSPS modifications 
for CO2 emissions as well. Moreover, our decision to 
eliminate the subcategories for small and large EGUs and set a single 
standard of 1,000 lb CO2/MWh-g has raised questions as to 
whether smaller existing combustion turbines that undertake a 
modification can meet this standard. As a result, we have concluded 
that it is prudent to delay issuing standards for sources that 
undertake modifications until we can gather more information.
    A more detailed discussion of the final standards of performance 
for stationary combustion turbines, the applicability criteria, and the 
comments that influenced the final standards is provided in Sections 
VIII and IX of this preamble.
3. Costs and Benefits
    As explained in the regulatory impact analysis (RIA) for this final 
rule, available data--including utility announcements and Energy 
Information Administration (EIA) modeling--indicate that, even in the 
absence of this rule, (i) existing and anticipated economic conditions 
are such that few, if any, fossil fuel-fired steam-generating EGUs will 
be built in the foreseeable future, and (ii) utilities and project 
developers are expected to choose new generation technologies 
(primarily NGCC) that would meet the final standards and renewable 
generating sources that are not affected by these final standards. 
These projections are consistent with utility announcements and EIA 
modeling that indicate that new units are likely to be NGCC and that 
any coal-fired steam generating units built between now and 2030 would 
have CCS, even in the absence of this rule.\16\ Therefore, based on the 
analysis presented in Chapter 4 of the RIA, the EPA projects that this 
final rule will result in negligible CO2 emission changes, 
quantified benefits, and costs by 2022 as a result of the performance 
standards for newly constructed EGUs.\17\ However, as noted earlier, 
for a variety of reasons, some companies may consider coal-fired steam 
generating units that the modeling does not anticipate. Thus, in 
Chapter 5 of the RIA, we also present an analysis of the project-level 
costs of a newly constructed coal-fired steam generating unit with 
partial CCS that meets the requirements of this final rule alongside 
the project-level costs of a newly constructed coal-fired unit without 
CCS. This analysis indicates that the

[[Page 64516]]

quantified benefits of the standards of performance would exceed their 
costs under a range of assumptions.
---------------------------------------------------------------------------

    \16\ The EPA's Integrated Planning Model (IPM) projects no new 
non-compliant coal (i.e., newly constructed coal-fired plants that 
do not meet the final standard of performance) throughout the model 
horizon of 2030 (there is a small amount of new coal with CCS that 
is hardwired into the modelling, consistent with EIA assumptions to 
represent units already under construction or under development).
    \17\ Conditions in the analysis year of 2022 are represented by 
a model year of 2020.
---------------------------------------------------------------------------

    As explained in the RIA and further below, the EPA has been 
notified of few power sector NSPS modifications or reconstructions. 
Based on that experience, the EPA expects that few EGUs will trigger 
either the modification or the reconstruction provisions that we are 
finalizing in this action. In Chapter 6 of the RIA, we discuss factors 
that limit our ability to quantify the costs and benefits of the 
standards for modified and reconstructed sources.

B. Does this action apply to me?

    The entities potentially affected by the standards are shown in 
Table 2 below.

                Table 2--Potentially Affected Entities a
------------------------------------------------------------------------
                                                 Examples of potentially
            Category               NAICS code       affected entities
------------------------------------------------------------------------
Industry.......................          221112  Fossil fuel electric
                                                  power generating
                                                  units.
Federal Government.............       \b\221112  Fossil fuel electric
                                                  power generating units
                                                  owned by the federal
                                                  government.
State/Local Government.........       \b\221112  Fossil fuel electric
                                                  power generating units
                                                  owned by
                                                  municipalities.
Tribal Government..............          921150  Fossil fuel electric
                                                  power generating units
                                                  in Indian Country.
------------------------------------------------------------------------
\a\ Includes NAICS categories for source categories that own and operate
  electric power generating units (including boilers and stationary
  combined cycle combustion turbines).
\b\ Federal, state, or local government-owned and operated
  establishments are classified according to the activity in which they
  are engaged.

    This table is not intended to be exhaustive, but rather to provide 
a guide for readers regarding entities likely to be affected by this 
action. To determine whether your facility, company, business, 
organization, etc., would be regulated by this action, refer to Section 
III of this preamble for more information and examine the applicability 
criteria in 40 CFR 60.1 (General Provisions) and Sec.  60.550840 of 
subpart TTTT (Standards of Performance for Greenhouse Gas Emissions for 
Electric Utility Generating Units). If you have any questions regarding 
the applicability of this action to a particular entity, consult either 
the air permitting authority for the entity or your EPA regional 
representative as listed in 40 CFR 60.4 or 40 CFR 63.13 (General 
Provisions).

C. Where can I get a copy of this document?

    In addition to being available in the docket, an electronic copy of 
this final action will also be available on the Worldwide Web (WWW). 
Following signature, a copy of this final action will be posted at the 
following address: http://www2.epa.gov/carbon-pollution-standards.

D. Judicial Review

    Under section 307(b)(1) of the CAA, judicial review of this final 
rule is available only by filing a petition for review in the U.S. 
Court of Appeals for the District of Columbia Circuit by December 22, 
2015. Moreover, under section 307(b)(2) of the CAA, the requirements 
established by this final rule may not be challenged separately in any 
civil or criminal proceedings brought by the EPA to enforce these 
requirements. Section 307(d)(7)(B) of the CAA further provides that 
``[o]nly an objection to a rule or procedure which was raised with 
reasonable specificity during the period for public comment (including 
any public hearing) may be raised during judicial review.'' This 
section also provides a mechanism mandating the EPA to convene a 
proceeding for reconsideration if the person raising an objection can 
demonstrate that it was impracticable to raise such objection within 
the period for public comment or if the grounds for such objection 
arose after the period for public comment (but within the time 
specified for judicial review) and if such objection is of central 
relevance to the outcome of the rule. Any person seeking to make such a 
demonstration should submit a Petition for Reconsideration to the 
Office of the Administrator, U.S. EPA, Room 3000, Ariel Rios Building, 
1200 Pennsylvania Ave. NW., Washington, DC 20460, with a copy to both 
the person(s) listed in the preceding FOR FURTHER INFORMATION CONTACT 
section, and the Associate General Counsel for the Air and Radiation 
Law Office, Office of General Counsel (Mail Code 2344A), U.S. EPA, 1200 
Pennsylvania Ave. NW., Washington, DC 20460.

E. How is this preamble organized?

    This action presents the EPA's final standards of performance for 
newly constructed, modified, and reconstructed fossil fuel-fired 
electric utility steam generating units and newly constructed and 
reconstructed stationary combustion turbines. Section II provides 
background information on climate change impacts from GHG emissions, 
GHG emissions from fossil fuel-fired EGUs, the utility power sector, 
the statutory and regulatory background relating to CAA section 111(b), 
EPA actions prior to this final action, and public comments regarding 
the proposed actions. Section III explains the EPA's authority to 
regulate CO2 and EGUs, identifies affected EGUs, and 
describes the source categories. Section IV provides a summary of the 
final standards for newly constructed, modified, and reconstructed 
fossil fuel-fired steam generating units. Sections V through VII 
present the rationale for the final standards for newly constructed, 
modified, and reconstructed steam generating units, respectively. 
Sections VIII and IX provide a summary of the final standards for 
stationary combustion turbines and present the rationale for the final 
standards for newly constructed and reconstructed combustion turbines, 
respectively. Section X provides a summary of other final requirements 
for newly constructed, modified, and reconstructed fossil fuel-fired 
steam generating units and stationary combustion turbines. Section XI 
addresses the consistency of the respective BSER determinations in 
these rules and under the emission guidelines issued separately under 
CAA section 111(d). Interactions with other EPA programs and rules are 
described in Section XII. Projected impacts of the final action are 
then described in Section XIII, followed by a discussion of statutory 
and executive order reviews in Section XIV. Section XV addresses the 
withdrawal of the proposed standards for steam generating EGUs that 
make modifications resulting in an increase of hourly CO2 
emissions of less than or equal to 10 percent and the proposed 
standards for modified stationary combustion turbines. The statutory 
authority for this action is provided in Section XVI. We address major 
comments throughout this preamble and in greater detail in an 
accompanying response-to-comments document located in the docket.

[[Page 64517]]

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 and 
describe the utility power sector and its changing structure. We then 
summarize the statutory and regulatory background relevant to this 
final rulemaking. In addition, we provide background information on the 
EPA's January 8, 2014 proposed carbon pollution standards for newly 
constructed fossil fuel-fired EGUs, the June 18, 2014 proposed carbon 
pollution standards for modified and reconstructed EGUs, and other 
actions associated with this final rulemaking. We close this section 
with a general discussion of comments and stakeholder input that the 
EPA received prior to issuing this final rulemaking.

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.'' \18\
---------------------------------------------------------------------------

    \18\ 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).\19\ 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 United States. We summarize these 
adverse effects on public health and welfare briefly here.
---------------------------------------------------------------------------

    \19\ ``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 United States. 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 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 flood 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 III.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

[[Page 64518]]

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 United States 
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 United States 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.'' \20\ In addition, 
increasing temperatures and loss of Arctic sea ice increases the risk 
of drowning for those engaged in traditional hunting and fishing.
---------------------------------------------------------------------------

    \20\ 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.
---------------------------------------------------------------------------

    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 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.\21\ In fact, that 
assessment stated that ``the magnitude and rate of the present 
greenhouse gas 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.'' \22\ 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 irreversible impacts that are 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.
---------------------------------------------------------------------------

    \21\ National Research Council, Understanding Earth's Deep Past, 
p. 1.
    \22\ 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

[[Page 64519]]

average global temperatures by the end of the century will likely be 
2.6 degrees Celsius ([deg]C) to 4.8 [deg]C (4.7 to 8.6 degrees 
Fahrenheit ([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 [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 CO2 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,'' \23\ 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 
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.'' \24\ 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.
---------------------------------------------------------------------------

    \23\ NRC, 2011: National Security Implications of Climate Change 
for U.S. Naval Forces. The National Academies Press, p. 28.
    \24\ 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 United States and have a 
greater impact on certain populations, such as indigenous peoples and 
the poor. The NCA3 finds that 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.'' \25\ 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.'' \26\
---------------------------------------------------------------------------

    \25\ 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.
    \26\ 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.
---------------------------------------------------------------------------

    CO2 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 that 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 CO2 
emissions; the rate of change exceeds any known to have occurred for at 
least the past

[[Page 64520]]

hundreds of thousands of years.'' \27\ 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.'' \28\
---------------------------------------------------------------------------

    \27\ NRC, 2010: Ocean Acidification: A National Strategy to Meet 
the Challenges of a Changing Ocean. The National Academies Press, p. 
5.
    \28\ Id.
---------------------------------------------------------------------------

    Events outside the United States, 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 United States. 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 [deg]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 have 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 has 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 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.\29\ 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 based on ice core 
records.\30\ 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.\31\ 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.\32\ The first months of 2015 have also been 
some of the warmest on record.
---------------------------------------------------------------------------

    \29\ ftp://aftp.cmdl.noaa.gov/products/trends/co2/co2_annmean_mlo.txt.
    \30\ http://www.esrl.noaa.gov/gmd/ccgg/trends/.
    \31\ Blunden, J., and D. S. Arndt, Eds., 2014: State of the 
Climate in 2013. Bull. Amer. Meteor. Soc., 95 (7), S1-S238.
    \32\ 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.'' \33\ For 
example:
---------------------------------------------------------------------------

    \33\ 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 greenhouse gases is on the higher end of 
the estimated range.
     Waiting for unacceptable impacts to occur before taking 
action is imprudent because the effects of greenhouse gas 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 eight regions of the 
United States, 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 [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 [deg]F of warming by

[[Page 64521]]

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 [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 
[deg]F. There have been increasing numbers of days above 95 [deg]F and 
nights above 75 [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 [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 is generally smaller than for other regions of the United States, 
projected warming for interior states of the region is larger than 
coastal regions by 1 [deg]F to 2 [deg]F. Projections further suggest 
that there will be fewer tropical storms globally, 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 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 to 
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 United States. 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[emsp14][deg]F in the 
northernmost parts of Alaska, by 8 to 10[emsp14][deg]F in the interior, 
and by 6 to 8[emsp14][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

[[Page 64522]]

or 8 inches in this region, contributing to inundation of Highway 101 
and back up 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[emsp14][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[emsp14][deg]F in the Southern 
Plains and more than 95[emsp14][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 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[emsp14][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[emsp14][deg]F by 2055 and 4.7[emsp14][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

    Fossil fuel-fired EGUs are by far the largest emitters of GHGs 
among stationary sources in the U.S., primarily in the form of 
CO2. 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 \34\ (the U.S. GHG Inventory).
---------------------------------------------------------------------------

    \34\ ``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 \35\ (GHGRP) that requires 
emitting facilities that emit over certain 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.
---------------------------------------------------------------------------

    \35\ 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

[[Page 64523]]

Change (UNFCCC). This inventory, which includes recent trends, is 
organized by industrial sector. It provides the information in Table 3 
below, which presents total U.S. anthropogenic emissions and sinks \36\ 
of GHGs, including CO2 emissions, for the years 1990, 2005 
and 2013.
---------------------------------------------------------------------------

    \36\ Sinks are physical units or processes that store GHGs, such 
as forests or underground or deep sea reservoirs of CO2.
    \37\ From Table ES-4 of ``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.
    \38\ 1 metric ton (tonne) is equivalent to 1,000 kilograms (kg) 
and is equivalent to 1.1023 short tons or 2,204.62 pounds (lb).
    \39\ 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 CO2e))\37\
                                                      \38\
----------------------------------------------------------------------------------------------------------------
                         Sector                                 1990               2005               2013
----------------------------------------------------------------------------------------------------------------
Energy\39\.............................................            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.\40\ In 2013, fossil fuel 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.\41\ Table 4 below presents 
total CO2 emissions from fossil fuel-fired EGUs, for years 
1990, 2005, and 2013.
---------------------------------------------------------------------------

    \40\ 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.
    \41\ 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)\42\
----------------------------------------------------------------------------------------------------------------
                     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 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.
---------------------------------------------------------------------------

    \42\ 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.
    \43\ U.S. EPA Greenhouse Gas Reporting Program Dataset as of 
August 18, 2014. http://ghgdata.epa.gov/ghgp/main.do.

   Table 5--Direct GHG Emissions Reported to GHGRP by Largest Emitting
                    Industrial Sectors (MMT CO2e)\43\
------------------------------------------------------------------------
                  Industrial sector                           2013
------------------------------------------------------------------------
Fossil Fuel-Fired EGUs...............................            2,039.8
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
------------------------------------------------------------------------


[[Page 64524]]

    It should be noted that the discussion above concerned all fossil 
fuel-fired EGUs. Steam generators emitted 1,627 MMT CO2e and 
combustion turbines emitted 401 MMT CO2e in 2013.\44\
---------------------------------------------------------------------------

    \44\ These figures are based on data for EGUs in the Acid Rain 
Program plus additional ones that report to the EPA under the 
Regional Greenhouse Gas Initiative.
---------------------------------------------------------------------------

C. The Utility Power Sector

1. Modern Electric System Trends
    The EPA includes a background discussion of the electricity system 
in the Clean Power Plan (CPP) rulemaking, which is the companion 
rulemaking to this rule that promulgates emission guidelines for states 
to use in regulating emissions of CO2 from existing fossil 
fuel-fired EGUs. Readers are referred to that rulemaking. The following 
discussion of electricity sector trends is of particular relevance for 
this rulemaking.
    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., with smaller 
amounts being provided by other types of generation, including nuclear 
and renewables such as wind, solar, and hydroelectric power. Coal has 
historically provided the largest percentage of fossil-fuel 
generation.\45\ 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.\46\ In 2013, fossil fuels supplied 67 
percent of U.S. electricity, but renewables made up 38 percent of the 
new generation capacity (over 5 GW out of 13.5 GW).\47\ From 2007 to 
2014, use of lower- and zero-carbon energy sources has grown, while 
other major energy sources such as coal and oil have experienced 
declines. Renewable electricity generation, including from large hydro-
electric projects, grew from 8 percent to 13 percent over that time 
period.\48\ Between 2000 and 2013, approximately 90 percent of new 
power generation capacity built in the U.S. has come in the form of 
natural gas or renewable energy facilities.\49\ 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, 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.\50\
---------------------------------------------------------------------------

    \45\ U.S. Energy Information Administration, ``Table 7.2b 
Electricity Net Generation: Electric Power Sector'' data from April 
2014 Monthly Energy Review, release data April 25, 2014, available 
at http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf.
    \46\ U.S. Energy Information Administration, ``Table 7.2b 
Electricity Net Generation: Electric Power Sector'' data from April 
2014 Monthly Energy Review, release data April 25, 2014, available 
at http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf.
    \47\ 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 renewable energy 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.
    \48\ 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.
    \49\ Energy Information Administration, Electricity: Form EIA-
860 detailed data (Feb. 17, 2015), available at http://www.eia.gov/electricity/data/eia860/.
    \50\ EIA, Annual Energy Outlook for 2015 with Projections to 
2040, Final Release, available at http://www.eia.gov/forecasts/AEO/pdf/0383(2015). The AEO numbers include projects that are under 
development and model-projected nuclear, coal, and NGCC projects.
---------------------------------------------------------------------------

    The change in the resource mix has accelerated in recent years, but 
wind, solar, other renewables, and energy-efficiency resources 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.\51\ For example, the average 
age of U.S. coal steam units in 2015 is 45 years.\52\ 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.'' \53\ While there has been an 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.''\54\ 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\55\ with the lowest possible 
emissions and the greatest efficiency.
---------------------------------------------------------------------------

    \51\ Quadrennial Energy Review, http://energy.gov/epsa/quadrennial-energy-review-qer.
    \52\ We calculated the average age of coal steam units based on 
the NEEDS inventory, and included units with planned retirements in 
2015-2016. See http://www.epa.gov/airmarkets/documents/ipm/needs_v514.xlsx.
    \53\ American Society for Civil Engineers, 2013 Report Card for 
America's Infrastructure (2013), available at http://www.infrastructurereportcard.org/energy/.
    \54\ American Society for Civil Engineers, 2013 Report Card for 
America's Infrastructure (2013), available at http://www.infrastructurereportcard.org/energy/.
    \55\ Business Council for Sustainable Energy Comments in Docket 
Id. No. EPA-HQ-OAR-2013-0602 at 2 (Nov. 19, 2014).
---------------------------------------------------------------------------

    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 36 percent between 2004 and 2014.\56\ In 2014, natural 
gas accounted for approximately 27 percent of net generation.\57\ The 
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.\58\
---------------------------------------------------------------------------

    \56\ U.S. Energy Information Administration (EIA), Electric 
Power Monthly: Table 1.1 Net Generation by Energy Source: Total (All 
Sectors), 2004-December 2014 (2015), available at http://www.eia.gov/electricity/monthly/epm_table_grapher.cfm?t=epmt_1_1.
    \57\ Id.
    \58\ The AEO 2015 Reference case projection is a business-as-
usual trend estimate, given known technology and technological and 
demographic trends. EIA explores the impacts of alternative 
assumptions in other cases with different macroeconomic growth 
rates, world oil prices, and resource assumptions. 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.
---------------------------------------------------------------------------

    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 renewable energy 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).\59\ QFs were either cogeneration 
facilities \60\ or small

[[Page 64525]]

generation resources that use renewables such as wind, solar, biomass, 
geothermal, or hydroelectric power as their primary fuels.\61\ Through 
PURPA, Congress supported the development of more renewable energy 
generation in the U.S. States have 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.\62\ In its AEO 2015 Reference case, the EIA found that 
renewable energy will account for 38 percent of the overall growth in 
electricity generation from 2013 to 2040.\63\ The AEO 2015 Reference 
case forecasts that the renewables share of U.S. electricity generation 
will grow from 13 percent in 2013 to 18 percent in 2040.\64\
---------------------------------------------------------------------------

    \59\ Casazza, J. and Delea, F., Understanding Electric Power 
Systems, IEEE Press, at 220-221 (2d ed. 2010).
    \60\ 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).
    \61\ Casazza, J. and Delea, F., Understanding Electric Power 
Systems, IEEE Press, at 220-221 (2d ed. 2010).
    \62\ U.S. Energy Information Administration (EIA), Annual Energy 
Outlook 2014 with Projections to 2040, at LR-5 (2014).
    \63\ U.S. Energy Information Administration (EIA), Annual Energy 
Outlook 2015 with Projections to 2040, at E-12 (2015).
    \64\ U.S. Energy Information Administration (EIA), Annual Energy 
Outlook 2015 with Projections to 2040, at 24-25(2015).
---------------------------------------------------------------------------

    Price pressures caused by oil embargoes in the 1970s also brought 
the issues of conservation and energy efficiency to the forefront of 
U.S. energy policy.\65\ This trend continued in the early 1990s. Some 
state regulatory commissions and utilities supported energy efficiency 
through least-cost planning, with the National Association of 
Regulatory Utility Commissioners (NARUC) ``adopting a resolution that 
called for the utility's least cost plan to be the utility's most 
profitable plan.'' \66\ Energy efficiency has been utilized to meet 
energy demand to varying levels since that time. As of April 2014, 25 
states \67\ have ``enacted long-term (3+ years), binding energy savings 
targets, or energy efficiency resource standards (EERS).'' \68\ Funding 
for energy efficiency programs has grown rapidly in recent years, with 
budgets for electric efficiency programs totaling $5.9 billion in 
2012.\69\
---------------------------------------------------------------------------

    \65\ Edison Electric Institute, Making a Business of Energy 
Efficiency: Sustainable Business Models for Utilities, at 1 (2007). 
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.
    \66\ 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.
    \67\ 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.
    \68\ 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.
    \69\ 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.
---------------------------------------------------------------------------

    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.
2. Fossil Fuel-Fired EGUs Regulated by this Action, Generally
    Natural gas-fired EGUs typically use one of two technologies: NGCC 
or simple cycle combustion turbines. NGCC units first generate power 
from a combustion turbine (the combustion cycle). The unused heat from 
the combustion turbine is then routed to a heat recovery steam 
generator (HRSG) that generates steam, which is then used to produce 
power using a steam turbine (the steam cycle). Combining these 
generation cycles increases the overall efficiency of the system. 
Simple cycle combustion turbines use a single combustion turbine to 
produce electricity (i.e., there is no heat recovery or steam cycle). 
The power output from these simple cycle combustion turbines can be 
easily ramped up and down making them ideal for ``peaking'' operations.
    Coal-fired utility boilers are primarily either pulverized coal 
(PC) boilers or fluidized bed (FB) boilers. At a PC boiler, the coal is 
crushed (pulverized) into a powder in order to increase its surface 
area. The coal powder is then blown into a boiler and burned. In a 
coal-fired boiler using FB combustion, the coal is burned in a layer of 
heated particles suspended in flowing air.
    Power can also be generated using gasification technology. An IGCC 
unit gasifies coal or petroleum coke to form a synthetic gas (or 
syngas) composed of carbon monoxide (CO) and hydrogen (H2), 
which can be combusted in a combined cycle system to generate power.
3. Technological Developments and Costs
    Natural gas prices have decreased dramatically and generally 
stabilized in recent years as new drilling techniques have brought 
additional supply to the marketplace and greatly increased the domestic 
resource base. As a result, natural gas prices are expected to be 
competitive for the foreseeable future, and EIA modeling and utility 
announcements confirm that utilities are likely to rely heavily on 
natural gas to meet new demand for electricity generation. On average, 
as discussed below, the cost of generation from a new natural-gas fired 
power plant (a NGCC unit) is expected to be significantly lower than 
the cost of generation from a new coal-fired power plant.\70\
---------------------------------------------------------------------------

    \70\ Levelized Cost and Levelized Avoided Cost of New Generation 
Resources in the Annual Energy Outlook 2015 http://www.eia.gov/forecasts/aeo/electricity_generation.html.
---------------------------------------------------------------------------

    Other drivers that may influence decisions to build new power 
plants are increases in renewable energy supplies, often due to state 
and federal energy policies. As previously discussed, many states have 
adopted RPS, which require a certain portion of electricity to come 
from renewable energy sources such as solar or wind. The federal 
government has also offered incentives to encourage further deployment 
of other forms of electric generation including renewable energy 
sources and new nuclear power plants.
    Reflecting these factors, the EIA projections from the last several 
years show that natural gas is likely to be the most widely-used fossil 
fuel for new construction of electric generating capacity through 2020, 
along with renewable energy, nuclear power, and a limited amount of 
coal with CCS.\71\
---------------------------------------------------------------------------

    \71\ http://www.eia.gov/forecasts/aeo/pdf/0383(2013).pdf; http:/
/www.eia.gov/forecasts/aeo/pdf/0383(2012).pdf; http://prod-http-80-800498448.us-east-1.elb.amazonaws.com/w/images/6/6d/0383%282011%29.pdf.
---------------------------------------------------------------------------

    While EIA data shows that natural gas is likely to be the most 
widely-used fossil fuel for new construction of electric generating 
capacity through 2030, a few coal-fired units still remain as viable 
projects at various advanced stages of construction and development. 
One new coal facility that has essentially completed construction,

[[Page 64526]]

Southern Company's Kemper County Energy Facility, deploys IGCC with 
partial CCS. Additionally, another project, Summit Power's Texas Clean 
Energy Project (TCEP), which will deploy IGCC with CCS, continues as a 
viable project.\72\ The EIA modeling projects that coal-fired power 
generation will remain the single largest portion of the electricity 
sector beyond 2030. The EIA modeling also projects that few, if any, 
new coal-fired EGUs will be built in this decade and that those that 
are built will have CCS.\73\ Continued progress on these projects is 
consistent with the EIA modeling that suggests that a small number of 
coal-fired power plants may be constructed. The primary reasons for 
this rate of current and projected future development of new coal 
projects include highly competitive natural gas prices, lower 
electricity demand growth, and increases in the supply of renewable 
energy. We recognize, however, that a variety of factors may come into 
play in a decision to build new power generation, and we want to ensure 
that there are standards in place to make sure that whatever fuel is 
utilized is done so in a way that minimizes CO2 emissions, 
as Congress intended with CAA section 111.\74\
---------------------------------------------------------------------------

    \72\ ``Odessa coal-to-gas power plant to break ground this 
year'', Houston Chronicle (April 1, 2015).
    \73\ This projection is for business as usual and does not 
account for the proposed or final CO2 emission standard. 
Even in its sensitivity analysis that assumes higher natural gas 
prices and electricity demand, EIA does not project any additional 
coal-fired power plants beyond its reference case until 2023, in a 
case where power companies assume no GHGs emission limitations, and 
until 2024 in a case where power companies do assume GHGs emission 
limitations.
    \74\ These sources received federal assistance under EPAct 2005. 
See Section III.H.3.g below. However, none of the constraints in 
that Act affect the discussion in the text above, since that 
discussion does not relate to technology use or emissions reduction 
by these sources.
---------------------------------------------------------------------------

4. Energy Sector Modeling
    Various energy sector modeling efforts, including projections from 
the EIA and the EPA, forecast trends in new power plant construction 
and utilization of existing power plants that are consistent with the 
above-described technological developments and costs. The EIA's annual 
report, the AEO, forecasts the structure of and developments in the 
power sector. These reports are based on economic modeling that 
reflects existing policy and regulations, such as state RPS programs 
and federal tax credits for renewables.\75\ The current report, AEO 
2015: \76\ (i) Shows that a modest amount of coal-fired power plants 
that are currently under construction are expected to begin operation 
in the next several years (referred to as ``planned''); and (ii) 
projects in the reference case \77\ that a very small amount of new 
(``unplanned'') conventional coal-fired capacity, with CCS, will come 
online after 2012 and through 2037 in response to federal and state 
incentives. According to the AEO 2015, the vast majority of new 
generating capacity during this period will be either natural gas-fired 
or renewable sources. Similarly, the EIA projections from the last 
several years show that natural gas is likely to be the most widely-
used fossil fuel for new construction of electric generating capacity 
through 2030.\78\
---------------------------------------------------------------------------

    \75\ http://www.eia.gov/forecasts/aeo/chapter_legs_regs.cfm.
    \76\ Energy Information Administration's Annual Energy Outlook 
for 2015, Final Release available at http://www.eia.gov/forecasts/aeo/index.cfm.
    \77\ EIA's reference case projections are the result of its 
baseline assumptions for economic growth, fuel supply, technology, 
and other key inputs.
    \78\ Annual Energy Outlook 2010, 2011, 2012, 2013, 2014 and 
2015.
---------------------------------------------------------------------------

    Specifically, the AEO 2015 projects 30.3 GW of additional base load 
or intermediate load generation capacity through 2020 (this includes 
projects that are under development--i.e., being constructed or in 
advance planning--and model-projected nuclear, coal, and NGCC 
projects). The vast majority of this new electric capacity (20.4 GW) is 
already under development (under construction or in advanced planning); 
it includes about 0.7 GW of new coal-fired capacity, 5.5 GW of new 
nuclear capacity, and 14.2 GW of new NGCC capacity. The EPA believes 
that most current fossil fuel-fired projects are already designed to 
meet limits consistent with this rule (or they have already commenced 
construction and are thus not subject to these final standards). The 
AEO 2015 also projects an additional 9.9 GW of new base load capacity 
additions, which are model-projected (unplanned). This consists of 7.7 
GW of new NGCC capacity, 1.2 GW of new geothermal capacity, 0.7 GW of 
new hydroelectric capacity, and 0.3 GW of new coal equipped with CCS 
(incentivized with some government funding). Therefore, the AEO 2015 
projection suggests that the new power generation capacity added 
through 2020 is expected to already meet the final emissions standards 
without incurring further control costs. This is also true during the 
period from 2020 through 2030, where new model-projected (unplanned) 
intermediate and base load capacity is expected to be compliant with 
the standards without incurring further control costs (i.e., an 
additional 31.3 GW of NGCC and no additional coal, for a total, from 
2015 through 2030, of 39 GW of NGCC and 0.3 GW of coal with CCS).
    Under the EIA projections, existing coal-fired generation will 
remain an important part of the mix for power generation. Modeling from 
both the EIA and the EPA project that coal-fired generation will remain 
the largest single source of electricity in the U.S. through 2040. 
Specifically, in the EIA's AEO 2015, coal will supply approximately 40 
percent of all electricity in the electric power sector in both 2020 
and 2025.
    The EPA modeling using the Integrated Planning Model (IPM), a 
detailed power sector model that the EPA uses to support power sector 
regulations, also shows limited future construction of new coal-fired 
power plants under the base case.\79\ The EPA's projections from IPM 
can be found in the RIA.
---------------------------------------------------------------------------

    \79\ http://www.epa.gov/airmarkets/progsregs/epa-ipm/BaseCasev410.html#documentation.
---------------------------------------------------------------------------

5. Integrated Resource Plans
    The trends in the power sector described above are also apparent in 
publicly available long-term resource plans, known as integrated 
resource plans (IRPs).
    The EPA has reviewed publicly available IRPs from a range of 
companies (e.g., varying in size, location, current fuel mix), and 
these plans are generally consistent with both EIA and EPA modeling 
projections.\80\ These IRPs indicate that companies are focused on 
demand-side management programs to lower future electricity demand and 
are mostly reliant on a mix of new natural gas-fired generation and 
renewable energy to meet increased load demand and to replace retired 
generation capacity.
---------------------------------------------------------------------------

    \80\ Technical Support Document--``Review of Electric Utility 
Integrated Resource Plans'' (May 2015), available in the rulemaking 
docket EPA-HQ-OAR-2013-0495.
---------------------------------------------------------------------------

    Notwithstanding this clear trend towards natural gas-fired 
generation and renewables, many of the IRPs highlight the value of fuel 
diversity and include options to diversify new generation capacity 
beyond natural gas and renewable energy. Several IRPs indicate that 
companies are considering new nuclear generation, including either 
traditional nuclear power plants or small modular reactors, and a 
smaller number are considering new coal-fired generation capacity with 
and without CCS technology. Based on public comments and on the 
information contained in these IRPs, the EPA acknowledges that a small 
number of

[[Page 64527]]

new coal-fired power plants may be built in the near future. While this 
outcome would be contrary to the economic modeling predictions, the 
agency understands that economic modeling may not fully reflect the 
range of factors that a particular company may consider when evaluating 
new generation options, such as fuel diversification. Further, it is 
possible that some of this potential new coal-fired construction may 
occur because developers are able to design projects with specific 
business plans, such as the cogeneration of chemicals, which allow the 
source to provide competitively priced electricity in specific 
geographic regions.

D. Statutory Background

    The U.S. Supreme Court ruled in Massachusetts v. EPA that GHGs \81\ 
meet the definition of ``air pollutant'' in the CAA,\82\ and premised 
its decision in AEP v. Connecticut,\83\ that the CAA displaced any 
federal common law right to compel reductions in CO2 
emissions from fossil fuel-fired power plants, on its view that CAA 
section 111 applies to GHG emissions.
---------------------------------------------------------------------------

    \81\ The EPA's 2009 endangerment finding defines the air 
pollution which may endanger public health and welfare as the well-
mixed aggregate group of the following gases: CO2, 
methane (CH4), nitrous oxide (N2O), sulfur 
hexafluoride (SF6), hydrofluorocarbons (HFCs), and 
perfluorocarbons (PFCs).
    \82\ 549 U.S. 497, 520 (2007).
    \83\ 131 S.Ct. 2527, 2537-38 (2011).
---------------------------------------------------------------------------

    CAA section 111 authorizes and directs the EPA to prescribe new 
source performance standards (NSPS) applicable to certain new 
stationary sources (including newly constructed, modified and 
reconstructed sources).\84\ As a preliminary step to regulation, the 
EPA must list categories of stationary sources that the Administrator, 
in his or her judgment, finds ``cause[], or contribute[] significantly 
to, air pollution which may reasonably be anticipated to endanger 
public health or welfare.'' The EPA has listed and regulated more than 
60 stationary source categories under CAA section 111.\85\ The EPA 
listed the two source categories at issue here in the 1970s--listing 
fossil fuel-fired electric steam generating units in 1971 \86\ and 
listing combustion turbines in 1977.\87\
---------------------------------------------------------------------------

    \84\ CAA section 111(b)(1)(A).
    \85\ See generally 40 CFR part 60, subparts D-MMMM.
    \86\ 36 FR 5931 (March 31, 1971).
    \87\ 42 FR 53657 (October 3, 1977).
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    Once the EPA has listed a source category, the EPA proposes and 
then promulgates ``standards of performance'' for ``new sources'' in 
the category.\88\ A ``new source'' is ``any stationary source, the 
construction or modification of which is commenced after,'' in general, 
final standards applicable to that source are promulgated or, if 
earlier, proposed.\89\ A modification is ``any physical change . . . or 
change in the method of operation . . . which increases the amount of 
any air pollutant emitted by such source or which results in the 
emission of any air pollutant not previously emitted.'' \90\ The EPA, 
through regulations, has determined that certain types of changes are 
exempt from consideration as a modification.\91\
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    \88\ CAA section 111(b)(1)(B).
    \89\ CAA section 111(a)(2).
    \90\ CAA section 111(a)(4); See also 40 CFR 60.14 concerning 
what constitutes a modification, how to determine the emission rate, 
how to determine an emission increase, and specific actions that are 
not, by themselves, considered modifications.
    \91\ 40 CFR 60.2, 60.14(e).
---------------------------------------------------------------------------

    The NSPS general provisions (40 CFR part 60, subpart A) provide 
that an existing source is considered to be a new source if it 
undertakes a ``reconstruction,'' which is the replacement of components 
of an existing facility to an extent that (1) 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 
(2) it is technologically and economically feasible to meet the 
applicable standards.\92\
---------------------------------------------------------------------------

    \92\ 40 CFR 60.15.
---------------------------------------------------------------------------

    CAA section 111(a)(1) defines a ``standard of performance'' as ``a 
standard for emissions . . . achievable through the application of the 
best system of emission reduction which [considering cost, non-air 
quality health and environmental impact, and energy requirements] the 
Administrator determines has been adequately demonstrated.'' This 
definition makes clear that the standard of performance must be based 
on ``the best system of emission reduction . . . adequately 
demonstrated'' (BSER).
    The standard that the EPA develops, reflecting the performance of 
the BSER, is commonly a numeric emission limit, expressed as a numeric 
performance level that can either be normalized to a rate of output or 
input (e.g., tons of pollution per amount of product produced--a so-
called rate-based standard), or expressed as a numeric limit on mass of 
pollutant that may be emitted (e.g., 100 ug/m\3\--parts per billion). 
Generally, the EPA does not prescribe a particular technological system 
that must be used to comply with a standard of performance.\93\ Rather, 
sources generally may select any measure or combination of measures 
that will achieve the emissions level of the standard.\94\ In 
establishing standards of performance, the EPA has significant 
discretion to create subcategories based on source type, class, or 
size.\95\
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    \93\ CAA section 111(b)(5) and (h).
    \94\ CAA section 111(b)(5).
    \95\ CAA section 111(b)(2); see also Lignite Energy Council v. 
EPA, 198 F. 3d 930, 933 (D.C. Cir. 1999).
---------------------------------------------------------------------------

    The text and legislative history of CAA section 111, as well as 
relevant court decisions, identify the factors that the EPA is to 
consider in making a BSER determination. The system of emission 
reduction must be technically feasible, the costs of the system must be 
reasonable, and the emission standard that the EPA promulgates based on 
the system of emission reduction must be achievable. In addition, in 
identifying a BSER, the EPA must consider the amount of emissions 
reductions attributable to the system, and must also consider non-air 
quality health and environmental impacts and energy requirements. The 
case law addressing CAA section 111 makes it clear that the EPA has 
discretion in weighing costs, amount of emission reductions, energy 
requirements, and impacts of non-air quality pollutants, and may weigh 
them differently for different types of sources or air pollutants. We 
note that under the case law of the D.C. Circuit, another factor is 
relevant for the BSER determination: Whether the standard would 
effectively promote further deployment or development of advanced 
technologies. Within the constraints just described, the EPA has 
discretion in identifying the BSER and the resulting emission standard. 
See generally Section III.H below.
    For more than four decades, the EPA has used its authority under 
CAA section 111 to set cost-effective emission standards which ensure 
that newly constructed, reconstructed, and modified stationary sources 
use the best performing technologies to limit emissions of harmful air 
pollutants. In this final action, the EPA is following the same well-
established interpretation and application of the law under CAA section 
111 to address GHG emissions from newly constructed, reconstructed, and 
modified fossil fuel-fired power plants. For each of the standards in 
this final action, the EPA considered a number of alternatives and 
evaluated them against the statutory factors. The BSER for each 
category of affected EGUs and the standards of performance based on 
these BSER are based on that evaluation.

[[Page 64528]]

E. Regulatory Background

    In 1971, the EPA initially included fossil fuel-fired EGUs (which 
includes natural gas, petroleum and coal) that use steam-generating 
boilers in a category that it listed under CAA section 
111(b)(1)(A),\96\ and promulgated the first set of standards of 
performance for sources in that category, which it codified in subpart 
D.\97\ In 1977, the EPA initially included fossil fuel-fired combustion 
turbines in a category that the EPA listed under CAA section 
111(b)(1)(A),\98\ and the EPA promulgated standards of performance for 
that source category in 1979, which the EPA codified in subpart GG.\99\
---------------------------------------------------------------------------

    \96\ 36 FR 5931 (March 31, 1971).
    \97\ ``Standards of Performance for Fossil-Fuel-Fired Steam 
Generators for Which Construction Is Commenced After August 17, 
1971,'' 36 FR 24875 (December 23, 1971) codified at 40 CFR 60.40-46.
    \98\ 42 FR 53657 (October 3, 1977).
    \99\ ``Standards of Performance for Electric Utility Steam 
Generating Units for Which Construction is Commenced After September 
18, 1978,'' 44 FR 33580 (June 11, 1979).
---------------------------------------------------------------------------

    The EPA has revised those regulations, and in some instances, has 
revised the codifications (that is, the 40 CFR part 60 subparts), 
several times over the ensuing decades. In 1979, the EPA divided 
subpart D into 3 subparts--Da (``Standards of Performance for Electric 
Utility Steam Generating Units for Which Construction is Commenced 
After September 18, 1978''), Db (``Standards of Performance for 
Industrial-Commercial-Institutional Steam Generating Units'') and Dc 
(``Standards of Performance for Small Industrial-Commercial-
Institutional Steam Generating Units'')--in order to codify separate 
requirements that it established for these subcategories.\100\ In 2006, 
the EPA created subpart KKKK, ''Standards of Performance for Stationary 
Combustion Turbines,'' which applied to certain sources previously 
regulated in subparts Da and GG.\101\ None of these subsequent 
rulemakings, including the revised codifications, however, constituted 
a new listing under CAA section 111(b)(1)(A).
---------------------------------------------------------------------------

    \100\ 44 FR 33580 (June 11, 1979).
    \101\ 71 FR 38497 (July 6, 2006), as amended at 74 FR 11861 
(March 20, 2009).
---------------------------------------------------------------------------

    The EPA promulgated amendments to subpart Da in 2006, which 
included new standards of performance for criteria pollutants for EGUs, 
but did not include specific standards of performance for 
CO2 emissions.\102\ Petitioners sought judicial review of 
the rule, contending, among other issues, that the rule was required to 
include standards of performance for GHG emissions from EGUs.\103\ The 
January 8, 2014 preamble to the proposed CO2 standards for 
new EGUs \104\ includes a discussion of the GHG-related litigation of 
the 2006 Final Rule as well as other GHG-associated litigation.
---------------------------------------------------------------------------

    \102\ ``Standards of Performance for Electric Utility Steam 
Generating Units, Industrial-Commercial-Institutional Steam 
Generating Units, and Small Industrial-Commercial-Institutional 
Steam Generating Units, Final Rule.'' 71 FR 9866 (February 27, 
2006).
    \103\ State of New York, et al. v. EPA, No. 06-1322.
    \104\ 79 FR 1430, 1444.
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F. Development of Carbon Pollution Standards for Fossil Fuel-Fired 
Electric Utility Generating Units

    On April 13, 2012, the EPA initially proposed standards under CAA 
section 111 for newly constructed fossil fuel-fired electric utility 
steam generating units. 77 FR 22392 (``April 2012 proposal''). The EPA 
withdrew that proposal (79 FR 1352 (January 8, 2014)), and, on the same 
day, proposed the standards addressed in this final rule. 79 FR 1430 
(``January 2014 proposal''). Specifically, the EPA proposed standards 
under CAA section 111 to limit emissions of CO2 from newly 
constructed fossil fuel-fired electric utility steam generating units 
and newly constructed natural gas-fired stationary combustion turbines.
    In support of the January 2014 proposal, on February 26, 2014, the 
EPA published a notice of data availability (NODA) (79 FR 10750). 
Through the NODA and an associated technical support document, Effect 
of EPAct05 on Best System of Emission Reduction for New Power Plants, 
the EPA solicited comment on its interpretation of the provisions in 
the Energy Policy Act of 2005 (EPAct05),\105\ including how the 
provisions may affect the rationale for the EPA's proposed 
determination that partial CCS is the best system of emission reduction 
adequately demonstrated for fossil fuel-fired electric utility steam 
generating units.
---------------------------------------------------------------------------

    \105\ See Section III.H.3.g below. The Energy Policy Act of 2005 
(EPAct05) was signed into law by President George W. Bush on August 
8, 2005. EPAct05 was intended to address energy production in the 
United States, including: (1) Energy efficiency; (2) renewable 
energy; (3) oil and gas; (4) coal; (5) Tribal energy; (6) nuclear 
matters and security; (7) vehicles and motor fuels, including 
ethanol; (8) hydrogen; (9) electricity; (10) energy tax incentives; 
(11) hydropower and geothermal energy; and (12) climate change 
technology. www2.epa.gov/laws-regulations/summary-energy-policy-act.
---------------------------------------------------------------------------

    On June 18, 2014, the EPA proposed standards of performance to 
limit emissions of CO2 from modified and reconstructed 
fossil fuel-fired electric utility steam generating units and natural 
gas-fired stationary combustion turbines (79 FR 34960; June 2014 
proposal). Specifically, the EPA proposed standards of performance for: 
(1) Modified fossil fuel-fired electric utility steam generating units, 
(2) modified natural gas-fired stationary combustion turbines, (3) 
reconstructed fossil fuel-fired electric utility steam generating 
units, and (4) reconstructed natural gas-fired stationary combustion 
turbines.

G. Stakeholder Engagement and Public Comments on the Proposals

1. Stakeholder Engagement
    The EPA has engaged extensively with a broad range of stakeholders 
and the general public regarding climate change, carbon pollution from 
power plants, and carbon pollution reduction opportunities. These 
stakeholders included industry and electric utility representatives, 
state and local officials, tribal officials, labor unions, non-
governmental organizations and many others.
    In February and March 2011, early in the process of developing 
carbon pollution standards for new power plants, the EPA held five 
listening sessions to obtain information and input from key 
stakeholders and the public. Each of the five sessions had a particular 
target audience: The electric power industry, environmental and 
environmental justice organizations, states and tribes, coalition 
groups, and the petroleum refinery industry.
    The EPA conducted subsequent outreach prior to the June 2014 
proposals of standards for modified and reconstructed EGUs and emission 
guidelines for existing EGUs, as well as during the public comment 
periods for the proposals. Although this stakeholder outreach was 
primarily framed around the GHG emission guidelines for existing EGUs, 
the outreach encompassed issues relevant to this rulemaking and 
provided an opportunity for the EPA to better understand previous state 
and stakeholder experience with reducing CO2 emissions in 
the power sector. In addition to 11 public listening sessions, the EPA 
held hundreds of meetings with individual stakeholder groups, and 
meetings that brought together a variety of stakeholders to discuss a 
wide range of issues related to the electricity sector and regulation 
of GHGs under the CAA. The agency met with electric utility 
associations and electricity grid operators. Agency officials engaged 
with labor unions and with leaders representing large and small 
industries. The agency also met with energy industries, such as coal 
and natural gas interests, as well as with representatives of energy-
intensive industries, such as

[[Page 64529]]

the iron and steel, and aluminum industries, to better understand the 
potential concerns of large industrial purchasers of electricity. In 
addition, the agency met with companies that offer new technology to 
prevent or reduce carbon pollution. The agency provided and encouraged 
multiple opportunities for engagement with state, local, tribal, and 
regional environmental and energy agencies. The EPA also met with 
representatives of environmental justice organizations, environmental 
groups, public health professionals, public health organizations, 
religious organizations, and other community stakeholders.
    The EPA received more than 2.5 million comments submitted in 
response to the original April 2012 proposal for newly constructed 
fossil fuel-fired EGUs. Because the original proposal was withdrawn, 
the EPA instructed commenters that wanted their comments on the April 
2012 proposal to be considered in connection with the January 2014 
proposal to submit new comments to the EPA or to re-submit their 
previous comments. We received more comments in response to the January 
2014 proposal, as discussed in the section below.
    The EPA has given stakeholder input provided prior to the 
proposals, as well as during the public comment periods for each 
proposal, careful consideration during the development of this 
rulemaking and, as a result, it includes elements that are responsive 
to many stakeholder concerns and that enhance the rule. This preamble 
and the Response-to-Comments (RTC) document summarize and provide the 
agency's responses to the comments received.
2. Comments on the January 2014 Proposal For Newly Constructed Fossil 
Fuel-Fired EGUs
    Upon publication of the January 8, 2014 proposal for newly 
constructed fossil fuel-fired EGUs, the EPA provided a 60-day public 
comment period. On March 6, 2014, in order to provide the public 
additional time to submit comments and supporting information, the EPA 
extended the comment period by 60 days, to May 9, 2014, giving 
stakeholders over 120 days to review, and comment upon, the January 
2014 proposal, as well as the NODA. A public hearing was held on 
February 6, 2014, with 159 speakers presenting testimony.
    The EPA received more than 2 million comments on the proposed 
standards for newly constructed fossil fuel-fired EGUs from a range of 
stakeholders that included industry and electric utility 
representatives, trade groups, equipment manufacturers, state and local 
government officials, academia, environmental organizations, and 
various interest groups. The agency received comments on a range of 
topics, including the determination that a new highly-efficient steam 
generating EGU implementing partial CCS was the BSER for such sources, 
the level of the CO2 standard based on implementation of 
partial CCS, the criteria that define which newly constructed natural 
gas-fired stationary combustion turbines will be subject to standards, 
the establishment of subcategories based on combustion turbine size, 
and the rule's potential effects on the Prevention of Significant 
Deterioration (PSD) preconstruction permit program and Title V 
operating permit program.
3. Comments on the June 2014 Proposal For Modified and Reconstructed 
Fossil Fuel-Fired EGUs
    Upon publication of the June 18, 2014 proposal for modified and 
reconstructed fossil fuel-fired EGUs, the EPA offered a 120-day public 
comment period--through October 16, 2014. The EPA held public hearings 
in four locations during the week of July 28, 2014. These hearings also 
addressed the EPA's June 18, 2014 proposed emission guidelines for 
existing fossil fuel-fired EGUs (reflecting the connections between the 
proposed standards for modified and reconstructed sources and the 
proposed emission guidelines). A total of 1,322 speakers testified, and 
a further 1,450 attended but did not speak. The speakers were provided 
the opportunity to present data, views, or arguments concerning one or 
both proposed actions.
    The EPA received over 200 comments on the proposed standards for 
modified and reconstructed fossil fuel-fired EGUs from a range of 
stakeholders similar to those that submitted comments on the January 
2014 proposal for newly constructed fossil fuel-fired EGUs (i.e., 
industry and electric utility representatives, trade groups, equipment 
manufacturers, state and local government officials, academia, 
environmental organizations, and various interest groups). The agency 
received comments on a range of topics, including the methodology for 
determining unit-specific CO2 standards for modified steam 
generating units and the use of supercritical boiler conditions as the 
basis for the CO2 standards for certain reconstructed steam 
generating units. Many of the comments regarding modified and 
reconstructed natural gas-fired stationary combustion turbines are 
similar to the comments regarding newly constructed combustion turbines 
described above (e.g., applicability criteria and subcategories based 
on turbine size).

III. Regulatory Authority, Affected EGUs and Their Standards, and Legal 
Requirements

    In this section, we describe our authority to regulate 
CO2 from fossil fuel-fired EGUs. We also describe our 
decision to combine the two existing categories of affected EGUs--steam 
generators and combustion turbines--into a single category of fossil 
fuel-fired EGUs for purposes of promulgating standards of performance 
for CO2 emissions. We also explain that we are codifying all 
of the requirements in this rule for new, modified, and reconstructed 
affected EGUs in new subpart TTTT of part 60 of Title 40 of the Code of 
Federal Regulations. In addition, we explain which sources are and are 
not affected by this rule, and the format of these standards. Finally, 
we describe the legal requirements for establishing these emission 
standards.

A. Authority To Regulate Carbon Dioxide From Fossil Fuel-Fired EGUs

    The EPA's authority for this rule is CAA section 111(b)(1). CAA 
section 111(b)(1)(A) requires the Administrator to establish a list of 
source categories to be regulated under section 111. A category of 
sources is to be included on the list ``if in [the Administrator's] 
judgment it causes, or contributes significantly to, air pollution 
which may reasonably be anticipated to endanger public health and 
welfare.'' This determination is commonly referred to as an 
``endangerment finding'' and that phrase encompasses both the ``causes 
or contributes significantly'' component and the ``endanger public 
health and welfare'' component of the determination. Then, for the 
source categories listed under section 111(b)(1)(A), the Administrator 
promulgates, under section 111(b)(1)(B), ``standards of performance for 
new sources within such category.''
    In this rule, the EPA is establishing standards under section 
111(b)(1)(B) for source categories that it has previously listed and 
regulated for other pollutants and which now are being regulated for an 
additional pollutant. Because of this, there are two aspects of section 
111(b)(1) that warrant particular discussion.
    First, because the EPA is not listing a new source category in this 
rule, the EPA is not required to make a new endangerment finding with 
regard to affected EGUs in order to establish standards of performance 
for the CO2 emissions from those sources. Under the plain 
language of CAA section

[[Page 64530]]

111(b)(1)(A), an endangerment finding is required only to list a source 
category. Further, though the endangerment finding is based on 
determinations as to the health or welfare impacts of the pollution to 
which the source category's pollutants contribute, and as to the 
significance of the amount of such contribution, the statute is clear 
that the endangerment finding is made with respect to the source 
category; section 111(b)(1)(A) does not provide that an endangerment 
finding is made as to specific pollutants. This contrasts with other 
CAA provisions that do require the EPA to make endangerment findings 
for each particular pollutant that the EPA regulates under those 
provisions. E.g., CAA sections 202(a)(1), 211(c)(1), and 231(a)(2)(A); 
see also American Electric Power Co. Inc., v. Connecticut, 131 S. Ct. 
2527, 2539 (2011) (``[T]he Clean Air Act directs the EPA to establish 
emissions standards for categories of stationary sources that, `in [the 
Administrator's] judgment,' `caus[e], or contribut[e] significantly to, 
air pollution which may reasonably be anticipated to endanger public 
health or welfare.' Sec.  7411(b)(1)(A).'') (emphasis added).
    Second, once a source category is listed, the CAA does not specify 
what pollutants should be the subject of standards from that source 
category. The statute, in section 111(b)(1)(B), simply directs the EPA 
to propose and then promulgate regulations ``establishing federal 
standards of performance for new sources within such category.'' In the 
absence of specific direction or enumerated criteria in the statute 
concerning what pollutants from a given source category should be the 
subject of standards, it is appropriate for the EPA to exercise its 
authority to adopt a reasonable interpretation of this provision. 
Chevron U.S.A. Inc. v. NRDC, 467 U.S. 837, 843-44 (1984).\106\
---------------------------------------------------------------------------

    \106\ In Chevron, the U.S. Supreme Court held that an 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.
---------------------------------------------------------------------------

    The EPA has previously interpreted this provision as granting it 
the discretion to determine which pollutants should be regulated. See 
Standards of Performance for Petroleum Refineries, 73 FR 35838 (June 
24, 2008) (concluding that the statute provides ``the Administrator 
with significant flexibility in determining which pollutants are 
appropriate for regulation under section 111(b)(1)(B)'' and citing 
cases). Further, in directing the Administrator to propose and 
promulgate regulations under section 111(b)(1)(B), Congress provided 
that the Administrator should take comment and then finalize the 
standards with such modifications ``as he deems appropriate.'' The D.C. 
Circuit has considered similar statutory phrasing from CAA section 
231(a)(3) and concluded that ``[t]his delegation of authority is both 
explicit and extraordinarily broad.'' National Assoc. of Clean Air 
Agencies v. EPA, 489 F.3d 1221, 1229 (D.C. Cir. 2007).
    In exercising its discretion with respect to which pollutants are 
appropriate for regulation under section 111(b)(1)(B), the EPA has in 
the past provided a rational basis for its decisions. See National Lime 
Assoc. v. EPA, 627 F.2d 416, 426 & n.27 (D.C. Cir. 1980) (court 
discussed, but did not review, the EPA's reasons for not promulgating 
standards for oxides of nitrogen (NOX), sulfur dioxide 
(SO2) and CO from lime plants); Standards of Performance for 
Petroleum Refineries, 73 FR at 35859-60 (June 24, 2008) (providing 
reasons why the EPA was not promulgating GHG standards for petroleum 
refineries as part of that rule). Though these previous examples 
involved the EPA providing a rational basis for not setting standards 
for a given pollutant, a similar approach is appropriate where the EPA 
determines that it should set a standard for an additional pollutant 
for a source category that was previously listed and regulated for 
other pollutants.
    In this rulemaking, the EPA has a rational basis for concluding 
that emissions of CO2 from fossil fuel-fired power plants, 
which are the major U.S. source of GHG air pollution, merit regulation 
under CAA section 111. As noted, in 2009, the EPA made a finding that 
GHG air pollution may reasonably be anticipated to endanger public 
health or welfare, and in 2010, the EPA denied petitions to reconsider 
that finding. The EPA extensively reviewed the available science 
concerning GHG pollution and its impacts in taking those actions. In 
2012, the U.S. Court of Appeals for the D.C. Circuit upheld the finding 
and the denial of petitions to reconsider.\107\ In addition, 
assessments from the NRC, the IPCC, and other organizations published 
after 2010 lend further credence to the validity of the Endangerment 
Finding. No information that commenters have presented or that the EPA 
has reviewed provides a basis for reaching a different conclusion. 
Indeed, current and evolving science discussed in detail in Section 
II.A of this preamble is confirming and enhancing our understanding of 
the near- and longer-term impacts emissions of CO2 are 
having on Earth's climate and the adverse public health, welfare, and 
economic consequences that are occurring and are projected to occur as 
a result.
---------------------------------------------------------------------------

    \107\ Coalition for Responsible Regulation v. EPA, 684 F.3d 102, 
119-126 (D.C. Circuit 2012).
---------------------------------------------------------------------------

    Moreover, the high level of GHG emissions from fossil fuel-fired 
EGUs makes clear that it is rational for the EPA to regulate GHG 
emissions from this sector. EGUs emit almost one-third of all U.S. GHGs 
and comprise by far the largest stationary source category of GHG 
emissions; indeed, as noted above, the CO2 emissions from 
fossil fuel-fired EGUs are almost three times as much as the emissions 
from the next ten source categories combined. Further, the 
CO2 emissions from even a single new coal-fired power plant 
may amount to millions of tons each year. See, e.g., Section V.K below 
(noting that even the difference in CO2 emissions between a 
highly efficient SCPC and the same unit meeting today's standard of 
performance can amount to hundreds of thousands of tons each year). 
These facts provide a rational basis for regulating CO2 
emissions from affected EGUs.
    Some commenters have argued that the EPA is required to make a new 
endangerment finding before it may regulate CO2 from EGUs. 
We disagree, for the reasons discussed above. Moreover, as discussed in 
the January 2014 proposal,\108\ even if CAA section 111 required the 
EPA to make endangerment and cause-or-contribute significantly findings 
as prerequisites for this rulemaking, then, so far as the 
``CO2 endangers public health and welfare'' component of an 
endangerment finding is concerned, the information and conclusions 
described above should be considered to constitute the requisite 
endangerment finding. Similarly, so far as a cause-or-contribute 
significantly finding is concerned, the information and conclusions 
described above should be considered to constitute the requisite 
finding. The EPA's rational basis for regulating CO2 under 
CAA section 111 is based primarily on the analysis and conclusions in 
the EPA's 2009 Endangerment Finding and 2010 denial of petitions to 
reconsider that Finding, coupled with the subsequent assessments from 
the IPCC and NRC that describe scientific developments since those EPA 
actions. In addition, we have reviewed comments presenting other 
scientific information to

[[Page 64531]]

determine whether that information has any meaningful impact on our 
analysis and conclusions. For both the endangerment finding and the 
rational basis, the EPA focused on public health and welfare impacts 
within the United States, as it did in the 2009 Finding. The impacts in 
other world regions strengthen the case because impacts in other world 
regions can in turn adversely affect the United States or its citizens.
---------------------------------------------------------------------------

    \108\ 79 FR 1430, 1455-56 (January 8, 2014).
---------------------------------------------------------------------------

    More specifically, our approach here--reflected in the information 
and conclusions described above--is substantially similar to that 
reflected in the 2009 Endangerment Finding and the 2010 denial of 
petitions to reconsider. The D.C. Circuit upheld that approach in 
Coalition for Responsible Regulation v. EPA, 684 F.3d 102, 117-123 
(D.C. Cir. 2012) (noting, among other things, the ``substantial . . . 
body of scientific evidence marshaled by EPA in support of the 
Endangerment Finding'' (id. at 120); the ``substantial record evidence 
that anthropogenic emissions of greenhouse gases `very likely' caused 
warming of the climate over the last several decades'' (id. at 121); 
``substantial scientific evidence . . . that anthropogenically induced 
climate change threatens both public health and public welfare . . . 
[through] extreme weather events, changes in air quality, increases in 
food- and water-borne pathogens, and increases in temperatures'' (id.); 
and ``substantial evidence . . . that the warming resulting from the 
greenhouse gas emissions could be expected to create risks to water 
resources and in general to coastal areas. . . .'' (id.)). The facts, 
unfortunately, have only grown stronger and the potential adverse 
consequences to public health and the environment more dire in the 
interim. Accordingly, that approach would support an endangerment 
finding for this rulemaking.\109\
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    \109\ Nor does the EPA consider the cost of potential standards 
of performance in making this Finding. Like the Endangerment Finding 
under section 202(a) at issue in State of Massachusetts v. EPA, 549 
U.S. 497 (2007) the pertinent issue is a scientific inquiry as to 
whether an endangerment to public health or welfare from the 
relevant air pollution may reasonably be anticipated. Where, as 
here, the scientific inquiry conducted by the EPA indicates that 
these statutory criteria are met, the Administrator does not have 
discretion to decline to make a positive endangerment finding to 
serve other policy grounds. Id. at 532-35. In this regard, an 
endangerment finding is analogous to setting national ambient air 
quality standards under section 109(b), which similarly call on the 
Administrator to set standards that in her ``judgment'' are 
``requisite to protect the public health''. The EPA is not permitted 
to consider potential costs of implementation in setting these 
standards. Whitman v. American Trucking Assn's, 531 U.S. 457, 466 
(2001); see also Michigan v. EPA, U.S. (no. 14-46, June 29, 2015) 
slip op. pp. 10-11 (reiterating Whitman holding). The EPA notes 
further that section 111(b)(1) contains no terms such as ``necessary 
and appropriate'' which could suggest (or, in some contexts, 
require) that costs may be considered as part of the finding. 
Compare CAA section 111(n)(1)(A); see State of Michigan, slip op. 
pp. 7-8. The EPA, of course, must consider costs in determining 
whether a best system of emission reduction is adequately 
demonstrated and so can form the basis for a section 111(b) standard 
of performance, and the EPA has carefully considered costs here and 
found them to be reasonable. See section V. H. and I. below. The EPA 
also has found that the rule's quantifiable benefits exceed 
regulatory costs under a range of assumptions were new capacity to 
be built. RIA chapter 5 and section XIII.G below. Accordingly, this 
endangerment finding would be justified if (against our view) it is 
both required, and (again, against our view) costs are to be 
considered as part of the finding.
---------------------------------------------------------------------------

    Likewise, if the EPA were required to make a cause-or-contribute-
significantly finding for CO2 emissions from the fossil 
fuel-fired EGUs as a prerequisite to regulating such emissions under 
CAA section 111, the same facts that support our rational basis 
determination would support such a finding. As shown in Tables 3 and 4 
in this preamble, fossil fuel-fired EGUs are very large emitters of 
CO2. All told, these fossil fuel-fired EGUs emit almost one-
third of all U.S. GHG emissions, and are responsible for almost three 
times as much as the emissions from the next ten stationary source 
categories combined. The CO2 emissions from even a single 
new coal-fired power plant may amount to millions of tons each year, 
and the CO2 emissions from even a single NGCC unit may 
amount to one million or more tons per year. It is not necessary in 
this rulemaking for the EPA to decide whether it must identify a 
specific threshold for the amount of emissions from a source category 
that constitutes a significant contribution; under any reasonable 
threshold or definition, the emissions from combustion turbines and 
steam generators are a significant contribution. Indeed, these 
emissions far exceed in magnitude the emissions from motor vehicles, 
which have already been held to contribute to the endangerment. See 
Coalition for Responsible Regulation, 684 F. 3d at 121 (``substantial 
evidence'' supports the EPA's determination ``that motor-vehicle 
emissions of greenhouse gases contribute to climate change and thus to 
the endangerment of public health and welfare'').\110\
---------------------------------------------------------------------------

    \110\ The ``air pollution'' defined in the Endangerment Finding 
is the atmospheric mix of six long-lived and directly emitted 
greenhouse gases: Carbon dioxide (CO2), methane 
(CH4), nitrous oxide (N2O), hydrofluorocarbons 
(HFCs), perfluorocarbons (PFCs), and sulfur hexafluoride 
(SF6). See 74 FR 66496 at 66497. The standards of 
performance adopted in the present rulemaking address only one 
component of this air pollution: CO2. This is reasonable, 
given that CO2 is the air pollutant emitted in the 
largest volume by the source category, and which is (necessarily) 
emitted by every affected EGU. There is, of course, no requirement 
that standards of performance address each component of the air 
pollution which endangers. Section 111(b)(1)(A) requires the EPA to 
establish ``standards of performance'' for listed source categories, 
and the definition of ``standard of performance'' in section 
111(a)(1) does not specify which air pollutants must be controlled. 
See also Section III.G below explaining that CH4 and 
N2O emissions represent less than 1 percent of total 
estimated GHG emissions (as CO2e) from fossil fuel-fired 
electric power generating units.
---------------------------------------------------------------------------

B. Treatment of Categories and Codification in the Code of Federal 
Regulations

    As discussed in the January 2014 proposal of carbon pollution 
standards for newly constructed EGUs (79 FR 1430) and above, in 1971 
the EPA listed fossil fuel-fired steam generating boilers as a new 
category subject to CAA 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 2014 proposal of carbon pollution standards for 
newly constructed EGUs (79 FR 1430) and the June 2014 proposal of 
carbon pollution standards for modified and reconstructed EGUs (79 FR 
34960), the EPA proposed separate standards of performance for new, 
modified, and reconstructed sources in the two categories. The EPA took 
comment on combining the two categories into a single category solely 
for purposes of the CO2 emissions from new, modified, and 
reconstructed affected EGUs. In addition, the EPA proposed codifying 
the standards of performance in the same Da and KKKK subparts that 
currently contain the standards of performance for other pollutants 
from those sources addressed in the NSPS program, but co-proposed 
codifying all the standards of performance for CO2 emissions 
in a new 40 CFR part 60, subpart TTTT.
    In this rule, the EPA is combining the steam generator and 
combustion turbine categories into a single category of fossil fuel-
fired electricity generating units for purposes of promulgating 
standards of performance for GHG emissions. Combining the two 
categories is reasonable because they both provide the same product: 
Electricity services. Moreover, combining them in this rule is 
consistent with our decision to combine them in the CAA section 111(d) 
rule for existing sources that accompanies this rule. In addition,

[[Page 64532]]

many of the monitoring, reporting, and verification requirements are 
the same for both source categories, and, as discussed next, we are 
codifying all requirements in a single new subpart of the regulations; 
as a result, combining the two categories into a single category will 
reduce confusion. It should be noted that in this rule, we are not 
combining the two categories for purposes of standards of performance 
for other air pollutants.
    Because these two source categories are pre-existing listed source 
categories and the EPA will not be subjecting any additional sources in 
the categories to CAA regulation for the first time, the combination of 
these two categories is not considered a new source category subject to 
the listing requirements of CAA section 111(b)(1)(A). As a result, this 
final rule does not list a new category under CAA section 111(a)(1)(A), 
nor does this final rule revise either of the two source categories. 
Thus, the EPA is not required to make a new endangerment and 
contribution finding for the combination of the two categories,\111\ 
although as discussed in the previous section, the evidence strongly 
supports such findings. Thus, the EPA has found, in the alternative, 
that this category of sources contributes significantly to air 
pollution which may be reasonably anticipated to endanger public health 
and welfare.
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    \111\ See, e.g., American Trucking Assn's v. EPA, 175 F.3d 1027, 
1055, rev'd on other grounds sub. nom. Whitman v. Am. Trucking 
Assn's, 531.U.S. 457 (because fine particulate matter 
(PM2.5) was already included as a sub-set of the listed 
pollutant particulate matter, it was not a new pollutant 
necessitating a new listing).
---------------------------------------------------------------------------

C. Affected Units

    We generally refer to fossil fuel-fired electric generating units 
that would be subject to a CAA section 111 emission standard as 
``affected'' or ``covered'' sources, units, facilities or simply as 
EGUs. An EGU is any boiler, IGCC unit, or combustion turbine (in either 
simple cycle or combined cycle configuration) that meets the 
applicability criteria. Affected EGUs include those that commenced 
construction after January 8, 2014, and meet the specified 
applicability criteria and, for modifications and reconstructions, EGUs 
that commenced those activities after June 18, 2014, and meet the 
specified applicability criteria.
    To be considered an EGU, the unit must: (1) Be capable of 
combusting more than 250 MMBtu/h (260 GJ/h) heat input of fossil fuel; 
\112\ and (2) serve a generator capable of supplying more than 25 MW 
net to a utility distribution system (i.e., for sale to the grid).\113\ 
However, we are not finalizing CO2 standards for certain 
EGUs. The EGUs that are not covered by the standards we are finalizing 
in this rule include: (1) Non-fossil fuel units subject to a federally 
enforceable permit that limits the use of fossil fuels to 10 percent or 
less of their heat input capacity on an annual basis; (2) combined heat 
and power (CHP) units that are subject to a federally enforceable 
permit limiting annual net-electric sales to no more than the unit's 
design efficiency multiplied by its potential electric output, or 
219,000 MWh or less, whichever is greater; (3) stationary combustion 
turbines that are not physically capable of combusting natural gas 
(e.g., not connected to a natural gas pipeline); (4) utility boilers 
and IGCC units that have always been subject to a federally enforceable 
permit limiting annual net-electric sales to one-third or less of their 
potential electric output (e.g., limiting hours of operation to less 
than 2,920 hours annually) or limiting annual electric sales to 219,000 
MWh or less; (5) municipal waste combustors that are subject to subpart 
Eb of this part; and (6) commercial or industrial solid waste 
incineration units subject to subpart CCCC of this part.
---------------------------------------------------------------------------

    \112\ We refer to the capability to combust 250 MMBtu/h of 
fossil fuel as the ``base load rating criterion.'' Note that 250 
MMBtu/h is equivalent to 73 MW or 260 GJ/h heat input.
    \113\ We refer to the capability to supply 25 MW net to the grid 
as the ``total electric sales criterion.''
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D. Units Not Covered by This Final Rule

    As described in the previous section, the EPA is not issuing 
standards of performance for certain types of sources--specifically, 
dedicated non-fossil fuel-fired (e.g., biomass) units and industrial 
CHP units, as well as certain projects under development. This section 
discusses these sources and our rationale for not issuing standards for 
them. Because the rationale applies to both steam generating units and 
combustion turbines, we are describing it here rather than in the 
separate steam generating unit and combustion turbine discussions. We 
discuss the proposed applicability criteria, the topics where the 
agency solicited comment, a brief summary of the relevant comments, and 
the rationale for the final applicability approach for these sources.
1. Dedicated Non-fossil Fuel Units
    The proposed applicability for newly constructed EGUs included 
those that primarily combust fossil fuels (e.g., coal, oil, and natural 
gas). The proposed applicability criteria were that affected units must 
burn fossil fuels for more than 10 percent of the unit's total heat 
input, on average, over a 3-year period.\114\ Under the proposed 
approach, applicability under the final NSPS for CO2 
emissions could have changed on an annual basis depending on the 
composition of fuel burned. We solicited comment on several aspects of 
the proposed applicability criteria for non-fossil fuel units. 
Specifically, we solicited comment on a broad applicability approach 
that would include non-fossil fuel-fired units as affected units, but 
that would impose an alternate standard when the unit fires fossil 
fuels for 10 percent or less of the heat input during the 3-year 
applicability-determination period. We solicited comment on whether, if 
such a subcategory is warranted, the applicability-determination period 
for the subcategory should be 1-year or a 3-year rolling period. We 
also solicited comment on whether the standard for such a subcategory 
should be an alternate numerical limit or ``no emission standard.''
---------------------------------------------------------------------------

    \114\ We refer to the fraction of heat input derived from fossil 
fuels as the ``fossil fuel-use criterion.''
---------------------------------------------------------------------------

    While the proposed exemption applied to all non-fossil fuels, most 
commenters focused on biomass-specific issues. Many commenters 
supported an exclusion for biomass-fired units that fire no more than 
10 percent fossil fuels. Some commenters suggested that the exclusion 
for biomass-fired units should be raised to a 25 percent fossil fuel-
use threshold.
    Many commenters supported the proposed 3-year averaging period for 
the fossil fuel-use criterion because it provides greater flexibility 
for operators to use fossil fuels when supply chains for the primary 
non-fossil fuels are disrupted, during unexpected malfunctions of the 
primary non-fossil fuel handling systems, or when the unit's maximum 
generating capacity is required by system operators for reliability 
reasons. Many commenters supported the 3-year averaging period because 
it is consistent with the final requirements under the EPA's Mercury 
and Air Toxics Standards (MATS) and would allow non-fossil fuel-fired 
units to use some fossil fuels for flame stabilization without 
triggering applicability. Some commenters requested that the EPA 
clarify the method an operator should use during the first 3 years of 
operations to determine if a particular unit will meet the 10 percent 
fossil fuel-use threshold. Others asked whether or not an affected 
facility has a compliance obligation during the first 3-year period 
and, if an

[[Page 64533]]

affected facility does not meet the 10 percent fossil fuel-use 
threshold during several 12-month periods during the first 3 years, 
whether compliance calculations would be required for such 12-month 
periods. Other commenters had concerns with the 3-year averaging 
period, stating that a source would no longer be subject to the NSPS if 
it fell below the threshold for any of the applicability metrics that 
the EPA proposed to calculate on a 3-year (or, in some cases, annual) 
basis. They argued that this would create a situation in which no one 
would know whether a particular plant will be subject to the standards 
until years after the emissions had already occurred. Some commenters 
were concerned that plants operating near the threshold could move in 
and out of the regulatory system, which would provide complications for 
compliance, enforcement, and permitting.
    After considering these comments, the EPA has concluded that the 
proposed fossil fuel-use criterion based on the actual amount of fossil 
fuel burned is not an ideal approach to determine applicability. As 
commenters pointed out, facilities, permitting authorities, and the 
public would not know when construction is commenced whether a facility 
will be subject to the final NSPS, and after operation has commenced, a 
unit could move in and out of applicability each year. The intent of 
this rulemaking is to establish CO2 standards for fossil 
fuel-fired EGUs, not for non-fossil fuel-fired EGUs. Therefore, to 
simplify compliance and establish CO2 standards for only 
those sources which we set out to regulate, we are finalizing a fossil 
fuel-use criterion that will exempt dedicated non-fossil units. 
Specifically, units that are capable of burning 50 percent or more non-
fossil fuel are exempt from the final standards so long as they are 
subject to a federally enforceable permit that limits their use of 
fossil fuels to 10 percent or less of their heat input capacity on an 
annual basis. This approach establishes clear applicability criteria 
and avoids the prospect of units moving in and out of applicability 
based on their actual fuel use in a given year. Consistent with the 
applicability approach in the steam generating unit criteria pollutant 
NSPS, subpart Da, the final fossil fuel-use criterion does not include 
``constructed for the purpose of'' language. Therefore, an owner or 
operator could change a unit's applicability in the future by seeking a 
modification of the unit's permit conditions. A unit with the 
appropriate permit limitation will not be subject to the requirements 
in this rulemaking. Similarly, an existing unit that takes a permit 
limitation restricting fossil-fuel use would no longer be an affected 
unit for the purposes of 111(d) state plans. This is consistent with 
our intent to reduce GHG emissions from fossil fuel-fired EGUs.
    We considered using either an annual or 3-year average for 
calculating compliance with the final fossil fuel-use criterion. 
Ultimately, we concluded that an annual average would provide 
sufficient flexibility for dedicated non-fossil units to combust fossil 
fuels for flame stabilization and other ancillary purposes, while 
maintaining consistency with the 12-month compliance periods used for 
most permit limitations. A 3-year average potentially would allow units 
to combust a significant quantity of fuels in a given year, leading to 
higher CO2 emissions, so long as they curtailed fossil-fuel 
use in a later year. This would defeat the purpose of the criterion, 
which is to exempt dedicated non-fossil units only. Finally, we are 
finalizing the 10 percent fossil-fuel use threshold in relation to a 
unit's heat input capacity rather than its actual heat input, which is 
consistent with past approaches we have taken under the industrial 
boiler criteria pollutant NSPS.
2. Industrial CHP Units
    Another approach to generating electricity is the use of CHP units. 
A CHP unit can use a boiler, combustion turbine, reciprocating engine, 
or various other generating technologies to generate electricity and 
useful thermal energy in a single, integrated system. CHP units are 
generally more efficient than conventional power plants because the 
heat that is normally wasted in a conventional power generation cooling 
system (e.g., cooling towers) is instead recovered as useful thermal 
output. While the EPA did propose some applicability provisions 
specific to CHP units (e.g., subtract purchased power of adjacent 
facilities when determining total electric sales), in general, the 
proposed applicability criteria for electric-only units and CHP units 
were similar. The intent of the proposed total and percentage electric 
sales criteria was to cover only utility CHP units, not industrial CHP 
units. To the extent that the proposal's applicability provisions would 
have the effect of covering industrial CHP units, we solicited comment 
on an appropriate applicability exemption, and the criteria for that 
exemption, for highly efficient CHP facilities.
    Many commenters supported the exclusion of CHP units as a means of 
encouraging capital investments in highly efficient and reliable 
distributed generation technologies. These commenters recommended that 
the EPA adopt an explicit exemption for CHP units at facilities that 
are classified as industrial (e.g., gas-fired CHPs within SIC codes 
2911--petroleum refining, 13--oil and gas extraction, and other 
industrial SIC codes as appropriate). They also stated that the EPA 
should exclude CHP units that have an energy savings of 10 percent or 
more compared to separate heat and power. One commenter suggested that 
the final rule should cover only industrial-commercial-institutional 
CHP units that supply, on a net basis, more than two-thirds of their 
potential combined thermal and electric energy output and more than 
450,000 MWh net-electric output to a utility power distribution system 
on an annual basis for five consecutive calendar years. The commenter 
also suggested that CHP units which have total thermal energy 
production that approaches or exceeds their total electricity 
production should be exempted.
    Other commenters suggested exempting CHP units by fuel type or 
based on the definition of potential electric output. For example, some 
commenters suggested modifying the percentage electric sales threshold 
to be based on net system efficiency (including useful thermal output) 
rather than the rated net-electric-output efficiency. They also 
suggested that the applicability criteria should use a default 
efficiency of 50 percent for CHP units. Some commenters suggested that 
a CHP unit should not be considered an affected EGU if 20 percent or 
more of its total gross or net energy output consisted of useful 
thermal output on a 3-year rolling average basis. Other commenters said 
that highly efficient CHP units that achieve an overall efficiency 
level of 60 to 70 percent or higher should be excluded from 
applicability.
    The intent of this rulemaking is to cover only utility CHP units, 
because they serve essentially the same purpose as electric-only EGUs 
(i.e., the sale of electricity to the grid). Industrial CHP units, on 
the other hand, serve a different primary purpose (i.e., providing 
useful thermal output with electric sales as a by-product). With these 
facts in mind and after considering the comments, the EPA has concluded 
that it is appropriate to consider two factors for the final CHP 
exemption: (1) Whether the primary purpose of the CHP unit is to 
provide useful thermal output rather than electricity and (2) whether 
the CHP unit

[[Page 64534]]

is highly efficient and thus achieves environmental benefits.
    We rejected many of the approaches suggested by the commenters 
because they did not achieve one or both of the factors we identified. 
Specifically, the EPA has concluded that SIC code classification is not 
a sufficient indicator of the purpose (i.e., it does not correlate to 
useful thermal output) or environmental benefits (i.e., efficiency) of 
a unit. Further, an exemption based on SIC code could result in 
circumvention of the intended applicability. For example, this approach 
would allow a new EGU to locate near an industrial site, provide a 
trivial amount of useful thermal output to that site, sell electricity 
to the grid, and nonetheless avoid applicability. Similarly, increasing 
the electric sales criteria to two-thirds of potential electric output 
and 450,000 MWh would essentially amount to a blanket exemption that 
tells us nothing about the primary purpose or efficiency of the unit.
    On the other hand, exemptions based on useful thermal output being 
greater than 20 percent of total output, thermal output being greater 
than electric output, or overall design efficiency value would identify 
whether the primary purpose of a unit is to generate thermal output, 
but they would not recognize the environmental benefits of highly 
efficient CHP units. While overall efficiency may appear to be a good 
indicator of environmental benefits, this is not always the case with 
CHP units. Overall efficiency is a function of both efficient design 
and the power to heat ratio (the amount of electricity relative to the 
amount of useful thermal output). For example, boiler-based CHP units 
tend to produce large amounts of useful thermal output relative to 
electric output and tend to have high overall efficiencies. For units 
producing primarily useful thermal output, the equivalent separate heat 
and power efficiency (i.e., the theoretical overall efficiency if the 
electricity and useful thermal output were produced by a stand-alone 
EGU and stand-alone boiler) would approach that of a stand-alone boiler 
(e.g., 80 percent). However, combustion turbine-based CHP units tend to 
produce relatively equal amounts of electricity and useful thermal 
output. In this case, the equivalent separate heat and power efficiency 
would be closer to 65 percent. Therefore, an exemption based on overall 
efficiency is not an indication of the fuel savings a CHP unit will 
achieve relative to separate heat and power. Further, this approach 
would encourage the development of CHP units that just meet the 
efficiency exemption criterion and would still cover many combustion 
turbine-based industrial CHP units. Conversely, while an exemption 
based on fuel savings relative to separate heat and power would 
recognize the environmental benefit of highly efficient CHP units, it 
would not consider the primary purpose of the CHP unit.
    In the end, the EPA has concluded that maintaining the proposed 
percentage electric sales criterion with two adjustments addresses both 
factors with which we are concerned. First, we are changing the 
definition of ``potential electric output'' to be based on overall net 
efficiency at the maximum electric production rate, instead of just 
electric-only efficiency. Second, we are changing the percentage 
electric sales criterion to reflect the sliding scale, which is the 
overall design efficiency, calculated at the maximum useful thermal 
rating of the CHP unit (e.g., a CHP unit with a extraction condensing 
steam turbine would determine the efficiency at the maximum extraction/
bypass rate), of the unit multiplied by the unit's potential electric 
output instead of one-third of potential electric output as proposed. 
This approach recognizes the primary purpose of industrial CHP units by 
providing a more generous percentage electric sales exemption to CHP 
units with high thermal output. As described previously, CHP units with 
high thermal loads tend to be more efficient and will therefore have a 
higher allowable percentage electric sales. By amending both the 
definition of ``potential electric output'' and the electric sales 
threshold, we assure that CHP units that primarily produce useful 
thermal output are exempted as industrial CHP units even if they are 
selling all of their electric output to the grid. As the relative 
amount of electricity generated by the CHP unit increases, efficiency 
will generally decrease, thus limiting allowable electric sales before 
applicability is triggered. This approach also recognizes the 
environmental benefits of increased efficiency by encouraging 
industrial CHP units to be designed as efficiently as possible to take 
advantage of the higher electric sales permitted by the sliding scale.
    In conclusion, a CHP unit will be an affected source unless it is 
subject to a federally enforceable permit that limits annual total 
electric sales to less than or equal to the unit's design efficiency 
multiplied by its potential electric output or 219,000 MWh,\115\ 
whichever is greater. This final applicability criterion will only 
cover CHP units that condense a significant portion of steam generated 
by the unit and use the electric power generated as a result of 
condensing that steam to supply electric power to the grid. CHP 
facilities that do not have a condensing steam turbine (e.g., 
combustion turbine-based CHP units without a steam turbine and boiler-
based systems with a backpressure steam turbine) would generally not be 
physically capable of selling enough electricity to meet the 
applicability criterion, even if they sold 100 percent of the 
electricity generated and did not subtract out the electricity used by 
the thermal host(s). The EPA has concluded that this is appropriate 
because these sources are industrial by design and provide mostly 
useful thermal output.
---------------------------------------------------------------------------

    \115\ The EPA has concluded that it is appropriate to maintain 
the 219,000 MWh total electric sales criterion for combustion 
turbine based CHP units to avoid potentially covering smaller 
industrial CHP units.
---------------------------------------------------------------------------

    CHP facilities with a steam extraction condensing steam turbine 
will determine their potential electric output based on their 
efficiency on a net basis at the maximum electric production rate at 
the base load heat input rating (e.g., the CHP is condensing as much 
steam as possible to create electricity instead of using it for useful 
thermal output). We have concluded that it is necessary for CHP units 
with extraction condensing steam turbines to calculate their potential 
electric output at the maximum condensing level to avoid circumvention 
of the applicability criteria. For example, to avoid applicability a 
CHP unit could locate next to an industrial host and have the 
capability of selling significant quantities of useful thermal output 
without ever actually intending to supply much, if any, useful thermal 
output to the industrial host. If we calculated the potential electric 
output at the maximum level of thermal output, this type of CHP unit 
could operate at full condensing mode at base load conditions for the 
entire year and still not exceed the electric sales threshold. During 
the permitting process, the owner or operator will be able to determine 
if the unit is subject to the final standards in this rule.
    New EGUs with only limited useful thermal output will be subject to 
the final standards, but the vast majority of new CHP units will be 
classified as industrial CHP and will not be subject to the final 
standards. The EPA has concluded that this approach is similar to 
exempting CHP facilities that sell less than half of their total output 
(electricity plus thermal), but has the benefit of accounting for 
overall design efficiency.

[[Page 64535]]

This approach both limits applicability to the industrial CHP units and 
encourages the installation of the most efficient CHP systems because 
more efficient designs will be able to have higher permitted electric 
sales while not being subject to the CO2 standards included 
in this rulemaking.
3. Municipal Waste Combustors and Commercial and Industrial Solid Waste 
Incinerators
    The purpose of this rulemaking is to establish CO2 
standards for fossil fuel-fired EGUs. Municipal waste combustors and 
commercial and industrial solid waste incinerators typically have not 
been included in this source category. Therefore, even if one of these 
types of units meets the general heat input and electric sales 
criteria, we are not finalizing CO2 emission standards for 
municipal waste combustors subject to subpart Eb of this part and 
commercial and industrial solid waste incinerators subject to subpart 
CCCC of this part.
4. Certain Projects Under Development
    The EPA proposed that a limited class of projects under development 
should not be subject to the proposed standards. These were planned 
sources that may be capable of commencing construction (within the 
meaning of section 111(a)) shortly after the standard's proposal date, 
and so would be classified as new sources, but which have a design 
which would be incapable of meeting the proposed standard of 
performance. See 79 FR 1461 and CAA section 111(a)(2). The EPA proposed 
that these sources would not be subject to the generally-applicable 
standard of performance, but rather would be subject to a unit-specific 
permitting determination if and when construction actually commences. 
The EPA indicated that there could be three sources to which this 
approach could apply, and further indicated that the EPA could 
ultimately adopt the generally-applicable standard of performance for 
these sources (if actually constructed). 79 FR 1461.
    As explained at Section III.J below, the EPA is finalizing this 
approach in this final rule. We again note that these sources, if and 
when constructed, could be ultimately subject to the 1,400 lb 
CO2/MWh-g standard, especially if there is no engineering 
basis, or demonstrated action in reliance, showing that the new source 
could not meet that standard.

E. Coal Refuse

    In the April 2012 proposal, we solicited comment on subcategorizing 
and exempting EGUs that burn over 75 percent coal refuse on an annual 
basis. Multiple commenters supported the exemption, citing numerous 
environmental benefits of remediating coal refuse piles. Observing that 
coal refuse-fired EGUs typically use fluidized bed technologies, other 
commenters disagreed with any exemption, specifically citing the 
N2O emissions from fluidized bed boilers. In light of the 
environmental benefits of remediating coal refuse piles cited by 
commenters, the limited amount of coal refuse, and the fact that a new 
coal refuse-fired EGU would be located in close proximity to the coal 
refuse pile, we sought additional comments regarding a subcategory for 
coal refuse-fired EGUs in the January 2014 proposal. Specifically, we 
requested additional information on the net environmental benefits of 
coal refuse-fired EGUs and information to support an appropriate 
emissions standard for coal refuse-fired EGUs. One commenter on the 
April 2012 proposal stated that existing coal refuse piles are 
naturally combusting at a rate of 0.3 percent annually, and we 
requested comment on this rate and the proper approach to account for 
naturally occurring emissions from coal refuse piles in the January 
2014 proposal.
    Commenters said that a performance standard is not feasible for 
coal refuse CFBs since there is no economically feasible way to capture 
CO2 through a conveyance designed and constructed to capture 
CO2. Commenters suggested that the EPA establish BSER for 
GHGs at modified coal refuse CFBs as a boiler tune-up that must be 
performed at least every 24 months. Commenters stated that the EPA 
should exempt coal refuse CFB units relative to their CO2 
emissions to the extent that these units offset the uncontrolled ground 
level emissions from spontaneous combustion of legacy coal refuse 
stockpiles and noted that the mining of coal waste not only produces 
less emissions in the long term, but also helps to reclaim land that is 
currently used to store coal waste. In contrast, one commenter saw no 
legitimate basis for coal refuse to be subcategorized and stated that 
it should be treated in the same manner as all other coal-fired EGUs.
    The EPA has concluded that an explicit exemption or subcategory 
specifically for coal refuse-fired EGUs is not appropriate. The costs 
faced by coal refuse facilities to install CCS are similar to coal-
fired EGUs burning any of the primary coals, and the final applicable 
requirements and standards in the rule do not preclude the development 
of new coal refuse-fired units without CCS. Specifically, we are not 
finalizing CO2 standards for industrial CHP units. Many 
existing coal refuse-fired units are relatively small and designed as 
CHP units. Due to the expense of transporting coal refuse long 
distances, we anticipate that any new coal refuse-fired EGU would be 
relatively small in size. Moreover, sites with sufficient thermal 
demand exist such that the unit could be designed as an industrial CHP 
facility and the requirements of this rule would not apply.

F. Format of the Output-Based Standard

1. Net and Gross Output-Based Standards
    For all newly constructed units, the EPA proposed standards as 
gross output emission rates consistent with current monitoring and 
reporting requirements under 40 CFR part 75.\116\ For a non-CHP EGU, 
gross output is the electricity generation measured at the generator 
terminals. However, we solicited comment on finalizing equivalent net-
output-based standards either as a compliance alternative or in lieu of 
the proposed gross-output-based standards. Net output is the gross 
electrical output less the unit's total parasitic (i.e., auxiliary) 
power requirements. A parasitic load for an EGU is a load or device 
powered by electricity, steam, hot water, or directly by the gross 
output of the EGU that does not contribute electrical, mechanical, or 
useful thermal output. In general, parasitic energy demands include 
less than 7.5 percent of non-IGCC and non-CCS coal-fired station power 
output, approximately 15 percent of non-CCS IGCC-based coal-fired 
station power output, and about 2.5 percent of non-CCS NGCC power 
output. The use of CCS increases both the electric and steam parasitic 
loads used internal to the unit, and these outputs are not considered 
when determining the emission rate. Net output is used to recognize the 
environmental benefits of: (1) EGU designs and control equipment that 
use less auxiliary power; (2) fuels that require less emissions control 
equipment; and (3) higher efficiency motors, pumps, and fans. For 
modified and reconstructed combustion turbines, the EPA also proposed 
standards as gross output emission rates, but solicited comment on 
finalizing net output standards. The rationale was that due to the low 
auxiliary loads in non-CCS NGCC designs, the difference between a 
gross-output standard and a net-output standard has a limited

[[Page 64536]]

impact on environmental performance. Auxiliary loads are more 
significant for modified and reconstructed boilers and IGCC units, and 
the EPA proposed standards on a net output basis for these units. The 
rationale included that this would enable owners/operators of these 
types of units to pursue projects that reduce auxiliary loads for 
compliance purposes. However, the EPA solicited comment on finalizing 
the standards on a gross-output basis. We also proposed to use either 
gross-output or net-output bases for each respective subcategory of 
EGUs (i.e., utility boilers, IGCC units, and combustion turbines) 
consistently across all CAA section 111(b) standards for new, modified, 
and reconstructed EGUs.
---------------------------------------------------------------------------

    \116\ 79 FR 1447-48.
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    Many commenters supported gross-output-based standards, maintaining 
that a net-output standard penalizes the operation of air pollution 
control equipment. Several commenters disagreed with the agency's 
proposed rationale that a net-output standard would provide incentive 
to minimize auxiliary loads. The commenters believe utility commissions 
and existing economic forces already provide utilities with appropriate 
incentives to properly manage all of these factors. Some commenters 
supported a gross-output-based standard because variations in site 
conditions (e.g., available natural gas pressure, available cooling 
water sources, and elevation) will likely penalize some owners and 
benefit others simply through variations in their particular plant-site 
conditions if a net basis is used. Several commenters stated that if 
the final rule includes a net-output-based standard, it should be 
included as an option in conjunction with a gross-output-based option.
    Several commenters opposed net-output-based standards because they 
believe it is difficult to accurately determine the net output of an 
EGU. They pointed out that many facilities have transformers that 
support multiple units at the facility, making unit-level reporting 
difficult. These commenters also stated that station electric services 
may come from outside sources to supply certain ancillary loads. One 
commenter stated that the benefit of switching to net-output-based 
standards would be small and would not justify the substantial 
complexities in both defining and implementing such a standard. 
Conversely, other commenters stated that net-metering is a well-
established technology that should be required, particularly for newly 
constructed units.
    Other commenters, however, maintained that the final rule should 
strictly require compliance on a net output-basis. They believe that 
this is the only way for the standards to minimize the carbon footprint 
of the electricity delivered to consumers. These commenters believe 
that, at a minimum, net-output-based standards should be included as an 
option in the final rule.
    We are only finalizing gross-output-based standards for utility 
boilers and IGCC units. Providing an alternate net-output-based 
standard that is based on gross-output-based emissions data and an 
assumed auxiliary load is most appropriate when the auxiliary load can 
be reasonably estimated and the choice between the net- and gross-
output-based standard will not impact the identified BSER. For example, 
the auxiliary load for combustion turbines is relatively fixed and 
small, approximately 2.5 percent, so the choice between a gross and 
net-output-based standard will not substantially impact technology 
choices. However, in the case of utility boilers, we have concluded 
that we do not have sufficient information to establish an appropriate 
net-output-based standard that would not impact the identified BSER for 
these types of units. The BSER for newly constructed steam generating 
units is based on the use of partial CCS. However, unlike the case for 
combustion turbines, owners/operators of utility boilers have multiple 
technology pathways available to comply with the actual emission 
standard. The choice of both control technologies and fuel impact the 
overall auxiliary load. For example, a coal-fired hybrid EGU (e.g., one 
that includes integrated solar thermal equipment for feedwater heating 
or steam augmentation) or a coal-fired EGU co-firing natural gas would 
have lower non-CCS related auxiliary loads and, because the amount of 
CCS needed to comply with the standard would also be smaller, the CCS 
auxiliary loads would also be reduced. Therefore, we cannot identify an 
appropriate assumed auxiliary load to establish an equivalent net-
output-based standard. In addition, many IGCC facilities (which could 
be used as an alternative technology for complying with the standard of 
performance; see Sections IV.B and V.P below) have been proposed or are 
envisioned as co-production facilities (i.e., to produce useful by-
products and chemicals along with electricity). As noted in the 
proposal, we have concluded that predicting the net electricity at 
these co-production facilities would be more challenging to implement 
under these circumstances.
    In contrast, based on further evaluation and review of issues 
raised by commenters, the EPA is finalizing the CO2 standard 
for combustion turbine EGUs in a format that is similar to the current 
NSPS format for criteria pollutants. The default final standards 
establish a gross-output-based standard. This allows owners/operators 
of new combustion turbines to comply with the CO2 emissions 
standard under part 60 using the same data currently collected under 
part 75.\117\ However, many permitting authorities commented 
persuasively that the environmental benefits of using net-output-based 
standards can outweigh any additional complexities for particular 
units, and have indeed adopted net-output standards in recent GHG 
operating permits for combustion turbines. We expect this trend to 
continue and have concluded that it is appropriate to support the 
expanded use of net-output-based standards, and therefore are allowing 
certain sources to elect between gross output-based and net-output-
based standards. Only combustion turbines are eligible to make this 
election.
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    \117\ Additionally, having an NSPS standard that is measured 
using the same monitoring equipment as required under the operating 
permit minimizes compliance burden. If a combustion turbine were 
subject to both a gross and net emission limit, more expensive 
higher accuracy monitoring could be required for both measurements.
---------------------------------------------------------------------------

    The rule specifies an alternative net-output-based standard of 
1,030 lb CO2/MWh-n for combustion turbines. This standard is 
equivalent to the otherwise-applicable gross-output-based standard of 
1,000 lb CO2/MWh-g.\118\
---------------------------------------------------------------------------

    \118\ Assuming a 3 percent auxiliary load for the NGCC system.
---------------------------------------------------------------------------

    The procedures for requesting this alternative net-output-based 
standard require the owner or operator to petition the Administrator in 
writing to comply with the alternate applicable net-output-based 
standard. If the Administrator grants the petition, this election would 
be binding and would be the unit's sole means of demonstrating 
compliance. Owners or operators complying with the net-output-based 
standard must similarly petition the Administrator to switch back to 
complying with the gross-output-based standard.
2. Useful Thermal Output
    For CHP units, useful thermal output is also used when determining 
the emission rate. Previous rulemakings issued by the EPA have 
prescribed various ``discount factors'' of the measured useful thermal 
output to be used when determining the emission rate. We proposed that 
75 percent credit is the appropriate discount factor for useful thermal 
output, and we solicited

[[Page 64537]]

comment on a range from two-thirds to three-fourths credit for useful 
thermal output in the proposal for newly constructed units and two-
thirds to one hundred percent credit in the proposal for modified and 
reconstructed units. The 75 percent credit was based on matching the 
emission rate, but not the overall emissions, of a hypothetical CHP 
unit to the proposed emission rate.
    Many commenters said that in order to fully account for the 
environmental benefits of CHP and to reflect the environmental benefits 
of CHP, the EPA should allow 100 percent of the useful thermal output 
from CHP units. Commenters noted that providing 100 percent credit for 
useful thermal output is consistent with the past practice of the EPA 
in the stationary combustion turbine criteria pollutant NSPS and state 
approaches for determining emission rates for CHP units.
    Based on further consideration and review of the comments 
submitted, we are finalizing 100 percent credit for useful thermal 
output for all newly constructed, modified, and reconstructed CHP 
sources. We have concluded that this is appropriate because, at the 
same reported emission rate, a hypothetical CHP unit would have the 
same overall GHG emissions as the combined emission rate of separate 
heat and power facilities. Any discounting of useful thermal output 
could distort the market and discourage the development of new CHP 
units. Full credit for useful thermal output appropriately recognizes 
the environmental benefit of CHP.

G. CO2 Emissions Only

    The air pollutant regulated in this final action is greenhouse 
gases. However, the standards in this rule are expressed in the form of 
limits on only emissions of CO2, and not the other 
constituent gases of the air pollutant GHGs.\119\ We are not 
establishing a limit on aggregate GHGs or separate emission limits for 
other GHGs (such as methane (CH4) or nitrous oxide 
(N2O)) as other GHGs represent less than 1 percent of total 
estimated GHG emissions (as CO2e) from fossil fuel-fired 
electric power generating units.\120\ Notwithstanding this form of the 
standard, consistent with other EPA regulations addressing GHGs, the 
air pollutant regulated in this rule is GHGs.\121\
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    \119\ As noted above, in the Endangerment Finding, the EPA 
defined the relevant ``air pollution'' as the atmospheric mix of six 
long-lived and directly-emitted greenhouse gases: carbon dioxide 
(CO2), methane (CH4), nitrous oxide 
(N2O), hydrofluorocarbons (HFCs), perfluorocarbons 
(PFCs), and sulfur hexafluoride (SF6). 74 FR 66497.
    \120\ EPA Greenhouse Gas Reporting Program; www.epa.gov/ghgreporting/.
    \121\ See 77 FR 31257-30 (June 3, 2010).
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H. Legal Requirements for Establishing Emission Standards

1. Introduction
    In the January 2014 proposal, we described the principal legal 
requirement for standards of performance under CAA section 111(b), 
which is that the standards of performance must consist of standards 
for emissions that reflect the degree of emission limitation achievable 
though the application of the ``best system of emission reduction . . . 
adequately demonstrated,'' taking into account cost and any non-air 
quality health and environment impact and energy requirements. We noted 
that the D.C. Circuit has handed down numerous decisions that interpret 
this CAA provision, including its component elements, and we reviewed 
that case law in detail.\122\
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    \122\ 79 FR 1430, 1462 (January 8, 2014).
---------------------------------------------------------------------------

    We received comments on our proposed interpretation, and in light 
of those comments, in this rule, we are clarifying our interpretation 
in certain respects. We discuss our interpretation below.\123\
---------------------------------------------------------------------------

    \123\ We also discuss our interpretation of the requirements for 
standards of performance and the BSER under section 111(d), for 
existing sources, in the section 111(d) rulemaking that the EPA is 
finalizing with this rule. Our interpretations and applications of 
these requirements in the two rulemakings are generally consistent 
with each other except to the extent that they reflect distinctions 
between new and existing sources. For example, the BSER for new 
industrial facilities, which are expected to have lengthy useful 
lives, should include, at a minimum, the most advanced pollution 
controls available, but for existing sources, the additional costs 
of retrofit may render those controls too expensive.
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2. CAA Requirements and Court Interpretation
    As noted above, the CAA section 111 requirements that govern this 
rule are as follows: As the first step towards establishing standards 
of performance, the EPA ``shall publish . . . a list of categories of 
stationary sources . . . [that] cause[ ], or contribute[ ] 
significantly to, air pollution which may reasonably be anticipated to 
endanger public health or welfare.'' CAA section 111(b)(1)(A). 
Following that listing, the EPA ``shall publish proposed regulations, 
establishing federal standards of performance for new sources within 
such category'' and then ``promulgate . . . such standards'' within a 
year after proposal. CAA section 111(b)(1)(B). The EPA ``may 
distinguish among classes, types, and sizes within categories of new 
sources for the purpose of establishing such standards.'' CAA section 
111(b)(2). The term ``standard of performance'' is defined to ``mean[ ] 
a standard for emissions . . . achievable through the application of 
the best system of emission reduction which [considering cost, non-air 
quality health and environmental impact, and energy requirements] the 
Administrator determines has been adequately demonstrated.'' CAA 
section 111(a)(1).
    As noted in the January 2014 proposal, 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 CAAAs that Congress primarily addressed 
the definition as it read at those times, and that legislative history 
provides guidance in interpreting this provision.\124\ In addition, the 
D.C. Circuit has reviewed rulemakings under CAA section 111 on numerous 
occasions during the past 40 years, handing down decisions dated from 
1973 to 2011,\125\ through which the

[[Page 64538]]

Court has developed a body of case law that interprets the term 
``standard of performance.''
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    \124\ In the 1970 CAAA, Congress defined ``standard of 
performance,'' under 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 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 environment 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 section 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. 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 in 
the case law remain relevant to the definition as it reads today.
    \125\ 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).
---------------------------------------------------------------------------

3. Key Elements of Interpretation
    By its terms, the definition of ``standard of performance'' under 
CAA section 111(a)(1) provides that the emission limits that the EPA 
promulgates must be ``achievable'' by application of a ``system of 
emission reduction'' that the EPA determines to be the ``best'' that is 
``adequately demonstrated,'' ``taking into account . . . 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'' \126\ reduced and the role of ``technological 
innovation.'' \127\ The Court has emphasized that the EPA has 
discretion in weighing those various factors.128 129
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    \126\ See Sierra Club v. Costle, 657 F.2d 298, 326 (D.C. Cir. 
1981).
    \127\ See Sierra Club v. Costle, 657 F.2d at 347.
    \128\ See Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. 
Cir. 1999).
    \129\ Although 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 325-26. It does not appear that those two 
approaches would lead to different outcomes. In this rule, the EPA 
is following the D.C. Circuit case law and treating the factors as 
part of the ``best'' determination.
---------------------------------------------------------------------------

    Our overall approach to determining the BSER, which incorporates 
the various elements, is as follows: First, the EPA identifies the 
``system[s] of emission reduction'' that have been ``adequately 
demonstrated'' for a particular source category. Second, the EPA 
determines the ``best'' of these systems after evaluating extent of 
emission reductions, costs, any non-air health and environmental 
impacts, and energy requirements. And third, the EPA selects an 
achievable standard for emissions--here, the emission rate--based on 
the performance of the BSER. The remainder of this subsection discusses 
the various elements in that analytical approach.
a. ``System[s] of Emission Reduction . . . Adequately Demonstrated''
    The EPA's first step is to identify ``system[s] of emission 
reduction . . . adequately demonstrated.'' For the reasons discussed 
below, for the various types of newly constructed, modified, and 
reconstructed sources in this rulemaking, the EPA focused on efficient 
generation, add-on controls, efficiency improvements, and clean fuels 
as the systems of emission reduction.
    An ``adequately demonstrated'' system, according to the D.C. 
Circuit, 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.'' \130\ It does not mean that the 
system ``must be in actual routine use somewhere.'' \131\ 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.'' \132\ 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.'' \133\ 
Ultimately, the analysis ``is partially dependent on `lead time,' '' 
that is, ``the time in which the technology will have to be 
available.'' \134\ Per CAA section 111(e), standards of performance 
under CAA section 111(b) are applicable immediately after the effective 
date of their promulgation.
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    \130\ Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433 (D.C. 
Cir. 1973), cert. denied, 416 U.S. 969 (1974).
    \131\ 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).
    \132\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 391 
(D.C. Cir. 1973) (citations omitted).
    \133\ Sierra Club v. Costle, 657 F.2d 298, 364 (1981).
    \134\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 391 
(D.C. Cir. 1973) (citations omitted).
---------------------------------------------------------------------------

(1) Technical Feasibility of the Best System of Emission Reduction
    As the January 2014 proposal indicates, the requirement that the 
standard for emissions be ``achievable'' based on the ``best system of 
emission reduction . . . adequately demonstrated'' indicates that one 
of the requirements for the technology or other measures that the EPA 
identifies as the BSER is that the measure must be technically 
feasible. See 79 FR 1430, 1463 (January 8, 2014).
b. ``Best''
    In determining which adequately demonstrated system of emission 
reduction is the ``best,'' the EPA considers the following factors:
(1) 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,\135\ 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,'' \136\ ``greater than the 
industry could bear and survive,'' \137\ ``excessive,'' \138\ or 
``unreasonable.'' \139\ For convenience, in this rulemaking, we use 
`reasonableness' to describe costs well within the bounds established 
by this jurisprudence.\140\
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    \135\ 79 FR 1464 (January 8, 2014).
    \136\ Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. 
Cir. 1999).
    \137\ Portland Cement Ass'n v. EPA, 513 F.2d 506, 508 (D.C. Cir. 
1975).
    \138\ Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981).
    \139\ Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981).
    \140\ 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. Some commenters asserted 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 may be 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 indicated that the EPA has substantial 
discretion in its consideration of cost under section 111(a). 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.'' \141\ See Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 
427, 440 (D.C. Cir. 1973); \142\ 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.

[[Page 64539]]

1981) (upholding standard imposing controls on SO2 emissions 
from coal-fired power plants when the ``cost of the new controls . . . 
is substantial'').\143\ Moreover, section 111(a) does not provide 
specific direction regarding what metric or metrics to use in 
considering costs, again affording the EPA considerable discretion in 
choosing a means of cost consideration.\144\
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    \141\ 1977 House Committee Report at 184.
    \142\ The costs for these standards were described in the 
rulemakings. See 36 FR 24876 (December 23, 1971), 37 FR 5767, 5769 
(March 21, 1972).
    \143\ Indeed, in upholding the EPA's consideration of costs 
under the provisions of the Clean Water Act authorizing technology-
based standards based on performance of a best technology taking 
costs into account, 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); Association of Iron and 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).
    \144\ See, e.g., Husqvarna AB v. EPA, 254 F.3d 195, 200 (D.C. 
Cir. 2001) (where CAA section 213 does not mandate a specific method 
of cost analysis, the EPA may make a reasoned choice as to how to 
analyze costs).
---------------------------------------------------------------------------

    As discussed below, the EPA may consider costs on both a source-
specific basis and a sector-wide, regional, or nationwide basis. The 
EPA is finding here that whether costs are considered on a source-
specific basis, an industry/national basis, or both, they are 
reasonable. See Sections V.H and I below.
(2) Non-Air Quality 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.\145\ The 
EPA has carefully considered such cross-media impacts here, in 
particular potential impacts to underground sources of drinking water 
posed by CO2 sequestration, and water use necessary to 
operate carbon capture systems. See Sections V.N and O below.
---------------------------------------------------------------------------

    \145\ 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).
---------------------------------------------------------------------------

(3) 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'' entail, for example, the 
impact, if any, of the system of emission reduction on the source's own 
energy needs. In this rulemaking, as discussed below in Section V.O.3, 
the EPA considered the parasitic load requirements of partial CCS. The 
EPA is finding here that whether energy requirements are considered on 
a source-specific basis, an industry/national basis, or both, they are 
reasonable. See Sections V.O.3 and XIII.C.
(4) Amount of Emissions Reductions
    At proposal, 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 in fact 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'').\146\ 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.\147\ 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.
---------------------------------------------------------------------------

    \146\ 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'' to read, 
``best technological system.'' As noted above, the 1990 CAAA deleted 
``technological,'' and thereby returned the phrase to how it read 
under the 1970 CAAA. The court's interpretation of this phrase in 
Sierra Club v. Costle to require consideration of the amount of air 
emissions reductions remains valid for the phrase ``best system.''
    \147\ See also NRDC v. EPA, 479 F.3d 875, 880 (D.C. Cir. 2006) 
(``best performing'' source for purposes of CAA section 112 (d)(3) 
is source with the lowest emission levels).
---------------------------------------------------------------------------

(5) Sector or Nationwide Component of the BSER Factors
    As discussed in the January 2014 proposal, 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.\148\ The D.C. Circuit based this 
conclusion on a review of the legislative history, stating,
---------------------------------------------------------------------------

    \148\ 79 FR 1430, 1465 January 8, 2014) (citing Sierra Club v. 
Costle, 657 F.2d at 351).

    The Conferees defined the best technology in terms of ``long-
term growth,'' ``long-term cost savings,'' effects on the ``coal 
market,'' including prices and utilization of coal reserves, and 
``incentives for improved technology.'' Indeed, the 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.\149\
---------------------------------------------------------------------------

    \149\ Sierra Club v. Costle, 657 F.2d at 331 (citations omitted) 
(citing legislative history).

    The Court has upheld 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.\150\
---------------------------------------------------------------------------

    \150\ Sierra Club v. Costle, 657 F.2d at 327-28 (quoting 44 FR 
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).

    Some commenters objected that this case law did not allow the EPA 
to ignore source-specific impacts (particularly cost impacts) by basing 
determinations solely on impacts at a regional or national level. In 
fact, the EPA's consideration of cost, non-air quality impacts, and 
energy requirements reflect source-specific impacts, as well as (for 
some considerations) impacts that are sector-wide, regional, or 
national. See Section V.H.6 below.
c. Achievability of the Standard for Emissions
    In the January 2014 proposal, the EPA recognized that the first 
element of the definition of ``standard of performance'' is that ``the 
emission limit [i.e., the `standard for emissions'] that the EPA 
promulgates must be `achievable' ''

[[Page 64540]]

based on performance of the BSER. 79 FR 1430, 1463 (January 8, 2014). 
According to the D.C. Circuit, a standard for emissions is 
``achievable'' if a technology can reasonably be projected to be 
available to new sources at the time they are constructed that will 
allow them to meet the standard.\151\ 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.'' 
\152\ 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 `cost 
of compliance.' '' \153\ To show that 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.'' \154\
---------------------------------------------------------------------------

    \151\ Portland Cement, 486 F.2d at 391-92. Some commenters 
stated that the EPA's analysis of the requirements for ``standard of 
performance,'' including the BSER, attempted to eliminate the 
requirement that the standard for emissions must be ``achievable.'' 
We disagree with this comment. As just quoted, the EPA's analysis 
recognizes that the standard for emissions must be achievable 
through the application of the BSER.
    \152\ Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433-34 
(D.C. Cir. 1973), cert. denied, 416 U.S. 969 (1974).
    \153\ Nat'l Lime Ass'n v. EPA, 627 F.2d 416, 433, n.46 (D.C. 
Cir. 1980).
    \154\ 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).
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    In Sections V.J and IX.D below, we show both that the BSER for new 
steam generating units and combustion turbines is technically feasible 
and adequately demonstrated, and that the standards of 1,400 lb 
CO2/MWh-g and 1,000 lb CO2/MWh-g are achievable 
considering the range of operating variables that affect achievability.
d. Expanded Use and Development of Technology
    In the January 2014 proposal, we noted that the D.C. Circuit has 
made clear 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.'' \155\
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    \155\ See 79 FR 1430, 1465 (January 8, 2014), Sierra Club v. 
Costle, 657 F.2d at 346-47.
---------------------------------------------------------------------------

    The Court grounded its reading in the statutory text.\156\ In 
addition, in the January 2014 proposal, we noted that the Court's 
interpretation finds additional support in the legislative 
history.\157\ We also explained that 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); (ii) the expanded use of the best demonstrated 
technology; and (iii) the development of emerging technology.\158\ 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. The interpretation is likewise consistent 
with the evident purpose of section 111(b) to require new sources to 
maximize emission reductions using state-of-the-art means of control.
---------------------------------------------------------------------------

    \156\ 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 the EPA must weigh are broadly 
defined and include within their ambit subfactors such as 
technological innovation.'').
    \157\ See 79 FR 1430, 1465 (January 8, 2014) (citing S.Rep. 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. 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'').
    \158\ 79 FR 1465 (citing case law and legislative history).
---------------------------------------------------------------------------

    Commenters stated that the requirement to consider technological 
innovation does not authorize the EPA to identify as the BSER a 
technology that is not adequately demonstrated. The proposal did not, 
and we do not in this final rule, claim to the contrary. In any event, 
as discussed below, the EPA may justify the control technologies 
identified in this rule as the BSER even without considering the factor 
of incentivizing technological innovation or development.
e. Agency Discretion
    As discussed in the January 2014 proposal, 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 NSPS,'' \159\ and emphasized that ``[t]he text gives the 
EPA broad discretion to weigh different factors in setting the 
standard.'' \160\ In Lignite Energy Council v. EPA, 198 F.3d 930 (D.C. 
Cir. 1999), the Court reiterated:
---------------------------------------------------------------------------

    \159\ Sierra Club v. Costle, 657 F.2d at 319.
    \160\ 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.\161\
---------------------------------------------------------------------------

    \161\ Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. 
Cir. 1999) (paragraphing revised for convenience). See also NRDC v. 
EPA, 25 F.3d 1063, 1071 (D.C. Cir. 1994) (The 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 decision making.'').

f. Lack of Requirement That Standard Must Be Met by All Sources
    In the January 2014 proposal, the EPA proposed that, under CAA 
section 111, an emissions standard may meet the requirements of a 
``standard of performance'' even if it cannot be met by every new 
source in the source category that would have constructed in the 
absence of that standard. As described in the January 2014 proposal, 
the EPA based this view on (i) the legislative history of CAA section 
111, read in conjunction with the legislative history of the CAA as a 
whole; (ii) case law under analogous CAA provisions; and (iii) long-
standing precedent in the EPA rulemakings under CAA section 111.\162\
---------------------------------------------------------------------------

    \162\ 79 FR 1430, 1466 (January 8, 2014).

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

[[Page 64541]]

    Commenters contested this assertion, arguing that a 111(b) standard 
must be achievable by all new sources. We continue to take the same 
position as at proposal for the reasons described there. We note that 
as a practical matter, in this rulemaking, the issue of whether all new 
steam-generating sources can implement partial-capture CCS is largely 
dependent on the geographic scope of geologic sequestration sites. As 
discussed below in Section V.M, geologic sequestration sites are widely 
available, and a steam-generating plant with partial CCS that is sited 
near an area that is suitable for geologic sequestration can serve 
demand in a large area that may not have sequestration sites available. 
In any event, the standard of 1,400 lb CO2/MW-g that we 
promulgate in this final rule can be achieved by new steam generating 
EGUs--including new utility boilers and IGCC units--through co-firing 
with natural gas in lieu of installing partial CCS, which moots the 
issue of the geographic availability of geologic sequestration.
g. EPAct05
    The Energy Policy Act of 2005 (``EPAct05'') authorizes assistance 
in the form of grants, loan guarantees, as well as federal tax credits 
for investment in ``clean coal technology.'' Sections 402(i), 421(a), 
and 1307(b) (adding section 48A(g) to the Internal Revenue Code 
(``IRC'')) address the extent to which information from clean coal 
projects receiving assistance under the EPAct05 may be considered by 
the EPA in determining what is the best system of emission reduction 
adequately demonstrated. Section 402(i) of the EPAct05 limits the use 
of information from facilities that receive assistance under EPAct05 in 
CAA section 111 rulemakings:
    ``No technology, or level of emission reduction, solely by reason 
of the use of the technology, or the achievement of the emission 
reduction, by 1 or more facilities receiving assistance under this Act, 
shall be considered to be adequately demonstrated [ ] for purposes of 
section 111 of the Clean Air Act. . . .'' \163\
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    \163\ Codified at 42 U.S.C. 15962(a). EPAct05 section 421(a) 
similarly states: ``No technology, or level of emission reduction, 
shall be treated as adequately demonstrated for purpose [sic] of 
section 7411 of this title, . . . solely by reason of the use of 
such technology, or the achievement of such emission reduction, by 
one or more facilities receiving assistance under section 
13572(a)(1) of this title''.
---------------------------------------------------------------------------

    IRC section 48A(g) contains a similar constraint concerning the use 
of technology or level of emission reduction from EGU facilities for 
which a tax credit is allowed:

    ``No use of technology (or level of emission reduction solely by 
reason of the use of the technology), and no achievement of any 
emission reduction by the demonstration of any technology or 
performance level, by or at one or more facilities with respect to 
which a credit is allowed under this section, shall be considered to 
indicate that the technology or performance level is adequately 
demonstrated [ ] for purposes of section 111 of the Clean Air Act. . 
. .''

    The EPA specifically solicited comment on its interpretation of 
these provisions. 79 FR 10750 (Feb. 26, 2014) (Notice of Data 
Availability). With respect to EPAct05 sections 402(i) and 421(a), the 
EPA proposed that these provisions barred consideration where EPAct05-
assisted facilities were the sole support for the BSER determination, 
but that these sources could support a BSER determination so long as 
there is additional evidence supporting the determination.\164\ In 
addition, the EPA viewed the two prohibitions as relating only to the 
technology or emissions reduction for which assistance was given.\165\ 
The EPA likewise interpreted IRC section 48A(g)--based on the plain 
language and the context provided by sections 402(i) and 421(a)--to 
mean that use of technology, or emission performance, from a facility 
for which the credit is allowed cannot, by itself, support a finding 
that the technology or performance level is adequately demonstrated, 
but the information can corroborate an otherwise supported 
determination or otherwise provide part of the basis for such a 
determination.\166\ The EPA also proposed to interpret the phrase 
``with respect to which a credit is allowed under this section'' as 
referring to the entire phrase ``use of technology (or level of 
emission reduction . . .) and [] achievement of any emission reduction 
. . . , by or at one or more facilities.'' Thus, if technology A 
received a tax credit, but technology B at the same facility did not, 
the constraint would not apply to technology B.\167\
---------------------------------------------------------------------------

    \164\ Technical Support Document, Effect of EPAct05 on Best 
System of Emission Reduction for New Power Plants, p. 6 (Docket 
entry: EPA-HQ-OAR-2013-0495-1873).
    \165\ Id.
    \166\ Id. p. 13.
    \167\ Id. p. 14.
---------------------------------------------------------------------------

    Some commenters supported the EPA's proposed interpretation. Others 
contended that the EPA's interpretation would allow it to support a 
BSER determination even where EPAct05 facility information comprised 99 
percent of the supporting information for a BSER determination because 
that determination would not be based ``solely'' on EPAct05 sources. 
These commenters urged the EPA to conclude that a determination 
``solely'' on the basis of information from EPAct05-assisted facilities 
is any determination where ``but for'' that information, the EPA could 
not justify its chosen standard as the BSER.\168\ Other commenters 
argued that the provisions bar the EPA from all consideration of 
EPAct05 facilities when determining that a technology or level of 
performance is adequately demonstrated.
---------------------------------------------------------------------------

    \168\ Comments of AFPM/API p. 46 (Docket entry: EPA-HQ-OAR-2013-
0495-10098).
---------------------------------------------------------------------------

    In this final rule, the EPA is adopting the interpretations of all 
three provisions that it proposed, largely for the reasons previously 
advanced. The EPA thus interprets these provisions to preclude the EPA 
from relying solely on the experience of facilities that received DOE 
assistance, but not to preclude the EPA from relying on the experience 
of such facilities in conjunction with other information. This reading 
of sections 402(i) and 421(a) is consistent with the views of the only 
court to date to consider the matter.\169\
---------------------------------------------------------------------------

    \169\ State of Nebraska v. EPA, 2014 U.S. Dist. LEXIS 141898 at 
n. 1 (D. Nebr. 2014). (``But the Court notes that Sec.  402(i) only 
forbids the EPA from considering a given technology or level of 
emission reduction to be adequately demonstrated solely on the basis 
of federally-funded facilities. 42 U.S.C. 15962(i). In other words, 
such technology might be adequately demonstrated if that 
determination is based at least in part on non-federally-funded 
facilities'') (emphasis original).
---------------------------------------------------------------------------

    The EPA notes that the extreme hypothetical posed in the comments 
(where the EPA might avoid a limitation on its consideration of 
EPAct05-assisted facilities by including a mere scintilla of evidence 
from non-EPAct05 facilities) is not presented here, where the principal 
evidence that partial post-combustion CCS is a demonstrated and 
feasible technology comes from sources which received no assistance of 
any type under EPAct05. The EPA also concludes that the ``but for'' 
test urged by these commenters is an inappropriate reading of the term 
``solely'' in sections 402(i) and 421(a), as any piece of evidence may 
be a necessary, or ``but for,'' cause without being a sufficient, or 
``sole,'' cause.\170\ Nonetheless, if the ``but for'' test were 
applicable here, the available evidence would satisfy it.
---------------------------------------------------------------------------

    \170\ For example, any vote of a Justice on the Supreme Court 
may be a necessary but not sufficient cause. In a 5-4 decision, the 
decision of the Court would have been different ``but for'' the 
assent of Justice A or Justice B, who were in the majority. But it 
would be incorrect to say that the assent of Justice A was the 
``sole'' reason for the outcome, when the decision also required the 
assent of Justice B.

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

[[Page 64542]]

    Other commenters took the extreme position that the EPAct05 
provisions bar all consideration of a facility's existence if the 
facility received EPAct05 assistance.\171\ The EPA does not accept this 
argument because it is contrary to both the plain statutory language 
\172\ (see Chapter 2 of the Response-to-Comment document) and to 
Congress's intent that the EPAct05 programs advance the 
commercialization of clean coal technology. For the same reason, the 
EPA does not accept some commenters' suggestion that sections 402(i), 
421(a), and 48A(g) preclude the EPA from considering NETL's cost 
projections for CCS, which base cost estimates on up-to-date vendor 
quotes reflecting costs for the CCS technology being utilized at the 
Boundary Dam Unit #3 facility (a facility receiving no assistance under 
EPAct05), but also considers that to-be-built plants will no longer be 
first-of-a kind. See generally Section V.I.2 below. Commenters suggest 
that the EPAct05 requires that the EPA treat future plants as ``first 
of a kind'' when projecting costs, as if EPAct05 facilities simply did 
not exist. This reading is contrary to the text of the provisions, 
which as noted, relates specifically to a source's performance and 
operation (whether a technology is demonstrated, and the level of 
performance achieved by use of technology), not to sources' existence. 
NETL's cost projections, on the other hand, merely acknowledge the 
evident fact that CCS technologies exist, and reasonably project that 
they will continue to develop. See Section V.I.2. The NETL cost 
estimates, moreover, are based on vendor quotes for the CCS technology 
in use at the Boundary Dam facility, a Canadian plant which obviously 
is not a recipient of EPAct05 assistance. See sections V.D.2.a and V. 
I.2 below.
---------------------------------------------------------------------------

    \171\ Supplemental Comments of Murray Energy p. 11 (Docket 
entry: EPA-HQ-OAR-2013-0495-9498).
    \172\ With respect to sections 402(i) and 421(a), commenters 
fail to reconcile their reading of the statute with the Act's 
grammatical structure, as explained in detail in chapter 2 of the 
Response-to-Comment document. One commenter supported its reading by 
adding suggested text to the statutory language, a highly disfavored 
form of statutory construction. Comments of UARG, p.124 n.38 (Docket 
entry: EPA-HQ-OAR-2013-0495-9666). With respect to section 48A(g), 
commenters misread the phrase ``considered to indicate,'' and do not 
explain how their reading of all three provisions together is 
tenable.
---------------------------------------------------------------------------

    In any case, as shown in Section V below, the EPA finds that a new 
highly-efficient SCPC EGU implementing partial post-combustion CCS is 
the best system of emission reduction adequately demonstrated and is 
doing so based in greater part on performance of facilities receiving 
no assistance under EPAct05, and on other information likewise not 
having any connection to EPAct05 assistance. The corroborative 
information from EPAct05 facilities, though supportive, is not 
necessary to the EPA's findings.

I. Severability

    This rule has numerous components, and the EPA intends that they be 
severable from each other to the extent that they function separately. 
For example, the EPA intends that each set of BSER determinations and 
standards of performance in this rulemaking be severable from each 
other set. That is, the BSER determination and standard of performance 
for newly constructed fossil fuel-fired electric utility steam 
generating units are severable from all the other BSER determinations 
and standards of performance, and the same is true for the BSER 
determination and standard of performance for modified fossil fuel-
fired electric utility steam generating units, and so on. It is 
reasonable to consider each set of BSER determination and standard of 
performance to be severable from each other set of BSER determination 
and standard of performance because each set is independently 
justifiable and does not depend on any other set. Thus, in the event 
that a court should strike down any set of BSER determination and 
standard of performance, the remaining BSER determinations and 
standards of performance should not be affected.

J. Certain Projects Under Development

    In the January 2014 proposal, the EPA indicated that the proposed 
Wolverine EGU project (Rogers City, Michigan) appeared to be the only 
fossil fuel-fired steam generating unit that was currently under 
development that may be capable of ``commencing construction'' for NSPS 
purposes at the time of the proposal. See 79 FR 1461. The EPA also 
acknowledged that the Wolverine EGU, as designed, would not meet the 
proposed standard of 1,100 lb CO2/MWh for new utility steam 
generating EGUs. The EPA proposed that, at the time of finalization of 
the proposed standards, if the Wolverine project remains under 
development and has not either commenced construction or been canceled, 
we anticipated proposing a standard of performance specifically for 
that facility. Additional discussion of the approach can be found in 
the proposal or in the technical support document in the docket 
entitled ``Fossil Fuel-Fired Boiler and IGCC EGU Projects under 
Development: Status and Approach.''
    In December 2013--after the proposed action was signed, but before 
it was published--Wolverine Power Cooperative announced that it was 
cancelling construction of the proposed coal-fired power plant in 
Rogers City, MI.\173\ Therefore, we are not finalizing the proposed 
exclusion for that project.
---------------------------------------------------------------------------

    \173\ ``Wolverine ends plant speculation in Rogers City'', The 
Alpena News, December 17, 2013. http://www.thealpenanews.com/page/content.detail/id/527862/Wolverine-ends-plant-speculation-in-Rogers-City.html?nav=5004.
---------------------------------------------------------------------------

    In the January 2014 proposal, the EPA also identified two other 
fossil fuel-fired steam generating EGU projects that, as currently 
designed, would not meet the proposed 1,100 lb CO2/MWh 
emissions standard--the Plant Washington project in Georgia and the 
Holcomb 2 project in Kansas. We indicated that, at the time of the 
proposal, those projects appeared to remain under development but that 
the project developers had represented that the projects have commenced 
construction for NSPS purposes and, thus, would not be new sources 
subject to the proposed or final NSPS. Based solely on the developers' 
representations, the EPA indicated that those projects, if ultimately 
fully constructed, would be existing sources, and would thus not be 
subject to the standards of performance in this final action.
    To date, neither developer has sought a formal EPA determination of 
NSPS applicability. As we specified in the January 2014 proposal--and 
we reiterate here--if such an applicability determination concludes 
that either the Plant Washington (GA) project or the Holcomb 2 (KS) 
project did not commence construction prior to January 8, 2014 (the 
publication of the January 2014 proposal), then the project should be 
situated similarly to the disposition the EPA proposed for the 
Wolverine project. Accordingly, the EPA is finalizing in this action 
that if it is determined that either of these projects has not 
commenced construction as January 8, 2014, then that project will be 
addressed in the same manner as was proposed for the Wolverine project.
    In public comments submitted in response to the January 2014, 
Power4Georgians (P4G), the Plant Washington developer, reiterated that 
they had executed binding contracts for the purchase and erection of 
the facility boiler prior to publication of the January 2014 proposal 
and believe that the binding contracts are sufficient to constitute 
commencement of construction for purposes of the NSPS program, so that 
they are existing rather than new sources for purposes of this

[[Page 64543]]

rule.\174\ Public comments submitted by Tri-State Generation and 
Transmission Association and Sunflower Electric Power Corporation, the 
developers of the Holcomb 2 project, discussed the cost incurred in the 
development of the project. They also indicated they had awarded 
contracts for the turbine/generator purchase and had negotiated a rail-
supply agreement that provides for the delivery of fuel to the proposed 
Holcomb 2 site. The developers did not, however, explicitly 
characterize the construction status of the project.\175\ Other groups 
submitted comments contending that neither project has actually 
commenced construction.
---------------------------------------------------------------------------

    \174\ Docket entry: EPA-HQ-OAR-2013-0495-9403.
    \175\ Docket entry: EPA-HQ-OAR-2013-0495-9599.
---------------------------------------------------------------------------

    In October 2013, the Kansas Supreme Court invalidated the 2010 air 
pollution permit granted to Sunflower Electric Power Corporation by the 
Kansas Department of Health and Environment (KDHE).\176\ In May 2014, 
the KDHE issued an air quality permit addendum for the proposed Holcomb 
2 coal plant. The addendum addressed federal regulations that the 
Kansas Supreme Court held had been overlooked in the initial permitting 
determination. In June 2014, the Sierra Club filed an appeal with the 
Kansas Appellate Court challenging the legality of the May 2014 permit. 
Since the publication of the January 2014 proposal, the EPA is unaware 
of any physical construction activity at the proposed Holcomb 2 site.
---------------------------------------------------------------------------

    \176\ ``Kansas High Court Invalidates 895-MW Coal Project Air 
Permit'', Power Magazine, 10/10/2013, available at: 
www.powermag.com/kansas-high-court-invalidates-2010-895-mw-coal-project-air-permit/.
---------------------------------------------------------------------------

    In October 2014, the Plant Washington project was given an 18-month 
air permit extension by the Georgia Environmental Protection Division 
(EPD). However, as with the Holcomb expansion project, the EPA is 
unaware of any physical construction that has taken place at the 
proposed Plant Washington site and a recent audit of the project 
described it as ``dormant''.\177\
---------------------------------------------------------------------------

    \177\ http://www.macon.com/2015/06/23/3811798/audit-sandersville-coal-plant.html.
---------------------------------------------------------------------------

    Based on this information, it appears that these sources have not 
commenced construction for purposes of section 111(b) and therefore 
would likely be new sources should they actually be constructed. As 
noted above, the EPA proposed that, if these projects are determined to 
not have commenced construction for NSPS purposes prior to the 
publication of the proposed rule, they will be addressed in the same 
manner proposed for the Wolverine project. 79 FR 1461. We are 
finalizing that proposal here. However, because these units may never 
actually be fully built and operated, we are not promulgating a 
standard of performance at this time because such action may prove to 
be unnecessary.\178\
---------------------------------------------------------------------------

    \178\ In the proposed emission guidelines for existing EGUs, the 
EPA did not include estimates of emissions for either Plant 
Washington or the Holcomb 2 unit in baseline data used to calculate 
proposed state goals for Georgia and Kansas. It appears that the 
possibility of these plants actually being built and operating is 
too remote. If either unit eventually seeks an applicability 
determination and that unit is determined to be an existing source, 
and there is reliable evidence that the source will operate, then 
the source will be subject to the final 111(d) rule and the EPA will 
allow the state to adjust its state goal to reflect adjustment of 
the state's baseline data so as to include the unit. Guidance for 
adjustment of state goals is provided in the record for the EPA's 
final CAA section 111(d) rulemaking.
---------------------------------------------------------------------------

    There is one possible additional new EGU, the Two Elk project in 
Wyoming. In a supporting TSD accompanying the January 2014 proposal, we 
discussed the Two Elk project and relied on developer statements and 
state acquiescence that the unit had commenced construction for NSPS 
purposes before January 8, 2014.\179\ We did not, therefore, propose 
any special section 111(b) standard for the project. Some commenters 
maintained that a continuous program of construction at the facility 
has not been maintained and that if the plant is ultimately 
constructed, it should be classified as a new source under CAA section 
111(b). These comments were not specific enough to change the EPA's 
view of the project for purposes of this rulemaking. We accordingly 
continue to rely on developer statements that this facility has 
commenced construction and would not be a new source for purposes of 
this proceeding.
---------------------------------------------------------------------------

    \179\ ``Fossil Fuel-Fired Boiler and IGCC EGU Projects Under 
Development: Status and Approach'', Technical Support Document at 
pp. 10-1 (Docket Entry: EPA-HQ-OAR-2013-0495-0024).
---------------------------------------------------------------------------

IV. Summary of Final Standards for Newly Constructed, Modified, and 
Reconstructed Fossil Fuel-Fired Electric Utility Steam Generating Units

    This section sets forth the standards for newly constructed, 
modified, and reconstructed steam generating units (i.e., utility 
boilers and IGCCs). We explain the rationale for the final standards in 
Sections V (newly constructed steam generating unit), VI (modified 
steam generating units), and VII (reconstructed steam generating 
units).

A. Applicability Requirements and Rationale

    We generally refer to fossil fuel-fired electric utility generating 
units that would be subject to an emission standard in this rulemaking 
as ``affected'' or ``covered'' sources, units, facilities or simply as 
EGUs. These units meet both the definition of ``affected'' and 
``covered'' EGUs subject to an emission standard as provided by this 
rule, and the criteria for being considered ``new,'' ``modified'' or 
``reconstructed'' sources as defined under the provisions of CAA 
section 111 and the EPA's regulations. This section discusses 
applicability for newly constructed, modified, and reconstructed steam 
generating units.
1. General Applicability Criteria
    The EPA is finalizing applicability criteria for new, modified, and 
reconstructed electric utility steam generating units (i.e., utility 
boilers and IGCC units) in 40 CFR part 60, subpart TTTT that are 
similar to the applicability criteria for those units in 40 CFR part 
60, subpart Da (utility boiler and IGCC performance standards for 
criteria pollutants), but with some differences. The proposed 
applicability criteria, relevant comments, and final applicability 
criteria specific to newly constructed, modified, and reconstructed 
steam generating units are discussed below.
    The applicability requirements in the proposal for newly 
constructed EGUs included that a utility boiler or IGCC unit must: (1) 
Be capable of combusting more than 250 MMBtu/h heat input of fossil 
fuel; (2) be constructed for the purpose of supplying, and actually 
supply, more than one-third of its potential net-electric output 
capacity to any utility power distribution system (that is, to the 
grid) for sale on an annual basis; (3) be constructed for the purpose 
of supplying, and actually supply, more than 219,000 MWh net-electric 
output to the grid on an annual basis; and (4) combust over 10 percent 
fossil fuel on a heat input basis over a 3-year average. At proposal, 
applicability was determined based on a combination of design and 
actual operating conditions that could change annually depending on the 
proportion and the amount of electricity actually sold and on the 
proportion of fossil fuels combusted by the unit.
    In the proposal for modified and reconstructed EGUs, we proposed a 
broader applicability approach such that applicability would be based 
solely on design criteria and would be identical to the applicability 
requirements in

[[Page 64544]]

subpart Da. First, we proposed electric sales criteria that the source 
be constructed for the purpose of selling more than one-third of their 
potential electric output and more than 219,000 MWh to the grid on an 
annual basis, regardless of the actual amount of electricity sold 
(i.e., we did not include the applicability criterion that the unit 
actually sell the specified amount of electricity on an annual basis). 
In addition, we proposed a base load rating criterion that the source 
be capable of combusting more than 250 MMBtu/h of fossil fuel, 
regardless of the actual amount of fossil fuel burned (i.e., we did not 
include the fossil fuel-use criterion that an EGU actually combust more 
than 10 percent fossil fuel on a heat input basis on a 3-year average). 
Under this approach, applicability would be known prior to the unit 
actually commencing operation and would not change on an annual basis. 
We also proposed that the final applicability criteria would be 
consistent for newly constructed, reconstructed, and modified units. 
The proposed broad applicability criteria would still not have included 
boilers and IGCC units that were constructed for the purpose of selling 
one-third or less of their potential output or 219,000 MWh or less to 
the grid on an annual basis. These units are not covered under subpart 
Da (the utility boiler and IGCC EGU criteria pollutant NSPS) but are 
instead covered as industrial boilers under subpart Db (industrial, 
institutional, and commercial boilers NSPS) or subpart KKKK (the 
combustion turbine criteria pollutant NSPS).
    We solicited comment on whether, to avoid implementation issues 
related with different interpretations of ``constructed for the 
purpose,'' the total and percentage electric sales criteria should be 
recast to be based on permit conditions. The ``constructed for the 
purpose'' language was included in the original subpart Da rulemaking. 
At that time, the vast majority of new steam generating units were 
clearly base load units. The ``constructed for the purpose'' language 
was intended to exempt industrial CHP units. These units tend to be 
relatively small and were not the focus of the rulemaking. In addition, 
units not meeting the electric sales applicability criteria in subpart 
Da would be covered by other NSPS so there is limited regulatory 
incentive, or impact to the environment, for owners/operators to avoid 
applicability with the utility NSPS. However, for new units, there is 
no corresponding industrial unit CO2 NSPS and existing units 
could debate their original intent (i.e., the purpose for which they 
were constructed) in an attempt to avoid applicability under section 
111(d) requirements. Consequently, there could be a regulatory 
incentive for owners/operators to circumvent the CO2 NSPS 
applicability. For units that avoid coverage, there would also be a 
corresponding environmental impact. For example, an owner/operator of a 
new unit could initially request a permit restriction to limit electric 
sales to less than one-third of potential annual electric output, but 
amend the operating permit shortly after operation has commenced to 
circumvent the intended applicability. Many existing units were 
initially built with excess capacity to account for projected load 
growth and were intended to sell more than one-third of their potential 
electric output. However, due to various factors (lower than expected 
load growth, availability of other lower cost units, etc.), certain 
units might have sold less than one-third of their potential electric 
output, at least during their initial period of operation. Therefore, 
the EPA has concluded that determining applicability based on whether a 
unit is ``constructed for the purpose of supplying one-third or more of 
its potential electric output and more than 219,000 MWh as net-electric 
sales'' (emphasis added) could create applicability uncertainty for 
both the regulated community and regulators. In addition, we have 
concluded that applicability based on actual operating conditions 
(i.e., actual electric sales) is not ideal because applicability would 
not be known prior to determining compliance and could change annually.
    This action finalizes applicability criteria based on design 
characteristics and federally enforceable permit restrictions included 
in each individual permit. Based on restrictions, if any, on annual 
total electric sales in the operating permit, it will be clear from the 
time of construction whether or not a new unit is subject to this rule. 
The applicability includes all utility boilers and IGCC units unless 
the electric sales restriction was in the original and remains in the 
current operating permit without any lapses (this is to be consistent 
with the `constructed for the purpose of' criteria in subpart Da). We 
have concluded that this approach is equivalent to, but clearer than, 
the existing language used in subpart Da. In addition, we have 
concluded that it is important for both the 111(b) and 111(d) 
requirements for electric-only steam generating units that the permit 
restriction limiting annual electric sales be included in both the 
original and current operating permit. Without this restriction, 
existing units could avoid obligations under state plans developed as 
part of the 111(d) program by amending their operating permit to limit 
total annual electric sales to one-third of potential electric output. 
These units would not be subject to any GHG NSPS requirements because 
they would not meet the 111(b) or 111(d) applicability criteria and, at 
this time, there is no NSPS that would cover these units. As described 
in Section III, industrial CHP and dedicated non-fossil units also are 
not affected EGUs under this final action.
    In this rule, we are finalizing the definition of a steam 
generating EGU as a utility boiler or IGCC unit that: (1) Has a base 
load rating greater than 260 GJ/h (250 MMBtu/h) of fossil fuel (either 
alone or in combination with any other fuel) and (2) serves a generator 
capable of supplying more than 25 MW-net to a utility distribution 
system (i.e., for sale to the grid). However, we are not establishing 
final CO2 standards for certain EGUs. These include: (1) 
Steam generating units and IGCC units that are currently subject to--
and have been continuously subject to--a federally enforceable permit 
limiting annual electric sales to one-third or less of their potential 
electric output (e.g., limiting hours of operation to less than 2,920 
hours annually) or limiting annual electric sales to 219,000 MWh or 
less; (2) units subject to a federally enforceable permit that limits 
the use of fossil fuels to 10 percent or less of the unit's heat input 
capacity on an annual basis; and (3) CHP units that are subject to a 
federally enforceable permit condition limiting annual total electric 
sales to no more than their design efficiency times their potential 
electric output, or to no more than 219,000 MWh, whichever is greater.
2. Applicability Specific to Newly Constructed Steam Generating Units
    In CAA section 111(a)(2), a ``new source'' is defined as 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 this section 
which will be applicable to such source. Accordingly, for purposes of 
this rule, a newly constructed steam generating EGU is a unit that fits 
the definition and applicability criteria of a fossil fuel-fired steam 
generating EGU and commences construction on or after January 8, 2014, 
which is the date that the proposed standards were published for those 
sources (see 79 FR 1430).

[[Page 64545]]

3. Applicability Specific to Modified Steam Generating Units
    In CAA section 111(a)(4), a ``modification'' is defined as ``any 
physical change in, or change in the method of operation of, a 
stationary source'' that either ``increases the amount of any air 
pollutant emitted by such source or . . . results in the emission of 
any air pollutant not previously emitted.'' The EPA, through 
regulations, has determined that certain types of changes are exempt 
from consideration as a modification.\180\
---------------------------------------------------------------------------

    \180\ 40 CFR 60.2, 60.14(e).
---------------------------------------------------------------------------

    For purposes of this rule, a modified steam generating EGU is a 
unit that fits the definition and applicability criteria of a fossil 
fuel-fired steam generating EGU and that modifies on or after June 18, 
2014, which is the date that the proposed standards were published for 
those sources (see 79 FR 34960).
4. Applicability Specific to Reconstructed Steam Generating Units
    The NSPS general provisions (40 CFR part 60, subpart A) provide 
that an existing source is considered a new source if it undertakes a 
``reconstruction,'' which is the replacement of components of an 
existing facility to an extent that: (1) 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 (2) it 
is technologically and economically feasible to meet the applicable 
standards.\181\
---------------------------------------------------------------------------

    \181\ 40 CFR 60.15.
---------------------------------------------------------------------------

    For purposes of this rule, a reconstructed steam generating EGU is 
a unit that fits the definition and applicability criteria of a fossil 
fuel-fired steam generating EGU and that reconstructs on or after June 
18, 2014, which is the date that the proposed standards were published 
for those sources (see 79 FR 34960).

B. Best System of Emission Reduction

1. BSER for Newly Constructed Steam Generating Units
    In the January 2014 proposal, the EPA proposed that highly 
efficient new generation technology implementing partial CCS is the 
BSER for GHG emissions from new steam generating EGUs. (See generally 
79 FR 1468-1469.) In this final action, the EPA has determined that the 
BSER for newly constructed steam generating units is a new highly 
efficient supercritical pulverized coal (SCPC) boiler implementing 
partial CCS technology to the extent of removal efficiency that meets a 
final emission limitation of 1,400 lb CO2/MWh-g. The final 
standard of performance is less stringent than the proposed emission 
limitation of 1,100 lb CO2/MWh-g. This change, as will be 
discussed in greater detail later in this preamble, is in response to 
public comments and reflects both a re-examination of the potential 
BSER technologies and the most recent, reliable information regarding 
technology costs. A newly constructed fossil fuel-fired supercritical 
utility boiler will be able to meet the final standard by implementing 
post-combustion carbon capture treating a slip-stream of the combustion 
flue gas. Alternative potential compliance paths are to build a new 
IGCC unit and co-fire with natural gas (or use pre-combustion carbon 
capture on a slip-stream), or for a supercritical utility boiler to co-
fire with natural gas.
    The EPA of course realizes that the final standard of performance 
(1,400 lb CO2/MWh-g) differs from the proposed standard 
(1,100 lb CO2/MWh-g). The EPA notes further, however, that 
the methodology for determining the final standard of performance is 
identical to that at proposal--determining that a new highly efficient 
generating technology implementing some degree of partial CCS is the 
BSER, with that degree of implementation being determined based on the 
reasonableness of costs. A key means of assessing the reasonableness of 
cost at proposal was comparison of the levelized cost of electricity 
(LCOE) with that of other dispatchable, base load non-NGCC generating 
options. We have maintained that approach in identifying BSER for the 
final standard. Applying this methodology to the most recent cost 
information has led the EPA to adopt the final standard of performance 
of 1,400 lb CO2/MWh-g. See Section V.H at Table 8 below. 
This final standard reflects the level of emission reduction achievable 
by a highly efficient SCPC implementing the degree of partial CCS that 
remains cost comparable to the other non-NGCC dispatchable base load 
generating options.
    The BSER for newly constructed steam generating EGUs in the final 
rule is very similar to that in the proposal. In this final action, the 
EPA finds that a highly efficient new SCPC EGU implementing partial CCS 
to the degree necessary to achieve an emission of 1,400 lb 
CO2/MWh-g is the BSER. Contrary to the January 2014 
proposal, the EPA finds that IGCC technology--either alone or 
implementing partial CCS--is not part of the BSER, but rather is a 
viable alternative compliance option. As noted at proposal, a BSER 
typically advances performance of a technology beyond current levels of 
performance. 79 FR 1465, 1471. Similarly, promotion of technology 
innovation can be a relevant factor in BSER determinations. Id. and 
Section III.H.3.d above. For these reasons, the EPA at proposal voiced 
concerns about adopting standards that would allow an IGCC to comply 
without utilizing CCS for slip-stream control. Id. at 1471. The final 
standard of 1,400 lb CO2/MWh-g, adopted as a means of 
assuring reasonableness of costs, allows IGCC units to comply without 
using partial CCS. Thus, although the standard can be met by a highly 
efficient new IGCC unit using approximately 3 percent partial CCS (see 
Sections V.E and V.H.7 below), the EPA does not believe that 
implementation of partial CCS at such a low level, while technically 
feasible, is the option that utilities and project developers will 
choose. The EPA believes that IGCC project developers will either 
choose to meet the final standard by co-firing with natural gas--which 
would be a less costly and very straightforward process for a new IGCC 
unit--or they will choose to install CCS equipment that will allow the 
facility to achieve much deeper CO2 reductions than required 
by this rule--likely to co-produce chemicals and/or to capture large 
volumes of CO2 for use in EOR operations. Similarly, project 
developers may also--as an alternative to utilizing partial CCS 
technology--meet the final standard by co-firing approximately 40 
percent natural gas in a new highly efficient SCPC EGU.
    While the EPA does not find that IGCC technology--either alone or 
with implementation of partial CCS--is part of the BSER for new steam 
generating EGUs, we remain convinced that it is technically feasible 
(see Section V.E below) and believe that it represents a viable 
alternative compliance option that some project developers will 
consider to meet the final standard issued in this action. The EPA 
notes further that IGCC is available at reasonable cost (see Table 9 
below), and involves use of an advanced technology. So, although the 
final standard reflects performance of a BSER which includes partial 
CCS, even in the instances that a compliance alternative might be 
utilized, that alternative would both result in emission reductions 
consistent with use of the BSER, and would reflect many of the 
underlying principles and attributes of the BSER (costs are both 
reasonable, not greatly dissimilar than BSER, no collateral adverse 
impacts on health or the environment, and reflects

[[Page 64546]]

performance of an advanced technology).
    In reaching the final standard of performance, the EPA is aware 
that at proposal, the agency stated that it was not ``currently 
considering'' a standard of performance as high as 1,400 lb 
CO2/MWh-g. 79 FR 1471. However, in that same discussion, the 
EPA noted the reasons for its reservations (chiefly reservations about 
the extent of emission reductions, promotion of advanced CO2 
control technologies, and whether the standard could be met by either 
utility boilers or IGCC units co-firing with natural gas, or otherwise 
complying without utilizing partial CCS), and we specifically solicited 
comment on the issue: ``We request that commenters who suggest emission 
rates above 1,200 lb CO2/MWh address potential concerns 
about providing adequate reductions and technology development to be 
considered BSER.'' Id. The proposal thus both solicited comment on 
higher emission standards (including 1,400 lb CO2/MWh-g 
based on a less aggressive rate of partial CCS), and provided ample 
notice of the methodology the EPA would use to determine the final BSER 
and the corresponding final standard.\182\ For these reasons, the EPA 
believes that it provided adequate notice of this potential outcome at 
proposal, that the final standard of performance was reasonably 
foreseeable, and that the final standard is a logical outgrowth of the 
proposed rule. Allina Health Services v. Sebelius, 746 F. 3d 1102, 1107 
(D.C. Cir. 2014).
---------------------------------------------------------------------------

    \182\ Although co-firing with natural gas is not part of BSER, 
as noted above, it could be part of a compliance pathway for either 
SCPC or IGCC units. In this regard, a number of commenters addressed 
the issue of natural gas co-firing, indicating that there were 
circumstances where it could be part of BSER. See e.g. Comments of 
Exelon Corp. p. 12 (Docket entry: EPA-HQ-OAR-2013-0495-9406); 
Comments of the Sierra Club p. 108 Docket entry: EPA-HQ-OAR-2013-
0495-9514). See Northeast Md. Waste Disposal Authority v. EPA, 358 
F.3d 936, 952 (D.C. Cir. 2004); Appalachian Power v. EPA, 135 F.3d 
791, 816 (D.C. Cir. 1998) (commenters understood a matter was under 
consideration when they addressed it in comments).
---------------------------------------------------------------------------

    A more detailed discussion of the rationale for the final BSER 
determination and of other systems that were also considered is 
provided in Section V.P of this preamble.\183\
---------------------------------------------------------------------------

    \183\ Certain commenters maintained that the BSER determination 
does not comply with (purportedly) binding legal requirements 
created by regulations implementing the Information Quality Act. 
These comments are mistaken as a matter of both law and fact. The 
Information Quality Act does not create legal rights in third 
parties (see, e.g. Mississippi Comm'n on Environmental Quality v. 
EPA, no. 12-1309 at 84 (D.C. Cir. June 2, 2015)), and the OMB 
Guidelines are not binding rules but rather, as their title 
indicates, guidance to assist agencies. See State of Mississippi, 
744 F.3d at 1347 (the Guidelines provide ``policy and procedural 
guidance'', are meant to be ``flexible'' and are to be implemented 
differently by different agencies accounting for circumstances). 
There are also significant factual omissions and 
mischaracterizations in these comments regarding peer review of the 
proposed standard and underlying record information. The complete 
response to these comments is in chapter 2 of the RTC. See also 
Section V.I.2.a and N below describing findings of the SAB panel 
that materials of the National Energy Technology Laboratory had been 
fully and adequately peer reviewed, and that the EPA findings 
related to sequestration of captured CO2 reflected the 
best available science.
---------------------------------------------------------------------------

2. BSER for Modified Steam Generating Units
    The EPA has determined that, as proposed, the BSER for steam 
generating units that trigger the modification provisions is the 
modified unit's own best potential performance. However, as explained 
below, the final BSER determination and the scope of modifications to 
which the final standards apply differ in some important respects from 
what the EPA proposed.
    The EPA proposed that the modified unit's best potential 
performance would be determined depending upon when the unit 
implemented the modification (i.e., before or after being subject to an 
approved CAA section 111(d) state plan). For units that commenced 
modification prior to becoming subject to an approved CAA section 
111(d) state plan, the EPA proposed unit-specific standards consistent 
with each modified unit's best one-year historical performance (during 
the years from 2002 to the time of the modification) plus an additional 
two percent reduction. For sources that commenced modification after 
becoming subject to an approved CAA section 111(d) plan, the EPA 
proposed that the unit's best potential performance would be determined 
from the results of an efficiency audit.
    The final standards in this action do not depend upon when the 
modification commences, as long as it commences after June 18, 2014. We 
are establishing emission standards for large modifications in this 
rule and deferring at this time the setting of standards for small 
modifications.
    In this final action, the EPA is issuing final emission standards 
for affected steam generating units that implement larger modifications 
that are consistent with the proposed BSER determination for those 
units. The final standard for those sources that implement larger 
modifications is a unit-specific emission limitation consistent with 
each modified unit's best one-year historical performance (during the 
years from 2002 to the time of the modification), but does not include 
the additional two percent reduction that was proposed in the January 
2014 proposal.
    In this action, the EPA is not finalizing standards for those 
sources that conduct smaller modifications and is withdrawing the 
proposed standards for those sources. See Section XV below.
    A more detailed discussion of the rationale for the BSER 
determination and final standards is provided in Section VI of this 
preamble.
3. BSER for Reconstructed Steam Generating Units
    Consistent with our proposal, the EPA has determined that the BSER 
for reconstructed steam generating units is the most efficient 
demonstrated generating technology for these types of units (i.e., 
meeting a standard of performance consistent with a reconstructed 
boiler using the most efficient steam conditions available, even if the 
boiler was not originally designed to do so). A more detailed 
discussion of the rationale for the BSER determination and the final 
standards is provided in Section VII of this preamble.

C. Final Standards of Performance

    The EPA is issuing final standards of performance for newly 
constructed, modified, and reconstructed affected steam generating 
units based on the degree of emission reduction achievable by 
application of the best system of emission reduction for those 
categories, as described above. The final standards are presented below 
in Table 6.

     Table 6--Final Standards of Performance for New, Modified, and
                  Reconstructed Steam Generating Units
------------------------------------------------------------------------
                                                    Final standard *  lb
           Source                  Description            CO2/MWh-g
------------------------------------------------------------------------
New Sources.................  All newly             1,400.
                               constructed steam
                               generating EGUs.

[[Page 64547]]

 
Modified Sources............  Sources that          Best annual
                               implement larger      performance (lb CO2/
                               modifications--thos   MWh-g) during the
                               e resulting in an     time period from
                               increase in hourly    2002 to the time of
                               CO2 emissions (lb     the modification.
                               CO2/hr) of more
                               than 10 percent.
Reconstructed Sources.......  Large **............  1,800.
Reconstructed Sources.......  Small **............  2,000.
------------------------------------------------------------------------
* Standards are to be met over a 12-operating-month compliance period.
** Large units are those with heat input capacity of >2,000 mmBtu/hr;
  small units are those with heat input capacity of <=2,000 mmBtu/hr.

    For newly constructed and reconstructed steam generating units and 
for modified steam generating sources that result in larger hourly 
increases of CO2 emissions, the EPA is finalizing standards 
in the form of a gross energy output-based CO2 emission 
limit expressed in units of mass per useful energy output, 
specifically, in pounds of CO2 per megawatt-hour (lb 
CO2/MWh-g).\184\ The standard of performance will apply to 
affected EGUs upon the effective date of the final action.
---------------------------------------------------------------------------

    \184\ Note that the standards for sources that conduct larger 
modifications is a unit-specific numerical standard based on the 
unit's best one-year historical performance during the period from 
2002 to the time of the modification. The unit-specific standard 
will also be in the form of a gross energy output-based 
CO2 emission limit expressed in pounds of CO2 
per megawatt-hour (lb CO2/MWh-g).
---------------------------------------------------------------------------

    Compliance with the final standard will be demonstrated by summing 
the emissions (in pounds of CO2) for all operating hours in 
the 12-operating-month compliance period and then dividing that value 
by the sum of the useful energy output (on a gross basis, i.e., gross 
megawatt-hours) over the rolling 12-operating-month compliance period. 
The final rule requires rounding of emission rates with numerical 
values greater than or equal to 1,000 to three significant figures and 
rounding of rates with numerical values less than 1,000 to two 
significant figures.
    For newly constructed steam generating units, we proposed two 
options for the compliance period. We proposed that a newly constructed 
source could choose to comply with a 12-operating-month standard or 
with a more stringent standard over an 84-operating-month compliance 
period, and we solicited comment on including an interim 12-operating-
month standard (based on use of supercritical boiler technology, see 79 
FR at 1448). We are not finalizing the proposed 84-operating-month 
compliance period option because the final standard of performance for 
newly constructed sources is less stringent than the proposed standard 
and because, as discussed in Section V below, we are identifying 
alternative compliance pathways for new steam generating EGUs. 
Specifically, we have concluded that there are unlikely to be 
significant issues with short-term variability during initial 
operation, in view of both the reduced numerical stringency of the 
standard, and the availability of compliance alternatives. The EPA 
notes that co-firing of natural gas can also serve as an interim means 
to reduce emissions if a new source operator believes additional time 
is needed to phase-in the operation of a CCS system. Therefore, the 
applicable final standards of performance for all newly constructed, 
modified, and reconstructed steam generating units must be met over a 
rolling 12-operating-month compliance period.
    In the Clean Power Plan, which is a separate rulemaking under CAA 
section 111(d) published at the same time as the present rulemaking 
under CAA section 111(b), the EPA is promulgating emission guidelines 
for states to develop state plans regulating CO2 emissions 
from existing fossil fuel-fired EGUs. Existing sources that are subject 
to state plans under CAA section 111(d) may undertake modifications or 
reconstructions and thereby become subject to the requirements under 
section 111(b) in the present rulemaking. In the section 111(d) Clean 
Power Plan rulemaking, the EPA discusses how undertaking a modification 
or reconstruction affects an existing source's section 111(d) 
requirements.

V. Rationale for Final Standards for Newly Constructed Fossil Fuel-
Fired Electric Utility Steam Generating Units

    In the discussion below, the EPA describes the rationale and 
justification of the BSER determination and the resulting final 
standards of performance for newly constructed steam generating units. 
We also explain why this determination is consistent with the 
constraints imposed by the EPAct05.

A. Factors Considered in Determining the BSER

    In evaluating the final determination of the BSER for newly 
constructed steam generating units, the EPA considered the factors for 
the BSER described above, looked widely at all relevant information and 
considered all the data, information, and comments that were submitted 
during the public comment period. We re-examined and updated the 
information that was available to us and concluded, as described below, 
that the final standard of 1,400 lb CO2/MWh-g is consistent 
with the degree of emission reduction achievable through the 
implementation of the BSER. This final standard of performance for 
newly constructed fossil fuel-fired steam generating units provides a 
clear and achievable path forward for the construction of new coal-
fired generating sources that addresses GHG emissions.

B. Highly Efficient SCPC EGU Implementing Partial CCS as the BSER for 
Newly Constructed Steam Generating Units

    In the sections that follow, we explain the technical 
configurations that may be used to implement BSER to meet the final 
standard, describe the operational flexibilities that partial CCS 
offers, and then provide the rationale for the final standard of 
performance. After that, we discuss, in greater detail, consideration 
of the criteria for the determination of the BSER. We describe why a 
highly efficient new SCPC EGU implementing partial CCS in the amount 
that results in an emission limitation of 1,400 lb CO2/MWh-g 
best meets those criteria, including, among others, that such a system 
is technically feasible, provides meaningful emission reductions, can 
be implemented at a reasonable cost, does not pose non-air quality 
health and environmental concerns or impair energy reliability, and 
consequently is adequately demonstrated. We also explain why the 
emission standard of 1,400 lb CO2/MWh-g is achievable, 
including under all circumstances

[[Page 64548]]

reasonably likely to occur when the system is properly designed and 
operated. We also discuss alternative compliance options that new 
source project developers can elect to use, instead of SCPC with 
partial CCS, to meet the final standard of performance.

C. Rationale for the Final Emission Standards

1. The Proposed Standards
    In the January 2014 proposal, the EPA proposed an emission 
limitation of 1,100 lb CO2/MWh-g, which a new highly 
efficient utility boiler burning bituminous coal could have met by 
capturing roughly 40 percent of its CO2 emissions and a new 
highly efficient IGCC unit could have met by capturing and storing 
roughly 25 percent of its CO2 emissions. The captured 
CO2 would then be securely stored in sequestration 
repositories subject to either Class II or Class VI standards under the 
Underground Injection Control program. The EPA arrived at the proposed 
standard by examining the available CCS implementation configurations 
and concluding that the proposed standard at the corresponding levels 
of partial CCS best balanced the BSER criteria and resulted in an 
achievable emission level. The EPA also proposed to find that highly 
efficient new generation implementing ``full CCS'' (i.e., more than 90 
percent capture and storage) was not the BSER because the costs of that 
configuration--for both utility boilers and IGCC units--are projected 
to substantially exceed the projected costs of other non-NGCC 
dispatchable technologies that utilities and project developers are 
considering (e.g., new nuclear and biomass). See generally 79 FR at 
1477-78. Conversely, the EPA rejected highly efficient SCPC as the BSER 
because it would not result in meaningful emission reductions from any 
newly constructed PC unit. Id. at 1470. The EPA also declined to base 
the BSER on IGCC operating alone due to the same concern--lack of 
emission reductions from a new IGCC unit otherwise planned. Id.
2. Basis for the Final Standards
    For this final action, the EPA reexamined the BSER options 
available at proposal. Those options are: (1) Highly efficient 
generation without CCS, (2) highly efficient generation implementing 
partial CCS, and (3) highly efficient generation implementing full CCS. 
Consistent with our determination in the January 2014 proposal, we 
remain convinced that highly efficient generation (i.e., a new 
supercritical utility boiler or a new IGCC unit) without CCS does not 
represent the BSER because it does not achieve emission reductions 
beyond the sector's business as usual, when options that do achieve 
more emission reductions are available. 79 FR 1470; see also Section 
V.P below. We also do not find that a highly efficient new steam 
generating unit implementing full CCS is the BSER because, at this 
time, the costs are predicted to be significantly more than the costs 
for implementation of partial CCS and significantly more than the costs 
for competing non-NGCC base load, dispatchable technologies--primarily 
new nuclear generation--and are, therefore, potentially unreasonable. 
See Section V.P.
    As with the proposal, the EPA has determined the final BSER and 
corresponding emission limitation by appropriately balancing the BSER 
criteria and determining that the emission limitation is achievable. 
The final standard of performance of 1,400 lb CO2/MWh-g is 
less stringent than at proposal and reflects changes that are 
responsive to comments received on, and the EPA's further evaluation 
of, the costs to implement partial CCS. The EPA has determined that a 
newly constructed highly efficient supercritical utility boiler burning 
bituminous coal can meet this final emission limitation by capturing 16 
percent of the CO2 produced from the facility (or 23 percent 
if burning subbituminous or dried lignite), which would be either 
stored in on-site or off-site geologic sequestration repositories 
subject to control under either the Class VI (for geologic 
sequestration) or Class II (for Enhanced Oil Recovery) standards under 
the UIC program. This BSER is technically feasible, as shown by the 
fact that post-combustion CCS technology--both the capture and storage 
components--is demonstrated in full-scale operation within the 
electricity generating industry. There are also numerous operating 
results from smaller-scale projects that are reasonably predictive of 
operation at full-scale. It is available at reasonable cost, does not 
have collateral adverse non-air quality health or environmental 
impacts, and does not have adverse energy implications.
    The proposed BSER was a highly efficient newly constructed steam 
generating EGU implementing partial CCS to an emission standard of 
1,100 lb CO2/MWh-g. The final BSER is a highly efficient 
SCPC EGU implementing partial CCS to achieve an emission standard of 
1,400 lb CO2/MWh-g. In both cases, the EPA specified that 
the BSER includes a ``highly efficient'' new EGU implementing partial 
CCS. This assumes that a new project developer will construct the most 
efficient generating technology available--i.e., a supercritical or 
ultra-supercritical utility boiler--that will inherently generate lower 
volumes of uncontrolled CO2 per MWh. See Section V.J below. 
A well performing and highly efficient new SCPC EGU will need to 
implement lower levels of partial CCS in order to meet the final 
standard of 1,400 lb CO2/MWh-g than a less efficient new 
steam generating EGU. The construction of highly efficient steam 
generating EGUs--as opposed to less efficient units such as a 
subcritical utility boiler--will result in lower overall costs from 
decreased fuel consumption and the need for lower levels of required 
partial CCS to meet the final standard.
3. Consideration of Projects Receiving Funding Under the EPAct05
    As noted in Section III.H.3.g above, the EPA's determination of the 
BSER here includes review of recently constructed facilities and those 
planned or under construction to evaluate the control technologies 
being used and considered. Some of the projects discussed in the 
January 2014 proposal, and discussed here in this preamble, received or 
are receiving financial assistance under the EPAct05 (P.L. 109-58). 
This assistance may include financial assistance from the Department of 
Energy (DOE), as well as receipt of the federal tax credit for 
investment in clean coal technology under IRC Section 48A.
    As noted above, the EPA interprets these provisions as allowing 
consideration of EPAct05 facilities provided that such information is 
not the sole basis for the BSER determination, and particularly so in 
circumstances like those here, where the information is corroborative 
but the essential information justifying the determinations comes from 
facilities and other sources of information with no nexus with EPAct05 
assistance. In the discussion below, the EPA explains its reliance on 
other information in making the BSER determination for new fossil fuel-
fired steam generating units. The EPA notes that information from 
facilities that did not receive any DOE assistance, and did not receive 
the federal tax credit, is sufficient by itself to support its BSER 
determination.

D. Post-Combustion Carbon Capture

    In this section, we describe a variety of facts that support our 
conclusion that the technical feasibility of post-combustion carbon 
capture is adequately demonstrated. First, we describe the technology 
of post-

[[Page 64549]]

combustion capture. We then describe EGUs that have previously utilized 
or are currently utilizing post-combustion carbon capture technology. 
This discussion is complemented by later sections that explain and 
justify our conclusions that the technical feasibility of other aspects 
of partial CCS are adequately demonstrated--namely, the transportation 
and carbon storage (see Sections V.M. and N). Further, the conclusions 
of this section are reinforced by the discussion in Section V.F. below, 
in which we identify commercial vendors that offer carbon capture 
technology and offer performance guarantees, and discuss industry and 
technology developers' public pronouncements of their confidence in the 
feasibility and availability of CCS technologies.
1. Post-Combustion Carbon Capture--How it Works
    Post-combustion capture processes remove CO2 from the 
exhaust gas of a combustion system--such as a utility boiler. It is 
referred to as ``post-combustion capture'' because the CO2 
is the product of the combustion of the primary fuel and the capture 
takes place after the combustion of that fuel. The exhaust gases from 
most combustion processes are at atmospheric pressure and are moved 
through the flue gas system by fans. The concentration of 
CO2 in most combustion flue gas streams is somewhat 
dilute.\185\ Most post-combustion capture systems utilize liquid 
solvents \186\ that separate the CO2 from the flue gas in 
CO2 scrubber systems. Because the flue gas is at atmospheric 
pressure and is somewhat dilute, the solvents used for post-combustion 
capture are ones that separate the CO2 using chemical 
absorption (or chemisorption). Amine-based solvents \187\ are the most 
commonly used in post-combustion capture systems. In a chemisorption-
based separation process, the flue gas is processed through the 
CO2 scrubber and the CO2 is absorbed by the 
liquid solvent and then released by heating to form a high purity 
CO2 stream. This heating step is referred to as ``solvent 
regeneration'' and is responsible for much of the ``energy penalty'' of 
the capture system. Steam from the boiler (or potentially from another 
external source) that would otherwise be used to generate electricity 
is instead used in the solvent regeneration process. The development of 
advanced solvents--those that are chemically stable, have high 
CO2 absorption capacities, and have low regeneration energy 
requirements--is an active area of research. Many post-combustion 
solvents will also selectively remove other acidic gases such as 
SO2 and hydrochloric acid (HCl), which can result in 
degradation of the solvent. For that reason, the CO2 
scrubber systems are normally installed downstream of other pollutant 
control devices (e.g., particulate matter and flue gas desulfurization 
controls) and in some cases, the acidic gases will need to be scrubbed 
to very low levels prior to the flue gas entering the CO2 
capture system. See also RIA chapter 5 (quantifying SO2 
reductions resulting from this scrubbing process).
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    \185\ The typical concentration of CO2 in the flue 
gas of a coal-fired utility boiler is roughly around 15 volume 
percent.
    \186\ A solvent is a substance (usually a liquid) that dissolves 
a solute (a chemically different liquid, solid or gas), resulting in 
a solution.
    \187\ Amines are derivatives of ammonia (NH3) where 
one or more hydrogen atoms have been replaced by hydrocarbon groups.
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    Additional information on post-combustion carbon capture--including 
process diagrams--can be found in a summary technical support 
document.\188\
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    \188\ Technical Support Document--``Literature Survey of Carbon 
Capture Technology'', available in the rulemaking docket (Docket ID: 
EPA-HQ-OAR-2013-0495).
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2. Post-Combustion Carbon Capture Projects That Have Not Received DOE 
Assistance Through the EPAct05 or Tax Credits Under IRC Section 48A
a. Boundary Dam Unit #3
    SaskPower's Boundary Dam CCS Project in Estevan, a city in 
Saskatchewan, Canada, is the world's first commercial-scale fully 
integrated post-combustion CCS project at a coal-fired power plant. The 
project fully integrates the rebuilt 110 MW coal-fired Unit #3 with a 
CO2 capture system using Shell Cansolv amine-based solvent 
to capture 90 percent of its CO2 emissions. The facility, 
which utilizes local Saskatchewan lignite, began operations in October 
2014 and accounts of the system's performance describe it as working 
even ``better than expected.'' 189 190 The plant 
started by capturing roughly 75 percent of CO2 from the 
plant emissions and its operators plan to increase the capture 
percentage as they optimize the equipment to reach full capacity. 
Initial indications are that the facility is producing more power than 
predicted and that the energy penalty (parasitic load--the energy 
needed to regenerate the CO2 capture solvent) is much lower 
than initially predicted.\191\ Water use at the facility is consistent 
with levels that were predicted.\192\ The total project costs--for the 
power plant and the carbon capture plant--was $1.467B (CAD).\193\ The 
CO2 from the capture system is more than 99.999 percent pure 
with only trace levels of N2 in the product stream.\194\ 
This purity is food-grade quality CO2 and is a clear 
indication that the system is working well. The captured CO2 
is transported by pipeline to nearby oil fields in southern 
Saskatchewan where it is being used for EOR operations. Any captured 
CO2 that is not used for EOR operations will be stored in 
nearby deep brine-filled sandstone formations. Thus, the Boundary Dam 
Unit #3 project is demonstrating CO2 post-combustion 
capture, CO2 compression and transport, and CO2 
injection for both EOR and geologic storage. The CCS system is fully 
integrated with the electricity production of the plant.
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    \189\ ``[W]e are achieving better than expected'' operation out 
of the plant, SaskPower's Mike Marsh said April 8, 2015 in 
Washington, DC, summarizing the status of the first-of-a-kind plant 
in Saskatchewan, Canada, known as Boundary Dam Unit 3. Marsh spoke 
at a meeting of the National Coal Council, which advises the Energy 
Department on coal-related topics. From ``Bolstering EPA's NSPS, 
Canadian CCS Plant Working `Better Than Expected' '', Climate Daily 
News, Inside EPA/climate (April 08, 2015); www.insideepa.com 
(subscription required).
    \190\ ``CCS performance data exceeding expectations at world-
first Boundary Dam Power Station Unit #3'', http://www.saskpowerccs.com/newsandmedia/latest-news/ccs-performance-data-exceeding-expectations/.
    \191\ Correspondence between Mike Monea (SaskPower) and Nick 
Hutson (EPA), February 20, 2015.
    \192\ 30 percent of the water used for cooling comes from the 
recycled or reclaimed water from the process itself; namely, water 
in the coal is reclaimed.
    \193\ About $1.2B USD; roughly $700M (USD) for the carbon 
capture system, which was on budget.
    \194\ ``Boundary Dam--The Future is Here'', plenary presentation 
by Mike Monea at the 12th International Conference on Greenhouse Gas 
Technologies (GHGT-12), Austin, TX (October 2014).
---------------------------------------------------------------------------

    Some commenters noted that, at 110 MW, the Boundary Dam Unit #3 is 
a relatively small coal-fired utility boiler and thus, in the 
commenters' view, does not demonstrate that such a system could be 
utilized at a much larger utility coal-fired boiler. However, there is 
nothing to indicate that the post-combustion system used at Boundary 
Dam could not be scaled-up for use at a larger utility boiler. In fact, 
the carbon capture system at Boundary Dam #3 is designed and 
constructed to implement ``full CCS''--that is to capture more than 90 
percent of the CO2 produced from the subcritical unit. A 
similarly-sized capture system--with no need for further scale-up--
could be used to treat a slip-stream of a much larger

[[Page 64550]]

supercritical utility boiler (a new unit of approximately 500 to 600 
MW) in order to meet the final standard of performance of 1,400 lb 
CO2/MWh-g, which would only require partial CCS on the order 
of approximately 16 to 23 percent (depending on the coal used).
    A ``slip-stream'' is a portion of the flue gas stream that can be 
treated separately from the bulk exhaust gas. It is not an uncommon 
configuration for the flue gas from a coal-fired boiler to be separated 
into two or more streams and treated separately in different control 
equipment before being recombined to exit from a common stack.\195\ A 
slip-stream configuration is often used to treat a smaller portion of 
the bulk flue gas stream as a way of testing or demonstrating a control 
device or measurement technology. For implementation of post-combustion 
partial carbon capture, a portion of the bulk flue gas stream would be 
treated separately to capture approximately 90 percent of the 
CO2 from that smaller slip-stream of the flue gas. For 
example, in order to capture 20 percent of the CO2 produced 
by a coal-fired utility boiler, an operator would treat approximately 
25 percent of the bulk flue gas stream (rather than treating the entire 
stream). Approximately 90 percent of the CO2 would be 
captured from the slip-stream gas, resulting in an overall capture of 
about 20 percent.
---------------------------------------------------------------------------

    \195\ See Figure 1A from Atmospheric Environment, 43, 3974 
(2009), for an example of this type of configuration.
---------------------------------------------------------------------------

    In its study on the cost and performance of a range of carbon 
capture rates, the DOE/NETL determined that the slip-stream approach 
was the most economical for carbon capture of less than 90 percent of 
the total CO2.\196\ The advantage of the slip-stream 
approach is that the capture system will be sized to treat a lower 
volume of flue gas flow, which reduces the size of the CO2 
absorption columns, induced draft fans, and other equipment, leading to 
lower capital and operating costs.
---------------------------------------------------------------------------

    \196\ ``Cost and Performance of PC and IGCC for a Range of 
Carbon Capture'', Rev 1 (2013), DOE/NETL-2011/1498 p. 2 (``A 
literature search was conducted to verify that <90 percent 
CO2 capture is most economical using a `slip-stream' (or 
bypass) approach. Indeed, the slip-stream approach is more cost-
effective for <90 percent CO2 capture than removing 
reduced CO2 fractions from the entire flue gas stream, 
according to multiple peer-reviewed studies.'' See also id. at 19, 
21, 77, and 478 (documenting further that treating a slip-stream is 
the most economical approach).
---------------------------------------------------------------------------

    The carbon capture system at Boundary Dam does not utilize the 
slip-stream configuration because it was designed to achieve more than 
90 percent capture rates from the 110 MW facility. However, the same 
carbon capture equipment could be used to treat approximately 50 
percent of the flue gas from a 220 MW facility--or 20 percent of the 
flue gas from a 550 MW facility. Thus, the equipment that is currently 
working very well (in fact, ``better than expected'') at the Boundary 
Dam plant can be utilized for partial carbon capture at a much larger 
coal-fired unit without the need for further scale-up.
    The experience at Boundary Dam is directly transferrable to other 
types of post-combustion sources, including those using different 
boiler types and those burning different coal types. There is nothing 
to suggest that the Shell CanSolv process would not work with other 
coal types and indeed, the latest NETL cost estimates assume that the 
capture technology would be used in a new unit using bituminous 
coal.\197\ The EPA is unaware of any reasons why the Boundary Dam 
technology would not be transferrable to another utility boiler at a 
different location at a different elevation or climate because the 
control technology is not climate or elevation-dependent.
---------------------------------------------------------------------------

    \197\ In fact, in ``Cost and Performance Baseline for Fossil 
Energy Plants Volume 1a: Bituminous Coal (PC) and Natural Gas to 
Electricity Revision 3'', DOE/NETL-2015/1723 (July 2015), Exh.2-3 
the Shell Cansolv process is used as the capture process for a new 
SCPC unit using bituminous coal rather than the subcritical PC unit 
at Boundary Dam that uses Canadian lignite. The study evidently 
assumes that the CanSolv process can be used effectively for 
bituminous coal since this type of coal is assumed for cost 
estimation purposes.
---------------------------------------------------------------------------

    Commenters also noted that the Boundary Dam Unit #3 project 
received financial assistance from both the Canadian federal government 
and from the Saskatchewan provincial government. But the availability 
of--or the lack of--external financial assistance does not affect the 
technical feasibility of the technology. Commenters further 
characterized Boundary Dam as a ``demonstration project''. These 
descriptors are beside the point. Regardless of what the project is 
called or how it was financed, the project clearly shows the technical 
feasibility of full-scale, fully integrated implementation of available 
post-combustion CCS technology, which in this case also appears to be 
commercially viable.
    The EPA notes that, although there is ample additional information 
corroborating that post-combustion CCS is technically feasible, which 
we describe below, the performance at Boundary Dam Unit #3 alone would 
be sufficient to support that conclusion. Essex Chemical Corp., 486 F. 
2d at 436 (test results from single facility demonstrates achievability 
of standard of performance). As mentioned above, the post-combustion 
capture technology used at Boundary Dam is transferrable to all other 
types of utility boilers.
b. AES Warrior Run and Shady Point
    AES's coal-fired Warrior Run (Cumberland, MD) and Shady Point 
(Panama, OK) plants are both circulating fluidized bed (CFB) coal-fired 
power plants with carbon capture amine scrubbers developed by ABB/
Lummus. The scrubbers were designed to process a slip-stream of each 
plant's flue gas. At the 180 MW Warrior Run Plant, a plant that burns 
bituminous coal, approximately 10 percent of the plant's CO2 
emissions (about 110,000 metric tons of CO2 per year) has 
been captured since 2000 and sold to the food and beverage industry. At 
the 320 MW Shady Point Plant, a plant that burns a blend of bituminous 
and subbituminous coals, CO2 from an approximate 5 percent 
slip-stream (about 66,000 metric tons of CO2 per year) has 
been captured since 2001. The captured CO2 from the Shady 
Point Plant is also sold for use in the food processing industry.\198\ 
While these projects do not demonstrate the CO2 storage 
component of CCS, they clearly demonstrate the technical viability of 
partial CO2 capture. The capture of CO2 from a 
slip-stream of the bulk flue gas, as described earlier, is the most 
economical method for capturing less than 90 percent of the 
CO2. The amounts of partial capture that these sources have 
demonstrated--up to 10 percent--is reasonably similar to the level, at 
16 to 23 percent, that the EPA predicts would be needed by a new highly 
efficient steam utility boiler to meet the final standard of 
performance. These facilities, which have been operating for multiple 
years, clearly show the technical feasibility of post-combustion carbon 
capture.
---------------------------------------------------------------------------

    \198\ Dooley, J. J., et al. (2009). ``An Assessment of the 
Commercial Availability of Carbon Dioxide Capture and Storage 
Technologies as of June 2009''. U.S. DOE, Pacific Northwest National 
Laboratory, under Contract DE-AC05-76RL01830.
---------------------------------------------------------------------------

c. Searles Valley Minerals
    Since 1978, the Searles Valley Minerals soda ash plant in Trona, CA 
has used post-combustion amine scrubbing to capture approximately 
270,000 metric tons of CO2 per year from the flue gas of a 
coal-fired power plant that generates steam and power for on-site use. 
The captured CO2 is used for the carbonation of brine in the 
process of producing soda ash.\199\ Again, while the captured 
CO2 is not

[[Page 64551]]

sequestered, this project clearly demonstrates the technical 
feasibility of the amine scrubbing system for CO2 capture 
from a coal-fired power plant.\200\ The fact that this system is an 
industrial coal-fired power plant rather than a utility coal-fired 
power plant is irrelevant as they both serve a similar purpose--the 
production of electricity.
---------------------------------------------------------------------------

    \199\ IEA (2009), World Energy Outlook 2009, OECD/IEA, Paris.
    \200\ Moreover, the final rule allows alternative means of 
storage of captured CO2 based on a case-by-case 
demonstration of efficacy. See Section V.M.4 below.
---------------------------------------------------------------------------

    Each of these processes indicate a willingness of industry to 
utilize available post-combustion technology for capture of 
CO2 for commercial purposes. Not one of the CO2 
capture systems at Warrior Run, Shady Point, or Searles Valley was 
installed for regulatory purposes or as government-funded demonstration 
projects. They were installed to capture CO2 for commercial 
use. The fact that the captured CO2 was utilized rather than 
being stored is of no consequence in the consideration of the technical 
feasibility of post-combustion CO2 capture technology. These 
commercial operations have helped to improve the performance of 
scrubbing systems that are available today. For example, the heat duty 
(i.e., the energy needed to remove the CO2) has been reduced 
by about 5 times from the amine process originally used at the Searles 
Valley facility. The amine scrubbing process used at Boundary Dam is 
equally efficient, and the amine scrubbing system to be used at the 
Petra Nova WA Parish project (Thompsons, TX) is projected to be as 
well.\201\
---------------------------------------------------------------------------

    \201\ The heat duty for the amine scrubbing process used at 
Searles Valley in the mid-70's was about 12 MJ/mt CO2 
removed as compared to a heat duty of about 2.5 MJ/mt CO2 
removed for the amine processes used at Boundary Dam and to be used 
at WA Parish. ``From Lubbock, TX to Thompsons, TX--Amine Scrubbing 
for Commercial CO2 Capture from Power Plants'', plenary 
address by Prof. Gary Rochelle at the 12th International Conference 
on Greenhouse Gas Technology (GHGT-12), Austin, TX (October 2014).
---------------------------------------------------------------------------

3. Post-Combustion Carbon Capture Projects That Received DOE Assistance 
Through the EPAct05, but Did Not Receive Tax Credits Under IRC Section 
48A
    The EPA considers the experiences from the CCS projects described 
above, coupled with evidence that the design of CCS is well accepted 
(also described above) and the strong support that CCS has received 
from vendors and others (described below) to adequately demonstrate 
that post-combustion partial CCS is technically feasible. The EPA finds 
that additional projects, described next, provide more support for that 
conclusion. These projects received funding under EPAct05 from the 
Department of Energy, but that does not disqualify them from being 
considered. See Section III.H.3 above.
a. Petra Nova WA Parish Project
    Petra Nova, a joint venture between NRG Energy Inc. and JX Nippon 
Oil & Gas Exploration, is constructing a commercial-scale post-
combustion carbon capture project at Unit #8 of NRG's WA Parish 
generating station southwest of Houston, Texas. The project is designed 
to utilize partial CCS by capturing approximately 90 percent of the 
CO2 from a 240 MW slip-stream of the 610 MW WA Parish 
facility. The project is expected to be operational in 2016 and thus 
does not yet directly demonstrate the technical feasibility or 
performance of the MHI amine scrubbing system. However, this project is 
a clear indication that the developers have confidence in the technical 
feasibility of the post-combustion carbon capture system.
    The project was originally envisioned as a 60 MW slip-stream 
demonstration and received DOE Clean Coal Power Initiative (CCPI) 
funding (as provided in EPAct05) on that basis. The developers later 
expanded the project to the larger 240 MW slip-stream because of the 
need to capture greater volumes of CO2 for EOR operations. 
No additional DOE or other federal funding was obtained for the 
expansion from a 60 MW slip-stream to a 240 MW slip-stream.\202\
---------------------------------------------------------------------------

    \202\ Thus, even if the project received DOE assistance for the 
initial 60 MW design, the expansion of the project from 60 MW to 240 
MW should not be considered a DOE-assisted project. In any case, as 
described above, even without consideration of this facility at all, 
other information adequately demonstrates the technical feasibility 
of post-combustion CCS.
---------------------------------------------------------------------------

    At 240 MW, the Petra Nova project will be the largest post-
combustion carbon capture system installed on an existing coal-fueled 
power plant. The project will use for EOR or will sequester 1.6 million 
tons of captured CO2 each year. The project is expected to 
be operational in 2016.
    In 2014 project materials,\203\ the project developer NRG 
recognized the importance of CCS technology by noting:
---------------------------------------------------------------------------

    \203\ WA Parish CO2 Capture Project Fact Sheet; 
available at www.nrg.com/documents/business/pla-2014-petranova-waparish-factsheet.pdf (2014).

    The technology has the potential to enhance the long-term 
viability and sustainability of coal-fueled power plants across the 
U.S. and around the world. . . . Post-combustion carbon capture is 
essential so that we can use coal to sustain our energy ecosystem 
---------------------------------------------------------------------------
while we begin reducing our carbon footprint.

    According to NRG, the Petra Nova Carbon Capture Project will 
utilize ``a proven carbon capture process,'' jointly developed by 
Mitsubishi Heavy Industries, Ltd. (MHI) and the Kansai Electric Power 
Co., that uses a high-performance solvent for CO2 absorption 
and desorption.\204\ In using the MHI high-performance solvent, the 
Petra Nova project will benefit from pilot-scale testing of this 
solvent at Alabama Power's Plant Barry and at other installations. WA 
Parish Unit #8 came on-line in 1982 and is thus an existing source that 
will not be subject to final standards of performance issued in this 
action. However, because it will be capturing roughly 35 percent of the 
CO2 generated by the facility, its emissions will be below 
the final new source emission limitation of 1,400 lb CO2/
MWh-g.\205\
---------------------------------------------------------------------------

    \204\ The WA Parish project (described earlier) will utilize the 
KM-CDR Process[supreg], which was jointly developed by MHI and the 
Kansai Electric Power Co., Inc. and uses the proprietary KS-
1TM high-performance solvent for the CO2 
absorption and desorption.
    \205\ Using emissions data reported to the Acid Rain Program, 
the EPA estimates that the CO2 emissions from the WA 
Parish Unit #8 will be 1,250-1,300 lb CO2/MWh-g during 
operations with the post-combustion capture system.
---------------------------------------------------------------------------

    The captured CO2 from the WA Parish CO2 
Capture Project will be used in EOR operations at mature oil fields in 
the Gulf Coast region. Using EOR at Hilcorp's West Ranch Oil Field, the 
production is expected to be boosted from around 500 barrels per day to 
approximately 15,000 barrels per day. Thus the project will utilize all 
aspects of CCS by capturing CO2 at the large coal-fired 
power plant, compressing the CO2, transporting it by 
pipeline to the EOR operations, and injecting it for EOR and eventual 
geologic storage.
    The carbon capture system at WA Parish will utilize a slip-stream 
configuration. However, as noted, the system is designed to capture 
roughly 35 percent of the CO2 from WA Parish Unit #8 (90 
percent of the CO2 from the 240 MW slip-stream from the 610 
MW unit). A carbon capture system of the same size as that used at WA 
Parish could be used to treat a 240 MW slip-stream from a 1,000 MW unit 
in order to meet the final standard of performance of 1,400 lb 
CO2/MWh-g.
    Again, the experience at the WA Parish Unit #8 project will be 
directly transferable to post-combustion capture at a new utility 
boiler, even though WA Parish Unit #8 is an existing source that has 
been in operation for over 30 years. In fact, retrofit of such 
technology at an existing unit can be more challenging than 
incorporating the technology into the design of a new facility. The

[[Page 64552]]

experience will be directly transferrable to other types of post-
combustion sources including those using different boiler types and 
those burning different coals. The amine scrubbing and associated 
systems are not boiler type- or coal-specific. The EPA is unaware of 
any reasons that the technology utilized at the WA Parish plant would 
not be transferrable to another utility boiler at a different location 
at a different elevation or climate, given that the technology is not 
dependent on either climate or topography.
b. AEP/Alstom Mountaineer Project
    In September 2009, AEP began a pilot-scale CCS demonstration at its 
Mountaineer Plant in New Haven, WV. The Mountaineer Plant is a very 
large (1,300 MW) coal-fired unit that was retrofitted with Alstom's 
patented chilled ammonia CO2 capture technology on a 20 MWe 
slip-stream of the plant's exhaust flue gas. In May 2011, Alstom Power 
announced the successful operation of the chilled ammonia CCS 
validation project. The demonstration achieved capture rates from 75 
percent (design value) to as high as 90 percent, and produced 
CO2 at a purity of greater than 99 percent, with energy 
penalties within a few percent of predictions. The facility reported 
robust steady-state operation during all modes of power plant 
operation, including load changes, and saw an availability of the CCS 
system of greater than 90 percent.\206\
---------------------------------------------------------------------------

    \206\ http://www.alstom.com/press-centre/2011/5/alstom-announces-sucessful-results-of-mountaineer-carbon-capture-and-sequestration-ccs-project/.
---------------------------------------------------------------------------

    AEP, with assistance from the DOE, had planned to expand the slip-
stream demonstration to a commercial scale, fully integrated 
demonstration at the Mountaineer facility. The commercial-scale system 
was designed to capture at least 90 percent of the CO2 from 
235 MW of the plant's 1,300 MW total capacity. Plans were for the 
project to be completed in four phases, with the system to begin 
commercial operation in 2015. However, in July 2011, AEP announced that 
it would terminate its cooperative agreement with the DOE and place its 
plans to advance CO2 capture and storage technology to 
commercial scale on hold. AEP cited the uncertain status of U.S. 
climate policy as a contributor to its decision, but did not express 
doubts about the feasibility of the technology. See Section V.L below.
    AEP also prepared a Front End Engineering & Design (FEED) 
Report,\207\ explaining in detail how its pilot-scale work could be 
scaled up to successful full-scale operation, and to accommodate the 
operating needs of a full-scale EGU, including reliable generating 
capacity capable of cycling up and down to accommodate consumer demand. 
Recommended design changes to accomplish the desired scaling included 
detailed flue gas specifications, ranges for temperature, moisture and 
SO2 content; careful scrutiny of makeup water composition 
and temperature; quality and quantity of available steam to accommodate 
heat cycle based on unit load changes; and detailed scrutiny of 
material and energy balances.\208\ See Section V.G.3 below, addressing 
in more detail the record support for how CCS technology can be scaled 
up to commercial size in both pre- and post-combustion applications.
---------------------------------------------------------------------------

    \207\ ``CCS front end engineering & design report: American 
Electric Power Mountaineer CCS II Project. Phase 1'', pp 10-11; 
available at: http://www.globalccsinstitute.com/publications/aep-mountaineer-ii-project-front-end-engineering-and-design-feed-report.
    \208\ Id. at 11. The EPA does not view this information as being 
affected by the constraints in EPAct05. The information does not 
relate to use of technology, level of emission reduction by reason 
of use of technology, achievement of emission reduction by 
demonstration of technology, or demonstration of a level of 
performance. The FEED study rather explains engineering challenges 
which would remain at full scale and how those challenges can be 
addressed.
---------------------------------------------------------------------------

c. Southern Company/MHI Plant Barry
    In June 2011, Southern Company and Mitsubishi Heavy Industries 
(MHI) launched operations at a 25 MW coal-fired carbon capture facility 
at Alabama Power's Plant Barry. The facility, which completed the 
initial demonstration phase, captured approximately 165,000 metric tons 
of CO2 annually at a CO2 capture rate of over 90 
percent. The facility employed the KM CDR Process, which uses a 
proprietary high performing solvent \209\ for CO2 absorption 
and desorption that was jointly developed by MHI and Japanese utility 
Kansai Electric Power Co. The captured CO2 has been 
transported via pipeline approximately 12 miles to the Citronelle oil 
field where it is injected into the Paluxy formation, a saline 
reservoir, for storage.\210\
---------------------------------------------------------------------------

    \209\ This is the same carbon capture system that is being 
utilized at the Petra Nova project at the NRG WA Parish plant.
    \210\ Ivie, M.A. et al.; ``Project Status and Research Plans of 
500 TPD CO2 Capture and Sequestration Demonstration at 
Alabama Power's Plant Barry'', Energy Procedia 37, 6335 (2013).
---------------------------------------------------------------------------

    Project participants have reported that ``[t]he plant performance 
was stable at the full load condition with CO2 capture rate 
of 500 TPD at 90 percent CO2 removal and lower steam 
consumption than conventional capture processes.'' \211\
---------------------------------------------------------------------------

    \211\ Id.
---------------------------------------------------------------------------

E. Pre-Combustion Carbon Capture

    As described earlier, the EPA does not find that IGCC technology--
either alone or implementing partial CCS--is part of the BSER for newly 
constructed steam generating EGUs. However, as noted, there may be 
specific circumstances and business plans--such as co-production of 
chemicals or fertilizers, or capture of CO2 for use in EOR 
operations--that encourage greater CO2 emission reductions 
than are required by this standard. In this section, we describe and 
justify our conclusion that the technical feasibility of pre-combustion 
carbon capture is adequately demonstrated, indicating that this could 
be a viable alternative compliance pathway. First, we explain the 
technology of pre-combustion capture. We then describe EGUs that have 
previously utilized or are currently utilizing pre-combustion carbon 
capture technology. This discussion is complemented by other sections 
that conclude the technical feasibility of other aspects of partial CCS 
are adequately demonstrated--namely, post-combustion carbon capture 
(Section V.D) and sequestration (Sections V.M and V.N). Further, this 
section's conclusions are reinforced by Section V.F, in which we 
identify commercial vendors that offer CCS performance guarantees as 
well as developers that have publicly stated their confidence in CCS 
technologies.
1. Pre-Combustion Carbon Capture--How It Works
    Pre-combustion capture systems are typically used with IGCC 
processes. In a gasification system, the fuel (usually coal or 
petroleum coke) is heated with water and oxygen in an oxygen-lean 
environment. The coal (carbon), water and oxygen react to form 
primarily a mixture of hydrogen (H2) and carbon monoxide 
(CO) known as synthesis gas or syngas according to the following high 
temperature reaction:

3C + H2O + O2 [rarr] H2 + 3CO

    In an IGCC system, the resulting syngas, after removal of the 
impurities, can be combusted using a conventional combustion turbine in 
a combined cycle configuration (i.e., a combustion turbine combined 
with a HRSG and steam turbine). The gasification process also typically 
produces some amount of CO2 \212\ as a by-product along with 
other

[[Page 64553]]

gases (e.g., H2S) and inorganic materials originating from 
the coal (e.g., minerals, ash). The amount of CO2 in the 
syngas can be increased by ``shifting'' the composition via the 
catalytic water-gas shift (WGS) reaction. This process involves the 
catalytic reaction of steam (``water'') with CO (``gas'') to form 
H2 and CO2 according to the following catalytic 
reaction:
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    \212\ The amount of CO2 in syngas depends upon the 
specific gasifier technology used, the operating conditions, and the 
fuel used; but is typically less than 20 volume percent (http://www.netl.doe.gov/research/coal/energy-systems/gasification/gasifipedia/syngas-composition).

---------------------------------------------------------------------------
CO + H2O [rarr] CO2 + H2

    An emission standard that requires partial capture of 
CO2 from the syngas could be met by adjusting the level of 
CO2 in the syngas stream by controlling the level of syngas 
``shift'' prior to treatment in the pre-combustion acid gas treatment 
system. If a high level of CO2 capture is required, then 
multi-stage WGS reactors will be needed and an advanced hydrogen 
turbine will likely be needed to combust the resulting hydrogen-rich 
syngas.
    Most syngas streams are at higher pressure and can contain higher 
concentrations of CO2 (especially if shifted to enrich the 
concentration). As such, the pre-combustion capture systems can utilize 
physical absorption (physisorption) solvents rather than the chemical 
absorptions solvents described earlier. Physical absorption has the 
benefit of relying on weak intermolecular interactions and, as a 
result, the absorbed CO2 can often be released (desorbed) by 
reducing the pressure rather than by adding heat. Pre-combustion 
capture systems have been used widely in industrial processes such as 
natural gas processing.
    Additional information on pre-combustion carbon capture can be 
found in a summary technical support document.\213\
---------------------------------------------------------------------------

    \213\ Technical Support Document--``Literature Survey of Carbon 
Capture Technology'', available in the rulemaking docket (Docket ID: 
EPA-HQ-OAR-2013-0495).
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2. Pre-Combustion Carbon Capture Projects That Have Not Received DOE 
Assistance Through EPAct05 or Tax Credits Under IRC Section 48A
a. Dakota Gasification Great Plains Synfuels Plant
    Each day, the Dakota Gasification Great Plains Synfuels Plant uses 
approximately 18,000 tons of North Dakota lignite in a coal 
gasification process that produces syngas (a mixture of CO, 
CO2, and H2), which is then converted to methane 
gas (synthetic natural gas) using a methanation process. Each day, the 
process produces an average of 145 million cubic feet of synthetic 
natural gas that is ultimately transported for use in home heating and 
electricity generation.\214\
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    \214\ http://www.dakotagas.com/Gasification/.
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    Capture of CO2 from the facility began in 2000. The 
Synfuels Plant, using a pre-combustion Rectisol[supreg] process, 
captures about 3 million tons of CO2 per year--more 
CO2 from coal conversion than any facility in the world, and 
is a participant in the world's largest carbon sequestration project. 
On average about 8,000 metric tons per day of captured CO2 
from the facility is sent through a 205-mile pipeline to oil fields in 
Saskatchewan, Canada, where it is used for EOR operations that result 
in permanent CO2 geologic storage. The geologic 
sequestration of CO2 in the oil reservoir is monitored by 
the International Energy Agency (IEA) Weyburn CO2 Monitoring 
and Storage Project.
    Several commenters to the January 2014 proposal argued that the 
Great Plains Synfuels facility is not an EGU, that it operates as a 
chemical plant, and that its experience is not translatable to an IGCC 
using pre-combustion carbon capture technology. The commenters noted 
that the Dakota facility can be operated nearly continuously without 
the need to adjust operations to meet cyclic electricity generation 
demands. In the January 2014 proposal, the EPA had noted that, while 
the facility is not an EGU, it has significant similarities to an IGCC 
and the implementation of the pre-combustion capture technology would 
be similar enough for comparison. See 79 FR at 1435-36 and n. 11. We 
continue to hold this view.
    As explained above, in an IGCC gasification system, coal (or 
petroleum coke) is gasified to produce a synthesis gas comprised of 
primarily CO, H2, and some amount of CO2 
(depending on the gasifier and the specific operating conditions). A 
water-gas-shift reaction using water (H2O, steam) is then 
used to shift the syngas to CO2 and H2. The more 
the syngas is ``shifted,'' the more enriched it becomes in 
H2. In an IGCC, power can be generated by directly 
combusting the un-shifted syngas in a conventional combustion turbine. 
If the syngas is shifted such that the resulting syngas is highly 
enriched in H2, then a special, advanced hydrogen turbine is 
needed. If CO2 is to be captured, then the syngas would need 
to be shifted either fully or partially, depending upon the level of 
capture required.\215\
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    \215\ ``Cost and Performance of PC and IGCC for a Range of 
Carbon Capture'', Rev 1 (2013), DOE/NETL-2011/1498.
---------------------------------------------------------------------------

    The Dakota Gasification process bears essential similarities to the 
just-described IGCC gasification system. As with the IGCC gasification 
system, the Dakota Gasification facility gasifies coal (lignite) to 
produce a syngas which is then shifted to increase the concentration of 
CO2 and to produce the desired ratio of CO and 
H2. As with the IGCC gasification system, the CO2 
is then removed in a pre-combustion capture system, and the syngas that 
results is made further use of. For present purposes, only the manner 
in which the syngas is used distinguishes the IGCC gasification system 
from the Dakota Gasification facility. In the IGCC process, the syngas 
is combusted. In the Dakota Gasification facility, the syngas is 
processed through a catalytic methanation process where the CO and 
H2 react to produce CH4 (methane, synthetic 
natural gas) and water. Importantly, the CO2 capture system 
that is used in the Dakota Gasification facility can readily be used in 
an IGCC EGU. There is no indication that the RECTISOL[supreg] process 
(or other similar physical gas removal systems) is not feasible for an 
IGCC EGU. In confirmation, according to product literature, 
RECTISOL[supreg], which was independently developed by Linde and Lurgi, 
is frequently used to purify shifted, partially shifted or un-shifted 
gas from the gasification of coal, lignite, and residual oil.\216\
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    \216\ www.linde-engineering.com/en/process_plants/hydrogen_and_synthesis_gas_plants/gas_processing/rectisol_wash/index.html.
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b. International Projects
    There are some international projects that are in various stages of 
development that indicate confidence by developers in the technical 
feasibility of pre-combustion carbon capture. Summit Carbon Capture, 
LLC is developing the Caledonia Clean Energy Project, a proposed 570-
megawatt IGCC plant with 90 percent CO2 capture that would 
be built in Scotland, U.K. Captured CO2 from the plant will 
be transported via on-shore and sub-sea pipeline for sequestration in a 
saline formation in the North Sea. The U.K. Department of Energy & 
Climate Change (DECC) recently announced funding to allow for 
feasibility studies for this plant.\217\ Commercial operation is 
expected in 2017.\218\
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    \217\ http://www.downstreambusiness.com/item/Summit-Power-Wins-Funding-Studies-Proposed-IGCC-CCS-Project_140878.
    \218\ http://www.summitpower.com/projects/carbon-capture/.
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    The China Huaneng Group--with multiple collaborators, including 
Peabody Energy, the world's largest private sector coal company--is 
building the 400 MW GreenGen IGCC

[[Page 64554]]

facility in Tianjin City, China. The goal is to complete the power 
plant before 2020. Over 80 percent of the CO2 will be 
separated using pre-combustion capture technology. The captured 
CO2 will be used for EOR operations.\219\
---------------------------------------------------------------------------

    \219\ http://sequestration.mit.edu/tools/projects/greengen.html.
---------------------------------------------------------------------------

    Vattenfall and Nuon's pilot project in Bugennum, The Netherlands 
involves carbon capture from coal- and biomass-fired IGCC plants. It 
has operated since 2011.\220\
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    \220\ Buggenum Fact Sheet: Carbon Dioxide Capture and Storage 
Project, Carbon Capture & Sequestration Technologies @MIT, http://sequestration.mit.edu/tools/projects/buggenum.html.
---------------------------------------------------------------------------

    Approximately 100 tons of CO2 per day are captured from 
a coal- and petcoke-fired IGCC plant in Puertollano, Spain. The 
facility began operating in 2010.\221\
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    \221\ Puertollano Fact Sheet: Carbon Dioxide Capture and Storage 
Project, Carbon Capture & Sequestration Technologies @MIT, https://sequestration.mit.edu/tools/projects/puertollanto.html.
---------------------------------------------------------------------------

    Emirates Steel Industries is expected to capture approximately 
0.8Mt of CO2 per year from a steel-production facility in 
the United Arab Emirates. Full-scale operations are scheduled to begin 
by 2016.\222\
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    \222\ ESI CCS Project Fact Sheet: Carbon Dioxide and Storage 
Project, Carbon Capture & Sequestration Technologies @MIT, https://sequestration.mit.edu/tools/projects/esi_ccs.html and https://www.globalccsinstitute.com/projects/large-scale-ccs-projects.
---------------------------------------------------------------------------

    The Uthmaniyah CO2 EOR Demonstration Project in Saudi 
Arabia will capture 0.8 Mt of CO2 from a natural gas 
processing plant over three years. It is expected to begin operating in 
2015.\223\
---------------------------------------------------------------------------

    \223\ Uthmaniyah CO2 EOR Demonstration Project, 
Global CCS Institute, https://www.globalccsinstitute.com/projects/large-scale-ccs-projects.
---------------------------------------------------------------------------

    The experience of the Dakota Gasification facility, coupled with 
the descriptions of the technology in the literature, the statements 
from vendors, and the experience of facilities internationally, are 
sufficient to support our determination that the technical feasibility 
of CCS for an IGCC facility is adequately demonstrated. The experience 
of additional facilities, described next, provides additional support.
3. Pre-Combustion Carbon Capture Projects That Have Received DOE 
Assistance Through EPAct05, but Did Not Receive Tax Credits Under IRC 
Section 48A
a. Coffeyville Fertilizer
    Coffeyville Resources Nitrogen Fertilizers, LLC, owns and operates 
a nitrogen fertilizer facility in Coffeyville, Kansas. The plant began 
operation in 2000 and is the only one in North America using a 
petroleum coke-based fertilizer production process. The petroleum coke 
is generated at an oil refinery adjacent to the plant. The petroleum 
coke is gasified to produce a hydrogen rich synthetic gas, from which 
ammonia and urea ammonium nitrate fertilizers are subsequently 
synthesized.
    As a by-product of manufacturing fertilizers, the plant also 
produces significant amounts of CO2. In March 2011, 
Chaparral Energy announced a long-term agreement for the purchase of 
captured CO2 which is transported 68 miles via 
CO2 pipeline for use in EOR operations in Osage County, OK. 
Injection at the site started in 2013.
    At least one commenter suggested that the cost and complexity of 
carbon capture from these and other industrial projects was 
significantly decreased because the sources already separate 
CO2 as part of their normal operations. The EPA finds this 
argument unconvincing. The Coffeyville process involves gasification of 
a solid fossil fuel (pet coke), shifting the resulting syngas stream, 
and separation of the resulting CO2 using a pre-combustion 
carbon capture system. These are the same, or very similar, processes 
that are used in an IGCC EGU. The argument is even less convincing when 
considering that the Coffeyville Fertilizer process uses the 
SelexolTM pre-combustion capture process--the same process 
that Mississippi Power described as having been ``in commercial use in 
the chemical industry for decades'' and is expected by Mississippi 
Power to ``pose little technology risk'' when used at the Kemper IGCC 
EGU.
4. Pre-Combustion Carbon Capture Projects That Have Received DOE 
Assistance Through EPAct05 and Tax Credits Under IRC Section 48A
a. Kemper County Energy Facility
    Southern Company's subsidiary Mississippi Power has constructed the 
Kemper County Energy Facility in Kemper County, MS. This is a 582 MW 
IGCC plant that will utilize local Mississippi lignite and includes a 
pre-combustion carbon capture system to reduce CO2 emissions 
by approximately 65 percent. The pre-combustion solvent, 
SelexolTM has also been used extensively for acid gas 
removal (including for CO2 removal) in various processes. In 
filings with the Mississippi Public Service Commission for the Kemper 
project, Mississippi described the carbon capture system:

    The Kemper County IGCC Project will capture and compress 
approximately 65% of the Plant's CO2 [. . .] a process 
referred to as SelexolTM is applied to remove the 
CO2 such that it is suitable for compression and delivery 
to the sequestration and EOR process. [. . .] The carbon capture 
equipment and processes proposed in this project have been in 
commercial use in the chemical industry for decades and pose little 
technology risk. (emphasis added) \224\
---------------------------------------------------------------------------

    \224\ Mississippi Power Company, Kemper County IGCC Certificate 
Filing, Updated Design, Description and Cost of Kemper IGCC Project, 
Mississippi Public Service Commission (MPSC) DOCKET NO. 2009-UA-
0014, filed December 7, 2009.

    Thus, Mississippi Power believes that, because the 
SelexolTM process has been in commercial use in the chemical 
industry for decades, it is well proven, and will pose little technical 
risk when used in the Kemper IGCC EGU.
b. Texas Clean Energy Project and Hydrogen Energy California Project
    The Texas Clean Energy Project (TCEP), a 400 MW IGCC facility 
located near Odessa, Texas will capture 90 percent of its 
CO2, which is approximately 3 million metric tons annually. 
The captured CO2 will be used for EOR in the West Texas 
Permian Basin. Additionally, the plant will produce urea and smaller 
quantities of commercial-grade sulfuric acid, argon, and inert slag, 
all of which will also be marketed. Summit has announced that they 
expect to commence construction on the project in 2015.\225\ The 
facility will utilize the Linde Rectisol[supreg] gas cleanup process to 
capture carbon dioxide \226\--the same process that has been deployed 
for decades, including at the Dakota Gasification facility, a clear 
indication of the developer's confidence in that technology and further 
evidence that the Dakota Gasification carbon capture technology is 
transferable to EGUs.
---------------------------------------------------------------------------

    \225\ ``Odessa coal-to-gas power plant to break ground this 
year'', Houston Chronicle (April 1, 2015).
    \226\ http://www.texascleanenergyproject.com/project/.
---------------------------------------------------------------------------

F. Vendor Guarantees, Industry Statements, Academic Literature, and 
Commercial Availability

    In this section, we describe additional information that supports 
our determination that CCS is adequately demonstrated to be technically 
feasible. This includes performance guarantees from vendors, public 
statements from industry officials, and review of the literature.
1. Performance Guarantees
    The D.C. Circuit made clear in its first cases concerning CAA 
section 111 standards, and has affirmed since then,

[[Page 64555]]

that performance guarantees from vendors are an important basis for 
supporting a determination that pollution technology is adequately 
demonstrated to be technically feasible. In 1973, in Essex Chem. Corp. 
v. Ruckelshaus, 486 F.2d 427, 440 (D.C. Cir. 1973), the Court upheld 
standards of performance for coal-fired steam generators based on 
``prototype testing data and full-scale control systems, considerations 
of available fuel supplies, literature sources, and documentation of 
manufacturer guarantees and expectations'' (emphasis supplied)).\227\ 
Subsequently, in Sierra Club v. Costle, the Court noted, in upholding 
the standard: ``we find it informative that the vendors of FGD 
equipment corroborate the achievability of the standard.'' \228\
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    \227\ See also Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 
375, 401-02 (D.C. Cir. 1973) (``It would have been entirely 
appropriate if the Administrator had justified the standards . . . 
on testimony from experts and vendors made part of the record.'').
    \228\ Sierra Club v. Costle, 657 F.2d 298, 364 (D.C. Cir. 1981). 
See also National Petrochem & Refiners Assn v. EPA, 287 F. 3d 1130, 
1137 (D.C. Cir. 2002) (noting that vendor guarantees are an indicia 
of availability and achievability of a technology-based standard 
since, notwithstanding a desire to promote sales, ``a manufacturer 
would risk a considerable loss of reputation if its technology could 
not fulfill a mandate that it had persuaded EPA to adopt'').
---------------------------------------------------------------------------

    Linde and BASF offer performance guarantees for carbon capture 
technology. The two companies are jointly marketing new, advanced 
technology for capturing CO2 from low pressure gas streams 
in power or chemical plants. In product literature,\229\ they note that 
Linde will provide a turn-key carbon capture plant using a scrubbing 
process and solvents developed by BASF, one of the world's leading 
technical suppliers for gas treatment. They further note that:
---------------------------------------------------------------------------

    \229\ www.intermediates.basf.com/chemicals/web/gas-treatment/en/function/conversions:/publish/content/products-and-industries/gas-treatment/images/Linde_and_BASF-Flue_Gas_Carbon_Capture_Plants.pdf.

    The captured carbon dioxide can be used commercially for example 
for EOR (enhanced oil recovery) or as a building block for the 
production of urea. Alternatively it can be stored underground as a 
carbon abatement measure. [. . .] The PCC (Post-Combustion Capture) 
technology is now commercially available for lignite and hard coal 
fired power plant [. . .] applications.
    The alliance between Linde, a world-leading gases and 
engineering company and BASF, the chemical company, offers great 
benefits [. . .] Complete capture plants including CO2 
compression and drying . . . Proven and tested processes including 
guarantee . . . Synergies between process, engineering, construction 
and operation . . . Optimized total and operational costs for the 
owner. (emphasis added)

    In addition, other well-established companies that either offer 
technologies that are actively marketed for CO2 capture from 
fossil fuel-fired power plants or that develop those power plants, have 
publicly expressed confidence in the technical feasibility of carbon 
capture. For example, Fluor has developed patented CO2 
recovery technologies to help its clients reduce GHG emissions. The 
Fluor product literature \230\ specifically points to the Econamine FG 
Plus\SM\ (EFG+) process, which uses an amine solvent to capture and 
produce food grade CO2 from post-combustion sources. The 
literature further notes that EFG+ is also used for carbon capture and 
sequestration projects, that the proprietary technology provides a 
proven, cost-effective process for the removal of CO2 from 
power plant flue gas streams, and that the process can be customized to 
meet a power plant's unique site requirements, flue gas conditions, and 
operating parameters.
---------------------------------------------------------------------------

    \230\ www.fluor.com/client-markets/energy-chemicals/Pages/carbon-capture.aspx.
---------------------------------------------------------------------------

    Fluor has also published an article titled ``Commercially Available 
CO2 Capture Technology'' in which it describes the EFG+ 
technology.\231\ The article notes, ``Technology for the removal of 
carbon dioxide (CO2) from flue gas streams has been around 
for quite some time. The technology was developed not to address the 
GHG effect but to provide an economic source of CO2 for use 
in enhanced oil recovery and industrial purposes, such as in the 
beverage industry.''
---------------------------------------------------------------------------

    \231\ http://www.powermag.com/commercially-available-co2-capture-technology/.
---------------------------------------------------------------------------

    Mitshubishi Heavy Industries (MHI) offers a CO2 capture 
system that uses a proprietary energy-efficient CO2 
absorbent called KS-1TM. Compared with the conventional 
monoethanolamine (MEA)-based absorbent, KS-1TM solvent 
requires less solvent circulation to capture the CO2 and 
less energy to recover the captured CO2.
    In addition, Shell has developed the CANSOLV CO2 Capture 
System, which Shell describes in its product literature \232\ as a 
world leading amine based CO2 capture technology that is 
ideal for use in fossil fuel-fired power plants where enormous amounts 
of CO2 are generated. The company also notes that the 
technology can help refiners, utilities, and other industries lower 
their carbon intensity and meet stringent GHG abatement regulations by 
removing CO2 from their exhaust streams, with the added 
benefit of simultaneously lowering SO2 and NO2 
emissions.
---------------------------------------------------------------------------

    \232\ http://www.shell.com/global/products-services/solutions-for-businesses/globalsolutions/shell-cansolv/shell-cansolv-solutions/co2-capture.html.
---------------------------------------------------------------------------

    At least one commenter suggested that it is unlikely that any 
vendor is willing or able to provide guarantees of the performance of 
the system as a whole, arguing that this shows the system isn't 
adequately demonstrated.\233\ However, this suggestion is inconsistent 
with the performance guarantees offered for other air pollution control 
equipment. Particulate matter (PM) is controlled in the flue gas stream 
of a coal-fired power plant using fabric filters or electrostatic 
precipitators (ESP). The captured PM is then moved using PM/ash 
handling systems and is then transported for storage or re-use. It is 
unlikely that a fabric filter or ESP vendor would provide a performance 
guarantee for ``the system as a whole.'' Similarly, a wet-FGD scrubber 
vendor would not be expected to provide a performance guarantee for 
handling, transportation, and re-use of scrubber solids for gypsum 
wallboard manufacturing. CO2 capture, transportation, and 
storage should, similarly, not be viewed as a single technology. 
Rather, these should be viewed as components of an overall system of 
emission reduction. Different companies will have expertise in each of 
these components, but it is unlikely that a single technology vendor 
would provide a guarantee for ``the system as a whole.''
---------------------------------------------------------------------------

    \233\ Comments of Murray Energy, p. 73, (Docket entry: EPA-HQ-
OAR-2013-0495-10046).
---------------------------------------------------------------------------

2. Academic and Other Literature
    Climate change mitigation options--including CCS--are the subject 
of great academic interest, and there is a large body of academic 
literature on these options and their technical feasibility. In 
addition, other research organizations (e.g., U.S. national 
laboratories and others) have also published studies on these subjects 
that demonstrate the availability of these technologies. A compendium 
of relevant literature is provided in a Technical Support Document 
available in the rulemaking docket.\234\
---------------------------------------------------------------------------

    \234\ Technical Support Document--``Literature Survey of Carbon 
Capture Technology'', available in the rulemaking docket (Docket ID: 
EPA-HQ-OAR-2013-0495).
---------------------------------------------------------------------------

3. Additional Statements by Technology Developers
    The discussion above of vendor guarantees, positive statements by 
industry officials, and the academic literature supports the EPA's 
determination that partial CCS is adequately demonstrated to be

[[Page 64556]]

technically feasible. Industry officials have made additional positive 
statements in conjunction with facilities that received DOE assistance 
under EPAct05 or the IRC Section 48A tax credit. These statements 
provide further, although not necessary, support.
    For example, Southern Company's Mississippi Power has stated that, 
because the SelexolTM process has been used in industry for 
decades, the technical risk of its use at the Kemper IGCC facility is 
minimized. For example:

    The carbon capture process being utilized for the Kemper County 
IGCC is a commercial technology referred to as SelexolTM. 
The SelexolTM process is a commercial technology that 
uses proprietary solvents, but is based on a technology and 
principles that have been in commercial use in the chemical industry 
for over 40 years. Thus, the risk associated with the design and 
operation of the carbon capture equipment incorporated into the 
Plant's design is manageable.\235\
---------------------------------------------------------------------------

    \235\ Testimony of Thomas O. Anderson, Vice President, 
Generation Development for Mississippi Power, MS Public Service 
Commission Docket 2009-UA-14 at 22 (Dec. 7, 2009).
---------------------------------------------------------------------------

    And . . .
    The carbon capture equipment and processes proposed in this 
project have been in commercial use in the chemical industry for 
decades and pose little technology risk.\236\
---------------------------------------------------------------------------

    \236\ Mississippi Power Company, Kemper County IGCC Certificate 
Filing, Updated Design, Description and Cost of Kemper IGCC Project, 
Mississippi Public Service Commission (MPSC) DOCKET NO. 2009-UA-
0014, filed December 7, 2009.

    Similarly, in an AEP Second Quarter 2011 Earnings Conference Call, 
---------------------------------------------------------------------------
Chairman and CEO Mike Morris said of the Mountaineer CCS project:

    We are encouraged by what we saw, we're clearly impressed with 
what we learned, and we feel that we have demonstrated to a 
certainty that the carbon capture and storage is in fact viable 
technology for the United States and quite honestly for the rest of 
the world going forward.\237\
---------------------------------------------------------------------------

    \237\ American Electric Power Co Inc AEP Q2 2011 Earnings Call 
Transcript, Morningstar, http://www.morningstar.com/earnings/28688913-american-electric-power-co-incaep-q2-2011-earnings-call-transcript.aspx.

    Some commenters have claimed that CCS technology is not technically 
feasible, and some further assert that vendors do not offer performance 
---------------------------------------------------------------------------
guarantees. For example, Alstom commented:

    The EPA referenced projects fail to meet the `technically 
feasible' criteria. These technologies are not operating at 
significant scale at any site as of the rule publication. We do not 
support mandating technology based on proposed projects (many of 
which may never be built).\238\
---------------------------------------------------------------------------

    \238\ Alstom Comments, p. 3 (Docket entry: EPA-HQ-OAR-2013-0495-
9033).

    As discussed above, vendors do in fact offer performance 
guarantees. We further note that, as noted above, Boundary Dam Unit #3 
is a full-scale project that is successfully implementing full CCS with 
post-combustion capture, and Dakota Gasification is likewise a full-
scale commercial operation that is successfully implementing pre-
combustion CCS technology. Moreover, as we explain above, this 
technology and performance is transferable to the steam electric 
generating sector. In addition, as noted above, technology providers 
and technology end users have expressed confidence in the availability 
and performance of CCS technology.\239\
---------------------------------------------------------------------------

    \239\ We note that before filing comments for this rule 
asserting that CCS is not technically feasible, Alstom issued public 
statements that, like the other industry officials quoted above, 
affirmed that CCS is technically feasible. According to an Alstom 
Power press release, Alstom President Phillipe Joubert, referencing 
results from an internal Alstom study, stated at an industry 
meeting: ``We can now be confident that carbon capture technology 
(CCS) works and that it is cost-effective''. http://www.alstom.com/press-centre/2011/6/2011-06-16-CCS-cost-competiveness/.
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G. Response to Key Comments on the Adequacy of the Technical 
Feasibility Demonstration

1. Commercial Availability
    Some commenters asserted that CCS cannot be considered the BSER 
because it is not commercially available. There is no requirement, as 
part of the BSER determination, that the EPA finds that the technology 
in question is ``commercially available.'' As we described in the 
January 2014 proposal, the D.C. Circuit has explained that a standard 
of performance is ``achievable'' if a technology or other system of 
emission reduction can reasonably be projected to be available to new 
sources at the time they are constructed that will allow them to meet 
the standard, and that there is no requirement that the technology 
``must be in routine use somewhere.'' See Portland Cement v. 
Ruckelshaus, 486 F. 2d at 391; 79 FR 1463. In any case, as discussed 
above, CCS technology is available through vendors who provide 
performance guarantees, which indicates that in fact, CCS is 
commercially available, which adds to the evidence that the technology 
is adequately demonstrated to be technically feasible. In sum, ``[t]he 
capture and CO2 compression technologies have commercial 
operating experience with demonstrated ability for high reliability.'' 
\240\
---------------------------------------------------------------------------

    \240\ ``Cost and Performance Baseline for Fossil Energy Plants 
Volume 1a: Bituminous Coal (PC) and Natural Gas to Electricity 
Revision 3'', DOE/NETL-2015/1723 (July 2015) at p. 36.
---------------------------------------------------------------------------

2. Must a technology or system of emission reduction be in full-scale 
use to be considered demonstrated?
    Commenters maintained that the EPA can only show that a BSER is 
``adequately demonstrated'' using operating data from the technology or 
system of emission reduction itself. This is mistaken. Since the very 
inception of the CAA section 111 program, courts have noted that ``[i]t 
would have been entirely appropriate if the Administrator had justified 
the standard, not on the basis of tests on existing sources or old test 
data in the literature, but on extrapolations from this data, on a 
reasoned basis responsive to comments, and on testimony from experts 
and vendors . . . .'' Portland Cement v. Ruckelshaus, 486 F. 2d at 401-
02.\241\
---------------------------------------------------------------------------

    \241\ More recently, the D.C. Circuit stated:
    Our prior decisions relating to technology-forcing standards are 
no bar to this conclusion. We recognize here, as we have recognized 
in the past, that an agency may base a standard or mandate on future 
technology when there exists a rational connection between the 
regulatory target and the presumed innovation.
    API v. EPA, 706 F. 3d at 480 (D.C. Cir. 2013) (citing the 
section 111 case Sierra Club v. Costle, 657 F. 2d at 364). The 
Senate Report to the original section 111 likewise makes clear that 
it was not intended that the technology ``must be in actual routine 
use somewhere.'' Rather, the question was whether the technology 
would be available for installation in new plants. S. Rep. No. 91-
1196, 91st Cong., 2d Sess. 16 (1970).
---------------------------------------------------------------------------

    In a related argument, other commenters stated that a system cannot 
be adequately demonstrated unless all of its component parts are 
operating together.\242\ Courts have, in fact, accepted that the EPA 
can legitimately infer that a technology is demonstrated as a whole 
based on operation of component parts which have not, as yet, been 
fully integrated. Sur Contra la Contaminacion v. EPA, 202 F. 3d 443, 
448 (1st Cir. 2000); Native Village of Point Hope v Salazar 680 F. 3d 
1123, 1133 (9th Cir. 2012). Moreover, all components of CCS are fully 
integrated at Boundary Dam: Post-combustion full CCS is being utilized 
at a steam electric fossil fuel-fired plant, with captured carbon being 
transported via dedicated pipeline to both sequestration and EOR sites. 
All components are likewise demonstrated for pre-combustion CCS at the 
Dakota Gasification facility, except that the facility does not 
generate electricity, a distinction without a difference for this 
purpose (see Section V.E.2.a above).
---------------------------------------------------------------------------

    \242\ See, e.g., Comments of UARG p. 5 (Docket entry: EPA-HQ-
OAR-2013-0495-9666).
---------------------------------------------------------------------------

    The short of it is that the ``EPA does have authority to hold the 
industry to a standard of improved design and

[[Page 64557]]

operational advances, so long as there is substantial evidence that 
such improvements are feasible and will produce the improved 
performance necessary to meet the standard.'' Sierra Club, 657 F. 2d at 
364. The EPA's task is to ``identify the major steps necessary for 
development of the device, and give plausible reasons for its belief 
that the industry will be able to solve those problems in the time 
remaining''. API v. EPA, 706 F. 3d at 480 (quoting NRDC v. EPA, 655 F. 
2d 318, 333 (D.C. Cir. 1981), and citing Sierra Club for this 
proposition).
3. Scalability of Pilot and Demonstration Projects
    Commenters maintained that the EPA had no basis for maintaining 
that pilot and demonstration plant operations showed that CCS was 
adequately demonstrated. This is mistaken. In a 1981 decision, Sierra 
Club v. Costle, the D.C. Circuit explained that data from pilot-scale, 
or less than full-scale operation, can be shown to reasonably 
demonstrate performance at full-scale operation, although it is 
incumbent on the EPA to explain the necessary steps involved in scaling 
up a technology and how any obstacles may reasonably be surmounted when 
doing so.\243\ The EPA has done so here.
---------------------------------------------------------------------------

    \243\ Sierra Club v. Costle, 657 F. 2d 298, 341 n.157 and 380-84 
(D.C. Cir. 1981). See also Essex Chemical Corp. v. EPA, 486 F. 2d at 
440 (upholding achievability of standard of performance for coal-
burning steam generating plants which hadn't been achieved in full-
scale performance based in part on ``prototype testing data'' which, 
along with vendor guarantees, indicated that the promulgated 
standard was achievable); Weyerhaeuser v. Costle, 590 F. 2d 1054 n. 
170 (D.C. Cir. 1978) (use of pilot plant information to justify 
technology-based standard for Best Available Technology Economically 
Achievable under section 304 of the Clean Water Act); FMC Corp. v. 
Train, 539 F. 2d 973, 983-84 (4th Cir. 1976)(same).
---------------------------------------------------------------------------

    Most obviously, the final standard reflects experience of full-
scale operation of post-combustion carbon capture. Pre-combustion 
carbon capture is likewise demonstrated at full-scale. Second, the 
record explains in detail how CCS can be implemented at full-scale. The 
NETL cost and performance reports, indeed, contain hundreds of pages of 
detailed, documented explanation of how CCS can be implemented at full-
scale for both utility boiler and IGCC facilities. See, for example, 
the detailed description of the following systems projected to be 
needed for a new supercritical PC boiler to capture CO2: 
Coal and sorbent receiving and storage, steam generator and 
ancillaries, NOX control system, particulate control, flue 
gas desulfurization, flue gas system, CO2 recovery facility, 
steam turbine generator system, balance of plant, and accessory 
electric plant, and instrumentation and control systems.\244\
---------------------------------------------------------------------------

    \244\ Cost and Performance Baseline for Fossil Energy Plants 
Volume 1: Bituminous Coal and Natural Gas to Electricity; Revision 
2a, pp. 57-74.
---------------------------------------------------------------------------

    It is important to note that, while some commenters challenged the 
EPA's use of costs in the DOE/NETL cost and performance reports, 
commenters did not challenge the technical methodology in the work.
    In addition, the AEP FEED study indicates how the development scale 
post-combustion CCS could be successfully scaled up to full-scale 
operation. See Section V.D.3.b above.
    Tenaska Trailblazer Partners, LLC also prepared a FEED study \245\ 
for the carbon capture portion of the previously proposed Trailblazer 
Energy Center, a 760 MW SCPC EGU that was proposed to include 85 to 90 
percent CO2 post-combustion capture. Tenaska selected the 
Fluor Econamine FG Plus\SM\ technology and contracted Fluor to conduct 
the FEED study. One of the goals of the FEED study was to ``[c]onfirm 
that scale up to a large commercial size is achievable.'' Tenaska 
ultimately concluded that the study had achieved its objectives 
resulting in ``[c]onfirmation that the technology can be scaled up to 
constructable design at commercial size through (1) process and 
discipline engineering design and CFD (computational fluid dynamics) 
analysis, (2) 3D model development, and (3) receipt of firm price 
quotes for large equipment.''
---------------------------------------------------------------------------

    \245\ Final front-end engineering design (FEED) study report'', 
available at: www.globalccsinstitute.com/publications/tenaska-trailblazer-front-end-engineering-design-feed-study.
---------------------------------------------------------------------------

    Much has been written about the complexities of adding CCS systems 
to fossil fuel-fired power plants. Some of these statements come from 
high government officials. Some commenters argued that the EPA 
minimized--or even ignored--these publically voiced concerns in the 
discussion presented in the January 2014 proposal. On the contrary, the 
EPA has not minimized or ignored these complexities, but it is 
important to realize that most of these statements come in a different 
context: Namely, implementing full CCS, or retrofitting CCS onto 
existing power plants. For example, in the Final Report of the 
President's CCS Task Force, it was noted that ``integration of CCS 
technologies with the power cycle at generating plants can present 
significant cost and operating issues that will need to be addressed to 
facilitate widespread, cost-effective deployment of CO2 
capture.'' \246\ This statement--and most of the statements in this 
vein--are in reference to implementation of full CCS systems that 
capture more than 90 percent of the CO2 and many reference 
widespread implementation of such technology. The EPA has addressed the 
concerns regarding ``significant cost'' by finalizing a standard that 
relies on partial CCS which we show, in this preamble and in the 
supporting record, can be implemented at a reasonable, non-exorbitant 
cost. The Boundary Dam facility, in particular, demonstrates that the 
complexities of implementing CCS--even full CCS--can be overcome.
---------------------------------------------------------------------------

    \246\ Report of the Interagency Task Force on Carbon Capture and 
Storage (August 2010), page 28. See also DOE Carbon Capture Web 
site: ``First generation CO2 capture technologies are 
currently being used in various industrial applications. However, in 
their current state of development, these technologies are not ready 
for implementation on coal-based power plants because they have not 
been demonstrated at appropriate scale, requisite approximately one-
third of the plant's steam power to operate, and are cost 
prohibitive.'' (Dec 2010); and Testimony of Dr. S. Julio Friedmann, 
Deputy Asst. Secretary of Energy for Clean Coal, U.S. Dept. of 
Energy, before the Subcommittee on Oversight and Investigations 
Committee on Energy and Commerce (Feb. 11, 2014): CCS technologies 
at new coal-fired plants would result in ``something like a 70 to 80 
percent increase on the wholesale price of electricity.''
---------------------------------------------------------------------------

    Concerns regarding ``operating issues'' are also often associated 
with implementation of full CCS--and often with implementation of full 
CCS as a retrofit to an existing source. Implementation of CCS at some 
existing sources may be challenging because of space limitations. That 
should not be an issue for a new facility because the developer will 
need to ensure that adequate space is available during the design of 
the facility. Constructing CCS technology at an existing facility can 
be challenging even if there is adequate space because the positioning 
of the equipment may be awkward when it must be constructed to fit with 
the existing equipment at the plant. Some commenters noted the 
challenges of diverting steam from the plant's steam cycle. Again, that 
is primarily an issue with full CCS implementation as a retrofit to an 
existing source. Consideration of steam requirements for solvent 
regeneration can be factored into the design of a new facility. We also 
note that issues of integration with the plant's steam cycle are less 
challenging when implementing partial CCS.
    Some commenters noted conclusions and statements from the CCS Task 
Force report as contradictory to the EPA's determination of that 
partial CCS is technically feasible and adequately demonstrated. 
However, the EPA mentioned in the January 2014

[[Page 64558]]

proposal, and we emphasize again here, that the Task Force was charged 
with proposing a plan to overcome the barriers to the widespread, cost-
effective deployment of CCS by 2020. Implicit in all of the 
conclusions, recommendations, and statements of that final report is a 
goal of widespread implementation of full CCS--including retrofits of 
existing sources. This final action does not require--nor does it 
envision--the near term widespread implementation of full CCS. On the 
contrary, as we have noted several times in this preamble, the EPA and 
others predict that very few, if any, new coal-fired steam generating 
EGUs will be built in the near term.
    Thus, the EPA has provided an ample record supporting its finding 
that partial CCS is feasible at full-scale. As in Sierra Club, the EPA 
has presented evidence from full-scale operation, smaller scale 
installations, and reasonable, corroborated technical explanations of 
how the BSER can be successfully operated at full scale. See 657 F. 2d 
at 380, 382. Indeed, the EPA has more evidence here, as the baghouse 
standard in Sierra Club was justified based largely on less-than-full-
scale operation. See 657 F.2d at 380 (there was only ``limited data 
from one full scale commercial sized operation''), 376 (``the baghouses 
surveyed were installed at small plants''), and 341 n.157; see also 
Section V.L, explaining why CCS is a more developed technology than FGD 
scrubbers were at the inception of the 1971 NSPS for this industry.

H. Consideration of Costs

    CAA section 111(a) defines ``standard of performance'' as an 
emission standard that reflects the best system of emission reduction 
that is adequately demonstrated, ``taking into account [among other 
things] the cost of achieving such reduction.'' Based on consideration 
of relevant cost metrics in the context of current market conditions, 
the EPA concludes that the costs associated with the final standard are 
reasonable.
    In reaching this determination, the EPA considered a host of 
different cost metrics, each of which illuminated a particular aspect 
of cost consideration, and each of which demonstrated that the costs of 
the final standard are reasonable. The EPA evaluated capital costs on a 
per-plant basis, responding to public comment that noted the particular 
significance of capital costs for coal-fired EGUs. As in the proposal, 
the EPA also considered how the standard would affect the LCOE for 
individual affected EGUs as well as national, overall cost impacts of 
the standard. The EPA found that the anticipated cost impacts are 
similar to those in other promulgated NSPS--including for this 
industry--that have been upheld by the D.C. Circuit. The costs are also 
comparable to those of other base load technologies that might be 
selected on comparable energy portfolio diversity grounds. Finally, the 
EPA does not anticipate any significant overall nationwide costs or 
cost impacts on consumers because projected new generating capacity is 
expected to meet the standards even in the baseline. Accordingly, after 
considering costs from a range of different perspectives, the EPA 
concludes that the costs of the final standard are reasonable.
1. Rationale at Proposal
    At proposal, the EPA evaluated the costs of new coal-fired EGUs 
implementing full (90 percent) and partial CCS. The EPA compared the 
predicted LCOE of those units against the LCOE of other new 
dispatchable technologies often considered for new base load power with 
fuel diversity, primarily including a new nuclear plant, as well as a 
new biomass-fired EGU. See 79 FR at 1475-78. The levelized cost for a 
new steam EGU implementing full CCS was higher than that of the other 
non-NGCC dispatchable technologies, and we did not propose to identify 
a new steam EGU implementing full CCS as BSER on that basis. Id. at 
1477. The EPA proposed that a standard of performance of 1,100 lb 
CO2/MWh-g, reflecting a new steam EGU implementing partial 
CCS, could be achieved at reasonable cost based on a comparison of the 
projected LCOE associated with achieving this standard with the 
alternative dispatchable technologies just mentioned. In the January 
2014 proposal, the EPA used LCOE projections for new fossil fuel-fired 
EGUs from a series of studies conducted by the DOE NETL. These 
studies--the ``cost and performance studies''--detail expected costs 
and performance for a range of technology options both with and without 
CCS.\247\ The EPA used LCOE projections for non-fossil dispatchable 
generation--specifically nuclear and biomass--from the EIA AEO 2013. 
See 79 FR 1435.
---------------------------------------------------------------------------

    \247\ For the cost estimates in the January 2014 proposal, the 
EPA used costs for new SCPC and IGCC units utilizing bituminous coal 
from the reports ``Cost and Performance Baseline for Fossil Energy 
Plants Volume 1: Bituminous Coal and Natural Gas to Electricity'', 
Revision 2, Report DOE/NETL-2010/1397 (November 2010) and ``Cost and 
Performance of PC and IGCC Plants for a Range of Carbon Dioxide 
Capture'', DOE/NETL-2011/1498, May 27, 2011. Additional cost and 
performance information can be found in additional volumes that are 
available at http://www.netl.doe.gov/research/energy-analysis/energy-baseline-studies.
---------------------------------------------------------------------------

    In addition, the EPA proposed that the costs to implement partial 
CCS were reasonable because a segment of the industry was already 
accommodating them. Id. at 1478. The EPA also considered anticipated 
decreases in the cost of CCS technologies, the availability of 
government tax benefits, loan guarantees, and direct expenditures, and 
the opportunity to generate income from sale of captured CO2 
for EOR. Id. at 1478-80. The EPA noted that the proposed standard was 
not expected to lead to any significant overall costs or effects on 
electricity prices. Id. at 1480-81. The EPA also acknowledged the 
overall market context, noting that fossil steam EGUs, even without any 
type of CCS, are significantly more expensive than new natural gas-
fired electricity generation, but that some electricity suppliers might 
include new coal-fired generating sources in their generation 
portfolio, and would pay a premium to do so. Id. at 1478.
2. Brief Summary of Cost Considerations Under CAA Section 111
    As explained above, CAA section 111(a) directs the EPA to ``tak[e] 
into account the cost'' of achieving reductions in determining if a 
particular system of emission reduction is the best that is adequately 
demonstrated. The statute does not provide further guidance on how 
costs should be considered, thus affording the EPA considerable 
discretion in choosing a means of cost consideration. In addition, it 
should be noted that in evaluating the reasonableness of costs, the 
D.C. Circuit has upheld application of a variety of metrics, such as 
the amount of control costs or product price increases. See Section 
III.H.3.(b).(1) above.
    Following the directive of CAA section 111(a) and applicable 
precedent, the EPA evaluated relevant metrics and context in 
considering the reasonableness of the regulation's costs. The EPA's 
findings demonstrate that the costs of the selected final standard are 
reasonable.
3. Current Context
    The EIA projects that few new coal-fired EGUs will be constructed 
over the coming decade and that those that are built will apply CCS, 
reflecting the broad consensus of government, academic, and industry 
forecasters.\248\

[[Page 64559]]

The primary reasons for this projected trend include low electricity 
demand growth, highly competitive natural gas prices, and increases in 
the supply of renewable energy. In particular, U.S. electricity demand 
growth has followed a downward sloping trend for decades with future 
growth expected to remain very low.\249\ Furthermore, the EPA projects 
that, for any new fossil fuel-fired electricity generating capacity 
that is constructed through 2030, natural gas will be the overwhelming 
fuel of choice.\250\ See RIA chapter 4.
---------------------------------------------------------------------------

    \248\ Even in its sensitivity analysis that assumes higher 
natural gas prices and electricity demand, EIA does not project any 
additional coal beyond its reference case until 2023, in a case 
where power companies assume no GHGs emission limitations, and until 
2024 in a case where power companies do assume GHGs emission 
limitations. EIA, ``Annual Energy Outlook 2015,'' DOE/EIA-
0383(2015), April 2015, ``[v]ery little unplanned coal-fired 
capacity is added across all the AEO 2015 cases'', p. 26.
    \249\ EIA, ``Annual Energy Outlook 2015,'' DOE/EIA-0383(2015), 
April 2015, p. 8.
    \250\ Integrated Planning Model (IPM) run by the EPA (v. 5.15) 
Base Case, available at www.epa.gov/airmarkets/powersectormodeling.html.
---------------------------------------------------------------------------

    The EIA's projection is confirmed by an examination of Integrated 
Resource Plans (IRPs) contained in a TSD in the docket for this 
rulemaking. IRPs are used by utilities to plan operations and 
investments in both owned generation and power purchase agreements over 
long time horizons. Though IRPs do not demonstrate a utility's intent 
to pursue a particular generation technology, they do indicate the 
types of new generating technologies that a utility would consider for 
new generating capacity. The EPA's survey of recent IRPs demonstrates 
that across the nation, utilities are not actively considering 
constructing new coal-fired generation without CCS in the near term.
    Accordingly, construction of new uncontrolled coal-fired generating 
capacity is not anticipated in the near term, even in the absence of 
the standards of performance we are finalizing in this rule, except 
perhaps in certain limited circumstances.
    In particular, commenters suggested that some developers might 
choose to build a new coal-fired EGU, despite its not being cost 
competitive, in order to achieve or maintain ``fuel diversity.'' Fuel 
diversity could provide important value by serving as a hedge against 
the possibility that future natural gas prices will far exceed 
projected levels.
    Public announcements, including IRPs, confirm that utilities are 
interested in technologies that could provide or preserve fuel 
diversity within generating fleets. The Integrated Resource Plan TSD 
\251\ notes examples where the goal of fuel diversity was considered in 
IRPs; in many cases, these plans considered new generation that would 
not rely on natural gas. In particular, several utilities that 
considered fuel diversity in developing their IRPs included new nuclear 
generation as a potential future generation strategy.
---------------------------------------------------------------------------

    \251\ Technical Support Document--``Review of Electric Utility 
Integrated Resource Plans'' (May 2015), available in the rulemaking 
docket EPA-HQ-OAR-2013-0495.
---------------------------------------------------------------------------

    In addition, the EPA recognizes that there may be interest in 
constructing a new combined-purpose coal-fired facility that would 
generate power as well as produce chemicals or CO2 for use 
in EOR projects. These facilities would similarly provide additional 
value due to the revenue streams from saleable chemical products or 
CO2.\252\
---------------------------------------------------------------------------

    \252\ The EPA may, of course, consider revenues generated as a 
result of application of pollution control measures in assessing the 
costs of a best system of emission reduction. See New York v. 
Reilly, 969 F.2d 1147, 1150-52 (D.C. Cir. 1992).
---------------------------------------------------------------------------

    As demonstrated below, the agency carefully considered the 
reasonableness of costs in identifying a standard that allows a path 
forward for such projects and rejects more stringent options that would 
impose potentially excessive costs. In fact, based on this careful 
consideration of costs, the EPA is finalizing a substantially lower 
cost standard than the one we proposed. At the same time, we note the 
unusual circumstances presented here, where the record, and indeed 
simple consideration of electricity market economics, demonstrates that 
non-economic factors such as fuel diversity are likely to drive any 
construction of new coal-fired generation. See also RIA chapter 4 
(documenting that electric power companies will choose to build new 
EGUs that comply with the regulatory requirements of this rule even in 
its absence, primarily NGCC units, because of existing and expected 
market conditions). Under these circumstances, the EPA's consideration 
of costs takes into account that higher costs can be viewed as 
reasonable when costs are not a paramount factor in new coal capacity 
decisions. At the same time, the EPA acknowledges and agrees with the 
public comments that such an argument, left unconstrained, could 
justify any standard and obviate all cost considerations.\253\ The EPA 
has reasonably cabined its consideration of costs by examining costs 
for comparable non-NGCC base load dispatchable technologies, as well as 
by considering capital costs and other cost metrics.\254\ This cost-
reasonable standard will preserve the opportunity for such projects 
while driving new technology deployment.\255\
---------------------------------------------------------------------------

    \253\ See, e.g., Comments of Murray Energy, pp. 79-80 (Docket 
entry: EPA-HQ-OAR-2013-0495-10046).
    \254\ Indeed, the EPA is not only adopting a standard predicated 
on a lower rate of carbon capture than proposed, but also rejecting 
full CCS for reasons of cost. See Section V.P below. Thus, although 
the EPA has reasonably taken into account the current economic 
posture of the industry whereby new capacity is not cost-competitive 
and so would be added for non-economic reasons, it is not using that 
fact to negate consideration of cost here. See also Section V.I.4 
below responding to comments that the incremental cost of partial 
CCS could prove the difference between constructing and not 
constructing new coal capacity.
    \255\ 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.''
---------------------------------------------------------------------------

4. Consideration of Capital Costs
    As noted above, CAA section 111 does not mandate any particular 
method for evaluating costs, leaving the EPA with significant 
discretion as to how to do so. One method is to consider the 
incremental capital costs required for a unit to achieve the standard 
of performance.
    The EPA included information on capital cost at proposal and, as 
discussed further below, the LCOE metric relied upon at proposal and in 
this final rulemaking incorporates and fully reflects capital 
costs.\256\ Nonetheless, extensive comment from industry 
representatives and others noted persuasively that fossil-steam units 
are very capital-intensive projects and recommended that a separate 
metric, solely of capital costs, be considered by the EPA in evaluating 
the final standard's costs. Accordingly, the EPA has considered the 
final standard's impact on the capital costs of new fossil-steam 
generation. The EPA has determined that the incremental capital costs 
of the final standard are reasonable because they are comparable to 
those in prior regulations and to industry experience, and because the 
fossil steam electric power industry has been shown to be able to 
successfully absorb capital costs of this magnitude in the past.
---------------------------------------------------------------------------

    \256\ See RIA chapter 4.5.4 and Fig. 4-3; see also ``Cost and 
Performance Baseline for Fossil Energy Plants Supplement: 
Sensitivity to CO2 Capture Rate in Coal-Fired Power 
Plants'', DOE/NETL-2015/1720 (July 2015) p. 17.
---------------------------------------------------------------------------

    Prior new source performance standards for new fossil steam 
generation units have had significant--yet manageable--impacts on the 
capital costs of construction. The EPA estimated that the costs for the 
1971 NSPS for coal-fired EGUs were $19M for a 600 MW plant, consisting 
of $3.6M for particulate matter controls, $14.4M for sulfur dioxide 
controls, and $1M for nitrogen oxides controls, representing a 15.8 
percent increase in capital costs

[[Page 64560]]

above the $120M cost of the plant. See 1972 Supplemental Statement, 37 
FR 5767, 5769 (March 21, 1972). The D.C. Circuit upheld the EPA's 
determination that the costs associated with the final 1971 standard 
were reasonable, concluding that the EPA had properly taken costs into 
consideration. Essex Cement v. EPA, 486 F. 2d at 440.
    In reviewing the 1978 NSPS for coal-fired EGUs, the D.C. Circuit 
recognized that ``EPA estimates that utilities will have to spend tens 
of billions of dollars by 1995 on pollution control under the new 
NSPS'' and that ``[c]onsumers will ultimately bear these costs.'' 
Sierra Club, 657 F.2d at 314. The court nonetheless upheld the EPA's 
determination that the standard was reasonable. Id. at 410.
    The cost and investment impacts of the 1978 NSPS on electric 
utilities were subsequently evaluated in a 1982 Congressional Budget 
Office (CBO) retrospective study.\257\ The CBO study highlighted that 
installation of scrubbers--capital intensive pollution control 
equipment that had ``in effect'' been mandated by the 1978 NSPS--
increased capital costs for new EGUs by 10 to as much as 20 
percent.\258\ The study further noted that air pollution control 
requirements in general had led to an estimated 37.5 to 45 percent 
increase in capital costs for coal-fired power plant installation 
between 1971 and 1980.\259\
---------------------------------------------------------------------------

    \257\ Congressional Budget Office report, ``The Clean Air Act, 
the Electric Utilities, and the Coal Market'', April 1982, p. 10-11, 
23.
    \258\ Id. at 10-11.
    \259\ Id. at 22.
---------------------------------------------------------------------------

    The study retrospectively confirmed the EPA's conclusion that 
imposition of these costs was reasonable, finding that ``utilities with 
commitments to pollution control tend to fare no better and no worse 
than all electric utilities in general.'' \260\ In assessing the 
capital cost impacts of the suite of 1970s EPA air pollution standards, 
the report concluded that ``though controlling emissions is indeed 
costly, it has not played a major role in impairing the utilities' 
financial position, and is not likely to do so in the future.'' \261\
---------------------------------------------------------------------------

    \260\ Id. at xvi.
    \261\ Id.
---------------------------------------------------------------------------

    In NSPS standards for other sectors, the EPA's determination that 
capital cost increases were reasonable has similarly been upheld. In 
Portland Cement Association, the D.C. Circuit upheld the EPA's 
consideration of costs for a standard of performance that would 
increase capital costs by about 12 percent, although the rule was 
remanded due to an unrelated procedural issue. 486 F.2d at 387-88. 
Reviewing the EPA's final rule after remand, the court again upheld the 
standards and the EPA's consideration of costs, noting that ``[t]he 
industry has not shown inability to adjust itself in a healthy economic 
fashion to the end sought by the Act as represented by the standards 
prescribed.'' Portland Cement v. Ruckelshaus, 513 F. 2d 506, 508 (D.C. 
Cir. 1975).
    The capital cost impacts incurred under these prior standards are 
comparable in magnitude on an individual unit basis to those projected 
for the present standard. We predict that the incremental costs of 
control for a new highly efficient SCPC unit to meet the final emission 
limitation of 1,400 lb CO2/MWh-g would be an increase of 21-
22 percent for capital costs. See Table 7 below.262 263
---------------------------------------------------------------------------

    \262\ We explain at Section V.I.2 and 3 below the reasonableness 
of the EPA's cost projections here.
    \263\ We estimate that a new SCPC EGU using low rank coal 
(subbituminous coal or dried lignite) would incur a capital cost 
increase of 23 percent to meet the final standard. See 
``Achievability of the Standard for Newly Constructed Steam 
Generating EGUs'' technical support document available in the 
rulemaking docket.
    \264\ Exhibit A-3 (p. 18); ``Cost and Performance Baseline for 
Fossil Energy Plants Supplement: Sensitivity to CO2 
Capture Rate in Coal-Fired Power Plants'', DOE/NETL-2015/1720 (June 
2015).

 Table 7--Comparison of Estimated Capital Costs for a New SCPC and a New
          SCPC Meeting the Final Standard of Performance \264\
------------------------------------------------------------------------
                                               Total      Total as-spent
                                          overnight cost  capital (2011$/
                                            (2011$/kW)          kW)
------------------------------------------------------------------------
SCPC--no CCS............................           2,507           2,842
SCPC--partial CCS (1,400 lb CO2/MWh-g)..           3,042           3,458
Incremental cost increase...............           21.3%           21.7%
------------------------------------------------------------------------

    By comparison, a SCPC that co-fires with natural gas to meet the 
final standard of 1,400 lb CO2/MWh-g would not result in an 
increase in capital cost over the uncontrolled SCPC. A compliant IGCC 
unit co-firing natural gas is predicted to have Total Overnight Cost of 
$3,036/kW--an approximately 21.1 percent increase in capital over the 
uncontrolled SCPC unit.
5. Consideration of Costs Based on Levelized Cost of Electricity
    As in the proposal, the EPA also considered the reasonableness of 
costs by evaluating the LCOE associated with the final standard. The 
LCOE is a commonly used economic metric that takes into account all 
costs to construct and operate a new power plant over an assumed time 
period and an assumed capacity factor. The LCOE is a summary metric, 
which expresses the full cost of generating electricity on a per unit 
basis (i.e., megawatt-hours). Levelized costs are often used to compare 
the cost of different potential generating sources. While capital cost 
is a useful and relevant metric for capital-intensive fossil-steam 
units, the LCOE can serve as a useful complement because it takes into 
account all specified costs (operation and maintenance, fuel--as well 
as capital costs), over the whole lifetime of the project.
    As previously mentioned, at proposal the EPA relied on LCOE 
projections for fossil fuel-fired EGUs (with and without CCS) from DOE/
NETL reports detailing the results of studies evaluating the costs and 
performance of such units. For non-fossil dispatchable generating 
sources, the EPA relied on LCOE projections from EIA AEO 2013. For this 
final action, the EPA is relying on updated costs from the same 
sources. The NETL has provided updated cost and performance information 
in recently published revisions of reports used in the January 2014 
proposal.\265\ The updated SCPC cases in the reports include up-to-date 
cost and performance information from recent vendor quotes

[[Page 64561]]

and implementation of the Shell Cansolv post-combustion capture 
process--the process that is currently being utilized at the Boundary 
Dam #3 facility. The IGCC cost and performance results in the updated 
reports utilize vendor quotes from the previous report; the costs are 
adjusted from $2007 to $2011. Important also to note is that DOE/NETL 
utilized conventional financing for cases without CCS and utilized 
high-risk financial assumptions for cases that include CCS.\266\
---------------------------------------------------------------------------

    \265\ ``Cost and Performance Baseline for Fossil Energy Plants: 
Volume 1a'' Bituminous Coal (PC) and Natural Gas to Electricity, 
Revision 3, U.S. DOE NETL report (2015) and ``Cost and Performance 
Baseline for Fossil Energy Plants: Volume 1b: Bituminous Coal (IGCC) 
to Electricity, Revision 2--Year Dollar Update, U.S. DOE NETL report 
(2015). Both reports are available at www.netl.doe.gov/research/energy-analysis/energy-baseline-studies.
    \266\ Cost and Performance Baseline for Fossil Energy Plants 
Supplement: Sensitivity to CO2 Capture Rate in Coal-Fired 
Power Plants'', DOE/NETL-2015/1720 (June 2015) p. 18.
---------------------------------------------------------------------------

    Using information from those reports, the DOE/NETL prepared a 
separate report summarizing a study that evaluated the cost and 
performance of various plants designed to meet a range of 
CO2 emissions by varying the CO2 capture rate 
(i.e., the level of partial capture).\267\ The EIA also updated LCOE 
projections from AEO 2013 to AEO 2014 and again in AEO 2015. Those are 
discussed in more detail in Section V.I.2.b and d. In evaluating costs 
for the final standards in this action, the EPA relied primarily on the 
updated NETL LCOE projections for new fossil fuel-fired EGUs provided 
in the reports described above and on the LCOE projections for non-
fossil, dispatchable generating options from the EIA's AEO 2015.\268\ 
Here, the EPA compared the LCOE of the final standard to the LCOE of 
analogous potential sources of intermediate and base load power. This 
comparison demonstrated that the LCOE for a fossil steam unit with 
partial CCS is within the range of the LCOE of comparable alternative 
non-NGCC generation sources. In particular, nuclear and biomass 
generation, which similarly provide both base load power and fuel 
diversity, have comparable LCOE. The EPA concludes that an evaluation 
of the LCOE also demonstrates that the costs of the final standard are 
reasonable.
---------------------------------------------------------------------------

    \267\ ``Cost and Performance Baseline for Fossil Energy Plants 
Supplement: Sensitivity to CO2 Capture Rate in Coal-Fired 
Power Plants'', DOE/NETL-2015/1720 (June 2015). Available at http://www.netl.doe.gov/research/energy-analysis/energy-baseline-studies.
    \268\ http://www.eia.gov/forecasts/aeo/electricity_generation.cfm.
---------------------------------------------------------------------------

a. Calculation of the LCOE
    The LCOE of a power plant source is calculated with the expected 
lifetime and average capacity factor, and represents the average cost 
of producing a megawatt-hour (MWh) of electricity over the expected 
lifetime of the asset.
    The LCOE incorporates all specified costs, and therefore is 
dependent on the project's capital costs, the fixed and variable 
operating and maintenance (O&M) costs, the fuel costs, the costs to 
finance the project, and finally on the assumed capacity factor.\269\ 
The relative contribution of each of these inputs to LCOE will vary 
among the generating technologies. For example, the LCOE for a new 
supercritical PC plant or a new IGCC plant is influenced more by the 
capital costs (and thus the financing assumptions) and less on fuel 
costs than a comparably sized new NGCC facility which would require 
less capital investment but would be more influenced by assumed fuel 
costs.
---------------------------------------------------------------------------

    \269\ See, e.g. ``Cost and Performance Baseline for Fossil 
Energy Plants Supplement: Sensitivity to CO2 Capture Rate 
in Coal-Fired Power Plants'', DOE/NETL-2015/1720 (June 2015) at p. 
17.
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b. Use of the LCOE
    The utility industry and electricity sector regulators often use 
levelized costs as a summary measure for comparing the cost of 
different potential generating sources. Use of the LCOE as a comparison 
measure is appropriate where the facilities being compared would serve 
load in a similar manner.
    The value of generation, as reflected in the wholesale electricity 
price, can vary seasonally and over the course of a day. In addition, 
electricity generation technologies differ on dimensions other than 
just cost, such as ramping efficiency, intermittency, or uncertainty in 
future fuel costs. These other factors are also important in 
determining the value of a particular generation technology to a firm, 
and accordingly cost comparisons between two different technologies are 
most appropriate and insightful when the technologies align along these 
other dimensions. Isolating a comparison of technologies based on their 
LCOE is appropriate when they can be assumed to provide similar 
services and similar values of electricity generated.
    As we indicated in the proposal, we evaluated publicly available 
IRPs and other available information (such as public announcements) to 
determine the types of technologies that utilities are considering as 
options for new generating capacity.\270\ In the near future, the 
largest sources of new fossil fuel-fired power generation are expected 
to be new NGCC units. But the IRPs also suggested that utilities are 
interested in a range of technologies that can be used to provide or 
preserve fuel diversity within the utilities' respective generating 
fleets.271 272 The options for

[[Page 64562]]

dispatchable generation that can provide intermediate or base-load 
power and fuel diversity would include new fossil steam units, new 
nuclear power, and biomass-fired generation.
---------------------------------------------------------------------------

    \270\ See also discussion at V.C.3 above. The IRPs do not 
provide an indication of the utility's intention to pursue a 
particular generation technology. However, the IRPs do provide an 
indication of the types of new generating technologies that the 
utility would consider for new generating capacity.
    \271\ See, e.g. the 2014 IRP of Dominion Virginia Power:
    With those factors in mind, the 2014 Plan presents two paths 
forward for resource expansion: a Base Plan, designed using least-
cost planning methods and consistent with the requirements of Rule 
R8-60 for utility plans to provide ``reliable electric utility 
service at least cost over the planning period;'' and a Fuel 
Diversity Plan, which includes a broader array of low or zero-
emissions options. While the Fuel 2 Diversity Plan currently 
represents a higher cost option at today's current and projected 
commodity prices, its resource mix provides the important benefits 
of greater fuel diversity and lower carbon intensity. Therefore, the 
Company will continue reasonable development of the more diverse and 
lower carbon intensive options in the Fuel Diversity Plan and will 
be ready to implement them as conditions warrant. . . . The Fuel 
Diversity Plan places a greater reliance on generation sources with 
little or no carbon emissions and is less reliant on natural gas. 
While following the resource expansion scenario in the least-cost 
Base Plan, the Company will continue evaluation and reasonable 
development efforts for the following projects identified in the 
Fuel Diversity Plan. These include:
    Continued development of a third nuclear reactor at North Anna 
Power Station, using reactor technology supplied by GE-Hitachi 
Nuclear Energy Americas LLC. While the Company has made no final 
commitment to building this unit, it recognizes the many operational 
and environmental benefits of nuclear power and continues to 
actively develop the project. Our customers have benefitted from the 
existing nuclear fleet for many years now, and they will continue to 
benefit from the existing fleet for many years in the future. A 
final decision on construction of North Anna Unit 3 will not be made 
until after the Company receives a Combined Operating License or COL 
from the U.S. Nuclear Regulatory Commission, now expected in 2016. 
The Fuel Diversity Plan includes the addition of North Anna Unit 3's 
1,453 megawatts of zero-emissions generation by 2028. If 
constructed, the project would provide a dramatic boost to the 
regional economy.
    Additional reliance on renewable energy, including 247 megawatts 
of onshore wind capacity at sites in western Virginia and a 12 
megawatt offshore wind demonstration project by 2018.
    An additional 559 megawatts of nameplate solar capacity, 
including several new Company-owned photovoltaic CPV) installations. 
Solar PV costs have declined significantly in recent years, making 
utility-scale solar much more cost-effective than distributed solar, 
and continuing technological development, in which the Company is 
participating, may allow it to become a more cost-effective source 
of intermittent generation in the future.cover letter for 2014 IRP--
https://www.dom.com/library/domcom/pdfs/corporate/integrated-resource-planning/va-irp-2014.pdf.
    \272\ Another example are the recent statements of officials of 
Tri-State Generation and Transmission, available at http://www.wyofile.com/coal-power/, including:
    ``We are considering nuclear, coal and natural gas,'' said Ken 
Anderson, general manager of Tri-State at a conference in October 
[2010], a position that Tri-State representatives say remains. ``We 
will pick our technology once policy certainty comes about,'' he 
added. . . . Longer-term forecasts are based on assumptions that may 
or may not prove well-founded. Because of this uncertainty, Tri-
State believes it must retain options for all fuels and 
technologies.
    ``We will not take anything off the table,'' [Tri-State 
spokesman Lee] Boughey said. That includes coal. ``Coal is an 
affordable and plentiful resource, but it does come with 
challenges--and we are looking to different technology that can 
address some of those challenges while continuing to provide a 
reliable and affordable power supply,'' Boughey said. ``Some critics 
believe we shouldn't be looking at resource options that include 
coal, and even nuclear technology,'' Boughey added. ``We believe it 
would be irresponsible not to consider these fuels or technologies 
as part of an affordable, reliable and responsible resource 
portfolio.''
---------------------------------------------------------------------------

    Thus, in both the proposal and in this final rule, the EPA is 
comparing the LCOE of technologies that would be reasonably anticipated 
to be designed, constructed, and operated for a similar purpose--that 
is, to provide dispatchable base load power that provides fuel 
diversity by relying on a fuel source other than natural gas. In 
contrast, it may not be appropriate to compare the LCOE for a base load 
coal-fired plant with that of a peaking natural gas-fired simple cycle 
turbine. Similarly, it may not be appropriate to compare LCOE for 
dispatchable technologies (i.e., generating sources that can be ramped 
up or down as needed, e.g., coal-fired units, NGCC units, nuclear) with 
that of non-dispatchable technologies (i.e., generating sources that 
cannot be reliably ramped up or down to meet demand, e.g., wind, 
solar.)
c. Reasonableness of Costs Based on LCOE
    An examination of the LCOE of analogous sources of base load, 
dispatchable power shows that the final standard's LCOE is comparable 
to that of other sources, as shown in Table 8 below. As mentioned 
earlier and discussed in further detail below, these estimates rely 
most heavily on DOE/NETL cost projections for fossil fuel generating 
technologies and on the updated EIA AEO 2015 for non-fossil generation 
technologies. Recent estimates from Lazard 273 274 are also 
provided for nuclear and biomass generation options.
---------------------------------------------------------------------------

    \273\ Lazard's Levelized Cost of Energy Analysis--Version 8.0; 
September 2014; available at: http://www.lazard.com/media/1777/levelized_cost_of_energy_-_version_80.pdf and in the rulemaking 
docket.
    \274\ Lazard is one of the world's preeminent financial advisory 
and asset management firms. Lazard's Global Power, Energy & 
Infrastructure Group serves private and public sector clients with 
advisory services regarding M&A, financing, and other strategic 
matters. The group is active in all areas of the traditional and 
alternative energy industries, including regulated utilities, 
independent power producers, advanced transportation technologies, 
renewable energy technologies, meters, smart grid and energy 
efficiency technologies, and infrastructure. http://www.marketwatch.com/story/lazard-releases-new-levelized-cost-of-energy-analysis-2014-09-18.
    \275\ LCOE cost estimates for SCPC and IGCC cases come from 
``Cost and Performance Baseline for Fossil Energy Plants Supplement: 
Sensitivity to CO2 Capture Rate in Coal-Fired Power 
Plants'' DOE/NETL-2015/1720 (June 22, 2015). Cost and performance 
for low rank SCPC is adapted from ``Cost and Performance Baseline 
for Fossil Energy Plants Volume 3 Executive Summary: Low Rank Coal 
and Natural Gas to Electricity'', DOE/NETL-2010/1399 (September 
2011). LCOE cost estimates for nuclear and biomass are derived from 
``Levelized Cost and Levelized Avoided Cost of New Generation 
Resources in the Annual Energy Outlook 2015'', June 2015, 
www.eia.gov/forecasts/aeo/pdf/electricity_generation.pdf. LCOE cost 
estimates for NGCC technology are EPA estimates based on a range of 
potential natural gas prices.
    \276\ Table 8 includes LCOE figures for biomass-fired 
generation, a potential sources of dispatchable base load power that 
is not fueled by natural gas. The EPA includes this information for 
completeness, while noting that biomass-fired units in operation in 
the U.S. are smaller scale and thus are not as robust analogues as 
nuclear power. CO2 emissions are not provided for biomass 
units because different biomass feedstocks have different net 
CO2 emissions; therefore a single emission rate is not 
appropriate to show in Table 8.
    \277\ ``Cost and Performance Baseline for Fossil Energy Plants 
Supplement: Sensitivity to CO2 Capture Rate in Coal-Fired 
Power Plants'', DOE/NETL-2015/1720 (June 2015) at p. 18.

Table 8--Predicted Cost and CO2 Emission Levels for a Range of Potential
                    New Generation Technologies \275\
------------------------------------------------------------------------
                                     Emission lb CO2/
     New generation technology            MWh-g           LCOE* $/MWh
------------------------------------------------------------------------
SCPC--no CCS (bit)................              1,620              76-95
SCPC--no CCS (low rank)...........              1,740              75-94
SCPC + ~16% partial CCS (bit).....              1,400             92-117
SCPC + ~23% partial CCS (low rank)              1,400             95-121
Nuclear (EIA).....................                  0             87-115
Nuclear (Lazard)..................                  0             92-132
Biomass (EIA) \276\...............                 --             94-113
Biomass (Lazard)..................                 --             87-116
IGCC..............................              1,430             94-120
NGCC..............................              1,000           ** 52-86
------------------------------------------------------------------------
* The LCOE ranges presented in Table 8 include an uncertainty of -15%/
  +30% on capital costs for SCPC and IGCC cases and an uncertainty of -
  10%/+30% on capital costs for nuclear and biomass cases from EIA. This
  reflects information provided by EIA. Nuclear staff experts expect
  that nuclear plants currently under construction would not have
  capital costs under estimates and that one could expect to see a 30%
  ``upside'' variation in capital cost. There is also insufficient
  market data to get a good statistical range of potential capital cost
  variation (i.e. only 2 plants under construction, neither complete).
  The nuclear cost estimates from Lazard likewise reflect the range of
  expected nuclear costs. LCOE estimates displayed in this table for
  SCPC units with partial CCS as well as for IGCC units use a higher
  financing cost rate in comparison to the SCPC unit without
  capture.\277\
** This range represents a natural gas price from $5/MMBtu to $10/MMBtu.

    As shown in Table 8, we project that the LCOE for new fossil steam 
capacity meeting the final 1,400 lb CO2/MWh-g standard to be 
substantially similar to that for a new nuclear unit, the principal 
other alternative to natural gas to provide new base load power. This 
is the case for new units firing bituminous and subbituminous coals and 
dried lignite. This is another demonstration that the costs of the 
final standard are reasonable because nuclear and fossil steam 
generation each would serve an analogous role in adding dispatchable 
base load generation diversity--or at least non-NGCC alternatives--to a 
power provider's portfolio; hence, they are reasonably viewed as 
comparable alternatives.\278\
---------------------------------------------------------------------------

    \278\ LCOE comparisons of reasonably available compliance 
alternatives--IGCC with natural gas co-firing, and SCPC with natural 
gas co-firing--are found below in Table 9. As shown there, these 
alternatives are either lower cost than SCPC with partial CCS, or of 
comparable cost.
---------------------------------------------------------------------------

    As previously mentioned, the DOE/NETL assumed conventional 
financing

[[Page 64563]]

for cases without CCS and assumed high-risk financing for cases with 
some level of CCS. Specifically a high-risk financial structure 
resulting in a capital charge factor (CCF) of 0.124 is used in the 
study to evaluate the costs of all cases with CO2 capture 
(non-capture case uses a conventional financial structure with a CCF of 
0.116).\279\ As a comparison of how this affects the resulting DOE/NETL 
costs, a new SCPC utilizing 16 percent partial CCS is projected to have 
an LCOE of $99/MWh (including transportation and storage costs; does 
not include the range for uncertainty). That projected LCOE includes 
the ``high risk financial assumptions''. If the LCOE for that unit were 
to be calculated using the ``conventional financing assumptions'', the 
resulting LCOE would be $94/MWh.
---------------------------------------------------------------------------

    \279\ ``Cost and Performance Baseline for Fossil Energy Plants 
Supplement: Sensitivity to CO2 Capture Rate in Coal-Fired 
Power Plants'', DOE/NETL-2015/1720 (June 2015) at p. 7.
---------------------------------------------------------------------------

    This approach is in contrast to that taken by the EIA which applies 
a 3-percentage-point cost of capital premium (the `climate uncertainty 
adder') to non-capture coal plants to reflect the market reaction to 
potential future GHG regulation.
    Under current and anticipated market conditions, power providers 
that are considering costs alone in choosing a fuel source for new 
intermediate or base load generation will choose natural gas because of 
its competitive current and projected price. However, as noted in 
Section V.H.3, public IRPs indicate that utilities are considering and 
selecting technologies that could provide or preserve fuel diversity 
within generating fleets. For example, utilities have been willing to 
pay a premium for nuclear power in certain circumstances, as indicated 
by the recent new constructions of nuclear facilities and by IRPs that 
include new nuclear generation in their plans. In general, fossil steam 
and nuclear generation each can provide dispatchable, base load power 
while also maintaining or increasing fuel diversity.\280\ Utilities may 
be willing to pay a premium for these generation sources because they 
could serve as a hedge against the possibility that future natural gas 
prices will far exceed projected levels. Accordingly, the LCOE analysis 
demonstrates that the final standard's costs are in line with power 
sources that provide analogous services--dispatchable base load power 
and fuel diversity.
---------------------------------------------------------------------------

    \280\ As another example, San Antonio customers will benefit 
from low-carbon power from the Texas Clean Energy Project. CPS 
Energy CEO Doyle Deneby said in a news release: ``Adding clean coal 
to our portfolio dovetails with our strategy to diversify and reduce 
the carbon intensity of the power we supply to our customers.'' 
www.bizjournals.com/sanantonio/news/2014/10/06/cps-energy-strikes-new-deal-to-buy-power-from.html.
---------------------------------------------------------------------------

    We further note a number of conservative elements of the costs we 
used in making this comparison. In particular, these estimates include 
the highest value in the projected range of potential costs for partial 
CCS. They do not reflect revenues which can be generated by selling 
captured CO2 for enhanced oil recovery, and reflect the 
costs of partial CCS rather than potentially less expensive alternative 
compliance paths such as a utility boiler co-firing with natural gas. 
See also V.H.7 and 8 below.
6. Overall Costs and Economic Impacts
    As noted above, an assessment of national costs is also an 
appropriate means of evaluating the reasonableness of costs under CAA 
section 111. See Sierra Club, 657 F.2d at 330.
    The EPA considered the regulation's overall costs and economic 
impacts as part of its RIA. The RIA demonstrates that these costs would 
be negligible and that the effects on electricity rates and other 
market indicators would similarly be minimal.
    These results are driven by the existing market context for fossil-
steam generation. Even in the absence of the standards of performance 
for newly constructed EGUs, substantial new construction of 
uncontrolled fossil steam units is not anticipated under existing 
prevailing and anticipated future economic conditions. Modeling 
projections from government, industry, and academia anticipate that few 
new fossil steam EGUs will be constructed over the coming decade and 
that those that are built would have CCS.\281\ Instead, EIA data shows 
that natural gas is likely to be the most widely-used fossil fuel for 
new construction of electric generating capacity in the near 
future.\282\ Of the coal-fired units moving forward at various advanced 
stages of construction and development--Southern Company's Kemper 
County Energy Facility and Summit Power's Texas Clean Energy Project 
(TCEP)--each will deploy IGCC with some level of CCS. The primary 
reasons for this rate of current and projected future development of 
new coal projects include highly competitive natural gas prices, lower 
electricity demand, and increases in the supply of renewable energy.
---------------------------------------------------------------------------

    \281\ RIA chapter 4. For example, even in the EIA's sensitivity 
analysis that assumes higher natural gas prices and electricity 
demand, the EIA does not project any additional coal beyond its 
reference case until 2023, in a case where power companies assume no 
GHGs emission limitations, and until 2024 in a case where power 
companies do assume GHGs emission limitations. AEO 2015.
    \282\ Annual Energy Outlook 2010, 2011, 2012, 2013, 2014 and 
2015.
---------------------------------------------------------------------------

    In its RIA, the EPA considered the overall costs of this regulation 
in the context of these prevailing market trends. Because of the 
expectation of no new fossil steam generation, the RIA projects that 
this final rule will result in negligible costs overall on owners and 
operators of newly constructed EGUs by 2022.\283\ More broadly, this 
regulation is not expected to have significant effects on fuel markets, 
electricity prices, or the economy as a whole, as described in detail 
in Chapter 4 of the RIA.
---------------------------------------------------------------------------

    \283\ Conditions in the analysis year of 2022 are represented by 
a model year of 2020.
---------------------------------------------------------------------------

    In comparison, courts have upheld past regulations that imposed 
substantial overall costs in order to protect against uncontrolled 
emissions. As noted above, in Sierra Club v. Costle, the D.C. Circuit 
upheld a standard of performance that imposed costly controls on 
SO2 emissions from new coal-fired power plants. 657 F.2d at 
410. These standards had implications for the economy ``at the local 
and national levels,'' as ``EPA estimates that utilities will have to 
spend tens of billions of dollars by 1995 on pollution control under 
the new NSPS.'' Id. at 314. Further, the court acknowledged that 
``[c]onsumers will ultimately bear these costs, both directly in the 
form of residential utility bills, and indirectly in the form of higher 
consumer prices due to increased energy costs,'' before concluding that 
the costs were reasonable. Id.
    The projected total incremental capital costs associated with the 
standard we are finalizing in this rule are dramatically lower than was 
the case for this prior standard, as well as other prior standards 
summarized previously. For example, when the standard at issue in 
Sierra Club was upheld, the industry was expected to build, and did 
build, dozens of plants ultimately meeting the standards--at a 
projected incremental cost of tens of billions of dollars.\284\ Here, 
by contrast, few if any fossil steam EGUs are projected to be built in 
the foreseeable future, indicating that the total incremental costs are 
likely to be considerably more modest.
---------------------------------------------------------------------------

    \284\ Sierra Club, 657 F.2d at 314.
---------------------------------------------------------------------------

    Commenters stated that the cost provision in CAA section 111(a)(1) 
does not authorize the EPA to consider the nationwide costs of a system 
of emission reduction in lieu of considering the cost impacts for 
individual new plants. In this rule, we

[[Page 64564]]

are considering both sets of costs and, in fact, we are not identifying 
full CCS as the BSER primarily for reasons of its cost to individual 
sources. At the same time, total projected costs are relevant in 
assessing the overall reasonableness of costs associated with a 
standard. Our analysis demonstrates that the impacts on the industry as 
a whole are negligible, and are certainly not greater than ``what the 
industry could bear and survive.'' \285\ These facts support the EPA's 
overall conclusion that the costs of the standard are reasonable.
---------------------------------------------------------------------------

    \285\ Portland Cement Ass'n, 513 F.2d at 508.
---------------------------------------------------------------------------

    However, as noted earlier, for a variety of reasons, some companies 
may consider coal-fired steam generating units that the modeling does 
not anticipate. Thus, in Chapter 5 of the RIA, we also present an 
analysis of the project-level costs of a newly constructed coal-fired 
steam generating unit with partial CCS that meets the requirements of 
this final rule alongside the project-level costs of a newly 
constructed coal-fired unit without CCS. This analysis in RIA chapter 5 
indicates that the quantified benefits of the standards of performance 
would exceed their costs under a range of assumptions.
    As required under Executive Order 12866, the EPA conducts benefit-
cost analyses for major Clean Air Act rules, and has done so here. 
While such 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 doing so here.\286\ Nonetheless, as 
just noted, the RIA analysis shows that the standard of performance has 
net quantified benefits under a range of assumptions.
---------------------------------------------------------------------------

    \286\ See Memorandum ``Consideration of Costs and Benefits under 
the Clean Air Act'' available in the rulemaking dockets, EPA-HQ-OAR-
2013-0495 (new sources) and EPA-OAR-HQ-2013-0603 (modified and 
reconstructed sources).
---------------------------------------------------------------------------

7. Opportunities to Further Reduce Compliance Costs
    While the EPA believes, as detailed above, that there is sufficient 
evidence to show that the final standards of performance for new steam 
generating units can be met at a reasonable cost, we also note that 
there are potential opportunities to further reduce compliance costs. 
We believe that, in most cases, the actual costs will be less than 
those presented earlier.
    As explained in more detail in the following subsection, a new 
utility boiler can meet the final standard of performance by co-firing 
with natural gas. Some project developers may choose to utilize natural 
gas co-firing as a means of delaying, rather than avoiding, 
implementation of partial CCS. Developers can also choose to install 
IGCC with a small amount of natural gas co-firing at costs within the 
range of SCPC with partial CCS, although slightly higher.
    The EPA also notes that new units that capture CO2 will 
likely be built in areas where there are opportunities to sell the 
captured CO2 for some useful purpose prior to (or 
concomitant with) permanent storage. The DOE refers to this as ``carbon 
capture, utilization and storage'' or CCUS. In particular, the ability 
to sell captured CO2 for use in enhanced oil recovery 
operations offers the most opportunity to reduce costs. In this regard, 
the newly-operating Boundary Dam facility is selling captured 
CO2 for EOR. The Kemper facility likewise plans to do 
so.\287\
---------------------------------------------------------------------------

    \287\ The EPA is referring to the Kemper facility here as an 
example of how costs can be defrayed, not for use of technology or 
level of emission reduction achieved. The EPA therefore does not 
believe that the EPAct05 prevents reference to the fact that Kemper 
plans to sell captured carbon.
---------------------------------------------------------------------------

    In some instances, the costs of CCS may be defrayed by grants or 
other benefits provided by federal or state governments. The need for 
subsidies to support emerging energy systems and new control 
technologies is not unusual. Each of the major types of energy used to 
generate electricity has been or is currently being supported by some 
type of government subsidy such as tax benefits, loan guarantees, low-
cost leases, or direct expenditures for some aspect of development and 
utilization, ranging from exploration to control installation. This is 
true for fossil fuel-fired, as well as nuclear-, geothermal-, wind-, 
and solar-generated electricity. As stated earlier, the EPA considers 
the costs of partial CCS at a level to meet the final standard of 
performance to be reasonable even without considering these 
opportunities to further reduce implementation and compliance costs. We 
did not in the proposal--and we do not here in this final action--rely 
on any cost reduction opportunities to justify the costs of meeting the 
standard as reasonable, but again note the conservative assumptions 
embodied in our assessment of compliance costs.
a. Cost and Feasibility of Natural Gas Co-firing as an Alternative 
Compliance Pathway
    Although the EPA has determined that implementation of partial CCS 
at an emission limitation of 1,400 lb CO2/MWh-g is the BSER 
for newly constructed fossil fuel-fired steam generating EGUs, we also 
note that operators can consider the use of natural gas co-firing to 
achieve the final emission limitation, likely at a lower cost.
    At the final emissions limitation of 1,400 lb CO2/MWh-g 
a new supercritical PC or supercritical CFB can meet the standard by 
co-firing with natural gas at levels up to approximately 40 percent 
(heat input basis) and could potentially avoid (or delay) installation 
and use of partial CCS altogether.
    Natural gas co-firing has long been recognized as an option for 
coal-fired boilers to reduce emissions of criteria and hazardous air 
pollutants. EPRI sponsored a study to assess both technical and 
economic issues associated with natural gas co-firing in coal-fired 
boilers.\288\ They determined that the largest number of applications 
and the longest experience time is with natural gas reburning and with 
supplemental gas firing. Natural gas reburning has been used primarily 
as a NOX control technology. It is implemented by 
introducing natural gas (up to 20 percent total fuel heat input) in a 
secondary combustion zone (called the ``reburn zone'') downstream of 
the primary combustion zone in the boiler. Injecting the natural gas 
creates a fuel-rich zone where NOX formed in the main 
combustion zone is reduced to nitrogen and water vapor.
---------------------------------------------------------------------------

    \288\ Gas Cofiring Assessment for Coal Fired Utility Boilers; 
Final Report, August 2000; EPRI Technical Report available at 
www.epri.com.
---------------------------------------------------------------------------

    Higher levels of natural gas co-firing can be met by utilizing 
supplemental gas co-firing (either alone or along with natural gas 
reburning). This involves the simultaneous firing of natural gas and 
pulverized coal in a boiler's primary combustion zone. Others have also 
evaluated configurations that would allow coal-fired units to utilize 
natural gas.289 290
---------------------------------------------------------------------------

    \289\ Many of the studies evaluated opportunities to use natural 
gas reburn, natural gas co-firing and other configurations in 
existing coal-fired boilers. Those conclusions would also be 
applicable for new coal-fired boilers.
    \290\ ``Dual Fuel Firing--The New Future for the Aging U.S. 
Based Coal-Fired Boilers'', presented by Riley Power, Inc. at 37th 
International Technical Conference on Clean Coal and Fuel Systems 
June 2012 Clearwater, FL, available at http://www.babcockpower.com/pdf/RPI-TP-0228.pdf.

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[[Page 64565]]

    A 2013 article entitled ``Utility Options for Leveraging Natural 
Gas'' \291\ noted that:
---------------------------------------------------------------------------

    \291\ Utility Options for Leveraging Natural Gas, 10/01/2013 
article in Power. Available at http://www.powermag.com/utility-options-for-leveraging-natural-gas/.

    Utility owners of coal-fired power stations that wish to balance 
their exposure to coal-fired generation with additional natural gas-
fired generation have several options to consider. The four most 
practical options are co-firing coal and gas in the same boiler, 
converting the coal-fired boiler to gas-only operation, repowering 
the coal plant with natural gas-fired combustion turbines, or 
replacing the coal plant with a combined cycle plant. [. . .] Co-
---------------------------------------------------------------------------
firing is the lowest-risk option for substituting gas use for coal.

    The EPA examined compliance costs for a new steam generating unit 
to meet the final standard of performance using natural gas co-firing 
and compared those costs to the estimated costs of meeting the final 
standards using partial CCS. Those costs are provided below in Table 9.
---------------------------------------------------------------------------

    \292\ Costs and emissions for cases that do not utilize natural 
gas co-firing are from ``Cost and Performance Baseline for Fossil 
Energy Plants Supplement: Sensitivity to CO2 Capture Rate 
in Coal-Fired Power Plants'', DOE/NETL-2015/1720 (June 2015). Costs 
and emissions for natural gas co-fired cases are EPA estimates.

Table 9--Predicted Costs to Meet the Final Standard Using Natural Gas Co-
                              firing \292\
------------------------------------------------------------------------
                                                 Emission lb    LCOE $/
          New generation technology               CO2/MWh-g       MWh
------------------------------------------------------------------------
SCPC--no CCS.................................           1,620         82
SCPC + ~16% partial CCS......................           1,400         99
SCPC + ~34% NG co-fire.......................           1,400         92
IGCC--no CCS.................................           1,434        103
IGCC + ~6% NG co-fire........................           1,400        105
NGCC*........................................           1,000         60
------------------------------------------------------------------------
* The generation cost using NG co-fire and NGCC assume a natural gas
  price of $6.19/mmBtu.

    The EPA thus again notes that the cost assumptions it is making in 
its BSER determination are conservative. That is, by costing partial 
CCS as BSER, the EPA may be overestimating actual compliance costs 
since there exist other less expensive means of meeting the promulgated 
standard.\293\
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    \293\ Certain commenters argued that the proposed standard 
essentially mandated a sole method of compliance, and hence 
constituted a work practice for purposes of section 111(h) of the 
Act. These commenters argued further that the EPA had failed to 
justify the proposal under the section 111(h) criteria. The EPA 
disagrees with the premise of these comments, but, in any case, 
there are clearly multiple compliance paths available for achieving 
the final standard.
---------------------------------------------------------------------------

    Notwithstanding that costs for a SCPC to meet the standard would be 
lower if it co-fired with natural gas, we have not identified that 
compliance alternative as BSER because we believe that new coal-fired 
steam electric generating capacity would be built to provide fuel 
diversity, and burning substantial amounts of natural gas would be 
contrary to that objective. In addition, this choice would not promote 
use of advanced pollution control technology. New IGCC has costs which 
are comparable to SCPC, as does IGCC with natural gas co-firing,\294\ 
but we are choosing not to identify it as BSER for reasons stated at 
Sections V.C.2 and V.P: use of IGCC does not advance emission control 
beyond current levels of performance for sources which may choose to 
utilize IGCC technology. Nonetheless, use of IGCC remains a viable, 
demonstrated compliance option to meet the 1,400 lb CO2/MWh-
g standard of performance, and is available at reasonable cost and (as 
shown at Section V.P below) without significant adverse non-air quality 
impacts or energy implications.
---------------------------------------------------------------------------

    \294\ IGCC units already have combined cycle capacity, and so 
can be readily operated in whole or in part using natural gas as a 
fuel. Indeed, both the Edwardsport and Kemper IGCC facilities have 
operated at times by firing exclusively natural gas.
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Costs are Reasonably Expected To Decrease Over Time
    The EPA reasonably expects that the costs of CCS will decrease over 
time as the technology becomes more widely deployed. Although, for the 
reasons that have been noted, we consider the current costs of CCS to 
be reasonable, the projected decrease in those costs further supports 
their reasonableness. The D.C. Circuit case law that authorizes 
determining the ``best'' available technology on the basis of 
reasonable future projections supports taking into account projected 
cost reductions as a way to support the reasonableness of the costs.
    We expect the costs of CCS technologies to decrease for several 
reasons. We expect that significant additional knowledge will be gained 
from deployment and operation of the new coal-fired generation 
facilities that are either operating or are nearing completion. These 
would include the Boundary Dam Unit #3 facility, the Petra Nova WA 
Parish project, and the Kemper County IGCC facility. The operators of 
the Boundary Dam Unit #3 are considering construction of additional CCS 
units and have projected that the next units could be constructed at a 
cost of at least 30 percent less than that at Unit #3.\295\ These 
savings primarily come from application of lessons learned from the 
Unit #3 design and construction.
---------------------------------------------------------------------------

    \295\ ``Boundary Dam--The Future is Here'', plenary presentation 
by Mike Monea at the 12th International Conference on Greenhouse Gas 
Technologies (GHGT-12), Austin, TX (October 2014).
---------------------------------------------------------------------------

    To facilitate the transfer of the technology and to accelerate 
development of carbon capture technology, SaskPower has created the CCS 
Global Consortium.\296\ This consortium provides SaskPower the 
opportunity to share the knowledge and experience from the Boundary Dam 
Unit #3 facility with global energy leaders, technology developers, and 
project developers. SaskPower, in partnership with Mitsubishi and 
Hitachi, is also helping to advance CCS knowledge and technology 
development through the creation of the Shand Carbon Capture Test 
Facility (CCTF).\297\ The test facility will provide technology 
developers with an opportunity to test new and emerging carbon capture 
systems for controlling carbon emissions from coal-fired power plants.
---------------------------------------------------------------------------

    \296\ http://www.saskpowerccs.com/consortium/.
    \297\ www.saskpowerccs.com/ccs-projects/shand-carbon-capture-test-facility/.
---------------------------------------------------------------------------

    The DOE also sponsors testing at the National Carbon Capture Center 
(NCCC). The NCCC--located at Southern Company's Plant Gaston in 
Wilsonville, AL--provides first-class facilities to test new capture 
technologies for extended periods under commercially representative 
conditions with coal-derived flue gas and syngas.\298\
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    \298\ www.nationalcarboncapturecenter.com/index.html.

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[[Page 64566]]

    We expect continued additional cost reductions to come from 
knowledge gained from continued operation of non-power sector 
industrial projects which, as we have discussed, are informative in 
transferring the technology to power sector applications. We expect the 
on-going research and development efforts--such as those sponsored by 
the DOE/NETL.
    Significant reductions in the cost of CO2 capture would 
be consistent with overall experience with the cost of pollution 
control technology. Reductions in the cost of air pollution control 
technologies as a result of learning-by-doing, reductions in financial 
premiums related to risk, research and development investments, and 
other factors have been observed over the decades.
c. Opportunities To Reduce Cost Through Sales of Captured 
CO2
    Geologic storage options include use of CO2 in EOR 
operations, which is the injection of fluids into a reservoir after 
production yields have decreased from primary production in order to 
increase oil production efficiency. CO2-EOR has been 
successfully used for decades at many production fields throughout the 
U.S. to increase oil recovery. The use of CO2 for EOR can 
significantly lower the net cost of implementing CCS. The opportunity 
to sell the captured CO2 for EOR, rather than paying 
directly for its long-term storage, improves the overall economics of 
the new generating unit. According to the International Energy Agency 
(IEA), of the CCS projects under construction or at an advanced stage 
of planning, 70 percent intend to use captured CO2 to 
improve recovery of oil in mature fields.\299\ See also Section V.M.3 
below.
---------------------------------------------------------------------------

    \299\ Tracking Clean Energy Progress 2013, International Energy 
Agency (IEA), Input to the Clean Energy Ministerial, OECD/IEA 2013.
---------------------------------------------------------------------------

I. Key Comments Regarding the EPA's Consideration of Costs

    In its consideration of the costs associated with the final 
standard, the EPA considered a range of different cost metrics, each 
with its individual strengths and weaknesses. As discussed above, each 
metric supports the EPA's conclusion that the costs of the final 
standard are reasonable.
    In this section, we review the comments received on assessing cost 
reasonableness and specific cost metrics. We explain how these comments 
informed our consideration of different metrics and cost reasonableness 
in general.
1. Use of LCOE as a Cost Metric
    As noted, CAA section 111(a) directs the EPA to consider ``cost'' 
in determining if the BSER is adequately demonstrated. It does not 
provide further guidance as to how costs are to be considered, thus 
affording the EPA considerable discretion to choose a reasonable means 
of cost consideration. See, e.g. Lignite Energy Council v. EPA, 198 F. 
3d at 933. Certain commenters nonetheless argued that LCOE was an 
impermissible metric because it does not measure the cost of achieving 
the emission reduction, but rather measures the impact on the product 
produced by the entity subject to the standard.\300\ The EPA does not 
agree that its authority is so limited. Indeed, in the first decided 
case under section 111, the D.C. Circuit, in holding that the EPA's 
consideration of costs was reasonable, specifically noted the EPA's 
examination of the impact of the standards on the regulated source 
category's product in comparison to competitive products. Portland 
Cement Ass'n v. EPA, 486 F. 2d at 388 (``costs of control equipment 
could be passed on without substantially affecting competition with 
construction substitutes such as steel, asphalt, and aluminum'').
---------------------------------------------------------------------------

    \300\ Comments of EEI, pp 94-5 (Docket entry: EPA-HQ-OAR-2013-
0495-9780).
---------------------------------------------------------------------------

    Commenters also argued that the choice of LCOE as a cost metric 
masked consideration of the considerable capital costs associated with 
CCS. The EPA disagrees with this contention. The LCOE does not mask 
consideration of capital costs. Rather, as explained at V.H.5 above, 
LCOE is a summary metric that expresses the full cost (e.g., capital, 
O&M, fuel) of generating electricity and therefore provides a useful 
summary metric of costs per unit of production (i.e., megawatt-hours). 
Provided that those megawatt-hours provide similar electricity services 
and align on dimensions other than just cost, then the LCOE provides a 
useful comparison of which technologies are least cost.
    The EPA certainly does not minimize that project developers must 
take capital costs into consideration, and as discussed in Section 
V.H.4 above, the EPA accordingly has considered direct capital costs 
here as part of its assessment and found those costs to be reasonable. 
In addition, the EPA notes that its comparison of the marginal impacts 
from an individual illustrative facility's compliance with the 
standard, discussed in detail above and in the RIA Chapter 5, took into 
account the marginal capital costs that would be incurred by an 
individual facility.
    According to EIA,\301\ capital costs represent approximately 63 
percent of the LCOE for a new coal-fired SCPC plant; approximately 66 
percent of the LCOE for a new IGCC plant; approximately 74 percent of 
the LCOE for a new nuclear plant; and only about 22 percent of the LCOE 
for a new NGCC unit. The LCOE of a new NGCC unit is much more strongly 
affected by fuel costs (natural gas). As we have discussed in detail in 
this preamble, in the preamble for the January 2014 proposal, and in 
associated technical support documents, the power sector has moved 
toward increased use of natural gas for a variety of reasons. If 
capital was the only cost that utilities and project developers 
considered, then they would almost certainly always choose to build a 
new NGCC unit. However, a variety of factors can be involved in 
selecting a generation source beyond capital costs. Accordingly, in 
considering cost reasonableness the EPA considered metrics that 
encompassed other costs as well as the value of fuel and fleet 
diversity.
---------------------------------------------------------------------------

    \301\ http://www.eia.gov/forecasts/aeo/electricity_generation.cfm.
---------------------------------------------------------------------------

    Some commenters maintained that even if LCOE was a proper cost 
metric, the comparison with the costs of a new nuclear power plant is 
improper because nuclear itself is a highly expensive technology. The 
EPA disagrees. The comparison is appropriate and valid because, as 
discussed at V.H.3 above, under current and foreseeable economic 
conditions affecting the cost of new fossil steam generation and new 
nuclear generation relative to the cost of new natural gas generation, 
neither new nuclear power nor fossil steam generation are competitive 
with new natural gas if evaluated on the basis of LCOE alone. 
Nonetheless, both are important potential alternatives to natural gas 
power for those interested in dispatchable base load power that 
maintains or increases fuel diversity. As shown in a survey of recent 
IRP filings in the docket \302\ and Section II.C.5 above, several 
utilities are considering new nuclear power as a potential generation 
option. Because both fossil steam and nuclear generation serve a 
comparable role of offering a diverse source of base load power 
generation, the EPA concludes that the comparison of their LCOE is a 
valid approach to evaluating cost reasonableness.
---------------------------------------------------------------------------

    \302\ Technical Support Document--``Review of Electric Utility 
Integrated Resource Plans'' (May 2015), available in the rulemaking 
docket EPA-HQ-OAR-2013-0495.

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

[[Page 64567]]

2. Use of Cost Estimates From DOE/NETL and DOE/EIA
    In the January 2014 proposal, the EPA relied mostly on the cost 
projections for new fossil fuel-fired generating sources that were 
informed by cost studies conducted by DOE/NETL. The EPA relied on the 
EIA's AEO 2013 projections for non-fossil based generating sources 
(i.e., nuclear, renewables, etc.). For this final rule, the EPA 
continues to rely most heavily on DOE/NETL cost projections for fossil 
fuel generating technologies and on the updated DOE/EIA AEO 2014 for 
nuclear and other base load non-fossil generation technologies.
a. DOE/NETL Cost and Performance Studies
    The DOE/NETL ``Cost and Performance Baselines for Fossil Energy 
Plants'' are a series of studies conducted by NETL to establish 
estimates for the cost and performance of combustion and gasification 
based power plants with and without CO2 capture and 
storage.\303\ The studies evaluate numerous technology configurations 
utilizing different coal ranks and natural gas.
---------------------------------------------------------------------------

    \303\ http://www.netl.doe.gov/research/energy-analysis/energy-baseline-studies.
---------------------------------------------------------------------------

    The EPA relied on those sources because the NETL studies are the 
most comprehensive and transparent of the available cost studies and 
NETL has a reputation in the power sector industry for producing high 
quality, reliable work.\304\ The NETL studies were extensively peer 
reviewed.\305\ The EPA Science Advisory Board Work Group considering 
the adequacy of the peer review noted the EPA staff's statement that 
``the NETL studies were all peer reviewed under DOE peer review 
protocols'', further noted the EPA staff's statement that ``the 
different levels of review of these DOE documents met the requirements 
to support the analyses as defined by the EPA Peer Review Handbook,'' 
and concluded that ``peer review on the DOE documents'' was conducted 
``at a level required by agency guidance.'' \306\
---------------------------------------------------------------------------

    \304\ The NETL costs and studies are often cited in academic and 
other publications.
    \305\ The initial NETL study ``Cost and Performance Baseline for 
Fossil Energy Plants, Vol. 1: Bituminous Coal and Natural Gas to 
Electricity'' (2006) was subject to peer review by industry experts, 
academia, and government research and regulatory agencies. 
Subsequent iterations of the study were not further peer reviewed 
because the modeling procedures used in the cost estimation were not 
revised.
    \306\ Letter from James Mihelcic, Chair, SAB Work Group on EPA 
Planned Actions for SAB Consideration of the Underlying Science to 
Members of the Chartered SAB and SAB Liaisons (page 3, Jan. 24, 
2014). http://yosemite.epa.gov/sab/sabproduct.nsf/
F43D89070E89893485257C5A007AF573/$File/
SAB+work+grp+memo+w+attach+20140107.pdf. The SAB's statement that 
these guidance documents ``require'' any specific peer review is an 
overstatement, since guidance documents, by definition, do not 
mandate any specific course of action.
---------------------------------------------------------------------------

    The cost estimates were indicated by DOE/NETL to carry an accuracy 
of -15 percent to +30 percent on the capital costs, consistent with a 
AACE Class 4 cost estimate--i.e., a ``feasibility study'' level of 
design engineering.\307\ The DOE/NETL further notes that ``The value of 
the study lies not in the absolute accuracy of the individual case 
results but in the fact that all cases were evaluated under the same 
set of technical and economic assumptions. This consistency of approach 
allows meaningful comparisons among the cases evaluated.'' \308\
---------------------------------------------------------------------------

    \307\ Recommended Practice 18R-97 of the Association for the 
Advancement of Cost Engineering International (AACE) describes a 
Cost Estimate Classification System as applied in Engineering, 
Procurement and Construction for the process industries.
    \308\ ``Cost and Performance Baseline for Fossil Energy Plants 
Volume 1: Bituminous Coal and Natural Gas to Electricity'' Rev 2a 
(Sept 2013); DOE/NETL-2010/1397, page 9.
---------------------------------------------------------------------------

    For the final standard, the EPA made particular use of the most 
recent NETL cost estimates for post-combustion CCS, which reflect up-
to-date vendor quotes and incorporate the post-combustion capture 
technology--the Shell Cansolv amine-based process--that is being 
utilized at the Boundary Dam Unit #3 facility.\309\ The EPA used this 
latest version of the NETL studies not only to assure that it considers 
the most up-to-date information but also to address public comments 
criticizing the proposal for relying on out-of-date cost information.
---------------------------------------------------------------------------

    \309\ Cost and Performance Baseline for Fossil Energy Plants 
Volume 1a: Bituminous Coal (PC) and Natural Gas to Electricity, 
Revision 3, July 6, 2015, DOE/NETL-2015/1723.
---------------------------------------------------------------------------

b. Other Studies That Corroborate NETL Cost Estimates
    A variety of government, industry and academic groups routinely 
conduct studies to estimate costs of new generating technologies. These 
studies use techno-economic models to predict the cost to build a new 
generating facility at some point in the future. These studies often 
use levelized cost of electricity (LCOE) to summarize costs and to 
compare the competiveness of the different generating technologies.
    A variety of groups have recently published LCOE estimates for new 
dispatchable generating technologies. Those are shown below in Table 
10. The table shows LCOE projections from the EPA's January 2014 
proposal, from studies conducted by the Electric Power Research 
Institute (EPRI),\310\ by the DOE's Energy Information Administration 
(EIA) in their 2015 Annual Energy Outlook (AEO 2015), by the DOE's 
National Energy Technology Laboratory (NETL), and by researchers from 
the Department of Engineering and Public Policy at the Carnegie Mellon 
University (CMU) in Pittsburgh, PA.
---------------------------------------------------------------------------

    \310\ EPRI is a non-profit organization, headquartered in Palo 
Alto, CA, that conducts research on issues related to the U.S. 
electric power industry (www.epri.com).
---------------------------------------------------------------------------

    The Global CCS Institute \311\ has recently published a report that 
examines costs of major low and zero emissions technologies currently 
available for power generation and compares the predicted LCOEs of 
those technologies. Importantly, the analysis presented in the report 
uses cost and performance data from several recent studies, and applies 
a common methodology and economic parameters to derive comparable 
lifetime costs. Analysis and findings in the paper reflect costs 
specific to the U.S.
---------------------------------------------------------------------------

    \311\ www.globalccsinstitute.com.
---------------------------------------------------------------------------

    The fact that these various groups have conducted independent 
studies and that the results of those independent studies are 
reasonably consistent with the estimates of DOE/NETL are further 
indications that the DOE/NETL cost estimates are reasonable.

[[Page 64568]]



                                         Table 10--Selection of Levelized Cost of Electricity (LCOE) Projections
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                           Lazard \312\     EPRI \313\     AEO2015 \314\  DOE/NETL \315\     CMU \316\     GCCSI \317\**
                New generation technology                    $2014/MWh       $2011/MWh      $2013/MWh*       $2011/MWh*      $2010/MWh       $2014/MWh
--------------------------------------------------------------------------------------------------------------------------------------------------------
SCPC--no CCS............................................              66           62-77              95           76-95              59              78
SCPC--full CCS..........................................             151         102-137              --         140-176              --         115-160
SCPC--16% CCS...........................................              --              --              --          92-117              --              --
Nuclear***..............................................          92-132           85-97          87-115              --              --          86-102
Biomass.................................................          87-116          90-155          94-113              --              --         123-137
IGCC....................................................             102           82-96             116          94-120              --              --
IGCC--full CCS..........................................             171         105-136             144         142-178              --              --
NGCC....................................................          61--87          33--65              73              58              63              60
--------------------------------------------------------------------------------------------------------------------------------------------------------
* EIA, in cost projections for SCPC and IGCC with no CCS, includes a climate uncertainty adder (CUA), which is a 3-percentage point increase in the cost
  of capital. In contrast, DOE/NETL utilized conventional financing for cases without CCS and utilized high-risk financial assumptions for cases that
  include CCS.
** The Global CCS Institute provided range for coal with full CCS (shown as ``CCS(coal)'' in Figure 5.2 of the referenced report) reflects a combination
  of costs for both PC and IGCC coal plants.
*** EIA AEO assumes use of Westinghouse AP1000 technology. Other groups assume a wider range of technology options.

    The LCOE values from the Lazard, EPRI, and NETL studies are 
presented as a range. The EPRI costs incorporate uncertainty reflecting 
the range of inputs (i.e., capital costs, fuel costs, fixed and 
variable O&M, etc.). The NETL costs are indicated to carry an accuracy 
of -15 percent to + 30 percent, consistent with a ``feasibility study'' 
level of design. The range in Table 10 is the NETL projected costs with 
the -15 percent to +30 percent uncertainty on the capital costs. 
Overall, as can be seen from the results in Table 10, the range of LCOE 
estimates from the different groups are in reasonable agreement with 
the DOE/NETL estimates most often representing the most conservative of 
the estimates shown.
---------------------------------------------------------------------------

    \312\ Lazard's Levelized Cost of Energy Analysis--Version 8.0 
(Sept 2014); available at http://www.lazard.com/media/1777/levelized_cost_of_energy_-_version_80.pdf and in the rulemaking 
docket.
    \313\ ``Program on Technology Innovation: Integrated Generation 
Technology Options 2012; Report 1026656; Available at: www.epri.com.
    \314\ ``Levelized Cost and Levelized Avoided Cost of New 
Generation Resources in the Annual Energy Outlook 2015'', Available 
at: www.eia.gov/forecasts/aeo/electricity_generation.cfm; the LCOE 
values displayed incorporate -10%/+30% for uncertainty for biomass 
and nuclear.
    \315\ ``Cost and Performance Baseline for Fossil Energy Plants 
Supplement: Sensitivity to CO2 Capture Rate in Coal-Fired 
Power Plants'' DOE/NETL-2015/1720 (June 22, 2015).
    \316\ CMU is Carnegie Mellon University; Zhai, H., Rubin, E.; 
``Comparative Performance and Cost Assessments of Coal- and Natural 
Gas-Fired Power Plants under a CO2 Emission Performance 
Standard Regulation'', Energy & Fuels, 2013, 27, 4290, Table 1.
    \317\ ``The Costs of CCS and other Low-Carbon Technologies--2015 
update'' July 2015, Global CCS Institute, Available at: http://hub.globalccsinstitute.com/sites/default/files/publications/195008/costs-ccs-other-low-carbon-technologies-2015-update.pdf.
---------------------------------------------------------------------------

    The EIA cost estimates include a climate uncertainty adder (CUA)--
represented by a three percent increase to the weighted average cost of 
capital--to certain coal-fired capacity types. The EIA developed the 
CUA to address inconsistencies between power sector modeling absent GHG 
regulation and the widespread use of a cost of CO2 emissions 
in power sector resource planning. The CUA reflects the additional 
planning cost typically assigned by project developers and utilities to 
GHG-intensive projects in a context of climate uncertainty. The EPA 
believes the CUA is consistent with the industry's planning and 
evaluation framework (demonstrable through IRPs and PUC orders) and is 
therefore pertinent when evaluating the cost competitiveness of 
alternative generating technologies. The EPA believes the CUA is 
relevant in considering the range of costs that power companies are 
willing to pay for generation alternatives to natural gas.
c. Industry Information That Corroborates NETL Cost Estimates
    Information from vendors of CCS technology also supports the 
reliability of the cost estimates the EPA is using here.\318\ 
Specifically, the EPA had conversations with representatives from 
Summit Carbon Capture, LLC regarding available cost information. Cost 
estimates provided by another leading provider of CCS technology 
likewise are consistent (indeed, somewhat less than) the estimates the 
EPA is using for purposes of cost analysis in the rule.
---------------------------------------------------------------------------

    \318\ See Section V.F above, explaining that the D.C. Circuit 
has repeatedly stated that vendor statements are probative in 
demonstrating that a technology is adequately demonstrated under 
section 111.
---------------------------------------------------------------------------

    Summit Carbon Capture's primary business is large-scale carbon 
capture from power and other industrial projects and use of the 
captured CO2 for EOR.\319\ Summit is actively working with 
several different technology companies offering CO2 capture 
systems, including the leading equipment manufacturers for fossil fuel 
power production equipment. Their current projects include the 400 MW 
IGCC Texas Clean Energy Project and the Caledonia Clean Energy 
Project--a new project underway in the United Kingdom--and a variety of 
other projects under development which are not yet public.
---------------------------------------------------------------------------

    \319\ http://www.summitpower.com/projects/carbon-capture/.
---------------------------------------------------------------------------

    Summit is also interested in potentially retrofitting CCS onto 
existing coal-fired plants for the purpose of capturing CO2 
for sale to EOR markets. Summit provided the EPA with copies of slides 
from a presentation that it has used in different public forums.\320\ 
The presentation focused on costs to retrofit available carbon capture 
equipment at an existing PC power plant that is ideally located to take 
advantage of opportunities to sell captured CO2 for use in 
EOR operations. Summit received proprietary costing information from 
numerous technology providers and that information, along with other 
publically available information, was used to develop their cost 
predictions.\321\ Though the primary focus of their effort was to 
examine costs associated with retrofitting CCS to an existing coal 
fired power plant, Summit Power also calculated costs for several new 
generation scenarios--including the cost of a new NGCC, a new SCPC, a 
new SCPC with full CCS, and a new SCPC with partial CCS at 50 percent. 
The costs are reasonably consistent with costs predicted by NETL, EIA, 
EPRI and others. The company ultimately concluded that ``in a world of 
uncertain gas prices, falling CO2 capture

[[Page 64569]]

equipment prices, improving CCS process efficiency, and possible 
compliance costs . . . existing coal plants retrofitted with available 
CCS equipment can be cost competitive with development of new NGCC 
generation.'' \322\
---------------------------------------------------------------------------

    \320\ ``Coal's Role in a Low Carbon Energy Environment'', 
presented at 2015 Euromoney Power & Renewables Conference, remarks 
by Jeffrey Brown (amended to address EPA questions on the original). 
Available in the rulemaking docket.
    \321\ No proprietary or business confidential information was 
shared with the EPA. No specific vendors were mentioned by name 
during discussions with Summit Power. Summit also used available 
DOE/NETL and EIA cost information.
    \322\ Others have come to similar conclusions--that retrofit of 
CCS technology at existing coal-fired power plants can be feasible--
e.g., ``The results indicate that for about 60 gigawatts of the 
existing coal-fired capacity, the implementation of partial 
CO2 capture appears feasible, though its cost is highly 
dependent on the unit characteristics and fuel prices.'' (Zhai, H.; 
Ou, Y.; Rubin, E.S.; ``Opportunities for Decarbonizing Existing U.S. 
Coal-fired Plants via CO2 Capture, Utilization, and 
Storage'', accepted for publication in Env. Sci & Tech. (2015).
---------------------------------------------------------------------------

    In June 2012, Alstom Power released a report entitled ``Cost 
assessment of fossil power plants equipped with CCS under typical 
scenarios''.\323\ The study examined costs for a new coal-fired power 
plant implementing post-combustion CCS (full CCS) in Europe, in North 
America, and in Asia. The results for the North American case--along 
with similar cost estimates from Summit--are shown in Table 11 below. 
The DOE/NETL estimated costs are also included for comparison. The 
results show predicted costs for a new SCPC ranging from $53/MWh to 
$82/MWh and costs to implement full CCS ranging from $97/MWh to $143/
MWh. Costs to implement varying levels of partial CCS are also provided 
for comparison. The industry cost estimates are on the lower end of the 
range of costs predicted from other techno-economic studies (see Table 
11 below) and, like those economic studies, are affected by the 
specific assumptions. As with the techo-economic studies presented 
earlier in Table 10, there is relatively good agreement among these 
projected costs and the DOE/NETL costs. There is relatively good 
agreement in the incremental levelized cost to implement full CCS on 
the new SCPC units (ranging from 74 to 85 percent) and to implement 50 
percent CCS on the new SCPC unit (from 41 to 45 percent increase). 
These industry estimates are also lower than the DOE/NETL estimates for 
both full and 50 percent partial CCS (with the incremental cost 
percentage for full CCS being almost identical), providing further 
support for the reasonableness of the EPA using the NETL cost estimates 
here.
---------------------------------------------------------------------------

    \323\ Leandri, J., Skea, A., Bohtz, C., Heinz, G.; ``Cost 
assessment of fossil power plants equipped with CCS under typical 
scenarios'', Alstom Power, June 2012. Available in the rulemaking 
docket: EPA-HQ-OAR-2013-0495.
    \324\ Note that in other tables in this preamble, the EPA has 
presented LCOE values from the DOE/NETL work as a range in order to 
incorporate the uncertainty on the capital costs. The range is not 
present here for easy comparison with the industry costs which were 
not provided as a range. The full range of DOE/NETL costs for each 
of the cases presented can be found in Exhibit A-3 in ``Cost and 
Performance Baseline for Fossil Energy Plants Supplement: 
Sensitivity to CO2 Capture Rate in Coal-Fired Power 
Plants'', DOE/NETL-2015/1720 (June 2015), p. 18.

                Table 11--Industry LCOE Estimates for Implementation of Post-Combustion CCS \324\
----------------------------------------------------------------------------------------------------------------
                                                                                                   DOE/NETL  $/
                                                                   Summit  $/MWh  Alstom  $/MWh*        MWh
----------------------------------------------------------------------------------------------------------------
SCPC............................................................            64.5            52.6            82.3
SCPC + full CCS.................................................           117.6            97.4           152.4
Full CCS incremental cost, %....................................           82.3%           85.0%           85.2%
SCPC + 50% CCS..................................................            91.1              --           123.6
50% CCS incremental cost, %.....................................           41.2%              --           50.1%
SCPC + 35% CCS..................................................              --              --           114.7
SCPC + 16% CCS..................................................              --              --           100.5
NGCC**..........................................................            47.7            35.0          **52.0
----------------------------------------------------------------------------------------------------------------
* Costs are from Figure 2 in the referenced Alstom report (North American case); costs are presented as [euro]/
  MWh in the report. The costs were converted to $/MWh assuming a conversion rate of 1 USD = 0.76 [euro] (in
  2012).
** NGCC cost is estimated by the EPA using NETL information. Assumed natural gas prices = Summit ($4/mmBtu);
  Astom ($3.9/mmBtu); EPA ($5.00/mmBtu).

    The EPA notes that in its public comments, Alstom maintained that 
``no CCS projects that would [sic] be considered cost competitive in 
today's energy economy.'' \325\ As explained above, no steam electric 
EGU would be cost competitive even without CCS--and that is 
substantiated in the projected costs presented above in Table 11 where 
NGCC is consistently the most economic new generation option when 
compared to the other listed technologies. Alstom does not explain (or 
address) why the cost premium for partial CCS would be a decisive 
deterrent for capacity that would otherwise be constructed. More 
important, Alstom does not challenge the specific cost estimates used 
by the EPA at proposal, nor disavow its own estimates of CCS costs 
(which are even less) which it is publically disseminating in the 
marketplace. See also Section V.F.3 above, quoting Alstom's press 
release stating unequivocally that ``CCS works and is cost-effective''. 
The EPA reasonably is relying on the specific Alstom estimates which it 
is using for its own commercial purposes, and not on the generalized 
concerns presented in its public comments.
---------------------------------------------------------------------------

    \325\ Alstom Comment p. 3 (Docket entry: EPA-HQ-OAR-2013-0495-
9033). The comment also urged the EPA to evaluate costs without 
considering EOR opportunities (which in fact is our methodology, 
albeit a conservative one), and without considering possible 
subsidies. Id. The LCOE and capital cost estimates above are direct 
cost comparisons, again consistent with the commenter's position.
---------------------------------------------------------------------------

d. Use of Cost Information From EIA Annual Energy Outlook (AEO)
    For the January 2014 proposal the EPA chose to rely on the EIA AEO 
2013 cost projections for non-fossil based generation. The AEO presents 
long-term annual projections of energy supply, demand, and prices 
focused on U.S. energy markets. The predictions are based on results 
from EIA's National Energy Modeling System (NEMS). The AEO costs are 
updated annually, they are highly scrutinized, and they are widely used 
by those involved in the energy sector.
    In the January 2014 proposal, the EPA presented LCOE costs for new 
non-fossil dispatchable generation (see 77 FR 1477, Table 7) from the 
AEO 2013. Those costs were updated as part of the AEO 2015 release. The 
estimated cost for all of these technologies decreased from AEO 2013 to 
AEO 2014 and AEO 2015. This was due to changes in the interest rates 
that resulted in lower financing costs relative to those used the AEO 
2013.\326\ The EIA commissioned a comprehensive update of its capital 
cost assumptions for all generation technologies in 2013. Fuel cost and

[[Page 64570]]

financial assumptions are updated for each edition of the Annual Energy 
Outlook.
---------------------------------------------------------------------------

    \326\ www.eia.gov/oiaf/beck_plantcosts/pdf/updatedplantcosts.pdf.
---------------------------------------------------------------------------

e. Accounting for Uncertainty of Projected Costs
    As previously mentioned, the projected costs are dependent upon a 
range of assumptions including the projected capital costs, the cost of 
financing the project, the fixed and variable O&M costs, the projected 
fuel costs, and incorporation of any incentives such as tax credits or 
favorable financing that may be available to the project developer. 
There are also regional or geographic differences that affect the final 
cost of a project. The LCOE projections in this final action are not 
intended to provide an absolute cost for a new project using any of 
these respective technologies. Large construction projects--as these 
would be--would be subjected to detailed cost analyses that would take 
into consideration site-specific information and specific design 
details in order to determine the project costs.
    The DOE/NETL noted that the cost estimates from their studies carry 
an accuracy in the range of -15 percent to +30 percent, which is 
consistent with a ``feasibility study'' level of design. They also 
noted that the value of the studies lies ``not in the absolute accuracy 
of the individual case results but in the fact that all cases were 
evaluated under the same set of technical and economic assumptions. 
This consistency of approach allows meaningful comparisons among the 
cases evaluated.''
    The EIA AEO 2015 presented LCOE costs as a single point estimate 
representing average nationwide costs and separately as a range to 
represent the regional variation in costs. In order to compare the 
fossil fuel generation technologies from the NETL studies with the cost 
projections for non-fossil dispatchable technologies from EIA AEO 2015, 
we assume that the EIA studies would carry a similar level of 
uncertainty (i.e., +30 percent) and we present the AEO 2015 projected 
costs as the average nationwide LCOE with a range of -10 percent to +30 
percent to account for uncertainty.\327\ The EIA does not provide 
uncertainty estimates in the AEO cost projections. However, nuclear 
experts from EIA staff have indicated to the EPA that a range of 
uncertainty of -10 percent to +30 percent on the capital component of 
the LCOE can be expected based on market uncertainties. Specifically, 
these staff experts expect that nuclear plants currently under 
construction would not have capital costs under estimates and that one 
could expect to see a 30 percent ``upside'' variation in capital cost. 
There is also insufficient market data to get a good statistical range 
of potential capital cost variation (i.e., only two plants under 
construction, neither complete). This is reasonably consistent with 
estimates for nuclear costs estimated by Lazard (see Table 8 above) 
which likewise reflect a similar level of cost uncertainty. The Lazard 
nuclear costs show a range of projected levelized capital cost from 
$73/MWh to $110/MWh--a range of 50 percent, very similar to the 40 
percent range (i.e., -10 percent to +30 percent) suggested by EIA 
nuclear experts. The Global CCS Institute, in its most recent cost 
update, also provides nuclear costs as a range from $86/MWh to $102/
MWh.\328\
---------------------------------------------------------------------------

    \327\ EIA does not provided uncertainty estimates in the AEO 
cost projections. However, EIA staff have indicated to the EPA that 
a range of uncertainty of -10%/+30% on the capital component of the 
LCOE can be expected based on market uncertainties. See memorandum 
``Range of uncertainty for AEO nuclear costs'' available in the 
rulemaking docket, EPA-HQ-OAR-2013-0495.
    \328\ ``The Costs of CCS and other Low-Carbon Technologies--2015 
update'' July 2015, Global CCS Institute, Available at: http://hub.globalccsinstitute.com/sites/default/files/publications/195008/costs-ccs-other-low-carbon-technologies-2015-update.pdf.
---------------------------------------------------------------------------

3. Use of Costs From Current Projects
    Although we are relying on cost estimates drawn from techno-
economic models, we recognize that there are a few steam electric 
plants that include CCS that have been built, or are being constructed. 
Some information about the costs (or cost-to-date) for these projects 
is known. We discuss in this section the costs at facilities which have 
installed or are installing CCS, why the EPA does not consider those 
costs to be reasonably predictive of the costs of the next new plants 
to be built, and why the EPA considers that the next new plants will 
have lower costs along the lines predicted by NETL.\329\
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    \329\ The EPA notes that two of these facilities, Kemper and 
TCEP, received both assistance from DOE under EPAct05 and the IRC 
section 48A tax credit; and that the AEP Mountaineer pilot project 
received assistance from DOE under EPAct05. Under the most extreme 
interpretations of those provisions offered by commenters, the EPA 
would be precluded from any consideration of any information from 
those sources, including cost information, in showing whether a 
system of emission reduction is adequately demonstrated. We note, 
however, that many of these same commenters urged consideration of 
the cost information from these sources. In fact, the EPA is not 
relying on information about the costs of these sources to determine 
the BSER or the standards of performance in this rulemaking, and the 
EPA is discussing the cost information here to explain why not. 
Accordingly, this discussion of cost information from these sources 
is not precluded by the EPAct05 and IRC section 48A provisions and, 
even if it is precluded, that would have no impact on the EPA's 
determination of the BSER and the standards of performance in this 
rule.
---------------------------------------------------------------------------

    The Boundary Dam Unit #3 facility utilizing post-combustion capture 
from Shell Cansolv is now operational. Petra Nova, a joint venture 
between NRG Energy Inc. and JX Nippon Oil & Gas Exploration, is 
currently constructing a post-combustion capture system at NRG's WA 
Parish generating station near Houston, TX. The post-combustion capture 
system will utilize MHI amine-based solvents and is currently being 
constructed with plans to initiate operation in 2016.\330\
---------------------------------------------------------------------------

    \330\ http://www.nrg.com/sustainability/strategy/enhance-generation/carbon-capture/wa-parish-ccs-project/.
---------------------------------------------------------------------------

    Construction on Mississippi Power's Kemper County Energy Center 
IGCC facility is now nearly complete. The combined cycle portion of the 
facility has been generating power using natural gas. The gasification 
portion of the facility and the carbon capture system are undergoing 
system checks and training to enable commercial operations using a UOP 
SelexolTM pre-combustion capture system in early 2016.\331\
---------------------------------------------------------------------------

    \331\ http://www.mississippipower.com/about-energy/plants/kemper-county-energy-facility/facts.
---------------------------------------------------------------------------

    Another full-scale project, the Summit Power Texas Clean Energy 
Project has not commenced construction but remains a viable project. 
Several other full-scale projects have been proposed and have 
progressed through the early stages of design, but have been cancelled 
or postponed for a variety of reasons.
    Some cost information is also available for small demonstration 
projects--including those that have been supported by USDOE research 
programs. These projects would include Alabama Power's demonstration 
project at Plant Barry and the AEP/Alstom demonstration at Plant 
Mountaineer.
    Many commenters felt that the EPA should rely on those high costs 
when considering whether the costs are reasonable. The costs from these 
large-scale projects appear to be consistently higher than those 
projected by techno-economic models. However, the costs from these 
full-scale projects represent first-of-a-kind (FOAK) costs and, it is 
reasonable to expect these costs to come down to the level projected in 
the NETL and other techno-economic studies for the next new projects 
that are built--which are the sources that would be subject to this 
standard.
    Significant reductions in the cost of CO2 capture would 
be consistent with overall experience with the cost of pollution 
control technology. A significant body of literature suggests

[[Page 64571]]

that the per-unit cost of producing or using a given technology 
declines as experience with that technology increases over time, and 
this has certainly been the case with air pollution control 
technologies. Reductions in the cost of air pollution control 
technologies as a result of learning-by-doing, research and development 
investments, and other factors have been observed over the decades. We 
expect that the costs of capture technology will follow this pattern.
    The NETL cost estimates reasonably account for this documented 
phenomenon. Specifically, ``[I]n all cases, the report intends to 
represent the next commercial offering, and relies on vendor cost 
estimates for component technologies. It also applies process 
contingencies at the appropriate subsystem levels in an attempt to 
account for expected but undefined costs (a challenge for emerging 
technologies).'' \332\
---------------------------------------------------------------------------

    \332\ ``Cost and Performance Baseline for Fossil Energy Plants 
Volume 1a: Bituminous Coal (PC) and Natural Gas to Electricity 
Revision 3'', DOE/NETL-2015/1723 (July 2015) at p. 38.
---------------------------------------------------------------------------

    Commenters argued that the next plants to be built would still 
reflect first-of-a-kind costs, pointing to the newness of the 
technology and the lack of operating experience, i.e. the alleged 
absence of learning by doing. The EPA disagrees. In addition to 
operating experience from operating and partially constructed CCS 
projects, substantial research efforts are underway providing a further 
knowledge base to reduce CO2 capture costs and to improve 
performance.
    The DOE/NETL sponsors an extensive research, development and 
demonstration program that is focused on developing advanced technology 
options that will dramatically lower the cost of capturing 
CO2 from fossil fuel energy plants compared to currently 
available capture technologies. The large-scale CO2 capture 
demonstrations that are currently planned and in some cases underway, 
under DOE's initiatives, as well as other domestic and international 
projects, will generate operational knowledge and enable continued 
commercialization and deployment of these technologies. Gas absorption 
processes using chemical solvents, such as amines, to separate 
CO2 from other gases have been in use since the 1930s in the 
natural gas industry and to produce food and chemical grade 
CO2. The advancement of amine-based solvents is an example 
of technology development that has improved the cost and performance of 
CO2 capture. Most single component amine systems are not 
practical in a flue gas environment as the amine will rapidly degrade 
in the presence of oxygen and other contaminants. The Fluor Econamine 
FG process, the process modeled in the NETL cost study for the SCPC 
cases, uses a monoethanolamine (MEA) formulation specially designed to 
recover CO2 and contains a corrosion inhibitor that allows 
the use of less expensive, conventional materials of construction. 
Other commercially available processes use sterically hindered amine 
formulations (for example, the Mitsubishi Heavy Industries KS-1 
solvent) which are less susceptible to degradation and corrosion 
issues.
    The DOE/NETL and private industry are continuing to sponsor 
research on advanced solvents (including new classes of amines) to 
improve the CO2 capture performance and reduce costs.
    As noted in Section V.H.7.d above, SaskPower has created the CCS 
Global Consortium to facilitate further knowledge regarding, and use 
of, carbon capture technology.\333\ This consortium provides SaskPower 
the opportunity to share its knowledge and experience with global 
energy leaders, technology developers, and project developers. 
SaskPower, in partnership with Mitsubishi and Hitachi, is also helping 
to advance CCS knowledge and technology through the creation of the 
Shand Carbon Capture Test Facility (CCTF).\334\ The test facility will 
provide technology developers with an opportunity to test new and 
emerging carbon capture systems for controlling carbon emissions from 
coal-fired power plants.
---------------------------------------------------------------------------

    \333\ http://www.saskpowerccs.com/consortium/.
    \334\ http://www.saskpowerccs.com/ccs-projects/shand-carbon-capture-test-facility/.
---------------------------------------------------------------------------

    We also note certain features of the commercial plants already 
built that suggest that their costs are uniquely high, and otherwise 
not fairly comparable to the costs of plants meeting the NSPS using the 
BSER. Most obviously, many of these projects involve deeper capture 
than the partial CCS that the EPA assumes in this final action. In 
addition, cost overruns at the Kemper facility, mentioned repeatedly in 
the public comments, resulted in major part from highly idiosyncratic 
circumstances, and are related to the cost of the IGCC system, not to 
the cost of CCS.\335\ The EPA does not believe that these unusual 
circumstances are a reasonable basis for assessing costs of either CCS 
or IGCC here.
---------------------------------------------------------------------------

    \335\ See Independent Monitor's Prudency Evaluation Report for 
the Kemper County IGCC Project (prepared for Mississippi Public 
Utilities Staff), available at www.psc.state.ms.us/InsiteConnect/InSiteView.aspx?model=INSITE_CONNECT&queue=CTS_ARCHIVEQ&docid=328417 
(``Report''). As documented in this Report, costs escalated 
significantly because the developers adopted a ``compressed 
schedule'' in an attempt to obtain the IRC 48A tax credit, resulting 
in ``engineering and design changes which are a normal result of 
detailed engineering and design . . . occurring at the same time as, 
rather than ahead of, construction activities'', which did not allow 
for proper sequencing during construction. This `` 'just-in-time' 
approach to engineering and procurement (meaning that the 
engineering was often completed shortly before material procurement 
and construction activities) resulted in a greater number of 
construction work-arounds, congestion of construction craft labor in 
the field, inefficiencies and additional steps that became necessary 
during construction to cope with this just-in-time engineering, 
procurement and construction approach.'' Report, p. 6. Ironically, 
work was still completed too late to obtain the tax credit. Id. p. 
15.
---------------------------------------------------------------------------

4. Cost Competitiveness of New Coal Units
    As the EPA noted, all indications suggest that very few new coal-
fired power plants will be constructed in the foreseeable future. 
Although a small number of new coal-fired power plants have been built 
recently, the industry generally is not building these kinds of power 
plants at present and is not expected to do so for the foreseeable 
future. The reasons include the current economic environment and 
improved energy efficiency, which has led to lower electricity demand, 
and competitive current and projected natural gas prices. On average, 
the cost of generation from a new NGCC power plant is expected to be 
lower than the cost of generation from a new coal-fired power plant, 
and the EPA has concluded that, even in the absence of the requirements 
of this final rule, very few new coal-fired power plants will be built 
in the near term.
    Some commenters, however, disagreed with this conclusion. They 
contended instead that it is the CCS-based NSPS that would preclude 
such new generation. However, as the EPA has discussed, there is 
considerable evidence that utilities and project developers are moving 
away--or have already moved away--from a long term dependence on coal-
fired generating sources. A review of publicly available integrated 
resource plans show that many utilities are not considering 
construction of new coal-fired sources without CCS. See Section V. H.3 
above. Few new coal-fired generating sources have commenced 
construction in the past 5 years and, of the projects that are 
currently in the development phase, the EPA is only aware of projects 
that will include CCS in the design. As we have noted in this preamble, 
the bulk of new

[[Page 64572]]

generation that has been added recently has been either natural gas-
fired or renewable sources. Overall, the EPA remains convinced that the 
energy sector modeling is reflecting the realities of the market in 
predicting very few new coal-fired power plants in the near future--
even in the absence of these final standards.
    In addition, we note that the Administration's CCS Task Force 
report recognized that CCS would not become more widely available 
without the advent of a regulatory framework that promoted CCS or 
provided a strong price signal for CO2. In this regard, we 
note American Electric Power's statements regarding the need for 
federal requirement for GHG control to aid in cost recovery for CCS 
projects, to attract other investment partners, and thereby promote 
advancement and deployment of CCS technology: ``as a regulated utility, 
it is impossible to gain regulatory approval to recover our share of 
the costs for validating and deploying the technology without federal 
requirements to reduce greenhouse gas emissions already in place. The 
uncertainty also makes it difficult to attract partners to help fund 
the industry's share''.\336\ Indeed, AEP has stated that CCS is 
important for the very future of the industry: ``AEP still believes the 
advancement of CCS is critical for the sustainability of coal-fired 
generation.'' \337\ This final rule's action is an important component 
in developing that needed regulatory framework.
---------------------------------------------------------------------------

    \336\ www.aep.com/newsroom/newsreleases/?id=1704.
    \337\ ``CCS LESSONS LEARNED REPORT American Electric Power 
Mountaineer CCS II Project Phase 1'', prepared for The Global CCS 
Institute Project # PRO 004, January 23, 2012, page 2. Available at: 
www.globalccsinstitute.com/publications/ccs-lessons-learned-report-american-electric-power-mountaineer-ccs-ii-project-phase-1; See also 
AEP FEED Study at pp. 4, 63, Available at: 
www.globalccsinstitute.com/publications/aep-mountaineer-ii-project-front-end-engineering-and-design-feed-report.
---------------------------------------------------------------------------

5. Accuracy of Cost Estimates for Transportation and Geologic 
Sequestration
    The EPA's estimates of costs take into account the transport of 
CO2 and sequestration of captured CO2. Estimates 
of transport and sequestration costs--approximately $5-$15 per ton of 
CO2--are based on DOE NETL studies and are also consistent 
with other published studies.\338\ For transport, costs reflect 
pipeline capital costs, related capital expenditures, and O&M costs. 
Sequestration cost estimates reflect the cost of site screening and 
evaluation, the cost of injection wells, the cost of injection 
equipment, operation and maintenance costs, pore volume acquisition 
expense, and long term liability protection. These sequestration costs 
reflect the regulatory requirements of the Underground Injection 
Control Class VI program and GHGRP subpart RR for geologic 
sequestration of CO2 in deep saline formations, which are 
discussed further in Sections V. M. and N below.\339\
---------------------------------------------------------------------------

    \338\ Updated Costs (June 2011 Basis) for Selected Bituminous 
Baseline Cases (DOE/NETL-341/082312); Cost and Performance of PC and 
IGCC Plants for a Range of Carbon Dioxide Capture (DOE/NETL-2011/
1498); Cost and Performance Baseline for Fossil Energy Plants (DOE/
NETL-2010/1397); Economic Evaluation of CO2 Storage and 
Sink Enhancement Options, Tennessee Valley Authority, NETL and EPRI, 
December 2002; Carbon Dioxide and Transport and Storage Costs in 
NETL Studies (DOE/NETL-2013/1614), March 2013; Carbon Dioxide and 
Transport and Storage Costs in NETL Studies (DOE/NETL-2014/1653), 
May 2014; Cost and Performance Baseline for Fossil Energy Power 
Plants, Volume 1a: Bituminous Coal (PC) and Natural Gas to 
Electricity (DOE-NETL-2015/1723), July 2015.
    \339\ Carbon Dioxide and Transport and Storage Costs in NETL 
Studies. DOE/NETL-2013/1614. March 2013. P. 13.
---------------------------------------------------------------------------

    Based on DOE/NETL studies, the EPA estimated that the total 
CO2 transportation, storage, and monitoring (TSM) cost 
associated with EGU CCS would comprise less than 5.5 percent of the 
total cost of electricity in all capture cases modeled--approximately 
$5-$15 per ton of CO2.\340\ The range of TSM costs the EPA 
relied on are broadly consistent with estimates provided by the Global 
Carbon Capture and Storage Institute as well.\341\ Some commenters 
suggested that the EPA underestimated the costs associated with 
transporting captured CO2 from an EGU to a sequestration 
site.\342\ Specifically, commenters suggested that the EPA's estimated 
costs for constructing pipelines were lower than costs based on actual 
industry experience. Commenters also opined that the EPA's assumed 
length of pipeline needed between the EGU and the sequestration site is 
not reasonable and that the DOE/NETL study upon which the EPA relied 
does not account for CO2 transport costs when EOR is not 
available.
---------------------------------------------------------------------------

    \340\ RIA at section 5.5; proposed rule RIA at 5-30.
    \341\ http://hub.globalccsinstitute.com/sites/default/files/publications/12786/economic-assessment-carbon-capture-and-storage-technologies-2011-update.pdf.
    \342\ See, for example, comments from American Electric Power, 
pp 97-8 (Docket entry: EPA-HQ-OAR-2013-0495-10618), Southern 
Company, pp. 47-48 (Docket entry: EPA-HQ-OAR-2013-0495-10095), and 
Duke Energy p. 28 (Docket entry: EPA-HQ-OAR-2013-0495-9426).
---------------------------------------------------------------------------

    The EPA believes its estimates of transportation and sequestration 
costs are reasonable. First, the EPA in fact includes cost estimates 
for CO2 transport when EOR opportunities are not available--
consistent with its overall conservative cost methodology of assuming 
no revenues from sale of captured CO2. Specifically, the EPA 
estimates transport, storage and monitoring (TSM) costs of $5-$15 per 
ton of CO2 for non-EOR applications.\343\ This estimate is 
reflected in the LCOE comparative costs.\344\
---------------------------------------------------------------------------

    \343\ See RIA at section 5.5 and proposed RIA at 5-30.
    \344\ See RIA at section 5.5.
---------------------------------------------------------------------------

    The EPA also carefully reviewed the assumptions on which the 
transport cost estimates are based and continues to find them 
reasonable. The NETL studies referenced in Section V.I.2 above based 
transport costs on a generic 100 km (62 mi) pipeline and a generic 80 
kilometer pipeline.\345\ At least one study estimated that of the 500 
largest point sources of CO2 in the United States, 95 
percent are within 50 miles of a potential storage reservoir.\346\ As a 
point of reference, the longest CO2 pipeline in the United 
States is 502 miles.\347\ For new sources, pipeline distance and costs 
can be factored into siting and, as discussed in Section V.M, there is 
widespread availability of geologic formations for geologic 
sequestration (GS). Moreover, data from the Pipeline and Hazardous 
Materials Safety Administration show that in 2013 there were 5,195 
miles of CO2 pipelines operating in the United States. This 
represents a seven percent increase in CO2 pipeline miles 
over the previous year and a 38 percent increase in CO2 
pipeline miles since 2004. For the reasons outlined above, the EPA 
believes its estimates have a reasoned basis. See also Section V.M 
below further discussing the current availability of CO2 
pipelines.
---------------------------------------------------------------------------

    \345\ The pipeline diameter was sized for this to be achieved 
without the need for recompression stages along the pipeline length.
    \346\ JJ Dooley, CL Davidson, RT Dahowski, MA Wise, N Gupta, SH 
Kim, EL Malone (2006), Carbon Dioxide Capture and Geologic Storage: 
A Key Component of a Global Energy Technology Strategy to Address 
Climate Change. Joint Global Change Research Institute, Battelle 
Pacific Northwest Division. PNWD-3602. College Park, MD.
    \347\ A Review of the CO2 Pipeline Infrastructure in 
the U.S., April 21, 2015, DOE/NETL-2014/1681, Office of Fossil 
Energy, National Energy Technology Laboratory.
---------------------------------------------------------------------------

    With respect to sequestration, certain commenters argued that the 
EPA's cost analysis failed to account for many contingencies and 
uncertainties (surface and sub-surface property rights in particular), 
ignored the costs of GHGRP subpart RR, and also was not representative 
of the costs associated with specific GS site characterization, 
development, and operation/injection of monitoring wells. Commenter 
American Electric Power (AEP) referred to its own

[[Page 64573]]

experience with the Mountaineer demonstration project. AEP noted that 
although this project was not full scale, finding a suitable 
repository, notwithstanding a generally favorable geologic area, proved 
difficult. The company referred to its estimated cost of expanding the 
existing Mountaineer plant to a larger scale project, particularly the 
cost of site characterization and well construction.\348\
---------------------------------------------------------------------------

    \348\ AEP Comments at pp. 93, 96 (Docket entry: EPA-HQ-OAR-2013-
0495-10618).
---------------------------------------------------------------------------

    The EPA's cost estimates account for the requirements of the 
Underground Injection Control Class VI program, and GHGRP subpart RR, 
among them site screening and evaluation costs, costs for injection 
wells and equipment, O&M costs, and monitoring costs. The estimated 
sequestration costs include operational and post-injection site care 
monitoring, which are components of the UIC Class VI requirements, and 
also reflect costs for sub-surface pore volume property rights 
acquisition.\349\ These estimates are consistent with the costs 
presented in the study CO2 Storage and Sink Enhancements: 
Developing Comparable Economics, which incorporates the costs 
associated with site evaluation, well drilling, and the capital 
equipment required for transporting and injecting 
CO2.350 351 Monitoring costs were evaluated based 
on the methodology set forth in the International Energy Agency 
Greenhouse Gas R&D Programme's Overview of Monitoring Projects for 
Geologic Storage Projects report.\352\
---------------------------------------------------------------------------

    \349\ ``Cost and Performance of PC and IGCC Plants for a Range 
of Carbon Dioxide Capture.'' DOE/NETL-2011/1498 (September 2013) p. 
49. Specifically, the report estimates the costs associated with 
acquiring rights to use the pore space in the geologic formation. 
Costs are estimated based on studies of subsurface rights 
acquisition for natural gas storage. The report also estimates costs 
for land acquisition for surface property rights. Id. p. 48.
    \350\ Bock, B., R. Rhudy, H. Herzog, M. Klett, J. Davidson, D.G. 
De La Torre Ugarte, and D. Simbeck. (2003). Economic Evaluation of 
CO2 Storage and Sink Enhancement Options, Final Technical 
Report Prepared by Tennessee Valley Authority for DOE.
    \351\ As noted above, other sequestration-related costs are also 
estimated, including injection wells and equipment, pore volume 
acquisition, and long-term-liability. ``Cost and Performance 
Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and 
Natural Gas to Electricity Revision 2a, September 2013 DOE/NETL-
2010/1397, p. 55.
    \352\ ``Overview of Monitoring Requirements for Geologic Storage 
Projects'', IEA Greenhouse Gas R&D Programme, Report Number PH4/29, 
November 2004.
---------------------------------------------------------------------------

    The EPA's cost estimates for sequestration thus cover all aspects 
commenters claimed the EPA disregarded. The EPA believes that the use 
of costs and scenarios presented in the studies referenced are 
representative for purposes of the cost analysis. The NETL cost 
estimates upon which the EPA's costs draw directly from the UIC Class 
VI economic impact analysis.\353\ That analysis is based on estimated 
characteristics for a representative group of projects over a 50-year 
period of analysis, as well as industry averages for several cost 
components and sub-components. The EPA also made reasonable assumptions 
regarding the assumed injection site: A deep saline formation with 
typical characteristics (e.g., representative depth and pressure).\354\
---------------------------------------------------------------------------

    \353\ Cost Analysis for the Federal Requirements Under the 
Underground Injection Control Program for Carbon Dioxide Geologic 
Sequestration Wells, U.S. Environmental Protection Agency Office of 
Water, EPA 816-R10-013, November 2010, pages 3-1, 5-42.
    \354\ Economic Evaluation of CO2 Storage and Sink 
Enhancement Options, Tennessee Valley Authority, NETL and EPRI, 
December 2002.
---------------------------------------------------------------------------

    With respect to AEP's experience with the Mountaineer demonstration 
project, sequestration siting issues are of course site-specific, and 
raise individual issues. For this reason, it is inappropriate to 
generalize from a particular individual experience. In this regard, as 
explained in Section V.N below, the construction permits issued by the 
EPA to-date under the Underground Injection Control Class VI 
regulations required far fewer wells for site characterization and 
monitoring than AEP found to be necessary at its Mountaineer site. 
Moreover, notwithstanding difficulties, the company was able to 
successfully drill and complete wells, and safely inject captured 
CO2. The company also indicated it fully expected to be able 
to do so at full scale and explained how.\355\ For discussion of 40 CFR 
part 98, subpart RR (the GHGRP requirements for geologic 
sequestration), including costs associated with compliance with those 
requirements, see Section V.N below.
---------------------------------------------------------------------------

    \355\ See ``CCS front end engineering & design report: American 
Electric Power Mountaineer CCS II Project. Phase 1'' at pp. 36-43. 
The company likewise explained the monitoring regime it would 
utilize to verify containment, and the well construction it would 
utilize to guarantee secure sequestration. Id. at pp. 44-54. 
Available at: http://www.globalccsinstitute.com/publications/aep-mountaineer-ii-project-front-end-engineering-and-design-feed-report.
---------------------------------------------------------------------------

J. Achievability of the Final Standards

    The EPA finds the final standard of 1,400 lb CO2/MWh-g 
to be achievable over a wide range of variable conditions that are 
reasonably likely to occur when the system is properly designed and 
operated. As discussed elsewhere, the final standard reflects the 
degree of emission limitation achievable through the application of the 
BSER which we have determined to be a highly efficient SCPC 
implementing partial CCS at a level sufficient to achieve the final 
standard--for such a unit utilizing bituminous coal that would be 
approximately 16 percent. In determining the predicted cost and 
performance of such a system, the EPA utilized information contained in 
updated DOE/NETL studies that assumed use of bituminous coal and an 85 
percent capacity factor. Here we examine the effects of deviating from 
those assumed operational parameters on the achievability of the final 
standard of performance.\356\ This is in keeping with the requirement 
that a standard of performance must be achievable accounting for all 
normal operating variability when a control system is properly 
designed, maintained, and operated. See Section III.H.1.c above.
---------------------------------------------------------------------------

    \356\ Additional information can be found in a Technical Support 
Document (TSD)--``Achievability of the Standard for Newly 
Constructed Steam Generating EGUs'' available in the rulemaking 
docket.
---------------------------------------------------------------------------

1. Operational Fluctuations, Start-Ups, Shutdowns, and Malfunctions
    Importantly, compliance with the standard must be demonstrated over 
a 12-operating-month average. The total CO2 emissions 
(pounds of CO2) over 12 operational months are summed and 
divided by the total gross output (in megawatt-hours) over the same 12 
operational months. Such a compliance averaging period is very 
forgiving of short-term excursions that can be associated with non-
routine events such as start-ups, shutdowns, and malfunctions. A new 
fossil fuel-fired steam generating EGU--if constructed--would, most 
likely, be built to serve base load power demand and would not be 
expected to routinely start-up or shutdown or ramp its capacity factor 
in order to follow load demand. Thus, planned start-up and shutdown 
events would only be expected to occur a few times during the course of 
a 12-operating-month compliance period. Malfunctions are unplanned and 
unpredictable events and emission excursions can happen at or around 
the time of the equipment malfunction. But a malfunctioning EGU that 
cannot be operated properly should be shut down until the 
malfunctioning equipment can be addressed and the EGU can be restarted 
to operate properly.
    The post-combustion capture systems that have been utilized have 
proven to be reliable. The Boundary Dam facility has been operating 
full CCS successfully at commercial scale since October 2014. As 
described earlier, in evaluating results from the Mountaineer slip-

[[Page 64574]]

stream demonstration, AEP and Alstom reported robust steady-state 
operation during all modes of power plant operation including load 
changes, and saw an availability of the CCS system of greater than 90 
percent.\357\
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    \357\ http://www.alstom.com/press-centre/2011/5/alstom-announces-sucessful-results-of-mountaineer-carbon-capture-and-sequestration-ccs-project/. The Boundary Dam facility likewise is 
operating reliably (see Section V.D.3.a above). See also ``Cost and 
Performance Baseline for Fossil Energy Plants Volume 1a: Bituminous 
Coal (PC) and Natural Gas to Electricity, Revision 3'', DOE/NETL-
2015/1723 (July 2015) at p. 36 (``[t]he capture and CO2 
compression technologies have commercial operating experience with 
demonstrated ability for high reliability'').
---------------------------------------------------------------------------

2. Variations in Coal Type
    The use of specific coal types can affect the amount of 
CO2 that is emitted from a new coal-fired power plant. As 
previously discussed, the EPA utilized studies by the DOE/NETL to 
predict the cost and performance of new steam generating units. Based 
on those reports, the EPA predicts that a new SCPC burning low rank 
coal (subbituminous coal or dried lignite) would have an uncontrolled 
emission rate about 7 percent higher than a similar unit firing typical 
bituminous coal.\358\ The EPA predicts that such a highly efficient new 
SCPC utilizing subbituminous coal or dried lignite would need to 
capture approximately 23 percent of the CO2. The EPA also 
believes that it is technically feasible to do so, although additional 
cost would be entailed. The EPA has evaluated those costs and finds 
them to remain reasonable.\359\ As shown in Table 8 above, the 
predicted cost remains within the estimated range for the other 
principal base load, dispatchable non-NGCC alternative technologies. 
Estimated capital cost using these coal types would also be somewhat 
higher, an estimated 23 percent increase.\360\ The EPA finds these 
increases to be reasonable because, as discussed earlier, the costs are 
reasonably consistent with capital cost increases in previous NSPS. See 
Section V.H.4 above.
---------------------------------------------------------------------------

    \358\ For additional detail, see the Technical Support Document 
(TSD)--``Achievability of the Standard for Newly Constructed Steam 
Generating EGUs''--available in the rulemaking docket.
    \359\ The cost of the lignite drying equipment is assumed to be 
low compared to the cost of the carbon capture equipment. Further, 
pre-drying of the lignite reduces fuel, auxiliary power consumption 
and other O&M costs. www.iea-coal.org.uk/documents/83436/9095/
Techno-economics-of-modern-pre-drying-technologies-for-lignite-
fired-power-plants,-CCC/241.
    \360\ Note that the 23 percent increase in expected capital 
costs and the 23 percent CO2 capture needed to meet the 
final standard are coincidental and are not correlated.
---------------------------------------------------------------------------

K. Emission Reductions Utilizing Partial CCS

    Although the definition of ``standard of performance'' does not by 
its terms identify the amount of emissions from the category of sources 
and 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 at 326 (``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'').\361\ This is consistent with the Court's statements in 
Essex Chemical Corp. v. Ruckelshaus, 486 F.2d at 437 that it is 
necessary to ``[k]eep[] in mind Congress' intent that new plants be 
controlled to the `maximum practicable degree' ''.
---------------------------------------------------------------------------

    \361\ 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'' to read, 
``best technological system.'' The 1990 CAAA deleted 
``technological,'' and thereby returned the phrase to how it read 
under the 1970 CAAA. The Sierra Club v. Costle's interpretation of 
this phrase to require consideration of the amount of air emissions 
remains valid for the phrase ``best system.''
---------------------------------------------------------------------------

    The final standard of performance will result in meaningful and 
significant emission reductions of GHG emissions from a new coal-fired 
steam generating unit. The EPA estimates that a new highly efficient 
500 MW coal-fired SCPC meeting the final standard of 1,400 lb 
CO2/MWh-g will emit about 354,000 fewer metric tons of 
CO2 each year than that new highly efficient unit would have 
emitted otherwise. That is equivalent to taking about 75,000 vehicles 
off the road each year \362\ and will result in over 14,000,000 fewer 
metric tons of CO2 in a 40-year operating life. To emphasize 
the importance of constructing a highly efficient SCPC unit that 
includes partial CCS--the highly efficient 500 MW coal-fired SCPC with 
partial CCS would emit about 675,000 fewer metric tons of 
CO2 each year than that from a new, less efficient coal-
fired utility boiler with an assumed emission of 1,800 lb 
CO2/MWh-g.
---------------------------------------------------------------------------

    \362\ Using U.S. EPA Office of Transportation and Air Quality 
(OTAQ) estimate of average vehicle emissions of 4.7 tonnes/year.
---------------------------------------------------------------------------

    For comparison, see Table 12 below which provides the amount of 
CO2 emissions captured each year by other CCS projects. 
These result show that, even though the emission reductions are 
significant, they are reasonably within the range of emission 
reductions that are currently being achieved now in existing 
facilities. For comparison, approximately 60,000,000 metric tons of 
CO2 were supplied to U.S. EOR operations in 2013.\363\
---------------------------------------------------------------------------

    \363\ Greenhouse Gas Reporting Program, data reported as of 
August 18, 2014.

 Table 12--Annual Metric Tons of CO2 Captured (or Predicted to Capture)
    From CCS Projects and From a Model 500 MW Plant Meeting the Final
                                Standard.
------------------------------------------------------------------------
                                                           CO2 captured
                         Project                            tonnes/year
------------------------------------------------------------------------
AES Shady Point.........................................          66,000
AES Warrior Run.........................................         110,000
Southern Company Plant Barry............................         165,000
Searles Valley Minerals.................................         270,000
New 500 MW SCPC EGU (1,400 lb CO2/MWh-g)................         354,000
Coffeyville Fertilizer..................................         700,000
Boundary Dam #3.........................................       1,000,000
Petra Nova/NRG WA Parish................................       1,400,000
Dakota Gasification.....................................       3,000,000
------------------------------------------------------------------------


[[Page 64575]]

L. Further Development and Deployment of CCS Technology

    Researchers at Carnegie Mellon University (CMU) have studied the 
history and the technological response to environmental 
regulations.\364\ By examining U.S. research funding and patenting 
activity over the past century, the CMU researchers found that 
promulgation of national policy requiring large reductions in power-
plant emissions resulted in a significant upswing in inventive activity 
to develop technologies to reduce those emissions. The researchers 
found that, following the 1970 Clean Air Act, there was a 10-fold 
increase in patenting activity directed at improving the SO2 
scrubbers that were needed to comply with stringent federal and state-
level standards.
---------------------------------------------------------------------------

    \364\ See Technical Support Document/Memorandum ``History Of 
Flue Gas Desulfurization in the United States'' (July 11, 2015) 
summarizing the doctoral dissertation of Margaret R. Taylor, ``The 
Influence of Government Actions on Innovative Activities in the 
Development of Environmental Technologies to Control Sulfur Dioxide 
Emissions from Stationary Sources,'' MA dissertation submitted to 
the Carnegie Institute of Technology, Carnegie Mellon University in 
partial fulfillment of the requirements for the degree of Doctor of 
Philosophy in Engineering and Public Policy, Pittsburgh, PA, January 
2001.
---------------------------------------------------------------------------

    Much like carbon capture scrubbers today, the technology to capture 
and remove SO2 from power plant flue gases was new to the 
industry and was not yet widely deployed at large coal-burning plants 
when the EPA first promulgated the 1971 standards.
    Many of the early Flue Gas Desulfurization (FGD) units did not 
perform well, as the technology at that time was poorly understood and 
there was little or no prior experience on coal-fired power plants. In 
contrast, amine-based capture systems have a much longer history of 
reliable use at coal-fired plants and other industrial sources. There 
is also a better understanding of the amine process chemistry and 
overall process design--and project developers have much sophisticated 
analytical tools available today than in the 1970s during the 
development of FGD scrubber technologies.
    While R&D efforts were essential to achieving improvements in FGD 
scrubber technology--and are also very important to improving carbon 
capture technologies, the influence of regulatory actions that 
establish commercial markets for advanced technologies cannot be 
minimized. The existence of national government regulation for 
SO2 emissions control stimulated innovation, as shown by the 
patent analysis following initial SO2 regulatory 
requirements for EGU emissions. The study author further found that 
regulatory stringency appears to be particularly important as a driver 
of innovation, both in terms of inventive activity and in terms of the 
communication processes involved in knowledge transfer and diffusion. 
Further, as electric power generation doubled, the operating and 
maintenance costs of FGD systems decline to 83 percent of their 
original level. This finding, which is very much in line with progress 
ratios determined in other industries, shows that quantifiable 
technological improvements can be shown to occur solely on the basis of 
the experience of operating an environmental control technology forced 
into being by government actions.

M. Technical and Geographic Aspects of Disposition of Captured 
CO2

    In the following sections of the preamble, we discuss issues 
associated with the disposition of captured CO2: the ``S''--
sequestration--in CCS. In this section, we review the existing 
processes, technologies, and geologic conditions that enable successful 
geologic sequestration (GS). In Section V.N., we discuss in detail the 
comprehensive, in-place regulatory structure that is currently 
available to oversee GS projects and assure their safety and 
effectiveness. Together, these discussions demonstrate that the 
technical feasibility of GS, another key component of a partial CCS 
unit, is adequately demonstrated. Sequestration is already well proven. 
CO2 has been retained underground for eons in geologic 
(natural) repositories and the mechanisms by which CO2 is 
trapped underground are well understood. The physical and chemical 
trapping mechanisms, along with the regulatory requirements and 
safeguards of the Underground Injection Control Program and 
complementary monitoring and reporting requirements of the GHGRP, 
together ensure that sequestered CO2 will remain secure and 
provide the monitoring to identify and address potential leakage using 
Safe Drinking Water Act (SDWA) and CAA authorities (see Section V.N of 
this preamble).\365\
---------------------------------------------------------------------------

    \365\ See also Carbon Sequestration Council and Southern Company 
Services v. EPA, No. 14-1406 (D.C. Cir. June 2, 2015) at *10 
(``[c]arbon capture and storage is an emerging climate change 
mitigation program that involves capturing carbon dioxide from 
industrial sources, compressing it into a `supercritical fluid,' and 
injecting that fluid underground for the purposes of geologic 
sequestration, with the goal of preventing the carbon from 
reentering the atmosphere. Because the last of these steps--geologic 
sequestration of the supercritical carbon dioxide--involves that 
injection of fluid into underground wells, it is subject to 
regulation under the Safe Drinking Water Act'').
---------------------------------------------------------------------------

1. Geologic and Geographic Considerations for GS
    Geologic sequestration (i.e., long-term containment of a 
CO2 stream in subsurface geologic formations) is technically 
feasible and available throughout most of the United States. GS is 
based on a demonstrated understanding of the processes that affect 
CO2 fate in the subsurface; these processes can vary 
regionally as the subsurface geology changes. GS occurs through a 
combination of mechanisms including: (1) Structural and stratigraphic 
trapping (generally trapping below a low permeability confining layer); 
(2) residual CO2 trapping (retention as an immobile phase 
trapped in the pore spaces of the geologic formation); (3) solubility 
trapping (dissolution in the in situ formation fluids); (4) mineral 
trapping (reaction with the minerals in the geologic formation and 
confining layer to produce carbonate minerals); and (5) preferential 
adsorption trapping (adsorption onto organic matter in coal and 
shale).\366\ These mechanisms are functions of the physical and 
chemical properties of CO2 and the geologic formations into 
which the CO2 stream is injected. Subsurface formations 
suitable for GS of CO2 captured from affected EGUs are 
geographically widespread throughout most parts of the United States.
---------------------------------------------------------------------------

    \366\ See, e.g., USEPA. 2008. Vulnerability Evaluation Framework 
for Geologic Sequestration of Carbon Dioxide.
---------------------------------------------------------------------------

    Storage security is expected to increase over time through post-
closure, resulting in a decrease in potential risks.\367\ This 
expectation is based in part on a technical understanding of the 
variety of trapping mechanisms that work to reduce CO2 
mobility over time.\368\ In addition, site characterization, site 
operations, and monitoring strategies can work in combination to 
promote storage security.
---------------------------------------------------------------------------

    \367\ Report of the Interagency Task Force on Carbon Capture and 
Storage (August 2010), page 47.
    \368\ See, e.g., Intergovernmental Panel on Climate Change. 
(2005). Special Report on Carbon Dioxide Capture and Storage.

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

[[Page 64576]]

    The effectiveness of long-term trapping of CO2 has been 
demonstrated by natural analogs in a range of geologic settings where 
CO2 has remained trapped for millions of years.\369\ For 
example, CO2 has been trapped for more than 65 million years 
in the Jackson Dome, located near Jackson, Mississippi.\370\ Other 
examples of natural CO2 sources include Bravo Dome and 
McElmo Dome in Colorado and New Mexico, respectively. These natural 
storage sites are themselves capable of holding volumes of 
CO2 that are larger than the volume of CO2 
expected to be captured from a fossil fuel-fired EGU. In 2010, the 
Department of Energy (DOE) estimated current CO2 reserves of 
594 million metric tons at Jackson Dome, 424 million metric tons at 
Bravo Dome, and 530 million metric tons at McElmo Dome.\371\
---------------------------------------------------------------------------

    \369\ Holloway, S., J. Pearce, V. Hards, T. Ohsumi, and J. Gale. 
2007. Natural Emissions of CO2 from the Geosphere and 
their Bearing on the Geological Storage of Carbon Dioxide. Energy 
32: 1194-1201.
    \370\ Intergovernmental Panel on Climate Change. (2005). Special 
Report on Carbon Dioxide Capture and Storage.
    \371\ DiPietro, P., Balash, P. & M. Wallace. A Note on Sources 
of CO2 Supply for Enhanced-Oil Recovery Operations. SPE 
Economics & Management. April 2012.
---------------------------------------------------------------------------

    GS is feasible in different types of geologic formations including 
deep saline formations (formations with high salinity formation fluids) 
or in oil and gas formations, such as where injected CO2 
increases oil production efficiency through a process referred to as 
enhanced oil recovery (EOR). Both deep saline and oil and gas formation 
types are widely available in the United States. The geographic 
availability of deep saline formations and EOR is shown in Figure 1 
below.\372\ As shown in the figure, there are 39 states for which 
onshore and offshore deep saline formation storage capacity has been 
identified.\373\ EOR operations are currently being conducted in 12 
states. An additional 17 states have geology that is amenable to EOR 
operations. Figure 1 also shows areas that are within 100 kilometers 
(62 miles) of where storage capacity has been identified.\374\ There 
are 10 states with operating CO2 pipelines and 18 states 
that are within 100 kilometers (62 miles) of an active EOR location.
---------------------------------------------------------------------------

    \372\ A color version of the figure, which readers may find 
easier to view, can be found in the technical support document on 
geographic availability in the rulemaking docket.
    \373\ Alaska is not shown in Figure 1; it has deep saline 
formation storage capacity, geology amenable to EOR operations, and 
potential GS capacity in unmineable coal seams.
    \374\ The distance of 100 kilometers reflects assumptions in 
DOE-NETL cost estimates which the EPA used for cost estimation 
purposes. See ``Carbon Dioxide and Transport and Storage Costs in 
NETL Studies'', DOE/NETL-2014/1653 (May 2014).
---------------------------------------------------------------------------

    CO2 may also be used for other types of enhanced 
recovery, such as for natural gas production. Reservoirs such as 
unmineable coal seams also offer the potential for geologic 
storage.\375\ Enhanced coalbed methane recovery is the process of 
injecting and storing CO2 in unmineable coal seams to 
enhance methane recovery. These operations take advantage of the 
preferential chemical affinity of coal for CO2 relative to 
the methane that is naturally found on the surfaces of coal. When 
CO2 is injected, it is adsorbed to the coal surface and 
releases methane that can then be captured and produced. This process 
effectively ``locks'' the CO2 to the coal, where it remains 
stored. DOE has identified over 54 billion metric tons of potential 
CO2 storage capacity in unmineable coal across 21 
states.\376\ The availability of unmineable coal seams is shown in 
Figure 1 below.
---------------------------------------------------------------------------

    \375\ Other types of opportunities include organic shales and 
basalt.
    \376\ The United States 2012 Carbon Utilization and Storage 
Atlas, Fourth Edition, U.S. Department of Energy, Office of Fossil 
Energy, National Energy Technology Laboratory (NETL).
---------------------------------------------------------------------------

    As discussed below in Section M.7, a few states do not have 
geologic conditions suitable for GS, or may not be located in proximity 
to these areas. However, in some cases, demand in those states can be 
served by coal-fired power plants located in areas suitable for GS, and 
in other cases, coal-fired power plants are unlikely to be built in 
those areas for other reasons, such as the lack of available coal or 
state law prohibitions and restrictions against coal-fired power 
plants.\377\
---------------------------------------------------------------------------

    \377\ Similarly, as discussed below, the U.S. territories lack 
available coal, do not currently have coal-fired power plants, and, 
as a result, are not expected to see new coal-fired power plants. 
Hawaii is not expected to constructed new coal plants as it intends 
to utilize 100 percent renewable energy sources by 2050.

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[[Page 64577]]

[GRAPHIC] [TIFF OMITTED] TR23OC15.000


[[Page 64578]]


[GRAPHIC] [TIFF OMITTED] TR23OC15.001

2. Availability of Geologic Sequestration in Deep Saline Formations
---------------------------------------------------------------------------

    \378\ Ventyx Velocity Suite Online. April 2015.
---------------------------------------------------------------------------

    The DOE and the United States Geological Survey (USGS) have 
independently conducted preliminary analyses of the availability and 
potential CO2 sequestration capacity of deep saline 
formations in the United States. DOE estimates are compiled by the 
DOE's National Carbon Sequestration Database and Geographic Information 
System (NATCARB) using volumetric models and published in a Carbon 
Utilization and Storage Atlas.\379\ DOE estimates that areas of the 
United States

[[Page 64579]]

with appropriate geology have a sequestration potential of at least 
2,035 billion metric tons of CO2 in deep saline formations. 
According to DOE and as noted above, at least 39 states have geologic 
characteristics that are amenable to deep saline GS in either onshore 
or offshore locations. In 2013, the USGS completed its evaluation of 
the technically accessible GS resources for CO2 in U.S. 
onshore areas and state waters using probabilistic assessment.\380\ The 
USGS estimates a mean of 3,000 billion metric tons of subsurface 
CO2 sequestration potential, including saline and oil and 
gas reservoirs, across the basins studied in the United States.
---------------------------------------------------------------------------

    \379\ The United States 2012 Carbon Utilization and Storage 
Atlas, Fourth Edition, U.S. Department of Energy, Office of Fossil 
Energy, National Energy Technology Laboratory (NETL).
    \380\ U.S. Geological Survey Geologic Carbon Dioxide Storage 
Resources Assessment Team, 2013, National assessment of geologic 
carbon dioxide storage resources--Results: U.S. Geological Survey 
Circular 1386, p. 41, http://pubs.usgs.gov/circ/1386/ 1386/.
---------------------------------------------------------------------------

    The DOE has created a network of seven Regional Carbon 
Sequestration Partnerships (RCSPs) to deploy large-scale field projects 
in different geologic settings across the country to demonstrate that 
GS can be achieved safely, permanently, and economically at large 
scales. Collectively, the seven RCSPs represent regions encompassing 97 
percent of coal-fired CO2 emissions, 97 percent of 
industrial CO2 emissions, 96 percent of the total land mass, 
and essentially all the geologic sequestration sites in the United 
States potentially available for GS.\381\ The seven partnerships 
include more than 400 organizations spanning 43 states (and four 
Canadian provinces).\382\ RCSP project objectives are to inject at 
least one million metric tons of CO2. In April 2015, DOE 
announced that CCS projects supported by the department have safely and 
permanently stored 10 million metric tons of CO2.\383\
---------------------------------------------------------------------------

    \381\ http://energy.gov/fe/science-innovation/carbon-capture-and-storage-research/regional-partnerships.
    \382\ http://energy.gov/fe/science-innovation/carbon-capture-and-storage-research/regional-partnerships.
    \383\ http://energy.gov/articles/milestone-energy-department-projects-safely-and-permanently-store-10-million-metric-tons.
---------------------------------------------------------------------------

    Eight RCSP ``Development Phase'' projects have been initiated and 
five of the eight projects are injecting or have completed 
CO2 injection into deep saline formations. Three of these 
projects have already injected more than one million metric tons each, 
and one, the Cranfield Site, injected over eight million metric tons of 
CO2 between 2009 and 2013.\384\ Various types of 
technologies for monitoring CO2 in the subsurface and air 
have been employed at these projects, such as seismic methods 
(crosswell seismic, 3-D and 4-D seismic, and vertical seismic 
profiling), atmospheric CO2 monitoring, soil gas sampling, 
well and formation pressure monitoring, and surface and ground water 
monitoring.\385\ No CO2 leakage has been reported from these 
sites, which further supports the availability of effective GS.
---------------------------------------------------------------------------

    \384\ U.S. Department of Energy, National Energy Technology 
Laboratory, Project Facts, Southeast Regional Carbon Sequestration 
Partnership--Development Phase, Cranfield Site and Citronelle Site 
Projects, NT42590, October 2013. Available at: http://www.netl.doe.gov/publications/factsheets/project/NT42590.pdf.
    \385\ A description of the types of monitoring technologies 
employed at RCSP projects can be found here: http://www.netl.doe.gov/research/coal/carbon-storage/carbon-storage-infrastructure/regional-partnership-development-phase-iii.
---------------------------------------------------------------------------

3. Availability of CO2 Storage via EOR
    Although the determination that the BSER is adequately demonstrated 
and the regulatory impact analysis for this rule relies on GS in deep 
saline formations, the EPA also recognizes the potential for securely 
sequestering CO2 via EOR.
    EOR is a technique that is used to increase the production of oil. 
Approaches used for EOR include steam injection, injection of specific 
fluids such as surfactants and polymers, and gas injection including 
nitrogen and CO2. EOR using CO2, sometimes 
referred to as ``CO2 flooding'' or CO2-EOR, 
involves injecting CO2 into an oil reservoir to help 
mobilize the remaining oil to make it more amenable for recovery. The 
crude oil and CO2 mixture is then recovered and sent to a 
separator where the crude oil is separated from the gaseous 
hydrocarbons, native formation fluids, and CO2. The gaseous 
CO2-rich stream then is typically dehydrated, purified to 
remove hydrocarbons, re-compressed, and re-injected into the reservoir 
to further enhance oil recovery. Not all of the CO2 injected 
into the oil reservoir is recovered and re-injected. As the 
CO2 moves from the injection point to the production well, 
some of the CO2 becomes trapped in the small pores of the 
rock, or is dissolved in the oil and water that is not recovered. The 
CO2 that remains in the reservoir is not mobile and becomes 
sequestered.
    The amount of CO2 used in an EOR project depends on the 
volume and injectivity of the reservoir that is being flooded and the 
length of time the EOR project has been in operation. Initially, all of 
the injected CO2 is newly received. As discussed above, as 
the project matures, some CO2 is recovered with the oil and 
the recovered CO2 is separated from the oil and recycled so 
that it can be re-injected into the reservoir in addition to new 
CO2 that is received. If an EOR operator will not require 
the full volume of CO2 available from an EGU, the EGU has 
other options such as sending the CO2 to other EOR 
operators, or sending it to deep saline formation GS facilities.
    CO2 used for EOR may come from anthropogenic or natural 
sources. The source of the CO2 does not impact the 
effectiveness of the EOR operation. CO2 capture, treatment 
and processing steps provide a concentrated stream of CO2 in 
order to meet the needs of the intended end use. CO2 
pipeline specifications of the U.S. Department of Transportation 
Pipeline Hazardous Materials Safety Administration found at 49 CFR part 
195 (Transportation of Hazardous Liquids by Pipeline) apply regardless 
of the source of the CO2 and take into account 
CO2 composition, impurities, and phase behavior. 
Additionally, EOR operators and transport companies have specifications 
related to the composition of the CO2 stream. The regulatory 
requirements and company specifications ensure EOR operators receive a 
known and consistent CO2 stream.
    EOR has been successfully used at numerous production fields 
throughout the United States to increase oil recovery. The oil industry 
in the United States has over 40 years of experience with EOR. An oil 
industry study in 2014 identified more than 125 EOR projects in 98 
fields in the United States.\386\ More than half of the projects 
evaluated in the study have been in operation for more than 10 years, 
and many have been in operation for more than 30 years. This experience 
provides a strong foundation for demonstrating successful 
CO2 injection and monitoring technologies, which are needed 
for safe and secure GS (see Section N below) that can be used for 
deployment of CCS across geographically diverse areas.
---------------------------------------------------------------------------

    \386\ Koottungal, Leena, 2014, 2014 Worldwide EOR Survey, Oil & 
Gas Journal, Volume 112, Issue 4, April 7, 2014 (corrected tables 
appear in Volume 112, Issue 5, May 5, 2014).
---------------------------------------------------------------------------

    Currently, 12 states have active EOR operations and most have 
developed an extensive CO2 infrastructure, including 
pipelines, to support the continued operation and growth of EOR. An 
additional 18 states are within 100 kilometers (62 miles) of current 
EOR operations. See Figure 1 above. The vast majority of EOR is 
conducted in oil reservoirs in the Permian Basin, which extends through 
southwest Texas and southeast New Mexico. States where EOR is utilized 
include Alabama, Colorado, Louisiana, Michigan,

[[Page 64580]]

Mississippi, New Mexico, Oklahoma, Texas, Utah, and Wyoming. Several 
commenters raised concerns about the volume of CO2 used in 
EOR projects relative to the scale of EGU emissions and the demand for 
CO2 for EOR projects. At the project level, the volume of 
CO2 already injected for EOR and the duration of operations 
are of similar magnitude to the duration and volume of CO2 
expected to be captured from fossil fuel-fired EGUs. The volume of 
CO2 used in EOR operations can be large (e.g., 55 million 
tons of CO2 were stored in the SACROC unit in the Permian 
Basin over 35 years), and operations at a single oil field may last for 
decades, injecting into multiple parts of the field.\387\ According to 
data reported to the EPA's GHGRP, approximately 60 million metric tons 
of CO2 were supplied to EOR in the United States in 
2013.\388\ Approximately 70 percent of this total CO2 
supplied was produced from natural (geologic) CO2 sources 
and approximately 30 percent was captured from anthropogenic 
sources.\389\
---------------------------------------------------------------------------

    \387\ Han, Weon S., McPherson, B J., Lichtner, P C., and Wang, F 
P. ``Evaluation of CO2 trapping mechanisms at the SACROC 
northern platform, Permian basin, Texas, site of 35 years of 
CO2 injection.'' American Journal of Science 310. (2010): 
282-324.
    \388\ Greenhouse Gas Reporting Program, data reported as of 
August 18, 2014.
    \389\ Greenhouse Gas Reporting Program, data reported as of 
August 18, 2014.
---------------------------------------------------------------------------

    A DOE-sponsored study has analyzed the geographic availability of 
applying EOR in 11 major oil producing regions of the United States and 
found that there is an opportunity to significantly increase the 
application of EOR to areas outside of current operations.\390\ DOE-
sponsored geologic and engineering analyses show that expanding EOR 
operations into areas additional to the capacity already identified and 
applying new methods and techniques over the next 20 years could 
utilize 18 billion metric tons of anthropogenic CO2 and 
increase total oil production by 67 billion barrels. The study found 
that one of the limitations to expanding CO2 use in EOR is 
the lack of availability of CO2 in areas where reservoirs 
are most amenable to CO2 flooding.\391\ DOE's Carbon 
Utilization and Storage Atlas identifies 29 states with oil reservoirs 
amenable to EOR, 12 of which currently have active EOR operations. A 
comparison of the current states with EOR operations and the states 
with potential for EOR shows that an opportunity exists to expand the 
use of EOR to regions outside of current areas. The availability of 
anthropogenic CO2 in areas outside of current sources could 
drive new EOR projects by making more CO2 locally available.
---------------------------------------------------------------------------

    \390\ ``Improving Domestic Energy Security and Lowering 
CO2 Emissions with ``Next Generation'' CO2-
Enhanced Oil Recovery'', Advanced Resources International, Inc. 
(ARI), 2011. Available at: http://www.netl.doe.gov/research/energy-analysis/publications/details?pub=df02ffba-6b4b-4721-a7b4-04a505a19185.
    \391\ ``Improving Domestic Energy Security and Lowering 
CO2 Emissions with ``Next Generation'' CO2-
Enhanced Oil Recovery'', Advanced Resources International, Inc. 
(ARI), 2011. Available at: http://www.netl.doe.gov/research/energy-analysis/publications/details?pub=df02ffba-6b4b-4721-a7b4-04a505a19185.
---------------------------------------------------------------------------

    Some commenters raised concerns that data are extremely limited on 
the extent to which EOR operations permanently sequester 
CO2, and the efficacy of long term storage, or that the EOR 
industry does not have the requisite experience with and technical 
knowledge of long-term CO2 sequestration. The EPA disagrees 
with these commenters. Several EOR sites, which have been operated for 
years to decades, have been studied to evaluate the viability of safe 
and secure long-term sequestration of injected CO2. Examples 
are identified below.
    CO2 has been injected in the SACROC Unit in the Permian 
basin since 1972 for EOR purposes. One study evaluated a portion of 
this project, and estimated that the injection operations resulted in 
final sequestration of about 55 million tons of CO2.\392\ 
This study used modeling and simulations, along with collection and 
analysis of seismic surveys, and well logging data, to evaluate the 
ongoing and potential CO2 trapping occurring through various 
mechanisms. The monitoring at this site demonstrated that 
CO2 can become trapped in geologic formations. In a separate 
study in the SACROC Unit, the Texas Bureau of Economic Geology 
conducted an extensive groundwater sampling program to look for 
evidence of CO2 leakage in the shallow freshwater aquifers. 
No evidence of leakage was detected.\393\
---------------------------------------------------------------------------

    \392\ Han, Weon S., McPherson, B J., Lichtner, P C., and Wang, F 
P. ``Evaluation of CO2 trapping mechanisms at the SACROC 
northern platform, Permian basin, Texas, site of 35 years of 
CO2 injection.'' American Journal of Science 310. (2010): 
282-324.
    \393\ Romanak, K.D., Smyth, R.C., Yang, C., and Hovorka, S., 
Detection of anthropogenic CO2 in dilute groundwater: 
field observations and geochemical modeling of the Dockum aquifer at 
the SACROC oilfield, West Texas, USA: presented at the 9th Annual 
Conference on Carbon Capture & Sequestration, Pittsburgh, PA, May 
10-13, 2010. GCCC Digital Publication Series #10-06.
---------------------------------------------------------------------------

    The International Energy Agency Greenhouse Gas Programme conducted 
an extensive monitoring program at the Weyburn oil field in 
Saskatchewan between 2000 and 2010 (the site receiving CO2 
captured by the Dakota Gasification synfuel plant discussed in Section 
V.E.2.a above). During that time over 16 million metric tons of 
CO2 were safely sequestered as evidenced by soil gas 
surveys, shallow groundwater monitoring, seismic surveys and wellbore 
integrity testing. An extensive shallow groundwater monitoring program 
revealed no significant changes in water chemistry that could be 
attributed to CO2 storage operations.\394\ The International 
Energy Agency Greenhouse Gas Programme developed a best practices 
manual for CO2 monitoring at EOR sites based on the 
comprehensive analysis of surface and subsurface monitoring methods 
applied over the 10 years.\395\
---------------------------------------------------------------------------

    \394\ Roston, B., and S. Whittaker (2010), 10+ years of the IEA-
GHG Weyburn-Midale CO2 monitoring and storage project; 
success and lessons learned from multiple hydrogeological 
investigations, to be published in Energy Procedia, Elsevier, 
Proceedings of 10th International Conference on Greenhouse Gas 
Control Technologies, IEA Greenhouse Gas Programme, Amsterdam, The 
Netherlands.
    \395\ Hitchon, B. (Editor), 2012, Best Practices for Validating 
CO2 Geological Storage: Geoscience Publishing, p. 353.
---------------------------------------------------------------------------

    The Texas Bureau of Economic Geology also has been testing a wide 
range of surface and subsurface monitoring tools and approaches to 
document sequestration efficiency and sequestration permanence at the 
Cranfield oilfield in Mississippi (see Section L.1 above).\396\ As part 
of a DOE Southeast Regional Carbon Sequestration Partnership study, 
Denbury Resources injected CO2 into a depleted oil and gas 
reservoir at a rate greater than 1.2 million tons/year. Texas Bureau of 
Economic Geology is currently evaluating the results of several 
monitoring techniques employed at the Cranfield project and preliminary 
findings indicate no impact to groundwater.\397\ The project also 
demonstrates the availability and effectiveness of many different 
monitoring techniques for tracking CO2 underground and 
detecting CO2 leakage to ensure CO2 remains 
safely sequestered.
---------------------------------------------------------------------------

    \396\ http://www.beg.utexas.edu/gccc/cranfield.php.
    \397\ http://www.beg.utexas.edu/gccc/cranfield.php.
---------------------------------------------------------------------------

    As discussed in Section M.1 above and as shown in Figure 1, the 
United States has widespread potential for storage, including in deep 
saline formations and oil and gas formations. However, some commenters 
maintained that the EPA's information regarding availability of GS 
sites is overly general and ignores important individual 
considerations. A number of commenters, for example, maintained that 
site conditions often make monitoring difficult or impossible, so

[[Page 64581]]

that sites are not available as a practical matter.\398\ Commenter 
American Electric Power pointed to its own experience in siting 
monitoring wells for its pilot plant Mountaineer CCS project, which 
involved protracted time and expense to eventually site monitoring 
wells.\399\ Other commenters noted significant geographic disparity in 
GS site availability, claiming absence of sites in southeastern areas 
of the country.\400\
---------------------------------------------------------------------------

    \398\ Comments of Southern Co., p. 38 (Docket entry: EPA-HQ-OAR-
2013-0495-10095).
    \399\ Comments of AEP pp. 93, 96 (Docket entry: EPA-HQ-OAR-2013-
0495-10618).
    \400\ Comments of Duke Energy, pp. 24-5 Docket entry: EPA-HQ-
OAR-2013-0495-9426); UARG, pp. 53, 57 (Docket entry: EPA-HQ-OAR-
2013-0495-9666) citing Cichanowicz (2012).
---------------------------------------------------------------------------

    Project- and site-specific factors do influence where 
CO2 can be safely sequestered. However, as outlined above, 
there is widespread potential for GS in the United States. If an area 
does not have a suitable GS site, EGUs can either transport 
CO2 to GS sites via CO2 pipelines (see Section 
M.5 below), or they may choose to locate their units closer to GS sites 
and provide electric power to customers through transmission lines (see 
Figure 2 and Section M.7). In addition, there are alternative means of 
complying with the final standards of performance that do not 
necessitate use of partial CCS, so any siting difficulties based on 
lack of a CO2 repository would be obviated. See Portland 
Cement Ass'n v. EPA, 665 F. 3d 177, 191 (D.C. Cir. 2011), holding that 
the EPA could adopt section 111 standards of performance based on the 
performance of a kiln type that kilns of older design would have great 
difficulty satisfying, since, among other things, there were 
alternative methods of compliance available should a new kiln of this 
older design be built.
4. Alternatives to Geologic Sequestration
    Potential alternatives to sequestering CO2 in geologic 
formations are emerging. These relatively new potential alternatives 
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. PCC is produced through 
a chemical reaction process that utilizes calcium oxide (quicklime), 
water, and CO2. Likewise, the combination of magnesium oxide 
and CO2 results in a precipitation reaction where the 
CO2 becomes mineralized. The carbonate materials produced 
can be tailored to optimize performance in specific industrial and 
commercial applications. 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 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, sodium bicarbonate, hydrochloric acid and bleach.\401\
---------------------------------------------------------------------------

    \401\ http://skyonic.com/technologies/skymine.
---------------------------------------------------------------------------

    A few commenters suggested that CO2 utilization 
technologies alternative to GS are being commercialized, and that these 
should be included as compliance options for this rule. The rule 
generally requires that captured CO2 be either injected on-
site for geologic sequestration or transferred offsite to a facility 
reporting under 40 CFR subpart RR. The EPA does not believe that the 
emerging technologies just discussed are sufficiently advanced to 
unqualifiedly structure this final rule to allow for their use. Nor are 
there plenary systems of regulatory control and GHG reporting for these 
approaches, as there are for geologic sequestration. Nonetheless, as 
stated above, these technologies not only show promise, but could 
potentially be demonstrated to show permanent storage of 
CO2.
    In the January 2014 proposal, the EPA noted that it would need to 
adopt a mechanism to evaluate these alternative technologies before any 
could be used in lieu of geologic sequestration. 79 FR at 1484. The EPA 
is establishing such a mechanism in this final rule. See Sec.  
60.5555(g). The rule provides for a case-by-case adjudication by the 
EPA of applications seeking to demonstrate to the EPA that a non-
geologic sequestration technology would result in permanent confinement 
of captured CO2 from an affected EGU. The criteria to be 
addressed in the application, and evaluated by the EPA, are drawn from 
CAA section 111(j), which provides an analogous mechanism for case-by-
case approval of innovative technological systems of continuous 
emission reduction which have not been adequately demonstrated. 
Applicants would need to demonstrate that the proposed technology would 
operate effectively, and that captured CO2 would be 
permanently stored. Applicants must also demonstrate that the proposed 
technology will not cause or contribute to an unreasonable risk to 
public health, welfare or safety. In evaluating applications, the EPA 
may conduct tests itself or require the applicant to conduct testing in 
support of its application. Any application would be publicly noticed, 
and the EPA would solicit comment on the application and on intended 
action the EPA might take. The EPA could also provide a conditional 
approval of an application on operating results from a proscribed 
period. The EPA could also terminate an approval, including a 
termination based on operating results calling into question a 
technology's effectiveness.
    As noted at proposal, given the unlikelihood of new coal-fired EGUs 
being constructed, the EPA does not expect there to be many (if any) 
applications for use of non-geologic sequestration technology. 79 FR at 
1484.
5. Availability of Existing or Planned CO2 Pipelines
    CO2 pipelines are the most economical and efficient 
method of transporting large quantities of CO2.\402\ 
CO2 has been transported via pipelines in the United States 
for nearly 40 years. Over this time, the design, construction, 
operation, and safety requirements for CO2 pipelines have 
been proven, and the U.S. CO2 pipeline network has been 
safely used and expanded. The Pipeline and Hazardous Materials Safety 
Administration (PHMSA) reported that in 2013 there were 5,195 miles of 
CO2 pipelines operating in the United States. This 
represents a seven percent increase in CO2 pipeline miles 
over the previous year and a 38 percent increase in CO2 
pipeline miles since 2004.\403\
---------------------------------------------------------------------------

    \402\ Report of the Interagency Task Force on Carbon Capture and 
Storage (August 2010), page 36.
    \403\ ``Annual Report Mileage for Hazardous Liquid or Carbon 
Dioxide Systems'', U.S. Pipeline and Hazardous Materials Safety 
Administration, March 2, 2015. Available at: http://www.phmsa.dot.gov/pipeline/library/data-stats.
---------------------------------------------------------------------------

    Some commenters argued that the existing CO2 pipeline 
capacity is not adequate and that CO2 pipelines are not 
available in a majority of the United States.
    The EPA does not agree. The CO2 pipeline network in the 
United States has almost doubled in the past ten years in order to meet 
growing demands for CO2 for EOR. CO2 transport 
companies have recently proposed initiatives to expand the 
CO2 pipeline network. Several hundred miles of dedicated 
CO2 pipeline are under construction, planned, or proposed, 
including

[[Page 64582]]

projects in Colorado, Louisiana, Montana, New Mexico, Texas, and 
Wyoming.
    Examples are identified below.
    Kinder Morgan has reported several proposed pipeline projects 
including the proposed expansion of the existing Cortez CO2 
pipeline, crossing Colorado, New Mexico, and Texas, to increase the 
CO2 transport capacity from 1.35 billion cubic feet per day 
(Bcf/d) to 1.7 Bcf/d, to support the expansion of CO2 
production capacity at the McElmo Dome production facility in Colorado. 
The Cortez pipeline expansion is expected to be placed into service in 
2015.\404\
---------------------------------------------------------------------------

    \404\ ``Form 10-K: Annual Report Pursuant to Section 13 or 15(d) 
of the Security and Exchange Act of 1934, For the Fiscal Year Ended 
December 31, 2014'', Kinder Morgan, February 2015. Available at: 
http://ir.kindermorgan.com/sites/kindermorgan.investorhq.businesswire.com/files/report/additional/KMI-2014-10K_Final.pdf.
---------------------------------------------------------------------------

    Denbury reported that the company utilized approximately 70 million 
cubic feet per day of anthropogenic CO2 in 2013 and that an 
additional approximately 115 million cubic feet per day of 
anthropogenic CO2 may be utilized in the future from 
currently planned or future construction of facilities and associated 
pipelines in the Gulf Coast region.\405\ Denbury also initiated 
transport of CO2 from a Wyoming natural gas processing plant 
in 2013 and reported transporting approximately 22 million cubic feet 
per day of CO2 in 2013 from that plant alone.\406\
---------------------------------------------------------------------------

    \405\ ``2013 Annual Report'', Denbury, April 2014. Available at 
http://www.denbury.com/files/doc_financials/2013/Denbury_Final_040814.pdf.
    \406\ ``CO2 Sources'', Denbury, 2015. Available at: 
http://www.denbury.com/operations/rocky-mountain-region/co2-sources-and-pipelines/default.aspx.
---------------------------------------------------------------------------

    Denbury completed the final section of the 325-mile Green Pipeline 
for transporting CO2 from Donaldsonville, Louisiana, to EOR 
oil fields in Texas.\407\ Denbury completed construction and commenced 
operation of the 232-mile Greencore Pipeline in 2013; the Greencore 
pipeline transports CO2 to EOR fields in Wyoming and 
Montana.\408\
---------------------------------------------------------------------------

    \407\ http://www.denbury.com/operations/gulf-coast-region/Pipelines/default.aspx.
    \408\ ``CO2 Pipelines'', Denbury, 2014. Available at: 
http://www.denbury.com/operations/rocky-mountain-region/COsub2-sub-Pipelines/default.aspx.
---------------------------------------------------------------------------

    A project being constructed by NRG and JX Nippon Oil & Gas 
Exploration (Petra Nova) would capture CO2 from a power 
plant in Fort Bend County, Texas for transport to EOR sites in Jackson 
County, Texas through an 82-mile CO2 pipeline.\409\ The 
project is anticipated to commence operation in 2016.\410\
---------------------------------------------------------------------------

    \409\ ``The West Ranch CO2-EOR Project, NRG Fact 
Sheet'', NRG, 2014. Available at: www.nrg.com/documents/business/pla-2014-west-ranch-fact-sheet.pdf.
    \410\ ``WA Parish Carbon Capture Project'', NRG, 2015. Available 
at: www.nrg.com/sustainability/strategy/enhance-generation/carbon-capture/wa-parish-ccs-project/.
---------------------------------------------------------------------------

    Some commenters suggested that there may be challenges associated 
with the safety of transporting supercritical CO2 over long 
distances, or that the EPA did not adequately consider the potential 
non-air environmental impacts of the construction of CO2 
pipelines.
    The EPA has carefully evaluated the safety of pipelines used to 
transport captured CO2 and determined that pipelines can 
indeed convey captured CO2 to sequestration sites with 
certainty and provide full protection of human health and the 
environment. 76 FR at 48082-83 (Aug. 8, 2011); 79 FR 352, 354 (Jan. 3, 
2014). Existing and new CO2 pipelines are comprehensively 
regulated by the Department of Transportation's Pipeline Hazardous 
Material Safety Administration. The regulations govern pipeline design, 
construction, operation and maintenance, and emergency response 
planning. See generally 49 CFR 195.2. Additional regulations address 
pipeline integrity management by requiring heightened scrutiny to 
assure the quality of pipeline integrity in areas with a higher 
potential for adverse consequences. See 49 CFR 195.450 and 195.452. On-
site pipelines are not subject to the Department of Transportation 
standards, but rather adhere to the Pressure Piping standards of the 
American Society of Mechanical Engineers (ASME B31), which the EPA has 
found would ensure that piping and associated equipment meet certain 
quality and safety criteria sufficient to prevent releases of 
CO2, such that certain additional requirements were not 
necessary (See 79 FR 358-59 (Jan. 3, 2014)).\411\ These existing 
controls over CO2 pipelines assure protective management, 
guard against releases, and assure that captured CO2 will be 
securely conveyed to a sequestration site.
---------------------------------------------------------------------------

    \411\ See the B31 Code for pressure piping, developed by the 
American Society of Mechanical Engineers, Pipeline Transportation 
Systems for liquid hydrocarbons and other liquids.
---------------------------------------------------------------------------

6. States With Emission Standards That Would Require CCS
    Several states have established emission performance standards or 
other measures to limit emissions of GHGs from new EGUs that are 
comparable to or more stringent than the final standard in this 
rulemaking. For example, in September 2006, California Governor 
Schwarzenegger signed into law Senate Bill 1368. The law limits long-
term investments in base load generation by the state's utilities to 
power plants that meet an emissions performance standard jointly 
established by the California Energy Commission and the California 
Public Utilities Commission. The Energy Commission has designed 
regulations that establish a standard for new and existing base load 
generation owned by, or under long-term contract to publicly owned 
utilities, of 1,100 lb CO2/MWh.
    In May 2007, Washington Governor Gregoire signed Substitute Senate 
Bill 6001, which established statewide GHG emissions reduction goals, 
and imposed an emission standard that applies to any base load electric 
generation that commenced operation after June 1, 2008 and is located 
in Washington, whether or not that generation serves load located 
within the state. Base load generation facilities must initially comply 
with an emission limit of 1,100 lb CO2/MWh.
    In July 2009, Oregon Governor Kulongoski signed Senate Bill 101, 
which mandated that facilities generating base load electricity, 
whether gas- or coal-fired, must have emissions equal to or less than 
1,100 lb CO2/MWh, and prohibited utilities from entering 
into long-term purchase agreements for base load electricity with out-
of-state facilities that do not meet that standard.
    In 2012 New York established emission standards of CO2 
at 925 lb CO2/MWh for new and expanded base load fossil 
fuel-fired plants.
    In May 2007, Montana Governor Schweitzer signed House Bill 25, 
adopting a CO2 emissions performance standard for EGUs in 
the state. House Bill 25 prohibits the state Public Utility Commission 
from approving new EGUs primarily fueled by coal unless a minimum of 50 
percent of the CO2 produced by the facility is captured and 
sequestered.
    On January 12, 2009, Illinois Governor Blagojevich signed Senate 
Bill 1987, the Clean Coal Portfolio Standard Law. The legislation 
establishes emission standards for new power plants that use coal as 
their primary feedstock. From 2009-2015, new coal-fueled power plants 
must capture and store 50 percent of the carbon emissions that the 
facility would otherwise emit; from 2016-2017, 70 percent must be 
captured and stored; and after 2017, 90 percent must be captured and 
stored.
7. Coal-by-Wire
    In addition, as discussed in the proposal, electricity demand in 
states

[[Page 64583]]

that may not have geologic sequestration sites may be served by coal-
fired electricity generation built in nearby areas with geologic 
sequestration, and this electricity can be delivered through 
transmission lines. This method, known as ``coal-by-wire,'' has long 
been used in the electricity sector because siting a coal-fired power 
plant near the coal mine and transmitting the generation long distances 
to the load area is generally less expensive than siting the plant near 
the load area and shipping the coal long distances.
    For example, we noted in the proposal that there are many examples 
where coal-fired power generated in one state is used to supply 
electricity in other states. In the proposal we specifically noted that 
historically nearly 40 percent of the power for the City of Los Angeles 
was provided from two coal-fired power plants located in Arizona and 
Utah and Idaho Power, which serves customers in Idaho and Eastern 
Oregon, meets its demand in part from coal-fired power plants located 
in Wyoming and Nevada. 79 FR at 1478.
    In the Technical Support Document on Geographic Availability 
(Geographic Availability TSD), we explore in greater detail the issue 
of coal-by-wire and the ability of demand in areas without geologic 
sequestration to be served by coal generation located in areas that 
have access to geologic sequestration. Figure 1 of this preamble (a 
color version of which is provided as Figure 1 of the Geographic 
Availability TSD) depicts areas of the country with: (1) existing 
CO2 pipeline; (2) probable, planned, or under study 
CO2 pipeline; (3) counties with active CO2-EOR 
operations; (4) oil and natural gas reservoirs; (5) deep saline 
formations; (6) unmineable coal seams; and (7) areas 100 kilometers 
from geologic sequestration. As demonstrated by Figure 1, the vast 
majority of the country has existing or planned CO2 
pipeline, active CO2-EOR operations, the necessary geology 
for CO2 storage, or is within 100 kilometers of areas with 
geologic sequestration.\412\ A review of Figure 1 indicates limited 
areas that do not fall into these categories.
---------------------------------------------------------------------------

    \412\ The NETL cost estimates for CO2 transport 
assume a pipeline of 100 kilometers. NETL (2015) at p. 44.
---------------------------------------------------------------------------

    As an initial matter, we note that the data included in Figure 1 is 
a conservative outlook of potential areas available for the development 
of CO2 storage in that we include only areas that have been 
assessed to date. Portions of the United States--such as the State of 
Minnesota--have not yet been assessed and thus are depicted as not 
having geological formations suitable for CO2 storage, even 
though assessment could in fact reveal additional formations.\413\
---------------------------------------------------------------------------

    \413\ The data in Figure 1 is based on estimates compiled by the 
DOE's National Carbon Sequestration Database and Geographic 
Information System (NATCARB) and published in the United States 2012 
Carbon Utilization and Storage Atlas, Fourth Edition. As discussed 
in the TSD, deep saline formation potential was not assessed for 
Alaska, Connecticut, Hawaii, Massachusetts, Nevada, Rhode Island, 
and Vermont. Oil and gas storage potential was not assessed for 
Alaska, Washington, Nevada, and Oregon. Unmineable coal seams were 
not assessed for Nevada, Oregon, California, Idaho, and New York. We 
are assuming for purposes of our analysis here that they do not have 
storage potential in those formations.
---------------------------------------------------------------------------

    As one considers the areas on the map depicted in Figure 1 that 
fall outside of the above enumerated categories, in many instances, we 
find areas with low population density, areas that are already served 
by transmission lines that could deliver coal-by-wire, and/or areas 
that have made policy or other decisions not to pursue a resource mix 
that includes coal. In many of these areas, utilities, electric 
cooperatives, and municipalities have a history of joint ownership of 
coal-fired generation outside the region or contracting with coal and 
other generation in outside areas to meet their demand. Some of the 
relevant areas are in RTOs \414\ which engage in planning across the 
RTO, balancing supply and demand in real time throughout the RTO. 
Accordingly, generating resources in one part of the RTO such as a coal 
generator can serve load in other parts of the RTO, as well as load 
outside of the RTO. As we consider each of these geographic areas in 
the Geographic Availability TSD, we make key points as to why this 
final rule does not negatively impact the ability of these regions to 
access new coal generation to the extent that coal is needed to supply 
demand and/or those regions want to include new coal-fired generation 
in their resource mix.
---------------------------------------------------------------------------

    \414\ In this discussion, we use the term RTO to indicate both 
ISOs and RTOs.
---------------------------------------------------------------------------

N. Final Requirements for Disposition of Captured CO2

    This section discusses the different regulatory components, already 
in place, that assure the safety and effectiveness of GS. This section, 
by demonstrating that GS is already covered by an effective regulatory 
structure, complements the analysis of the technical feasibility of GS 
contained in Sec. V.M. Together, these sections affirm that the 
technical feasibility of GS is adequately demonstrated.
    In 2010, the EPA finalized an effective and coherent regulatory 
framework to ensure the long-term, secure and safe storage of large 
volumes of CO2. The EPA developed these Underground 
Injection Control (UIC) Class VI well regulations under authority of 
the Safe Drinking Water Act (SDWA) to facilitate injection of 
CO2 for GS, while protecting human health and the 
environment by ensuring the protection of underground sources of 
drinking water (USDWs). The Class VI regulations are built upon 35 
years of federal experience regulating underground injection wells, and 
many additional years of state UIC program expertise. The EPA and 
states have decades of UIC experience with the Class II program, which 
provides a regulatory framework for the protection of USDWs for 
CO2 injected for purposes of EOR.
    In addition, to complement both the Class VI and Class II rules, 
the EPA used CAA authority to develop air-side monitoring and reporting 
requirements for CO2 capture, underground injection, and 
geologic sequestration through the GHGRP. Information collected under 
the GHGRP provides a transparent means for the EPA and the public to 
continue to evaluate the effectiveness of GS.
    As explained below, these requirements help ensure that sequestered 
CO2 will remain in place, and, using SDWA and CAA 
authorities, provide the monitoring mechanisms to identify and address 
potential leakage. We note the near consensus in the public responses 
to the Class VI rulemaking that saline and oil and gas reservoirs 
provide ready means for secure GS of CO2.\415\
---------------------------------------------------------------------------

    \415\ In that rulemaking, we stated that ``most commenters 
encouraged the EPA not to automatically exclude any potential 
injection formations for GS at this stage of deployment.'' We added 
that commenters suggested, in particular, ``that there is sufficient 
technical basis and scientific evidence to allow GS in depleted oil 
and gas reservoirs and in saline formations, noting that there is 
consensus on how to inject into these formation types.'' 75 FR at 
77252 (Dec. 10, 2010).
---------------------------------------------------------------------------

1. Requirements for UIC Class VI and Class II Wells
    Under SDWA, the EPA developed the UIC Program to regulate the 
underground injection of fluids in a manner that ensures protection of 
USDWs. UIC regulations establish six different well classes that manage 
a range of injectates (e.g., industrial and municipal wastes; fluids 
associated with oil and gas activities; solution mining fluids; and 
CO2 for geologic sequestration) and which accommodate 
varying geologic, hydrogeological, and other conditions. The standards 
apply to injection into any type of formation that meets the rule's 
rigorous criteria, and so apply not only to injection into deep

[[Page 64584]]

saline formations, but also can apply to injection into unmineable coal 
seams and other formations. See 75 FR 77256 (Dec. 10, 2010).
    The EPA's UIC regulations define the term USDWs to include current 
and future sources of drinking water and aquifers that contain a 
sufficient quantity of ground water to supply a public water system, 
where formation fluids either are currently being used for human 
consumption or that contain less than 10,000 ppm total dissolved 
solids.\416\ UIC requirements have been in place for over three decades 
and have been used by the EPA and states to manage hundreds of 
thousands of injection wells nationwide.
---------------------------------------------------------------------------

    \416\ 40 CFR 144.3.
---------------------------------------------------------------------------

a. Class VI Requirements
    In 2010, the EPA established a new class of well, Class VI. Class 
VI wells are used to inject CO2 into the subsurface for the 
purpose of long-term sequestration. See 75 FR 77230 (Dec. 10, 2010). 
This rule accounts for the unique nature of CO2 injection 
for large-scale GS. Specifically, the EPA addressed the unique 
characteristics of CO2 injection for GS including the large 
CO2 injection volumes anticipated at GS projects, relative 
buoyancy of CO2, its mobility within subsurface geologic 
formations, and its corrosivity in the presence of water. The UIC Class 
VI rule was developed to facilitate GS and ensure protection of USDWs 
from the particular risks that may be posed by large scale 
CO2 injection for purposes of long-term GS. The Class VI 
rule establishes technical requirements for the permitting, geologic 
site characterization, area of review (i.e., the project area) and 
corrective action, well construction, operation, mechanical integrity 
testing, monitoring, well plugging, post-injection site care, site 
closure, and financial responsibility for the purpose of protecting 
USDWs.\417\ Notably:
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    \417\ The Class VI rule rests on a robust technical and 
scientific foundation, reflecting scientific oversight and peer 
review. In developing these Class VI rules, the EPA engaged with the 
SAB, providing detailed information on key issues relating to 
geologic sequestration--including monitoring schemes; methods to 
predict and verify capacity, injectivity, and effectiveness of 
subsurface CO2 storage; and characterization and 
management of risks associated with plume migration and pressure 
increases in the subsurface. See: http://yosemite.epa.gov/sab/sabproduct.nsf/0/AD09B42B75D9E36D85257704004882CF?OpenDocument. In 
addition, the EPA developed a peer reviewed Vulnerability Evaluation 
Framework, which served as a technical support document for both the 
Class VI and Subpart RR rules. See: http://www.epa.gov/climatechange/Downloads/ghgemissions/VEF-Technical_Document_072408.pdf. In the section 111(b) rulemaking 
here, the SAB Work Group, in a letter endorsed by the full SAB 
Committee, found that ``while the scientific and technical basis for 
carbon storage provisions is new and emerging science, the agency is 
using the best available science and has conducted peer review at a 
level required by agency guidance.'' Memorandum of Jan. 7, 2014, 
from SAB Work Group Chair to Members of the Chartered SAB and SAB 
Liaisons, p. 3. The letter was subsequently endorsed by the full 
SAB. Work Group Letter of Jan. 24, 2014, as edited by the full 
Committee.
---------------------------------------------------------------------------

    Site characterization includes assessment of the geologic, 
hydrogeologic, geochemical, and geomechanical properties of a proposed 
GS site to ensure that Class VI wells are sited in appropriate 
locations and CO2 streams are injected into suitable 
formations with a confining zone or zones free of transmissive faults 
or fractures to ensure USDW protection.418 419 Site 
characterization is designed to eliminate unacceptable sites that may 
pose risks to USDWs. Generally, injection of CO2 for GS 
should occur beneath the lowermost formation containing a USDW.\420\ To 
increase the availability of Class VI sites in geographic areas with 
very deep USDWs, waivers from the injection depth requirements may be 
sought where owners or operators can demonstrate USDW protection.\421\
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    \418\ 75 FR 77240 and 75 FR 77247 (December 10, 2010).
    \419\ 40 CFR 146.82 and 146.83. Comments indicating that EPA 
rules have not considered issues of exposure pathways such as 
abandoned wells or formation fissures are mistaken. (See, e.g., 
Comments of UARG, p. 52 (Docket entry: EPA-HQ-OAR-2013-0495-9666).)
    \420\ 40 CFR 146.81(d).
    \421\ 40 CFR 146.95.
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    Owners or operators of Class VI wells must delineate the project 
area of review using computational modeling that accounts for the 
physical and chemical properties of the injected CO2 and 
displaced fluids and is based on an iterative process of available site 
characterization, monitoring, and operational data.\422\ Within the 
area of review, owners or operators must identify and evaluate all 
artificial penetrations to identify those that need corrective action 
to prevent the movement of CO2 or other fluids into or 
between USDWs.423 424 Due to the potentially large size of 
the area of review for Class VI wells, corrective actions may be 
conducted on a phased basis during the lifetime of the project.\425\ 
Periodic reevaluation of the area of review is required and enables 
owners or operators to incorporate previously collected monitoring and 
operational data to verify that the CO2 plume and the 
associated area of elevated pressure are moving as predicted within the 
subsurface.\426\
---------------------------------------------------------------------------

    \422\ 40 CFR 146.84(a).
    \423\ 40 CFR 146.84(c)(1)(3) and 146.90(d)(1).
    \424\ 40 CFR 146.81(d) and 146.84.
    \425\ 40 CFR 146.84(b)(2)(iv).
    \426\ 40 CFR 146.84(e)(1).
---------------------------------------------------------------------------

    Well construction must use materials that can withstand contact 
with CO2 over the operational and post-injection life of the 
project.\427\ These requirements address the unique physical 
characteristics of CO2, including its buoyancy relative to 
other fluids in the subsurface and its potential corrosivity in the 
presence of water.
---------------------------------------------------------------------------

    \427\ 40 CFR 146.86(b).
---------------------------------------------------------------------------

    Requirements for operation of Class VI injection wells account for 
the unique conditions that will occur during large-scale GS including 
buoyancy, corrosivity, and high sustained pressures over long periods 
of operation.428 429
---------------------------------------------------------------------------

    \428\ 75 FR 77250-52 (December 10, 2010); see also id. at 77234-
35. Commenters were mistaken in asserting (without reference to 
Class VI provisions) that the EPA had ignored issues relating to 
CO2 properties when injected in large volumes in 
supercritical state into geologic formations.
    \429\ 40 CFR 146.88.
---------------------------------------------------------------------------

    Owners or operators of Class VI wells must develop and implement a 
comprehensive testing and monitoring plan for their projects that 
includes injectate analysis, mechanical integrity testing, corrosion 
monitoring, ground water and geochemical monitoring, pressure fall-off 
testing, CO2 plume and pressure front monitoring and 
tracking, and, at the discretion of the Class VI director, surface air 
and/or soil gas monitoring.\430\ Owners and operators must periodically 
review the testing and monitoring plan to incorporate operational and 
monitoring data and the most recent area of review reevaluation.\431\ 
Robust monitoring of the CO2 stream, injection pressures, 
integrity of the injection well, ground water quality and geochemistry, 
and monitoring of the CO2 plume and position of the pressure 
front throughout injection will ensure protection of USDWs from 
endangerment, preserve water quality, and allow for timely detection of 
any leakage of CO2 or displaced formation fluids.
---------------------------------------------------------------------------

    \430\ 40 CFR 146.90.
    \431\ 40 CFR 146.90(j).
---------------------------------------------------------------------------

    Although subsurface monitoring is the primary and effective means 
of determining if there are any risks to a USDW, the Class VI rule also 
authorizes the UIC Program Director to require surface air and/or soil 
gas monitoring on a site-specific basis. For example, the Class VI 
Director may require surface air/soil gas monitoring of the flux of 
CO2 out of the subsurface, with elevation of CO2 
levels above background serving as

[[Page 64585]]

an indicator of potential leakage and USDW endangerment.\432\
---------------------------------------------------------------------------

    \432\ 40 CFR 146.90(h)(1) and 75 FR at 77259 (Dec. 10, 2010).
---------------------------------------------------------------------------

    Class VI well owners or operators must develop and update a site-
specific, comprehensive emergency and remedial response plan that 
describes actions to be taken (e.g., cease injection) to address 
potential events that may cause endangerment to a USDW during the 
construction, operation, and post-injection site care periods of the 
project.\433\
---------------------------------------------------------------------------

    \433\ 40 CFR 146.94.
---------------------------------------------------------------------------

    Financial responsibility demonstrations are required to ensure that 
funds will be available for all area of review corrective action, 
injection well plugging, post-injection site care, site closure, and 
emergency and remedial response.\434\
---------------------------------------------------------------------------

    \434\ 40 CFR 146.85.
---------------------------------------------------------------------------

    Following cessation of injection, the operator must conduct 
comprehensive post-injection site care activities to show the position 
of the CO2 plume and the associated area of elevated 
pressure to demonstrate that neither poses an endangerment to 
USDWs.\435\ The injection well also must be plugged, and following a 
demonstration of non-endangerment of USDWs by the Class VI owner or 
operator, the site must be closed.436 437 The default 
duration for the post-injection site care period is 50 years, with 
flexibility for demonstrating that an alternative period is appropriate 
if it ensures non-endangerment of USDWs.\438\ Following successful 
closure, the facility property deed must record that the underlying 
land is used for GS.\439\
---------------------------------------------------------------------------

    \435\ 40 CFR 146.93.
    \436\ 40 CFR 146.92.
    \437\ 40 CFR 146.93.
    \438\ 40 CFR 146.93(b).
    \439\ 40 CFR 146.93(c).
---------------------------------------------------------------------------

    The EPA has completed technical guidance documents on Class VI well 
site characterization, area of review and corrective action, well 
testing and monitoring, project plan development, well construction, 
and financial responsibility.440 441 442 443 444 445 The EPA 
has also issued guidance documents on transitioning Class II wells to 
Class VI wells; well plugging, post-injection site care, and site 
closure; and recordkeeping, reporting, and data 
management.446 447 448 449
---------------------------------------------------------------------------

    \440\ http://water.epa.gov/type/groundwater/uic/class6/upload/epa816r13004.pdf.
    \441\ http://water.epa.gov/type/groundwater/uic/class6/upload/epa816r13005.pdf.
    \442\ http://water.epa.gov/type/groundwater/uic/class6/upload/epa816r13001.pdf.
    \443\ http://water.epa.gov/type/groundwater/uic/class6/upload/epa816r11017.pdf.
    \444\ http://water.epa.gov/type/groundwater/uic/class6/upload/epa816r11020.pdf.
    \445\ http://water.epa.gov/type/groundwater/uic/class6/upload/uicfinancialresponsibilityguidancefinal072011v.pdf.
    \446\ http://water.epa.gov/type/groundwater/uic/class6/upload/epa816p13004.pdf. See also 40 CFR 144.19 and ``Key Principles in 
EPA's Underground Injection Control Program Class VI Rule Related to 
Transition of Class II Enhanced Oil Recovery or Gas Recovery Wells 
to Class VI'', April 23, 2015, Available at: http://water.epa.gov/type/groundwater/uic/class6/upload/class2eorclass6memo.pdf.
    \447\ http://water.epa.gov/type/groundwater/uic/class6/upload/epa816p13005.pdf.
    \448\ http://water.epa.gov/type/groundwater/uic/class6/upload/epa816p13001.pdf.
    \449\ http://water.epa.gov/type/groundwater/uic/class6/upload/epa816p13002.pdf.
---------------------------------------------------------------------------

    To inform the development of the UIC Class VI rule, the EPA 
solicited stakeholder input and reviewed ongoing domestic and 
international GS research, demonstration, and deployment projects. The 
EPA also leveraged injection experience of the UIC Program, such as 
injection via Class II wells for EOR. A description of the work 
conducted by the EPA in support of the UIC Class VI rule can be found 
in the preamble for the final rule (see 75 FR 77230 and 77237-
240(December 10, 2010)).
    The EPA has issued Class VI permits for six wells under two 
projects. In September 2014, a UIC Class VI injection well permit (to 
construct) was issued by the EPA to Archer Daniels Midland for an 
ethanol facility in Decatur, Illinois. The goal of the project is to 
demonstrate the ability of the Mount Simon geologic formation, a deep 
saline formation, to accept and retain industrial scale volumes of 
CO2 for permanent GS. The permitted well has a projected 
operational period of five years, during which time 5.5 million metric 
tons of CO2 will be injected into an area of review with a 
radius of approximately 2 miles.\450\ Following the operational period, 
Archer Daniels Midland plans a post-injection site care period of ten 
years.\451\ In September 2014, the EPA also issued four Class VI 
injection well permits (to construct) to the FutureGen Industrial 
Alliance project in Jacksonville, Illinois, which proposed to capture 
CO2 emissions from a coal-fired power plant in Meredosia, 
Illinois and transport the CO2 by pipeline approximately 30 
miles to the deep saline GS site.\452\ The Alliance proposed to inject 
a total of 22 million metric tons of CO2 into an area of 
review with a radius of approximately 24 miles over the 20-year life of 
the project, with a post-injection site care period of fifty 
years.\453\
---------------------------------------------------------------------------

    \450\ http://www.epa.gov/region5/water/uic/adm/. In addition, 
Archer Daniels Midland received a UIC Class VI injection well permit 
for a second well in December 2014. Archer Daniels Midland had been 
injecting CO2 at this well since 2011 under a UIC Class I 
permit issued by the Illinois EPA.
    \451\ http://www.epa.gov/region5/water/uic/adm/.
    \452\ After permit issuance, and for reasons unrelated to the 
permitting proceeding, DOE initiated a structured closeout of 
federal support for the FutureGen project in February 2015. However, 
these are still active Class VI permits.
    \453\ http://www.epa.gov/r5water/uic/futuregen/.
---------------------------------------------------------------------------

    Both permit applicants addressed siting and operational aspects of 
GS (including issues relating to volumes of the CO2 and 
nature of the CO2 injectate), and included monitoring that 
helps provide assurance that CO2 will not migrate to 
shallower formations. The permits were based on findings that regional 
and local features at the site allow the site to receive injected 
CO2 in specified amounts without buildup of pressure which 
would create faults or fractures, and further, that monitoring provides 
early warning of any changes to groundwater or CO2 
leakage.\454\
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    \454\ http://www.epa.gov/r5water/uic/futuregen/; http://www.epa.gov/region5/water/uic/adm/.
---------------------------------------------------------------------------

    The permitting of these projects illustrates that permit applicants 
were able to address perceived challenges to issuance of Class VI 
permits. These permits demonstrate that these projects are capable of 
safely and securely sequestering large volumes of CO2--
including from steam generating units--for long-term storage since the 
EPA would not otherwise have issued the permits.
b. Class II Requirements
    As explained in Section M.3 above, CO2 has been injected 
into the subsurface via injection wells for EOR, boosting production 
efficiency by re-pressurizing oil and gas reservoirs and increasing the 
mobility of oil. There are decades of industry experience in operating 
EOR projects. The CO2 injection wells used for EOR are 
regulated through the UIC Class II program.\455\ CO2 storage 
associated with Class II wells is a common occurrence and 
CO2 can be safely stored where injected through Class II-
permitted wells for the purpose of enhanced oil or gas-related 
recovery.
---------------------------------------------------------------------------

    \455\ 40 CFR 144.6(b).
---------------------------------------------------------------------------

    UIC Class II regulations issued under section 1421 of SDWA provide 
minimum federal requirements for site characterization, area of review, 
well construction (e.g., casing and cementing), well operation (e.g., 
injection pressure), injectate sampling, mechanical integrity testing, 
plugging and abandonment, financial responsibility, and reporting. 
Class II wells must undergo periodic mechanical integrity testing which 
will detect well construction and operational

[[Page 64586]]

conditions that could lead to loss of injectate and migration into 
USDWs.
    Section 1425 of SDWA allows states to demonstrate that their 
program is effective in preventing endangerment of USDWs. These 
programs must include permitting, inspection, monitoring, record-
keeping, and reporting components.
2. Relevant Requirements of the GHGRP
    The GHGRP requires reporting of facility-level GHG data and other 
relevant information from large sources and suppliers in the United 
States. The final rules under 40 CFR part 60 specifically require that 
if an affected EGU captures CO2 to meet the applicable 
emissions 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 
reports in accordance with 40 CFR part 98, subpart RR (Geologic 
Sequestration of Carbon Dioxide). See Sec.  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.
    Specifically, subpart PP provides requirements to account for 
CO2 supplied to the economy. This subpart requires affected 
facilities with production process units that capture a CO2 
stream for purposes of supplying CO2 for commercial 
applications or that capture and maintain custody of a CO2 
stream in order to sequester or otherwise inject it underground to 
report the mass of CO2 captured and supplied to the 
economy.\456\ CO2 suppliers are required to report the 
annual quantity of CO2 transferred offsite and its end use, 
including GS.\457\
---------------------------------------------------------------------------

    \456\ 40 CFR 98.420(a)(1).
    \457\ 40 CFR 98.426.
---------------------------------------------------------------------------

    This 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.\458\
---------------------------------------------------------------------------

    \458\ 40 CFR 98.426(h).
---------------------------------------------------------------------------

    As noted, this final rule also requires that any affected EGU unit 
that captures CO2 to meet the applicable emissions limit 
must transfer the captured CO2 to a facility that reports 
under GHGRP subpart RR. In order to provide clarity on this 
requirement, the EPA reworded the proposed language under Sec.  
60.5555(f) to use the phrase ``If your affected unit captures 
CO2'' in place of the phrase ``If your affected unit employs 
geologic sequestration''. This revision is not a change from the EPA's 
initial intent.
    Reporting under subpart RR is required for all facilities that have 
received a Class VI UIC permit for injection of CO2.\459\ 
Subpart RR requires facilities meeting the source category definition 
(40 CFR 98.440) for any well or group of wells to report basic 
information on the mass of CO2 received for injection; 
develop and implement an EPA-approved monitoring, reporting, and 
verification (MRV) plan; report the mass of CO2 sequestered 
using a mass balance approach; and report annual monitoring 
activities.460 461 462 463 Although deep subsurface 
monitoring is the primary and effective means of determining if there 
are any leaks to a USDW, the monitoring employed under a subpart RR MRV 
Plan can be utilized, if required by the UIC Program Director, to 
further ensure protection of USDWs.\464\ The subpart RR MRV plan 
includes five major components:
---------------------------------------------------------------------------

    \459\ 40 CFR 98.440.
    \460\ 40 CFR 98.446.
    \461\ 40 CFR 98.448.
    \462\ 40 CFR 98.446(f)(9) and (10).
    \463\ 40 CFR 98.446(f)(12).
    \464\ See 75 FR at 77263 (Dec. 10, 2010).
---------------------------------------------------------------------------

    A delineation of monitoring areas based on the CO2 plume 
location. Monitoring may be phased in over time.\465\
---------------------------------------------------------------------------

    \465\ 40 CFR 98.448(a)(1).
---------------------------------------------------------------------------

    An identification and evaluation of the potential surface leakage 
pathways and an assessment of the likelihood, magnitude, and timing, of 
surface leakage of CO2 through these pathways. The 
monitoring program will be designed to address the risks 
identified.\466\
---------------------------------------------------------------------------

    \466\ 40 CFR 98.448(a)(2).
---------------------------------------------------------------------------

    A strategy for detecting and quantifying any surface leakage of 
CO2 in the event leakage occurs. Multiple monitoring methods 
and accounting techniques can be used to address changes in plume size 
and risks over time.\467\
---------------------------------------------------------------------------

    \467\ 40 CFR 98.448(a)(3).
---------------------------------------------------------------------------

    An approach for establishing the expected baselines for monitoring 
CO2 surface leakage. Baseline data represent pre-injection 
site conditions and are used to identify potential anomalies in 
monitoring data.\468\
---------------------------------------------------------------------------

    \468\ 40 CFR 98.448(a)(4).
---------------------------------------------------------------------------

    A summary of considerations made to calculate site-specific 
variables for the mass balance equation. Site-specific variables may 
include calculating CO2 emissions from equipment leaks and 
vented emissions of CO2 from surface equipment, and 
considerations for calculating CO2 from produced 
fluids.\469\
---------------------------------------------------------------------------

    \469\ 40 CFR 98.448(a)(5).
---------------------------------------------------------------------------

    Subpart RR provides a nationally consistent mass balance framework 
for reporting the mass of CO2 that is sequestered. Certain 
monitoring and operational data for a GS site is required to be 
reported to the EPA annually. More information on the MRV plan and 
annual reporting is available in the subpart RR final rule (75 FR 
75065; December 1, 2010) and its associated technical support 
document.\470\
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    \470\ Technical Support Document: ``General Technical Support 
Document for Injection and Geologic Sequestration of Carbon Dioxide: 
Subparts RR and UU'' (Docket EPA-HQ-OAR-2009-0926), November 2010.
---------------------------------------------------------------------------

    Under this final rule, any well receiving CO2 captured 
from an affected EGU, be it a Class VI or Class II well, must report 
under subpart RR.\471\ As explained below in Section V.N.5.a, a Class 
II well's UIC regulatory status does not change because it receives 
such CO2. Nor does it change by virtue of reporting under 
subpart RR.
---------------------------------------------------------------------------

    \471\ See Sec.  60.5555(f).
---------------------------------------------------------------------------

3. UIC and GHGRP Rules Provide Assurance To Prevent, Monitor, and 
Address Releases of Sequestered CO2 to Air
    Together the requirements of the UIC and GHGRP programs help ensure 
that sequestered CO2 will remain secure, and provide the 
monitoring mechanisms to identify and address potential leakage using 
SDWA and CAA authorities. The EPA designed the GHGRP subpart RR 
requirements for GS with consideration of UIC requirements. The 
monitoring required by GHGRP subpart RR is complementary to and builds 
on UIC monitoring and testing requirements. 75 FR 77263. Although the 
regulations for Class VI and Class II injection wells are designed to 
ensure protection of USDWs from endangerment the practical effect of 
these complementary technical requirements, as explained below, is that 
they also prevent releases of CO2 to the atmosphere.
    The UIC and GHGRP programs are built upon an understanding of the 
mechanisms by which CO2 is retained in geologic formations, 
which are well understood and proven.
    Structural and stratigraphic trapping is a physical trapping 
mechanism that occurs when the CO2 reaches a stratigraphic 
zone with low permeability (i.e., geologic confining

[[Page 64587]]

system) that prevents further upward migration.
    Residual trapping is a physical trapping mechanism that occurs as 
residual CO2 is immobilized in formation pore spaces as 
disconnected droplets or bubbles at the trailing edge of the plume due 
to capillary forces.
    Adsorption trapping is another physical trapping mechanism that 
occurs when CO2 molecules attach to the surfaces of coal and 
certain organic rich shales, displacing other molecules such as 
methane.
    Solubility trapping is a geochemical trapping mechanism where a 
portion of the CO2 from the pure fluid phase dissolves into 
native ground water and hydrocarbons.
    Mineral trapping is a geochemical trapping mechanism that occurs 
when chemical reactions between the dissolved CO2 and 
minerals in the formation lead to the precipitation of solid carbonate 
minerals.
a. Class VI Wells
    As just discussed in Section V.N.1, the UIC Class VI rule provides 
a framework to ensure the safety of underground injection of 
CO2 such that USDWs are not endangered. As explained below, 
protection against releases to USDWs likewise assures against releases 
to ambient air. Through the injection well permit application process, 
the Class VI permit applicant (i.e., a prospective Class VI well owner 
or operator) must demonstrate that the injected CO2 will be 
trapped and retained in the geologic formation, and not migrate out of 
the injection zone or the approved project area (i.e., the area of 
review). To assure that CO2 is confined within the injection 
zone, major components to be considered and included in Class VI 
permits are site characterization, area of review delineation and 
corrective action, well construction and operation, testing and 
monitoring, financial responsibility, post-injection site care, well 
plugging, emergency and remedial response, and site closure as 
described in Section V.N.1.
    Site characterization provides the foundation for successful GS 
projects. It includes evaluation of the chemical and physical 
mechanisms that will occur in the subsurface to immobilize and securely 
store the CO2 within the injection zone over the long-term 
(see above). Site characterization requires a detailed assessment of 
the geologic, hydrogeologic, geochemical, and geomechanical properties 
of the proposed GS site to ensure that wells are sited in suitable 
locations.\472\ Data and information collected during site 
characterization are used in the development of injection well 
construction and operating plans; provide inputs for modeling the 
extent of the injected CO2 plume and related pressure front; 
and establish baseline information to which geochemical, geophysical, 
and hydrogeologic site monitoring data collected over the life of the 
injection project can be compared.
---------------------------------------------------------------------------

    \472\ 40 CFR 146.82(a) and (c).
---------------------------------------------------------------------------

    The Class VI rules contain rigorous subsurface monitoring 
requirements to assure that the chosen site is functioning as 
characterized. This subsurface monitoring should detect leakage of 
CO2 before CO2 would reach the atmosphere. For 
example, when USDWs are present, they are generally located above the 
injection zone. If CO2 were to reach a USDW prior to being 
released to the atmosphere, the presence of CO2 or 
geochemical changes that would be caused by CO2 migration 
into unauthorized zones would be detected by a UIC Class VI monitoring 
program that is approved and periodically evaluated/adjusted based on 
permit conditions.
    Likewise, UIC Class VI mechanical integrity testing requirements 
are designed to confirm that a well maintains internal and external 
mechanical integrity. Continuous monitoring of the internal mechanical 
integrity of Class VI wells ensures that injection wells maintain 
integrity and serves as a way to detect problems with the well system. 
Mechanical integrity testing provides an early indication of potential 
issues that could lead to CO2 leakage from the confining 
zone, providing assurance and verification that CO2 will not 
reach the atmosphere.
    Further assurance is provided by the regulatory requirement that 
injection must cease if there is evidence that the injected 
CO2 and/or associated pressure front may cause endangerment 
to a USDW.\473\ Once the anomalous operating conditions are verified, 
the cessation of injection, as required by UIC permits, will minimize 
any risk of release to air.
---------------------------------------------------------------------------

    \473\ 40 CFR 146.94(b).
---------------------------------------------------------------------------

    Following cessation of injection, the operator must conduct 
comprehensive post-injection site care to show the position of the 
CO2 plume and the associated area of elevated pressure to 
demonstrate that neither poses an endangerment to USDWs--also having 
the practical effect of preventing releases of CO2 to the 
atmosphere. Post-injection site care includes appropriate monitoring 
and other needed actions (including corrective action). The default 
duration for the post-injection site care period is 50 years, with 
flexibility for demonstrating that an alternative period is appropriate 
if it ensures non-endangerment of USDWs.
    As the EPA has found, the UIC Class VI injection well requirements 
protect against releases from all exposure pathways. Specifically, the 
EPA stated that the Class VI rules ``[are] specifically designed to 
ensure that the CO2 (and any incidental associated 
substances derived from the source materials and the capture process) 
will be isolated within the injection zone.'' The EPA further stated 
that ``[t]he EPA concluded that the elimination of exposure routes 
through these requirements, which are implemented through a SDWA UIC 
permit, will ensure protection of human health and the environment. . 
.''.\474\
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    \474\ 79 FR at 353 (January 3, 2014) (Final Hazardous Waste 
Management System: Conditional Exclusion for Carbon Dioxide 
(CO2) Streams in Geologic Sequestration Activities under 
subtitle C of RCRA). See Section N.5.c below.
---------------------------------------------------------------------------

    GHGRP subpart RR complements these UIC Class VI requirements. 
Requirements under the UIC program are focused on demonstrating that 
USDWs are not endangered as a result of CO2 injection into 
the subsurface, while requirements under the GHGRP through subpart RR 
enable accounting for CO2 that is geologically sequestered. 
A methodology to account for potential leakage is developed as part of 
the subpart RR MRV plan (see Section V.N.2). The MRV plan submitted for 
subpart RR may describe (or provide by reference to the UIC permit) the 
relevant elements of the UIC permit (e.g. assessment of leakage 
pathways in the monitoring area) and how those elements satisfy the 
subpart RR requirements. The MRV plan required under subpart RR may 
rely upon the knowledge of the subsurface location of CO2 
and site characteristics that are developed in the permit application 
process, and operational monitoring results for UIC Class VI permitted 
wells.
    In summary, there are well-recognized physical mechanisms for 
storing CO2 securely. The comprehensive and rigorous site 
characterization requirements of the Class VI rules assure that sites 
with these properties are selected. Subsurface monitoring serves to 
assure that the sequestration site operates as intended, and this 
monitoring continues through a post-closure period. Although release of 
CO2 to air is unlikely and should be detected prior to 
release by subsurface monitoring, the subpart RR air-side monitoring 
and reporting regime

[[Page 64588]]

provides back up assurance that sequestered CO2 has not been 
released to the atmosphere.
b. Class II Wells
    The Class II rules likewise are designed to protect USDWs during 
EOR operation, including the injection of CO2 for EOR. For 
example, UIC Class II minimum federal requirements promulgated under 
SDWA address site characterization, area of review, well construction 
(e.g., casing and cementing), well operation (e.g., injection 
pressure), injectate sampling, mechanical integrity testing, plugging 
and abandonment, financial responsibility, and reporting. Class II 
wells must undergo periodic mechanical integrity testing which will 
detect well construction and operational conditions that could lead to 
loss of injectate and migration into USDWs. The establishment of 
maximum injection pressures, designed to ensure that the pressure in 
the injection zone during injection does not initiate new fractures or 
propagate existing fractures in the confining zone, prevents injection 
from causing the movement of fluids into an underground source of 
drinking water. The safeguards that protect USDWs also serve as an 
early warning mechanism for releases of CO2 to the 
atmosphere.
    CO2 injected via Class II wells becomes sequestered by 
the trapping mechanisms described above in this Section V.N.3. As with 
Class VI wells, for Class II wells that report under subpart RR, there 
is monitoring to evaluate whether CO2 used for EOR will 
remain safely in place both during and after the injection period. 
Subpart RR provides a CO2 accounting framework that will 
enable the EPA to assess both the project-level and national efficacy 
of geologic sequestration to determine whether additional requirements 
are necessary and, if so, inform the design of such regulations.
c. Response to Comments
    Commenters maintained that GS was not demonstrated for 
CO2 captured from EGUs. In addition, commenters noted that 
the volumes of captured CO2 would be considerably larger 
than from existing GS sites, and could quadruple amounts injected into 
Class II EOR wells. In addition to volumes of CO2 to be 
injected, commenters opined on the possibility of sporadic 
CO2 supply due to the nature of EGU operation.\475\
---------------------------------------------------------------------------

    \475\ See, e.g. Comments of Southern Company, p. 41 (Docket 
entry: EPA-HQ-OAR-2013-0495-10095).
---------------------------------------------------------------------------

    The EPA does not agree. CO2 capture from EGUs is 
demonstrated as discussed in Sections V.D and V.E. As discussed below, 
the volumes of CO2 are comparable to the amounts that have 
been injected at large scale commercial operations. The EPA also 
disagrees that the volume of CO2 would quadruple amounts 
injected into Class II EOR wells because CO2 may be 
sequestered in deep saline formations, which have widespread geographic 
availability (see Section M.1). The BSER determination and regulatory 
impact analysis for this rule relies on GS in deep saline 
formations.\476\ However, the EPA also recognizes the potential for 
sequestering CO2 via EOR and allows the use of EOR as a 
compliance option. According to data reported to the GHGRP, 
approximately 60 million metric tons of CO2 were supplied to 
EOR in the United States in 2013.\477\ Approximately 70 percent of 
total CO2 supplied in the United States was produced from 
geologic (natural) CO2 sources and approximately 30 percent 
was captured from anthropogenic sources. CO2 pipeline 
systems, such as those serving the Permian Basin, have multiple sources 
of CO2 that serve to levelize the pipeline supply, thus 
minimizing the effect of supply on the EOR operator.
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    \476\ The EPA anticipates EOR projects may be early GS projects 
because these formations have been previously well characterized for 
hydrocarbon recovery, likely already have suitable infrastructure 
(e.g., wells, pipelines, etc.), and have an associated economic 
benefit of oil production.
    \477\ Greenhouse Gas Reporting Program, data reported as of 
August 18, 2014.
---------------------------------------------------------------------------

    GS of anthropogenic CO2 in deep saline formations is 
demonstrated. First, as explained above, the EPA has issued 
construction permits under the Class VI program. It would not have done 
so, and under the regulations cannot have done so, without 
demonstrations that CO2 would be securely confined. One of 
these projects was for a steam generating EGU.
    Second, international experience with large scale commercial GS 
projects has demonstrated through extensive monitoring programs that 
large volumes of CO2 can be safely injected and securely 
sequestered for long periods of time at volumes and rates consistent 
with those expected under this rule. This experience has also 
demonstrated the value and efficacy of monitoring programs to determine 
the location of CO2 in the subsurface and detect potential 
leakage through the presence of CO2 in the shallow 
subsurface, near surface and air.
    The Sleipner CO2 Storage Project is located at an 
offshore gas field in the North Sea where CO2 must be 
removed from the natural gas in order to meet customer requirements and 
reduce costs. The project began injecting CO2 into the deep 
subsurface in 1996. The single offshore injection well injects 
approximately 1 million metric tons per year into a thick, permeable 
sandstone above the gas producing zone. Approximately 15 million metric 
tons of CO2 have been injected since inception. Many US and 
international organizations have conducted monitoring at Sleipner. The 
location and dimensions of the CO2 plume have been measured 
numerous times using 3-dimensional seismic monitoring since the 1994 
pre-injection survey. The monitoring data have demonstrated that 
although the plume is behaving differently than initially modeled due 
to thin layers of impermeable shale that were not initially identified 
in the reservoir model, the CO2 remains trapped in the 
injection zone. Numerous other techniques have been successfully used 
to monitor CO2 storage at Sleipner. The research and 
monitoring at Sleipner demonstrates the value of a comprehensive 
approach to site characterization, computational modeling and 
monitoring, as is required under UIC Class VI rules. The experience at 
Sleipner demonstrates that large volumes of CO2, of the same 
order of magnitude expected for an EGU, can be safely injected and 
stored in saline reservoirs over an extended period.
    Sn[oslash]hvit is another large offshore CO2 storage 
project, located at a gas field in the Barents Sea. Like Sleipner the 
natural gas must be treated to reduce high levels of CO2 to 
meet processing standards and reduce costs. Gas is transported via 
pipeline 95 miles to a gas processing and liquefied natural gas plant 
and the CO2 is piped back offshore for injection. 
Approximately 0.7 million metric tons per year CO2 are 
injected into permeable sandstone below the gas reservoir. Between 2008 
and 2011, the operator observed pressure increases in the injection 
formation (Tubaen Formation) greater than expected and conducted time 
lapse seismic surveys and studies of the injection zone and concluded 
that the pressure increase was mainly caused by a limited storage 
capacity in the formation.\478\ In 2011,

[[Page 64589]]

the injection well was modified and injection was initiated in a second 
interval (St[oslash] Formation) in the field to increase the storage 
capacity. Approximately 3 million metric tons of CO2 have 
been injected since 2008. Monitoring demonstrates that no leakage has 
occurred, again demonstrating that large volumes of CO2, of 
the same order of magnitude expected for an EGU, can be safely injected 
and stored in deep saline formations over an extended period.
---------------------------------------------------------------------------

    \478\ Grude, S. M. Landr[oslash]a, and J. Dvorkinb, 2014, 
Pressure effects caused by CO2 injection in the 
Tub[aring]en Fm., the Sn[oslash]hvit field. International Journal of 
Greenhouse Gas Control 27 (2014) 178-187. Commenters argued that the 
project had failed to sequester CO2, referring to the 
initial cessation of injection. See, e.g. Comments of UARG p. 56 
(Docket entry: EPA-HQ-OAR-2013-0495-9666). In fact, injection 
resumed successfully, as described in the text above.
---------------------------------------------------------------------------

    As discussed above in Sections V.E.2.a and M, CO2 from 
the Great Plains Synfuels plant in North Dakota has been injected into 
the Weyburn oil field in Saskatchewan Canada since 2000. Over that time 
period the project has injected more than 16 million metric tons of 
CO2. It is anticipated that approximately 40 million metric 
tons of CO2 will be permanently sequestered over the 
lifespan of the project. Extensive monitoring by U.S. and international 
partners has demonstrated that no leakage has occurred. The sources of 
CO2 for EOR may vary (e.g., industrial processes, power 
generation); however, this does not impact the effectiveness of EOR 
operations (see Section V.M.3).
    CO2 used for EOR may come from anthropogenic or natural 
sources. The source of the CO2 does not impact the 
effectiveness of the EOR operation. CO2 capture, treatment 
and processing steps provide a concentrated stream of CO2 in 
order to meet the needs of the intended end use. CO2 
pipeline specifications of the U.S. Department of Transportation 
Pipeline Hazardous Materials Safety Administration found at 49 CFR part 
195 (Transportation of Hazardous Liquids by Pipeline) apply regardless 
of the source of the CO2 and take into account 
CO2 composition, impurities, and phase behavior. 
Additionally, EOR operators and transport companies have specifications 
to ensure related to the composition of CO2. These 
requirements and specifications ensure EOR operators receive a known 
and consistent CO2 stream.
    At the In Salah CO2 storage project in Algeria, 
CO2 is removed from natural gas produced at three nearby gas 
fields in order to meet export quality specification. The 
CO2 is transported by pipeline approximately 3 miles to the 
injection site. Three horizontal wells are used to inject the 
CO2 into the down-dip aquifer leg of the gas reservoir 
approximately 6,200 feet deep. Between 2004 and 2011 over 3.8 million 
metric tons of CO2 were stored. Injection rates in 2010 and 
2011 were approximately 1 million metric tons per year. Storage 
integrity has been monitored by several U.S. and international 
organizations and the monitoring program has employed a wide range of 
geophysical and geochemical methods, including time lapse seismic, 
microseismic, wellhead sampling, tracers, down-hole logging, core 
analysis, surface gas monitoring, groundwater aquifer monitoring and 
satellite data. The data have been used to support periodic risk 
assessments during the operational phase of the project. In 2010 new 
data from seismic, satellite and geomechanical models were used to 
inform the risk assessment and led to the decision to reduce 
CO2 injection pressures due to risk of vertical leakage into 
the lower caprock, and risk of loss of well integrity. The caprock at 
the site consisted of main caprock units, providing the primary seal, 
and lower caprock units, providing additional buffers. There was no 
leakage from the well or through the caprock, but the risk analysis 
identified an increased risk of leakage, therefore, the aforementioned 
precautions were taken. Additional analysis of the reservoir, seismic 
and geomechanical data led to the decision to suspend CO2 
injection in June 2011. No leakage has occurred and the injected 
CO2 remains safely stored in the subsurface. The decision to 
proceed with safe shutdown of injection resulted from the analysis of 
seismic and geomechanical data to identify and respond to storage site 
risk. The In Salah project demonstrates the value of developing an 
integrated and comprehensive set of baseline site data prior to the 
start of injection, and the importance of regular review of monitoring 
data. Commenters also noted that the data collection and analysis had 
proven effective at preventing any release of sequestered 
CO2 to either underground drinking water sources or to the 
atmosphere.\479\
---------------------------------------------------------------------------

    \479\ ``It is important to note that although the In Salah 
project is no longer injecting CO2, the CCS community 
still views this early saline project as a success because the 
monitoring program served its intended purpose. That is, the 
monitoring methods deployed at this site informed the operator of a 
potential problem, leading to a shutdown of CO2 injection 
before the Caprock was breached.'' Comment of EPRI, p. 14 Docket 
entry: EPA-HQ-OAR-2013-0495-8925).
---------------------------------------------------------------------------

    These projects demonstrate that sequestration of CO2 
captured from industrial operations has been successfully conducted on 
a large scale and over relatively long periods of time. The volumes of 
captured CO2 are within the same order of magnitude as that 
expected from EGUs. Even though potentially adverse conditions were 
identified at some projects (In Salah and Sn[oslash]hvit), there were 
no releases to air and the monitoring systems were effective in 
identifying the issues in a timely manner, and these issues were 
addressed effectively. In each case, the site-specific characteristics 
were evaluated on a case-by-case basis to select a site where the 
geologic conditions are suitable to ensure long-term, safe storage of 
CO2. Each project was designed to address the site-specific 
characteristics and operated to successfully inject CO2 for 
safe storage.
4. Must the standard of performance for CO2 include CAA 
requirements on the sequestration site?
    One commenter maintained as a matter of law that a standard 
predicated on use of CCS is not a ``system of emission reduction'', and 
therefore is not a ``standard of performance'' within the meaning of 
section 111 (a)(1) of the Act. The commenter argued that the standard 
does not require sequestration of captured CO2 but only 
capture, so that no emission reductions are associated with the 
standard. A gloss on this argument is that there are no enforceable 
requirements for the captured CO2 (``[t]he fate of that 
[captured] CO2 is something that the proposed standard does 
not proscribe with enforceable requirements''). The commenter further 
argues that a ``system of emission reduction'' under section 111 must 
be ``designed into the new source itself'' so that off-site underground 
sequestration of captured CO2 emissions ``could never 
satisfy the statutory requirements governing a `standard of 
performance''' (emphasis original).\480\
---------------------------------------------------------------------------

    \480\ Comments of UARG, pp. 37-38 (Docket entry: EPA-HQ-OAR-
2013-0495-9666).
---------------------------------------------------------------------------

    The EPA disagrees with both the legal and factual assertions in 
this comment. As to the legal point, the commenter fails to distinguish 
capture and sequestration of carbon from every other section 111 
standard which is predicated on capture of a pollutant. Indeed, all 
emission standards not predicated on outright pollutant destruction 
involve capture of the pollutant and its subsequent disposition in the 
capturing medium. Thus, metals are captured in devices like baghouses 
or scrubbers, leaving a solid waste or wastewater to be managed. Gases 
can be captured with activated carbon or under pressure, again 
requiring further management of the captured pollutant(s). The EPA is 
required to consider these potential implications in promulgating an 
NSPS. See section 111(a)(1) (in promulgating a standard of performance 
under section 111, the EPA must ``tak[e] into account . . . any nonair 
quality health and environmental

[[Page 64590]]

impact''). The EPA thus considers such issues as solid waste and 
wastewater generation as part of determining if a system of emission 
reduction is ``best'' and ``adequately demonstrated'' under section 
111. See Section V.O below (discussion of this rule's potential cross-
media impacts).
    The further comment that the standard is arbitrary because it fails 
to impose any requirements on the captured CO2 is misplaced. 
The commenter mischaracterizes the standard as requiring capture only. 
The BSER is not just capturing a certain amount of CO2, but 
sequestering it. Sequestration can occur either on-site or off-site. 
Sequestration sites receiving and injecting the captured CO2 
are required to obtain UIC permits and report under subpart RR of the 
GHGRP. They must conduct comprehensive monitoring as part of these 
obligations. Although the NSPS does not impose regulatory requirements 
on the transportation pipeline or the sequestration site, such 
requirements already exist under other regulatory programs of the 
Department of Transportation and the EPA. In particular, the EPA is 
reasonably relying on the already-adopted, and very rigorous, Class VI 
well requirements in combination with the subpart RR requirements to 
provide secure sequestration of captured CO2. The EPA has 
also considered carefully the requirements and operating history of the 
Class II requirements for EOR wells, which, in combination with the 
subpart RR requirements, ensure protection of USDWs from endangerment, 
provide the monitoring mechanisms to identify and address potential 
leakage using SDWA and CAA authorities, and have the practical effect 
of preventing releases of CO2 to the atmosphere. This is 
analogous to the many section 111 standards of performance for metals 
which result in a captured air pollution control residue to be disposed 
of pursuant to waste management requirements of the rules implementing 
the Resource Conservation and Recovery Act. It is also analogous to the 
many section 111 standards of performance for metals or organics 
captured in wet air pollution control systems resulting in wastewater 
discharged to a navigable water where pollutant loadings are controlled 
under rules implementing the Clean Water Act. Again, these are non-air 
environmental impacts for which the EPA must account in establishing a 
section 111(a) standard. The EPA has reasonably done so here based on 
the regulatory regimes of the Class VI and Class II UIC requirements in 
combination with the monitoring regime of the subpart RR reporting 
rules, as well as the CO2 pipeline standards of the 
Department of Transportation.
    In this regard, the EPA notes that at proposal it acknowledged the 
possibility ``that there can be downstream losses of CO2 
after capture, for example during transportation, injection or 
storage.'' 79 FR at 1484. Given the rigorous substantive requirements 
and the monitoring required by the Class VI rules, the complementary 
monitoring regime of the subpart RR MRV plan and reporting rules, as 
well as the regulatory requirements for Class II wells, any such losses 
would be de minimis. Indeed, the same commenter maintained that the 
monitoring requirements of the Class VI rule are overly stringent and 
that a 50-year post-injection site care period is unnecessarily 
long.\481\ As it happens, as noted above, the Class VI rules allow for 
an alternative post-injection site care period based on a site-specific 
demonstration. See 40 CFR 146.93(b).
---------------------------------------------------------------------------

    \481\ Comments of UARG, p. 63 (Docket entry: EPA-HQ-OAR-2013-
0495-9666).
---------------------------------------------------------------------------

    The EPA addresses this comment in more detail in Chapter 2 of the 
Response-to-Comment Document.
5. Other Perceived Obstacles to Geologic Sequestration
a. Class II to Class VI transition
    A number of commenters maintained that the Class VI rules could 
effectively force all Class II wells to transition to Class VI wells if 
they inject anthropogenic CO2, and further maintained that, 
as a practical matter, this would render EOR unavailable for such 
CO2. The EPA disagrees with these comments. Injection of 
anthropogenic CO2 into Class II wells does not force 
transition of these wells to Class VI wells--not during the well's 
active operation and not when EOR operations cease. We recognize the 
widespread use of EOR and the expectation that injected CO2 
can remain underground. The EPA issued a memorandum to its regional 
offices on April 23, 2015 reflecting these principles: \482\
---------------------------------------------------------------------------

    \482\ ``Key Principles in EPA's Underground Injection Control 
Program Class VI Rule Related to Transition of Class II Enhanced Oil 
Recovery or Gas Recovery Wells to Class VI'', April 23, 2015. 
Available at: http://water.epa.gov/type/groundwater/uic/class6/upload/class2eorclass6memo.pdf.
---------------------------------------------------------------------------

    Geologic storage of CO2 can continue to be permitted 
under the UIC Class II program.
    Use of anthropogenic CO2 in EOR operations does not 
necessitate a Class VI permit.
    Class VI site closure requirements are not required for Class II 
CO2 injection operations.
    EOR operations that are focused on oil or gas production will be 
managed under the Class II program. If oil or gas recovery is no longer 
a significant aspect of a Class II permitted EOR operation, the key 
factor in determining the potential need to transition an EOR operation 
from Class II to Class VI is increased risk to USDWs related to 
significant storage of CO2 in the reservoir, where the 
regulatory tools of the Class II program cannot successfully manage the 
risk.\483\
---------------------------------------------------------------------------

    \483\ In this regard, the Class VI rules provide that, owners or 
operators that are injecting carbon dioxide for the primary purpose 
of long-term storage into an oil and gas reservoir must apply for 
and obtain a Class VI geologic sequestration permit when there is an 
increased risk to USDWs compared to Class II operations. 40 CFR 
144.19.
---------------------------------------------------------------------------

b. GHGRP Subpart RR
    A number of commenters maintained that no EOR operator would accept 
captured carbon from an EGU due to the reporting and other regulatory 
burdens imposed by the monitoring requirements of GHGRP subpart 
RR.\484\ They noted that preparing a subpart RR MRV plan could cost 
upwards of $100,000 which would be cost prohibitive given other 
available sources of CO2.
---------------------------------------------------------------------------

    \484\ See e.g., comments of UARG, p, 63 (Docket entry: EPA-HQ-
OAR-2013-0495-9666); Southern Co., p. 37 (Docket entry: EPA-HQ-OAR-
2013-0495-10095); American Petroleum Institute pp. 40-50 Docket 
entry: EPA-HQ-OAR-2013-0495-10098).
---------------------------------------------------------------------------

    The EPA disagrees with this comment in several respects. First, the 
BSER determination and regulatory impact analysis for this rule relies 
on GS in deep saline formations, not on EOR. However, the EPA also 
recognizes the potential for sequestering CO2 via EOR, but 
disagrees that subpart RR requirements effectively preclude or 
substantially inhibit the use of EOR.
    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. First, the costs 
associated with subpart RR are relatively modest, especially in 
comparison with revenues from an EOR field. In the economic impact 
analysis for subpart RR, the EPA estimated that an EOR project with a 
Class II permit would incur a first year cost of up to $147,030 to 
develop an MRV plan, and an annual cost of $27,787 to maintain the 
plan; the EPA estimated annual reporting and recordkeeping costs at 
$13,262 per year.\485\ Monitoring costs

[[Page 64591]]

are estimated to range from $0.02 per metric ton (base case scenario) 
to approximately $2 per metric ton of CO2 (high scenario). 
Using a range of scenarios (that included high end estimates), these 
subpart RR costs are approximately three to four percent of estimated 
revenues for an average EOR field, indicating that the costs can 
readily be absorbed. 75 FR 75073.
---------------------------------------------------------------------------

    \485\ Subpart RR costs are presented in 2008 US dollars.
---------------------------------------------------------------------------

    Furthermore, there is a demand for new CO2 by EOR 
operators, even beyond current natural sources of CO2. For 
example, in an April 2014 study, DOE concluded that future development 
of EOR will need to rely on captured CO2.\486\ Thus, the 
argument that EOR operators will obtain CO2 from other 
sources without triggering subpart RR responsibilities, which assumes 
adequate supplies of CO2 from other sources, lacks 
foundation. In addition, the Internal Revenue Code section 45Q provides 
a tax credit for CO2 sequestration which is far greater than 
subpart RR costs.\487\ In sum, the cost of complying with subpart RR 
requirements, including the cost of MRV, is not significant enough to 
deter EOR operators from purchasing EGU captured CO2.
---------------------------------------------------------------------------

    \486\ ``Near Term Projections of CO2 Utilization for 
Enhanced Oil Recovery''. DOE/NETL-2014/1648. April 2014.
    \487\ http://www.irs.gov/irb/2009-44_IRB/ar11.html. The section 
45Q tax credit for calendar year 2015 is $10.92 per metric ton of 
qualified CO2 that is captured and used in a qualified 
EOR project and $21.85 per metric ton of qualified CO2 
that is captured and used in a qualified non-EOR GS project. http://www.irs.gov/irb/2015-26_IRB/ar14.html.
---------------------------------------------------------------------------

    The EPA addresses these comments in more detail in the Response to 
Comment Document.
c. Conditional exclusion for geologic sequestration of CO2 streams 
under the Resource Conservation and Recovery Act (RCRA)
    Certain commenters voiced concerns that regulatory requirements for 
hazardous wastes might apply to captured CO2 and these 
requirements might be inconsistent with, or otherwise impede, GS of 
captured CO2 from EGUs. The EPA has acted to remove any such 
(highly conjectural) uncertainty. The Resource Conservation and 
Recovery Act (RCRA) authorizes the EPA to regulate the management of 
hazardous wastes. In particular, RCRA Subtitle C authorizes a cradle to 
grave regulatory program for wastes identified as hazardous, whether 
specifically listed as hazardous or whether the waste fails certain 
tests of hazardous characteristics. The EPA currently has little 
information to conclude that CO2 streams (defined in the 
RCRA exclusion rule as including incidental associated substances 
derived from the source materials and the capture process, and any 
substances added to the stream to enable or improve the injection 
process) might be identified as ``hazardous wastes'' subject to RCRA 
Subtitle C regulation.\488\ Nevertheless, to reduce potential 
uncertainty regarding the regulatory status of CO2 streams 
under RCRA Subtitle C, and in order to facilitate the deployment of 
geologic sequestration, the EPA recently concluded a rulemaking to 
exclude certain CO2 streams from the RCRA definition of 
hazardous waste.\489\ In that rulemaking, the EPA determined that if 
any such CO2 streams would be hazardous wastes, further RCRA 
regulation is unnecessary to protect human health and the environment 
provided certain conditions are met. Specifically, the rule 
conditionally excludes from Subtitle C regulations CO2 
streams if they are (1) transported in compliance with U.S. Department 
of Transportation or state requirements; (2) injected in compliance 
with UIC Class VI requirements (summarized above); (3) no other 
hazardous wastes are mixed with or co-injected with the CO2 
stream; and (4) generators (e.g., emission sources) and Class VI well 
owners or operators sign certification statements. See 40 CFR 
261.4(h)).\490\ The D.C. Circuit recently dismissed all challenges to 
this rule in Carbon Sequestration Council and Southern Company Services 
v. EPA, No. 787 F. 3d 1129 (D.C. Cir. 2015).
---------------------------------------------------------------------------

    \488\ No hazardous waste listings apply to CO2 
streams. Therefore, a CO2 stream could be identified 
(i.e. defined) as a hazardous waste only if it exhibits one or more 
of the hazardous characteristics. 79 FR 355 (Jan 3. 2014).
    \489\ 79 FR 350 (Jan. 3, 2014).
    \490\ The EPA made clear in the final conditional exclusion that 
that rule does not address, and is not intended to affect the RCRA 
regulatory status of CO2 streams that are injected into 
wells other than Class VI. However, the EPA noted in the preamble to 
the final rule that (based on the limited information provided in 
public comments) should CO2 be used for its intended 
purpose as it is injected into UIC Class II wells for the purpose of 
EOR/EGR (enhanced oil recovery/enhanced gas recovery), it is the 
EPA's expectation that such an injection process would not generally 
be a waste management activity. 79 FR 355. The EPA encouraged 
persons to consult with the appropriate regulatory authority to 
address any fact-specific questions that they may have regarding the 
status of CO2 in situations that are beyond the scope of 
that rule. Id. Moreover, use of anthropogenic CO2 for EOR 
is long-standing and has flourished in all of the years that EPA's 
subtitle C regulations (which among other things, define what a 
solid waste is for purposes of those regulations) have been in 
place. The RCRA subtitle C regulatory program consequently has not 
been an impediment to use of anthropogenic CO2 for EOR.
---------------------------------------------------------------------------

d. Other perceived uncertainties
    Other commenters claimed that various legal uncertainties preclude 
a finding that geologic sequestration of CO2 from EGUs can 
be considered to be adequately demonstrated. Many of the issues 
referred to in comments relate to property rights: issues of ownership 
of pore space, relationship of sequestration to ownership of mineral 
rights, issues of dealing with multiple landowners, lack of state law 
frameworks, or competing, inconsistent state laws.\491\ Other 
commenters noted the lack of long-term liability insurance, and noted 
uncertainties regarding long-term liability generally.\492\
---------------------------------------------------------------------------

    \491\ See e.g. Comments of Duke Energy, p. 28 Docket entry: EPA-
HQ-OAR-2013-0495-9426); UARG, p. 62 (Docket entry: EPA-HQ-OAR-2013-
0495-9666); AEP, p. 91 (Docket entry: EPA-HQ-OAR-2013-0495-10618).
    \492\ See e.g. Comments of UARG, pp. 26 (Docket entry: EPA-HQ-
OAR-2013-0495-9666), 62; EEI, p. 92 Docket entry: EPA-HQ-OAR-2013-
0495-9780); Duke Energy, pp. 27, 28 Docket entry: EPA-HQ-OAR-2013-
0495-9426).
---------------------------------------------------------------------------

    An IPCC special report on CCS found that with an appropriate site 
selection, a monitoring program, a regulatory system, and the 
appropriate use of remediation methods, the risks of GS would be 
comparable to risks of current activities, such as EOR, acid gas 
injection and underground natural gas storage.\493\ Furthermore, an 
interagency CCS task force examined GS-related legal issues thoroughly 
and concluded that early CCS projects can proceed under the existing 
legal framework with respect to issues such as property rights and 
liability.\494\ As noted earlier, both the Archer Daniels Midland (ADM) 
and FutureGen projects addressed siting and operational aspects of GS 
(including issues relating to volumes of the CO2 and the 
nature of the CO2 injectate) in their permit applications. 
The fact that these applicants pursued permits indicates that they 
regarded any potential property rights issues as resolvable.
---------------------------------------------------------------------------

    \493\ Intergovernmental Panel on Climate Change. (2005). Special 
Report on Carbon Dioxide Capture and Storage.
    \494\ http://www.epa.gov/climatechange/Downloads/ccs/CCS-Task-Force-Report-2010.pdf.
---------------------------------------------------------------------------

    Commenter American Electric Power (AEP) referred to its own 
experience with the Mountaineer demonstration project. AEP noted that 
although this project was not full scale, finding a suitable 
repository, notwithstanding a generally favorable geologic area, proved 
difficult. The company referred to years spent in site characterization 
and digging multiple wells.\495\ Other commenters noted more generally 
that site characterization issues can be time-consuming and difficult, 
and quoted

[[Page 64592]]

studies suggesting that it could take 5 years to obtain a Class VI 
permit.\496\
---------------------------------------------------------------------------

    \495\ AEP Comments at pp. 93, 96 (Docket entry: EPA-HQ-OAR-2013-
0495-10618).
    \496\ See e.g. Comments of UARG, p. 55 (Docket entry: EPA-HQ-
OAR-2013-0495-9666), citing to Cichanowitz CCS Report (2012).
---------------------------------------------------------------------------

    The EPA agrees that robust site characterization and selection is 
important to ensuring capacity needs are met and that the sequestered 
CO2 is safely stored. Efforts to characterize geologic 
formations suitable for GS have been underway at DOE through the RCSPs 
since 2003 (see Section V.M). Additionally, since 2007, the USGS has 
been assessing U.S. geologic storage resources for CO2. As 
noted earlier, DOE, in partnership with researchers, universities, and 
organizations across the country, is demonstrating that GS can be 
achieved safely, permanently, and economically at large scales, and 
projects supported by the department have safely and permanently stored 
10 million metric tons of CO2.
    In the time since the commenter submitted comments several Class VI 
permits have been issued by the EPA. These projects demonstrate that a 
GS site permit applicant could potentially prepare and obtain a UIC 
permit concurrent with permits required for an EGU. With respect to 
AEP's experience with the Mountaineer demonstration project, 
notwithstanding difficulties, the company was able to successfully dig 
wells, and safely inject captured CO2. Moreover, the company 
indicated it fully expected to be able to do so at full scale and 
explained how.\497\ The EPA notes further that a monitoring program and 
its associated infrastructure (e.g., monitoring wells) and costs will 
be dependent on site-specific characteristics, such as CO2 
injection rate and volume, geology, the presence of artificial 
penetrations, among other factors. It is thus not appropriate to 
generalize from AEP's experience, and assume that other sites will 
require the same number of wells for site characterization or 
injection. In this regard, we note that the ADM and FutureGen 
construction permits for Class VI wells involved far fewer injection 
wells than AEP references.\498\ See also discussion of this issue in 
Section V.I.5 above.
---------------------------------------------------------------------------

    \497\ See AEP FEED Study at pp. 36-43. The company likewise 
explained the monitoring regime it would utilize to verify 
containment, and the well construction it would utilize to guarantee 
secure sequestration. Id. at pp. 44-54. Available at: 
www.globalccsinstitute.com/publications/aep-mountaineer-ii-project-front-end-engineering-and-design-feed-report.
    \498\ The FutureGen UIC Class VI injection well permits (four in 
total) require nine monitoring wells. http://www.epa.gov/r5water/uic/futuregen/. The Archer Daniels Midland UIC Class VI injection 
well permit issued in September 2014 (CCS2) requires five monitoring 
wells and the Archer Daniels Midland UIC Class VI injection well 
permit issued in December 2014 (CCS1) was permitted with two 
monitoring wells. http://www.epa.gov/region5/water/uic/adm/.
---------------------------------------------------------------------------

O. Non-air Quality Impacts and Energy Requirements

    As part of the determination that SCPC with partial CCS is the best 
system of emission reduction adequately demonstrated, the EPA has given 
careful consideration to non-air quality health and environmental 
impacts and energy requirements, as required by CAA section 111 (a). We 
have also considered those factors for alternative potential compliance 
paths to assure that the standard does not have unintended adverse 
health, environmental or energy-related consequences. The EPA finds 
that neither the BSER, nor the possible alternative compliance 
pathways, would have adverse consequences from either a non-air quality 
impact or energy requirement perspective.
    1. Transport and Sequestration of Captured CO2
    As just discussed in detail, the EPA finds that the Class VI and II 
rules, as complemented by the subpart RR GHGRP reporting and monitoring 
requirements, amply safeguard against potential of injected 
CO2 to degrade underground sources of drinking water and 
amply protect against any releases of sequestered CO2 to the 
atmosphere. The EPA likewise finds that the plenary regulatory controls 
on CO2 pipelines assure that CO2 can be safely 
conveyed without environmental release, and that these rules, plus the 
complementary tracking and reporting rules in subpart RR, assure that 
captured CO2 will be properly tracked and conveyed to a 
sequestration site.
2. Water Use Impacts
    Commenters claimed that the EPA ignored the negative environmental 
impacts of the use of CCS for the mitigation of CO2 
emissions from fossil fuel-fired steam generating EGUs. In particular, 
commenters noted that the use of CCS will increase the water usage at 
units that implement CCS to meet the proposed standard of performance. 
At least one commenter claimed that addition of an amine-based CCS 
system would double the consumptive water use of a power plant, which 
would be unacceptable, especially in drought-ridden states and in the 
arid west and referenced a study in the scientific literature as 
support.\499\ The commenter also references a DOE/NETL report that 
likewise notes significant increases in the amount of cooling and 
process water required with the use of carbon capture technology.\500\ 
However, those studies discuss increased water use for cases where full 
CCS (90 percent or greater capture) is implemented. As we discussed in 
both the proposal and in this preamble, the EPA does not find that 
highly efficient new generation technology implementing full CCS is the 
BSER for new steam generating EGUs.
---------------------------------------------------------------------------

    \499\ See comments of UARG at p. 84 (Docket entry: EPA-HQ-OAR-
2013-0495-9666) referencing Haibo Zhai, et al., Water Use at 
Pulverized Coal Power Plants with Post-combustion Carbon Capture and 
Storage, 45 Environ. Sci. Technol., 2479-85 (2011).
    \500\ Id at p. 84 referencing DOE/NETL-402/080108, ``Water 
Requirements for Existing and Emerging Thermoelectric Plant 
Technologies'' at 13 (Aug. 2008, Apr. 2009 revision).
---------------------------------------------------------------------------

    The EPA examined water use predicted from the updated DOE/NETL 
studies in order to determine the magnitude of increased water usage 
for a new SCPC implementing partial CCS to meet the final standard of 
1,400 lb CO2/MWh-g. The predicted water consumption for 
varying levels of partial and full CCS are provided in Table 13. The 
results show that a new SCPC unit that implements 16 percent partial 
CCS to meet the final standard would see an increase in water 
consumption (the difference between the predicted water withdraw and 
discharge) of about 6.4 percent compared to an SCPC with no CCS and the 
same net power output. By comparison, a unit implementing 35 percent 
CCS to meet the proposed emission limitation of 1,100 lb 
CO2/MWh-g would see an increase in water consumption of 16.0 
percent and a new unit implementing full (90 percent) CCS would see an 
increase of almost 50 percent.

  Table 13--Predicted Water Consumption With Implementation of Various
                       Levels of Partial CCS \501\
------------------------------------------------------------------------
                                             Raw water       Increase
               Technology                  consumption,     compared to
                                                gpm           SCPC, %
------------------------------------------------------------------------
SCPC....................................           4,095              --

[[Page 64593]]

 
SCPC + 16% CCS..........................           4,359             6.4
SCPC + 35% CCS..........................           4,751            16.0
SCPC + 90% CCS..........................           6,069            48.2
IGCC*...................................           3,334           -18.6
IGCC + 90% CCS*.........................           4,815            17.6
------------------------------------------------------------------------
* The IGCC results presented in the DOE/NETL report are for an IGCC with
  net output of 622 MWe and an IGCC with full CCS with net output of 543
  MWe. The water consumption for each was normalized to 550 MWe to be
  consistent with the SPCP cases.

    Similar to other air pollution controls--such as a wet flue gas 
desulfurization scrubber--utilization of post-combustion amine-based 
capture systems results in increased consumption of water. However, by 
finalizing a standard that is less stringent than the proposed 
limitation and by rejecting full CCS as the BSER, the EPA has reduced 
the increased amount of water needed as compared to a similar unit 
without CCS. Further, the EPA notes that there are additional 
opportunities to minimize the water usage at such a facility. For 
example, the SaskPower Boundary Dam Unit #3 post-combustion capture 
project captures water from the coal and from the combustion process 
and recycles the captured water in the process, resulting in decreased 
need for withdrawal of fresh water.
---------------------------------------------------------------------------

    \501\ Exhibits A-1 and A-2 at p. 16-17 from ``Cost and 
Performance Baseline for Fossil Energy Plants Supplement: 
Sensitivity to CO2 Capture Rate in Coal-Fired Power 
Plants'', DOE/NETL-2015/1720 (June 22, 2015).
---------------------------------------------------------------------------

    The EPA also examined the predicted water usage for a new IGCC and 
for a new IGCC implementing 90 percent CCS. The predicted water 
consumption for the new IGCC unit is nearly 20 percent less than that 
predicted for the new SCPC unit without CCS (and almost 25 percent less 
than the SCPC unit meeting the final standard). The EPA rejected new 
IGCC implementing full CCS as BSER because the predicted costs were 
significantly more than alternative technologies. The EPA also does not 
find that a new IGCC EGU is part of the final BSER (for reasons 
discussed in Section V.P). However, the EPA does note that IGCC is a 
viable alternative compliance option and, as shown here, would result 
in less water consumption than a compliant SCPC EGU. The EPA also notes 
that predicted water consumption at a new NGCC unit would be less than 
half that for a new SCPC EGU with the same net output.\502\
---------------------------------------------------------------------------

    \502\ The EPA also finds that the standards would not result in 
any significant impact on solid waste generation or management. See 
Section XIII.D below.
---------------------------------------------------------------------------

3. Energy Requirements
    The EPA also examined the expected impacts on energy requirements 
for a new unit meeting the final promulgated standard and finds impacts 
to be minimal. Specifically, the EPA examined the increased auxiliary 
load or parasitic energy requirements of a system implementing CCS. The 
EPA examined the predicted auxiliary power demand from the updated DOE/
NETL studies in order to determine the increased energy requirement for 
a new SCPC implementing partial CCS to meet the final standard of 1,400 
lb CO2/MWh-g. The predicted gross power output, the 
auxiliary power demand, and the parasitic power demand (percent of 
gross output) are provided in Table 14 for varying levels of partial 
and full CCS.

      Table 14--Predicted Parasitic Power Demand With Implementation of Various Levels of Partial CCS \503\
----------------------------------------------------------------------------------------------------------------
                                                                    Gross power      Auxiliary       Parasitic
                      Generation technology                         output, MWe     power, MWe      demand (%)
----------------------------------------------------------------------------------------------------------------
    SCPC........................................................             580              30             5.2
    SCPC + 16% CCS..............................................             599              38             6.3
SCPC + 35% CCS..................................................             603              53             8.8
    SCPC + 90% CCS..............................................             642              91            14.2
    IGCC........................................................             748             126            16.8
    IGCC + 90% CCS..............................................             734             191            26.0
CCS.............................................................             734             191            26.0
----------------------------------------------------------------------------------------------------------------

    The auxiliary power demand is the amount of the gross power output 
that is utilized within the facility rather than used to produce 
electricity for sale to the grid. The parasitic power demand (or 
parasitic load) is the percentage of the gross power output that is 
needed to meet the auxiliary power demand.\504\ In an SCPC EGU without 
CCS, the auxiliary power is used to primarily to operate fans, motors, 
pumps, etc. associated with operation of the facility and the 
associated pollution control equipment. When carbon capture equipment 
is incorporated, additional power is needed to operate associated 
equipment, and steam is need to regenerate the capture solvents (i.e., 
the solvents are heated to release the captured CO2).
---------------------------------------------------------------------------

    \503\ Exhibits A-1 and A-2 at p. 16-17 from ``Cost and 
Performance Baseline for Fossil Energy Plants Supplement: 
Sensitivity to CO2 Capture Rate in Coal-Fired Power 
Plants'', DOE/NETL-2015/1720 (June 2015).
    \504\ Note that this auxiliary power demand is not necessarily 
met from power or steam generated from the EGU. External sources can 
also be utilized for this purpose.
---------------------------------------------------------------------------

    The results in Table 14 show that a new SCPC unit without CCS can 
expect a parasitic power demand of about 5.2 percent. A new SCPC unit 
meeting the

[[Page 64594]]

final standard of performance by implementing 16 percent partial CCS 
will see a parasitic power demand of about 6.3 percent, which is not a 
significant increase in energy requirement. Of course, new SCPC EGUs 
that implement higher levels of CCS will expect higher amounts of 
parasitic power demand. As shown in Table 14, a new SCPC EGU 
implementing full CCS would expect to utilize over 14 percent of its 
gross power output to operate the facility and the carbon capture 
system. But, the EPA does not find that a new SCPC implementing full 
CCS is the BSER for new fossil-fired steam generating units. See 
Section V.P.2 below.
    The EPA also notes that there is on-going research sponsored by 
DOE/NETL and others to further reduce the energy requirements of the 
carbon capture systems. Progress is being made. As was mentioned 
previously, the heat duty (the energy required to regenerate the 
capture solvent) for the amine scrubbing process used at the Searles 
Valley facility in the mid-70's was about 12 MJ/mt CO2 
removed as compared to a heat duty of about 2.5 MJ/mt CO2 
removed for the amine processes used at Boundary Dam and for the amine 
system that will be used at the WA Parish facility.\505\
---------------------------------------------------------------------------

    \505\ ``From Lubbock, TX to Thompsons, TX--Amine Scrubbing for 
Commercial CO2 Capture from Power Plants'', plenary 
address by Prof. Gary Rochelle at the 12th International Conference 
on Greenhouse Gas Technology (GHGT-12), Austin, TX (October 2014).
---------------------------------------------------------------------------

    The EPA also examined the predicted parasitic power demand for a 
new IGCC and for a new IGCC implementing 90 percent CCS. As we have 
noted elsewhere, the auxiliary power demand for a new IGCC unit is more 
than that for that of a new SCPC. As one can see in Table 14, a new 
IGCC unit can expect to see a nearly 17 percent parasitic power demand; 
and a new IGCC unit implementing full CCS would expect a parasitic 
power demand of nearly 30 percent. Of course, the EPA rejected new IGCC 
implementing full CCS as BSER because of the potentially unreasonable 
costs. The EPA also does not find that a new IGCC EGU is part of the 
final BSER (for reasons discussed elsewhere in Section V.P.1 below). 
However, as we have noted, the EPA does find IGCC to be a viable 
alternative compliance option. Utilities and project developers should 
consider the increased auxiliary power demand for an IGCC when 
considering their options for new power generation. The EPA also notes 
that the predicted parasitic load for a new NGCC unit would be about 2 
percent--less than half that for a new SCPC EGU with the same net 
output.\506\
---------------------------------------------------------------------------

    \506\ The EPA also finds that the standards would not result in 
any significant impact on solid waste generation or management. See 
Section XII.D below.
---------------------------------------------------------------------------

    With respect to potential nationwide impacts on energy 
requirements, as described above in Section V.H.3 and more extensively 
in the RIA chapter 4, the EPA reasonably projects that no new non-
compliant fossil-fuel fired steam electric capacity will be constructed 
through 2022 (the end of the 8 year review cycle for NSPS). It is 
possible, as described earlier, that some new sources could be built to 
preserve fuel diversity, but even so, the number of such sources would 
be small and therefore would not significantly impact national energy 
requirements (assuming that such sources would not already be reflected 
in the baseline conditions just noted).

P. Options That Were Considered by the EPA but Were Ultimately Not 
Determined To Be the BSER

    In light of the comments received, the EPA re-examined several 
alternative systems of emission reduction and reaffirms in this 
rulemaking our proposed determination that those alternatives do not 
represent the ``best'' system of emission reduction when compared 
against the other available emission reduction options. These are 
described below. See also Section IV.B.1 above.
1. Highly Efficient Generation Technology (e.g., Supercritical or 
Ultra-supercritical Boilers)
    In the January 2014 proposal, we considered whether `Highly 
Efficient New Generation without CCS Technology' should constitute the 
BSER for new steam generating units. 79 FR at 1468-69. The discussion 
focused on the performance of highly efficient generation technology 
(that does not include any implementation of CCS), such as a 
supercritical \507\ pulverized coal (SCPC) or a supercritical CFB 
boiler, or a modern, well-performing IGCC unit.
---------------------------------------------------------------------------

    \507\ Subcritical coal-fired boilers are designed and operated 
with a steam cycle below the critical point of water. Supercritical 
coal-fired boilers are designed and operated with a steam cycle 
above the critical point of water. Increasing the steam pressure and 
temperature increases the amount of energy within the steam, so that 
more energy can be extracted by the steam turbine, which in turn 
leads to increased efficiency and lower emissions.
---------------------------------------------------------------------------

    All these options are technically feasible--there are numerous 
examples of each operating in the U.S. and worldwide. However, we do 
not find them to qualify as the best system for reduction of 
CO2 emissions for the following reasons:
a. Lack of Significant CO2 Reductions When Compared to 
Business as Usual
    At the outset, we reviewed the emission rates of efficient PC and 
CFB units. According to the DOE/NETL estimates, a newly constructed 
subcritical PC unit firing bituminous coal would emit approximately 
1,800 lb CO2/MWh-g,\508\ a new highly efficient SCPC unit 
using bituminous coal would emit nearly 1,720 lb CO2/MWh-g, 
and a new IGCC unit would emit about 1,430 lb CO2/MWh-
g.509 510 Emissions from comparable sources utilizing sub-
bituminous coal or lignite will have somewhat higher CO2 
emissions.\511\
---------------------------------------------------------------------------

    \508\ Exhibit ES-2 from ``Cost and Performance Baseline for 
Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to 
Electricity'', Revision 2, Report DOE/NETL-2010/1397 (November 
2010).
    \509\ ``Cost and Performance Baseline for Fossil Energy Plants 
Supplement: Sensitivity to CO2 Capture Rate in Coal-Fired 
Power Plants'', DOE/NETL-2015/1720 (June 2015); SCPC rates come from 
Exhibit A-2 and IGCC rates come from Exhibit A-4.
    \510\ The comparable emissions on a net basis are: subcritical 
PC--1,890 lb CO2/MWh-n; SCPC-1,705 lb CO2/MWh-
n; and IGCC--1,724 lb CO2/MWh-n. (See same references as 
for gross emissions provided in the text).
    \511\ Exhibit ES-2 from ``Cost and Performance Baseline for 
Fossil Energy Plants Volume 3b: Low Rank Coal to Electricity: 
Combustion Cases'', Report DOE/NETL-2010/1463 (March 2011).
---------------------------------------------------------------------------

    Some commenters noted that new coal-fired plants utilizing 
supercritical boiler design or IGCC would provide substantial emission 
reductions compared to the emissions from the existing subcritical coal 
plants that are currently in wide use in the power sector. However, 
most of the recent new power sector projects using solid fossil fuel 
(coal or petroleum coke) as the primary fuel--both those that have been 
constructed and those that have been proposed--are supercritical 
boilers and IGCC units. About 60 percent of new coal-fired utility 
boiler capacity that has come on-line since 2005 was supercritical and 
of the new capacity that came on-line since 2010, about 70 percent was 
supercritical. No new coal-fired utility boilers began operation in 
either 2013 or 2014. Coal-fired power plants that have come on-line 
most recently include AEP's John W. Turk, Jr. Power Plant, which is a 
600 MW ultra-supercritical \512\ PC (USCPC) facility located in the 
southwest corner of Arkansas, and Duke Energy's Edwardsport plant, 
which is a 618 MW

[[Page 64595]]

``CCS ready'' \513\ IGCC unit located in Knox County, Indiana. Both of 
those facilities came on-line in 2012. It is likely that the units that 
initiated operation in 2010 or later were conceived of, planned, 
designed, and permitted well before 2010--likely in the early 2000s. 
Thus, it seems clear that the power sector had already, at that point, 
transitioned to the selection of supercritical boiler technology as 
``business as usual'' for new coal-fired power plants. Since that time, 
there have been other coal-fired power plants that have been proposed 
and almost all of them have been either supercritical boiler designs or 
IGCC units. In Table 1 of the Technical Support Document Fossil Fuel-
Fired Boiler and IGCC EGU Projects Under Development: Status and 
Approach \514\ for the January 2014 proposal, the EPA listed the 
development status of ``potential transitional sources'' (i.e., 
projects that had been proposed and had received Prevention of 
Significant Deterioration (PSD) preconstruction permits as of April 13, 
2012). Of the 16 proposed EGU projects in Table 1--most of which have 
been cancelled or converted to or replaced with NGCC projects--the 
majority (nine) are either supercritical PC or IGCC designs. Five of 
the proposed projects were CFB designs with only one being a 
subcritical PC design.
---------------------------------------------------------------------------

    \512\ Ultra-supercritical (U.S.C.) and advanced ultra-
supercritical (A-U.S.C.) are terms often used to designate a coal-
fired power plant design with steam conditions well above the 
critical point.
    \513\ A ``CCS ready'' facility is one that is designed such that 
the CCS equipment can be more easily added at a later time.
    \514\ Available in the rulemaking docket (entry: EPA-HQ-OAR-
2013-0495-0024).
---------------------------------------------------------------------------

    The EPA is aware of only one new coal-fired power plant that is 
actively in the construction phase. That plant is Mississippi Power's 
Kemper County Energy Facility in Kemper County, MS--an IGCC unit that 
plans to begin operations in 2016 and will implement partial CCS to 
capture approximately 65 percent of the available CO2, which 
will be sold for use in EOR operations.
    Considering the direction that the power sector has been taking and 
the changes that it is undergoing, identifying a new supercritical unit 
as the BSER and requiring an emission limitation based on the 
performance of such units thus would provide few, if any, additional 
CO2 emission reductions beyond the sector's ``business as 
usual''. As noted, for the most part, new sources are already designed 
to achieve at least that emission limitation. This criterion does not 
itself eliminate supercritical technology from consideration as BSER. 
However, existing technologies must be considered in the context of the 
range of technically feasible technologies and, as we discuss elsewhere 
in this final preamble, partial CCS can achieve emission limitations 
beyond business as usual and do so at a reasonable cost.
    The EPA also considered IGCC technology and whether it represents 
the BSER for new power plants utilizing coal or other solid fossil 
fuels. IGCC units, on a gross-output basis, have inherently lower 
CO2 emission rates when compared to similarly-sized SCPC 
units. However, the net emission rates and overall emissions to the 
atmosphere (i.e., tons of CO2 per year) tend to be more 
similar (though still somewhat lower) for new IGCC units when compared 
to new SCPC units with the same electrical output. Therefore an 
emission limitation based on the expected performance of a new IGCC 
unit would result in some CO2 emission reductions from the 
segment of the industry that would otherwise construct new PC units, 
but not from the segment of the industry that would already construct 
new IGCC units. A gross-output-based emission limitation consistent 
with the expected performance of a new IGCC unit would still require 
some additional control, such as partial CCS, on a new supercritical 
boiler.
    As is shown in Section V.J and H, additional emission reductions 
beyond those that would result from an emission standard based on a new 
SCPC boiler or even a new IGCC unit as the BSER can be achieved at a 
reasonable cost. Because practicable emission controls are available 
that are of reasonable cost at the source level and that will have 
little cost and energy impact at the national level, the EPA is 
according significant weight to the factor of amount of emissions 
reductions in determining the BSER. As discussed above, the D.C. 
Circuit has emphasized this factor in describing the purpose of CAA 
section 111 as to achieve ``as much [emission reduction] as 
practicable.'' \515\
---------------------------------------------------------------------------

    \515\ Sierra Club, 657 F.2d at 327 & n. 83.
---------------------------------------------------------------------------

b. Lack of Incentive for Technological Innovation
    As discussed above, the EPA is justifying its identification of the 
BSER based on its weighing of the factors explicitly identified in CAA 
section 111(a)(1), including the amount of the emission reduction. 
Under the D.C. Circuit case law, encouraging the development and 
implementation of advanced control technology must also be considered 
(and, in any case, may reasonably be considered; see Section V.H.3.d 
above). Consideration of this factor confirms the EPA's decision not to 
identify highly efficient generation technology (without CCS) as the 
BSER. At present, CCS technologies are the most promising options to 
achieve significant reductions in CO2 emissions from newly 
constructed fossil fuel-fired steam generating units. CCS technology is 
also now a viable retrofit option for some modified, reconstructed and 
existing sources--depending upon the configuration, location and age of 
those sources. As CCS technologies are deployed and used more there is 
an expectation that, based on previous experience with advanced 
technologies, the performance will improve and the implementation costs 
will decline. The improved performance and lower costs will provide 
additional incentive for further implementation in the future.
    The Intergovernmental Panel on Climate Change (IPCC) recently 
released its Fifth Assessment report, \516\ which recognizes that 
widespread deployment of CCS is crucial to reach the long term climate 
goals. The authors of the report used models to predict the likelihood 
of stabilizing the atmospheric concentration of CO2 at 450 
ppm by 2050 with or without carbon capture and storage (CCS). They 
found that several of the models were not able to reach this goal 
without CCS, which underlines the importance of deploying and further 
developing CCS on a large scale.
---------------------------------------------------------------------------

    \516\ IPCC, Working Group III, Climate Change 2014: Mitigation 
of Climate Change, http://mitigation2014.org/report/publication/.
---------------------------------------------------------------------------

    American Electric Power (AEP), in an evaluation of lessons learned 
from the Phase 1 of its Mountaineer CCS project, wrote: ``AEP still 
believes the advancement of CCS is critical for the sustainability of 
coal-fired generation.'' \517\
---------------------------------------------------------------------------

    \517\ CCS LESSONS LEARNED REPORT American Electric Power 
Mountaineer CCS II Project Phase 1, Prepared for The Global CCS 
Institute Project # PRO 004, January 23, 2012, page 2. See also AEP 
FEED Study at pp. 4, 63 (same). Available at: http://www.globalccsinstitute.com/publications/aep-mountaineer-ii-project-front-end-engineering-and-design-feed-report.
---------------------------------------------------------------------------

    Some commenters felt that the proposed standard of performance for 
new steam generating units, based on implementation of partial CCS at 
an emission rate of 1,100 lb/MWh-g, would not serve to promote the 
increased deployment and implementation of CCS. The commenters argued 
that such a standard could instead have the unintended result of 
discouraging the further development of advanced coal generating 
technologies such as ultra-supercritical boilers and improved IGCC 
designs.
    Commenters further argued that such a standard will stifle further

[[Page 64596]]

development of CCS technologies. Commenters felt that the standard 
would effectively deter the construction of new coal-fired generation--
and, if there is no new coal-fired generation, then there will be no 
implementation of CCS technology and, therefore, no need for continued 
research and development of CCS technologies. They argued, in fact, 
that the best way to promote the development of CCS was to set a 
standard that did not rely on it.
    The EPA does not agree with these arguments and, in particular, 
does not see how a standard that is not predicated on performance of an 
advanced control technology would serve to promote development and 
deployment of that advanced control technology. On the contrary, the 
history of regulatory actions has shown that emission standards that 
are based on performance of advanced control equipment lead to 
increased use of that control equipment, and that the absence of a 
requirement stifles technology development.
    There is a dramatic instance of this paradigm presented in the 
present record. In 2011, AEP deferred construction of a large-scale CCS 
retrofit demonstration project on one of its coal-fired power plants 
because the state's utility regulators would not approve cost recovery 
for CCS investments without a regulatory requirement to reduce 
CO2 emissions. AEP's chairman was explicit on this point, 
stating in a July 17, 2011 press release announcing the deferral:
    We are placing the project on hold until economic and policy 
conditions create a viable path forward . . . We are clearly in a 
classic `which comes first?' situation. The commercialization of this 
technology is vital if owners of coal-fueled generation are to comply 
with potential future climate regulations without prematurely retiring 
efficient, cost-effective generating capacity. But as a regulated 
utility, it is impossible to gain regulatory approval to recover our 
share of the costs for validating and deploying the technology without 
federal requirements to reduce greenhouse gas emissions already in 
place. The uncertainty also makes it difficult to attract partners to 
help fund the industry's share.\518\
---------------------------------------------------------------------------

    \518\ http://www.aep.com/newsroom/newsreleases/?id=1704.
---------------------------------------------------------------------------

    Some commenters also argued that the incremental cost associated 
with including CCS at the proposed level would prevent new coal-fired 
units from being built. Instead, they advocated for a standard based on 
most efficient technology (supercritical) coupled with government 
subsidies to advance and promote CCS technology. The final standard is 
less stringent than that proposed, and can be met at a lower cost than 
the proposed standard, and as explained above in Section V.H, the EPA 
has carefully evaluated those costs and finds them to be reasonable. 
Further, the record and current economic conditions (fuel costs, 
renewables, demand growth, etc.) show that non-economic factors such as 
a desire for fuel diversity will likely drive future development of any 
new coal-fired EGUs. For this reason, the EPA does not find the 
commenters' bare assertions that the incremental cost of CCS 
(particularly as reasonably modulated for this final standard) would 
make the difference between constructing and not constructing new coal 
capacity to be persuasive. Rather, a cost-reasonable standard 
reflecting use of the new technology is what will drive new technology 
deployment.
    The EPA expects that it is unlikely that a new IGCC unit would 
install partial CCS to meet the final standard unless the facility is 
built to take advantage of EOR opportunities or to operate as a poly-
generation facility (i.e., to co-produce power along with chemicals or 
other products). For new IGCC units, the final standard of performance 
can be met by co-firing a small amount of natural gas. Some commenters 
argued that IGCC is an advanced technology that, like CCS, should be 
promoted. The EPA agrees. IGCC is a low-emitting, versatile technology 
that can be used for purposes beyond just power production (as 
mentioned just above). Commenters further argued that a requirement to 
include partial CCS (at a level to meet the proposed standard of 
performance) would serve to deter--rather than promote--more 
installation of IGCC technology. We disagree with a similar argument 
that commenters make with respect to partial CCS for post-combustion 
facilities, but our final standard moots that argument for IGCC 
facilities because the final emission limitation of 1,400 lb 
CO2/MWh-g will not itself deter installation of IGCC 
technology, by the terms of the commenters' own argument.
2. ``Full'' Carbon Capture and Storage (i.e., 90 Percent Capture)
    We also reconsidered whether the emission limitation for new coal-
fired EGUs should be based on the performance of full implementation of 
CCS technology. For a newly constructed utility boiler, this would mean 
that a post-combustion capture system would be used to treat the entire 
flue gas stream to achieve an approximately 90 percent reduction in 
CO2 emissions. For a newly constructed IGCC unit, a pre-
combustion capture system would be used to capture CO2 from 
a fully shifted gasification syngas stream to achieve an approximately 
90 percent reduction in CO2 emissions.
    In the proposal for newly constructed sources, we found that ``full 
CCS'' would certainly result in significant CO2 reductions 
from any new source implementing the technology. However, we also found 
that the costs associated with implementation, on either a new utility 
boiler system or a new IGCC unit, are predicted to substantially exceed 
the costs for other dispatchable non-NGCC generating options that are 
being considered by utilities and project developers (e.g., new nuclear 
plants and new biomass-fired units). See 79 FR at 1477. This remains 
the case, and indeed, the difference between cost of full capture and 
new nuclear technology is estimated to be even greater than at 
proposal. The EPA thus is not selecting full capture CCS as BSER.

Q. Summary

    The EPA finds that the best system of emission reduction adequately 
demonstrated is a highly efficient supercritical pulverized coal boiler 
using post-combustion partial CCS so that CO2 is captured, 
compressed and safely stored over the long-term. Properly designed, 
operated, and maintained, this best system can achieve a standard of 
performance of 1,400 lb CO2/MWh-g, an emission limitation 
that is achievable over the 12-operating-month compliance period 
considering usual operating variability (including use of different 
coal types, periods of startup and shutdown, and malfunction 
conditions). This standard of performance is technically feasible, 
given that the BSER technology is already operating reliably in full-
scale commercial application. The technology adds cost to a new 
facility which the EPA has evaluated and finds to be reasonable because 
the costs are in the same range as those for new nuclear generating 
capacity--a competing non-NGCC, dispatchable technology that utilities 
and project developers are also considering for base load application. 
The EPA has also considered capital cost increases associated with use 
of post-combustion partial CCS at the level needed to meet the final 
standard and found them to be reasonable, and within the range of 
capital cost increases for this industry in prior NSPS which have been 
adjudicated as reasonable. The EPA's consideration of costs is also 
informed by its judgment that new coal-

[[Page 64597]]

fired capacity would be constructed not as the most economic option, 
but for such purposes as preserving fuel diversity in an energy 
portfolio, and so would not be cost competitive with natural gas-fired 
capacity, so that some additional cost premium may therefore be 
reasonable. The EPA has carefully evaluated the non-air quality health 
and environmental impacts of the final standard and found them to be 
reasonable: CO2 pipelines and CO2 sequestration 
via deep well injection are subject already to rigorous control under 
established regulatory programs which assure prevention of 
environmental release during transport and storage. In addition, water 
use associated with use of partial CCS at the level to meet the final 
standard is acceptable, and use of the technology does not impose 
significant burdens on energy requirements at either the plant or 
national level. The 1,400 lb CO2/MWh-g standard reflecting 
performance of the BSER may be achieved without geographic constraint, 
both because geologic sequestration and EOR capacity are widely 
available and accessible, and also because alternative compliance 
pathways are available in the unusual circumstance where a new coal-
fired plant is sited in an area without such access, that area has not 
already limited construction of new coal-fired capacity in some way, 
and the area cannot be serviced by coal-by-wire. Accordingly, the EPA 
finds that the promulgated standard of performance for new fossil fuel-
fired steam electric generating units satisfies the requirements of CAA 
section 111(a).

VI. Rationale for Final Standards for Modified Fossil Fuel-Fired 
Electric Utility Steam Generating Units

    The EPA has determined that, as proposed, the BSER for steam 
generating units that trigger the modification provisions is each 
affected unit's own best potential performance as determined by that 
unit's historical performance. The final standards of performance are 
similar to those proposed in the June 2014 proposal. Differences 
between the proposed standards and the final standards issued in this 
action reflect responses to comments received on the proposal. Those 
changes are described below.
    As noted previously, the EPA is issuing final emission standards 
only for affected modified steam generating units that conduct 
modifications resulting in a hourly increase in CO2 
emissions (mass per hour) of more than 10 percent (``large'' 
modifications). The EPA is continuing to review the appropriate 
standards for modified sources that conduct modifications resulting in 
a hourly increase in CO2 emissions (mass per hour) of less 
than or equal to 10 percent (``small'' modifications), is not issuing 
final standards for those sources in this action, and is withdrawing 
the proposed standards for those sources. See Section XV below.

A. Rationale for Final Applicability Criteria for Modified Steam 
Generating Units

    Final applicability criteria for modified steam generating EGUs 
include those discussed earlier in Section III.A.1 (General 
Applicability) and Section III.A.3 (Applicability Specific to Modified 
Sources).
    CAA section 111(a)(4) defines a ``modification'' as ``any physical 
change in, or change in the method of operation of, a stationary 
source'' that either ``increases the amount of any air pollutant 
emitted by such source or . . . results in the emission of any air 
pollutant not previously emitted.'' Certain types of physical or 
operational changes are exempt from consideration as a modification. 
Those are described in 40 CFR 60.2, 60.14(e). To be clear, our action 
in this final rule, and the discussion below, does not change anything 
concerning what constitutes or does not constitute a modification under 
the CAA or the EPA's regulations.\519\
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    \519\ CAA section 111(a)(4); See also 40 CFR 60.14 concerning 
what constitutes a modification, how to determine the emission rate, 
how to determine an emission increase, and specific actions that are 
not, by themselves, considered modifications.
---------------------------------------------------------------------------

    A modified steam generating unit is a source that fits the 
definition and applicability criteria of a fossil fuel-fired steam 
generating unit and that commences a qualifying modification on or 
after June 18, 2014 (the publication date of the proposed modification 
standards). 79 FR 34960.
    For the reasons discussed below, the EPA in this final action is 
finalizing requirements only for steam generating units that conduct 
modifications resulting in an increase in hourly CO2 
emissions (mass per hour) of more than 10 percent as compared to the 
source's highest hourly emission during the previous five years. With 
respect to modifications with smaller increases in CO2 
emissions (specifically, steam generating units that conduct 
modifications resulting in an increase in hourly CO2 
emissions (mass per hour) of 10 percent or less compared to the 
source's highest hourly emission during the previous 5 years), the EPA 
is not finalizing any standard or other requirements, and is 
withdrawing the June 2014 proposal with respect to these sources (see 
Section XV below).
    The effect of the EPA's deferral on setting standards for sources 
undertaking modifications resulting in smaller increases in 
CO2 emissions and the withdrawal of the June 2014 proposal 
with respect to such sources is that such sources will continue to be 
existing sources and subject to requirements under section 111(d). This 
is because an existing source does not always become a new source when 
it modifies. Under the definition of ``new source'' in section 
111(a)(2), an existing source only becomes a new source if it modifies 
after the publication of proposed or final regulations that will be 
applicable to it. Thus, if an existing source modifies at a time that 
there is no promulgated final standard or pending proposed standard 
that will be applicable to it as a modified ``new'' source, that source 
is not a new source and continues to be an existing source. Here, 
because the EPA is not finalizing standards for sources undertaking 
modifications resulting in smaller increases in CO2 
emissions and is withdrawing the proposal with respect to such sources, 
these sources do not fall within the definition of ``new source'' in 
section 111(a)(2) and continue to be an ``existing source'' as defined 
in section 111(a)(6). See Section XV below.
    As we discussed in the June 2014 proposal, the EPA has historically 
been notified of only a limited number of NSPS modifications \520\ 
involving fossil steam generating units and therefore predicted that 
very few of these units would trigger the modification provisions and 
be subject to the proposed standards. Given the limited information 
that we have about past modifications, the agency has concluded that it 
lacks sufficient information to establish standards of performance for 
all types of modifications at steam generating units at this time. 
Instead, the EPA has determined that it is appropriate to establish 
standards of performance at this time for larger modifications, such as 
major facility upgrades involving, for example, the refurbishing or 
replacement of steam turbines and other equipment upgrades that result 
in substantial increases in a unit's hourly CO2 emissions 
rate. The agency has determined, based on its review of public comments 
and other publicly available information, that it has adequate 
information regarding the types of modifications that could result in 
large increases in hourly CO2 emissions, as well as on the 
types of

[[Page 64598]]

measures available to control emissions from sources that undergo such 
modifications, and on the costs and effectiveness of such control 
measures, upon which to establish standards of performance for 
modifications with large emissions increases at this time.
---------------------------------------------------------------------------

    \520\ NSPS modifications resulting in increases in hourly 
emissions of criteria pollutants.
---------------------------------------------------------------------------

    In establishing standards of performance at this time for 
modifications with large emissions increases, but not for those with 
small increases, the EPA is exercising its policy discretion to 
promulgate regulatory requirements in a sequential fashion for classes 
of modifications within a source category, accounting for the 
information available to the agency, while also focusing initially on 
those modifications with the greatest potential environmental impact. 
This approach is consistent with the case law that authorizes agencies 
to establish a regulatory framework in an incremental fashion, that is, 
a step at a time.\521\
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    \521\ As the U.S. Supreme Court recently stated 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.' '' See Grand Canyon Air Tour 
Coalition v. F.A.A., 154 F.3d 455 (D.C. Cir. 1998), City of Las 
Vegas v. Lujan, 891 F.2d 927, 935 (D.C. Cir. 1989), National 
Association of Broadcasters v. FCC, 740 F.2d 1190, 1209-14 (D.C. 
Cir. 1984). See also, Hazardous Waste Treatment Council v. U.S. 
E.P.A., 861 F.2d 277, 287 (D.C. Cir. 1988) (``[A]n agency's failure 
to regulate more comprehensively is not ordinarily a basis for 
concluding that the regulations already promulgated are invalid. 
`The agency might properly take one step at a time.' United States 
Brewers Assoc. v. EPA, 600 F.2d 974,982 (D.C. Cir. 1979). Unless the 
agency's first step takes it down a path that forecloses more 
comprehensive regulation, the first step is not assailable merely 
because the agency failed to take a second. The steps may be too 
plodding, but that raises an entirely different issue . . . .'').
---------------------------------------------------------------------------

    To be clear, the EPA is not reaching a final decision as to whether 
it will regulate modifications with smaller increases, or even that 
such modifications should be subject to different requirements than we 
are finalizing in this rule for the modifications with larger 
increases. We have made no decisions and this matter is not concluded. 
We plan to continue to gather information, consider the options for 
modifications with smaller increases, and, in the future, develop a 
proposal for these modifications or otherwise take appropriate steps.
    As a means of determining the proper threshold between the larger 
and smaller increases in CO2 emissions, the EPA examined 
changes in CO2 emissions that may result from large, 
capital-intensive projects, such as major facility upgrades involving 
the refurbishing or replacement of steam turbines and other equipment 
upgrades that would significantly increase a unit's capacity to burn 
more fossil fuel, thereby resulting in large emissions increases. Major 
upgrades such as these could increase a steam generating unit's hourly 
CO2 emissions by well over 10 percent.\522\
---------------------------------------------------------------------------

    \522\ See e.g., Power Engineering, Steam Turbine Upgrades Boost 
Plant Reliability, Efficiency, available at www.power-eng.com/articles/print/volume-116/issue-11/features/steam-turbine-upgrades-boost-plant-reliability-efficiency.html.
---------------------------------------------------------------------------

    An example of such major upgrade would be work performed at 
AmerenUE's Labadie Plant, a facility with four 600-MW (nominal) coal-
fired units located 35 miles west of St. Louis. In the early 2000s, 
plant staff conducted process improvements that raised maximum unit 
capacity by nearly 10 percent (from 580 MW to 630 MW).\523\ Those 
changes included boiler improvements necessitated by its switch from 
bituminous to subbituminous coal,\524\ installation of low-
NOX burners, an overfire air system, and advanced computer 
controls. One of the performance gains came from upgrading all four 
steam turbines, which AmerenUE chose to replace as modules allowing 
engineers more freedom to maximize performance unconstrained by the 
units' existing outer casing.
---------------------------------------------------------------------------

    \523\ ``Steam turbine upgrading: Low-hanging fruit'', Power (04/
15/2006), www.powermag.com/steam-turbine-upgrading-low-hanging-fruit.
    \524\ Note that a change in coal-type or change in the use of 
other raw material does not necessarily constitute an ``operational 
change''. See 40 CFR 60.14(e)(4).
---------------------------------------------------------------------------

    Another example is the refurbishment of the 2,100 MW Eskom Arnot 
coal-fired power plant in South Africa with a resulting increase in its 
power output by 300 MW to 2,400 MW--an increase in capacity of 14 
percent.\525\ For each of the plant's six steam generating units, the 
company conducted a complete retrofit of the high pressure and 
intermediate pressure steam turbines, a capacity upgrade of the low 
pressure steam turbine, and the replacement and upgrade of associated 
turbine side pumps and auxiliaries. In addition, major upgrades to the 
boiler plant were conducted, including supply of new pressure part 
components, new burners, and modification to other equipment such as 
the coal mills and classifiers, fans, and heaters. Other examples are 
provided in a technical memo available in the rulemaking docket.\526\
---------------------------------------------------------------------------

    \525\ www.alstom.com/press-centre/2006/10/alstom-signs-power-plant-upgrade-and-retrofit-contract-with-eskom-in-south-africa/.
    \526\ See ``U.S. DOE Information Relevant to Technical Basis for 
``Large Modification'' Threshold'' available in the rulemaking 
docket EPA-HQ-OAR-2013-0495.
---------------------------------------------------------------------------

    The EPA does not intend to imply that these specific projects would 
have resulted in an increase in hourly CO2 emissions of 
greater than 10 percent. Capacity increases are often the result of 
efficient improvements or are accompanied by other facility 
improvements that can offset emissions increases due to increased fuel 
input capacity. However, these examples are intended to show the types 
of large, more capital intensive projects that can potentially result 
in increases in hourly emissions of CO2 of at least 10 
percent.
    The EPA believes that it is reasonable to set the threshold between 
``large'' modifications and ``small'' modifications at 10 percent, a 
level commensurate with the magnitude of the emissions increases that 
could result from the types of projects described above, and we are 
issuing a final standard of performance for those sources that conduct 
modifications resulting in hourly CO2 emission increases 
that exceed that threshold. We are not issuing standards of performance 
for those sources that conduct modifications resulting in an hourly 
increase of CO2 emissions of less than or equal to 10 
percent.
    Therefore, the EPA is withdrawing the proposed standards for those 
sources that conduct modifications resulting in a hourly increase in 
CO2 emissions (mass per hour) of less than or equal to ten 
percent and is not issuing final standards for those sources at this 
time. See Section XV below. Utilities, states and others should be 
aware that the differentiation between modifications with larger and 
smaller increases in CO2 emissions only applies to sources 
covered under 40 CFR part 60, subpart TTTT, i.e., it is only applicable 
to CO2 emissions from fossil fuel-fired steam generating 
units. There is no similar provision for criteria pollutants or for 
other source categories. Utilities, states and others should also be 
aware that the distinction between large and small modifications only 
applies to NSPS modifications. Sources undertaking modifications may 
still be subject to requirements of New Source Review under CAA Title I 
part C or D (which have different standards for modifications than the 
NSPS and require a case-by-case analysis) or other CAA requirements.
    The EPA notes that some commenters expressed concern that a number 
of existing fossil steam generating units, in order to fulfill 
requirements of an approved CAA section 111(d) plan, may pursue actions 
that involve physical or operational changes that result in some 
increase in their CO2 emissions on an hourly basis, and thus 
constitute

[[Page 64599]]

modifications. Some commenters suggested that the EPA should exempt 
projects undertaken specifically for the purpose of complying with CAA 
section 111(d).
    The EPA does not have sufficient information at this time to 
predict the full array of actions that existing steam generating units 
may undertake in response to applicable requirements under an approved 
CAA section 111(d) plan, or which, if any, of these actions may result 
in increases in CO2 hourly emissions. Nevertheless, the EPA 
expects that, to the extent actions undertaken by existing steam 
generating units in response to 111(d) requirements trigger 
modifications, the magnitude of the increases in hourly CO2 
emissions associated with such modifications would generally be smaller 
and would therefore generally not subject such modifications to the 
standards of performance that the EPA is finalizing in this rule for 
modified steam generating units with larger increases in hourly 
CO2 emissions.

B. Identification of the Best System of Emission Reduction

    The EPA has determined that, as was proposed, the BSER for steam 
generating units that trigger the modification provisions is the 
affected EGU's own best potential performance as determined by that 
source's historical performance.
    The EPA proposed that the BSER for modified steam generating EGUs 
is each unit's own best potential performance based on a combination of 
best operating practices and equipment upgrades. Specifically, the EPA 
co-proposed two alternative standards for modified utility steam 
generating units. In the first co-proposed alternative, modified steam 
generating EGUs would be subject to a single emission standard 
determined by the affected EGU's best demonstrated historical 
performance (in the years from 2002 to the time of the modification) 
with an additional 2 percent emission reduction. The EPA proposed that 
the standard could be met through a combination of best operating 
practices and equipment upgrades. To account for facilities that have 
already implemented best practices and equipment upgrades, the proposal 
also specified that modified facilities would not have to meet an 
emission standard more stringent than the corresponding standard for 
reconstructed EGUs.
    The EPA also co-proposed that the specific standard for modified 
sources would be dependent on the timing of the modification. We 
proposed that sources that modify prior to becoming subject to a CAA 
section 111(d) plan would be required to meet the same standard 
described in the first co-proposal--that is, the modified source would 
be required to meet a unit-specific emission limit determined by the 
affected EGU's best demonstrated historical performance (in the years 
from 2002 to the time of the modification) with an additional 2 percent 
emission reduction (based on equipment upgrades). We also proposed that 
sources that modify after becoming subject to a CAA section 111(d) plan 
would be required to meet a unit-specific emission limit that would be 
determined by the CAA section 111(d) implementing authority and would 
be based on the source's expected performance after implementation of 
identified unit-specific energy efficiency improvement opportunities.
    The final standards in this action do not depend upon when the 
modification commences (as long as it commences after June 8, 2014). 
The EPA received comments on the June 2014 proposal that called into 
question the need to differentiate the standard based on when the 
modification was undertaken. Further, commenters noted that the 
proposed requirements for sources modifying after becoming subject to a 
CAA section 111(d) plan, which were based on energy efficiency 
improvement opportunities were vague and that standard setting under 
CAA section 111(b) is a federal duty and would require notice-and-
comment rulemaking. The EPA considered those comments and has 
determined that we agree that there is no need for subcategories based 
on the timing of the modification.

C. BSER Criteria

1. Technical Feasibility
    The EPA based technical feasibility of the unit-specific efficiency 
improvement on analyses done to support heat rate improvement for the 
proposed CAA section 111(d) emission guidelines (Clean Power Plan). 
That work was summarized in Chapter 2 of the TSD, ``GHG Abatement 
Measures''.\527\ In response to comments on the proposed Clean Power 
Plan, the approach was adjusted, as described in the final CAA section 
111(d) emission guidelines. As with proposed actions, the EPA is basing 
technical feasibility for final standards for modified source 
efficiency improvements on the analyses for heat rate improvements for 
the CAA 111(d) final rule.
---------------------------------------------------------------------------

    \527\ Technical Support Documents ``GHG Abatement Measures'' 
(proposal) and ``GHG Mitigation Measures'' (final) available in the 
rulemaking docket EPA-HQ-OAR-2013-0495.
---------------------------------------------------------------------------

2. Cost
    Any efficiency 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 a 4 percent heat rate improvement 
would be sufficient to cover much of the associated costs, and thus 
that the net costs of heat rate improvements associated with reducing 
CO2 emissions from affected EGUs are relatively low.
    We recognize that our cost analysis just described will represent 
the costs for some EGUs better than others because of differences in 
EGUs' individual circumstances. We further recognize that reduced 
generation from coal-fired EGUs will 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 the majority 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 modified fossil fuel-fired EGUs are reasonable. The EPA further 
notes that the types of large, more capital intensive projects that may 
trigger the ``larger modifications'' threshold (i.e., result in an 
hourly increase in CO2 emissions of more than 10 percent) 
often are undertaken in order to increase the capacity of the source 
but also to improve the heat rate or efficiency of the unit.
3. Emission Reductions
    This approach would achieve reasonable reductions in CO2 
emissions from the affected modified units as those units will be 
required to meet an emission standard that is consistent with more 
efficient operation. In light of the limited opportunities for emission 
reductions from retrofits, these reductions are adequate.
4. Promotion of Technology and Other Systems of Emission Reduction
    As noted previously, the case law makes clear that the EPA is to 
consider

[[Page 64600]]

the effect of its selection of the BSER on technological innovation or 
development, but that the EPA also has the authority to weigh this 
factor, along with the various other factors. With the selection of 
emissions controls, modified sources face inherent constraints that 
newly constructed greenfield and even reconstructed sources do not; as 
a result, modified sources present different, and in some ways more 
limited, opportunities for technological innovation or development. In 
this case, the standards promote technological development by promoting 
further development and market penetration of equipment upgrades and 
process changes that improve plant efficiency.

VII. Rationale for Final Standards for Reconstructed Fossil Fuel-Fired 
Electric Utility Steam Generating Units

A. Rationale for Final Applicability Criteria for Reconstructed Sources

    The applicability rationale for reconstructed utility steam 
generating units is the same as for newly constructed utility steam 
generating units. We are finalizing the same general criteria and not 
amending the reconstruction provisions included in the general 
provisions.

B. Identification of the Best System of Emission Reduction

    In the proposal, the EPA evaluated seven different control 
technology configurations to determine the BSER for reconstructed 
fossil fuel-fired boiler and IGCC EGUs: (1) The use of partial CCS, (2) 
conversion to (or co-firing with) natural gas, (3) the use of CHP, (4) 
hybrid power plants, (5) reductions in generation associated with 
dispatch changes, renewable generation, and demand side energy 
efficiency, (6) efficiency improvements achieved through the use of the 
most efficient generation technology, and (7) efficiency improvements 
achieved through a combination of best operating practices and 
equipment upgrades.
    Although the EPA concluded that the first 4 technologies met most 
of the evaluation criteria, namely they are adequately demonstrated, 
have reasonable costs and provide GHG emissions reductions, they were 
inappropriate for BSER due to site specific constraints for existing 
EGUs on a nationwide basis. We rejected best operating practices and 
equipment upgrades because we concluded the GHG reductions are not 
sufficient to qualify as BSER. The majority of commenters agree with 
the EPA's decision that these technologies are not BSER. In contrast, 
as described in more detail later in this section a few commenters did 
support partial CCS as BSER.
    The fifth option, reductions in generation associated with dispatch 
changes, renewable generation, and demand side energy efficiency, is 
comparable to application of measures identified in building blocks 
two, three and four in the emissions guidelines that we proposed under 
CAA section 111(d). We solicited comment on any additional 
considerations that the EPA should take into account in the 
applicability of building blocks two, three and four in the BSER 
determination. Most commenters stated that building blocks two, three 
and four should not be considered for reconstructed sources.
    The proposed BSER was based on the performance of the most 
efficient generation technology available, which we concluded was the 
use of the best available subcritical steam conditions for small units 
and the use of supercritical steam conditions for large units. We 
concluded this technology to be technically feasible, to have 
sufficient emission reductions, to have reasonable costs, and some 
opportunity for technological innovation. The proposed emission 
standard for these sources was 1,900 lb CO2/MWh-n for units 
with a heat input rating of greater than 2,000 MMBtu/h and 2,100 lb 
CO2/MWh-n for units with a heat input rating of 2,000 MMBtu/
h or less. The difference in the proposed standards for larger and 
smaller units was based on greater availability of higher pressure/
temperature steam turbines (e.g. supercritical steam turbines) for 
larger units. As explained in Section III of this preamble, we are 
finalizing the standard on a gross output basis for utility steam 
generating units. The equivalent gross-output-based standards are 1,800 
lb CO2/MWh and 2,000 lb CO2/MWh respectively.
    We solicited comment on multiple aspects of the proposed standards. 
First, we solicited comment on a range of 1,600 to 2,000 lb 
CO2/MWh-g for large units and 1,800 to 2,200 lb 
CO2/MWh-g for small units. We also solicited comment on 
whether the standards for utility boilers and IGCC units should be 
subcategorized by primary fuel type. In addition, we solicited comment 
on if there are sufficient alternate compliance technologies (e.g., co-
firing natural gas) that the small unit subcategory is unnecessary and 
should be eliminated. Those small sources would be required to meet the 
same emission standard as large utility boilers and IGCC units.
    Many commenters supported the upper limits of the suggested ranges, 
saying the standard will be consistently met. Some commenters raised 
concerns about the achievability of these limits for the many boiler 
and fuel types. A few commenters suggested that there should be 
separate subcategories for coal-fired utility boilers and IGCC units, 
since IGCC units have demonstrated limits closer to 1,500 lb 
CO2/MWh-n and the units' designs are so fundamentally 
different. Some commenters said that CFB (due to lower maximum steam 
temperatures), IGCC, and traditional boilers each need their own 
subcategory. Some commenters suggested that due to high moisture 
content and high relative CO2 emissions of lignite, lignite-
fired units should have its own subcategory. Other commenters opposed 
the proposed standards for reconstructed units because they thought the 
BSER determination for reconstructed subpart Da units was inconsistent 
with the BSER determination for newly constructed units. These 
commenters stated that the EPA did not provide sufficient justification 
for eliminating partial carbon capture and sequestration (CCS). These 
commenters also stated that the reason the EPA gave for dismissing CCS 
in the proposal was a lack of ``sufficient information about costs.'' 
These commenters hold that the cost rationale does not apply for 
reconstructed coal-fired power plants. The fact that reconstructed 
units may face greater costs to comply with a CAA section 111(b) 
standard than new sources does not relieve them of their compliance 
obligation.
    Based on a review of the comments, we have concluded that both the 
proposed BSER and emission standards are appropriate, and we are 
finalizing the standards as proposed. Nothing in the comments changed 
our view that the BSER for reconstructed steam generating units should 
be based on the performance of a well operated and maintained EGU using 
the most efficient generation technology available, which we have 
concluded is a supercritical pulverized coal (SCPC) or supercritical 
circulating fluidized bed (CFB) boiler for large units, and subcritical 
for small units. As described at proposal, we have concluded that these 
standards are achievable by all the primary coal types. The final 
standards for reconstructed utility boilers and IGCC units is 1,800 lb 
CO2/MWh-g for sources with a heat input rating of greater 
than 2,000 MMBtu/h and 2,000 lb CO2/MWh-g for sources with a 
heat input rating of 2,000 MMBtu/h or less.

[[Page 64601]]

    While the final emission standards are based on the identified 
BSER, a reconstructed EGU would not necessarily have to rebuild the 
boiler to use steam temperatures and pressures that are higher than the 
original design. As commenters noted, a reconstructed unit is not 
required to meet the standards if doing so is deemed to be 
``technologically and economically'' infeasible. 40 CFR 60.15(b). This 
provision inherently requires case-by-case reconstruction 
determinations in the light of considerations of economic and 
technological feasibility. However, this case-by-case determination 
would consider the identified BSER (the use of the best available steam 
conditions), as well as--at a minimum--the first four technologies the 
EPA considered, but rejected, as BSER for a nationwide rule. One or 
more of these technologies could be technically feasible and reasonable 
cost, depending on site specific considerations and, if so, would 
likely result in sufficient GHG reductions to comply with the 
applicable reconstructed standards. Finally, in some cases, equipment 
upgrades and best operating practices would result in sufficient 
reductions to achieve the reconstructed standards.

VIII. Summary of Final Standards for Newly Constructed and 
Reconstructed Stationary Combustion Turbines

    This section summarizes the final applicability requirements, BSER 
determinations, and emission standards for newly constructed and 
reconstructed stationary combustion turbines. In addition, it also 
summarizes significant differences between the proposed and final 
provisions.

A. Applicability Requirements

    We are finalizing BSER determinations and emission standards for 
newly constructed and reconstructed stationary combustion turbines that 
(1) have a base load rating for fossil fuels greater than 260 GJ/h (250 
MMBtu/h) and (2) serve a generator capable of selling more than 25 MW-
net of electricity to the grid. We also are finalizing applicability 
requirements that will exempt from the final standards (1) all 
stationary combustion turbines that are dedicated non-fossil fuel-fired 
units (i.e., combustion turbines capable of combusting 50 percent or 
more non-fossil fuel) and subject to a federally enforceable permit 
condition restricting annual fossil fuel use to 10 percent or less of a 
unit's annual heat input capacity; (2) the large majority of industrial 
CHP units (i.e., CHP combustion turbines that are subject to a 
federally enforceable permit condition limiting annual net-electric 
sales to the product of the unit's net design efficiency multiplied by 
the unit's potential output, or 219,000 MWh, whichever is greater); (3) 
combustion turbines that are physically incapable of burning natural 
gas (i.e., not connected to a natural gas pipeline); and (4) municipal 
waste combustors and commercial or industrial solid waste incinerators 
(units subject to subparts Eb or CCCC of this part).
    For combustion turbines subject to an emission standard, we are 
finalizing three subcategories: base load natural gas-fired units, non-
base load natural gas-fired units, and multi-fuel-fired units. We use 
the term base load natural gas-fired units to refer to stationary 
combustion turbines that (1) burn over 90 percent natural gas and (2) 
sell electricity in excess of their design efficiency (not to exceed 50 
percent) multiplied by their potential electric output. To be in this 
subcategory, a stationary combustion turbine must exceed the ``natural 
gas-use criterion'' on a 12-operating-month rolling average and the 
``percentage electric sales'' criterion on both a 12-operating-month 
and 3-year rolling average basis. We use the term non-base load natural 
gas-fired units to refer to stationary combustion turbines that (1) 
burn over 90 percent natural gas and (2) have net-electric sales equal 
to or below their design efficiency (not to exceed 50 percent) 
multiplied by their potential electric output. These criteria are 
calculated on the same rolling average bases as for the base load 
subcategory. Finally, we use the term multi-fuel-fired units to refer 
to stationary combustion turbines that burn 10 percent or more non-
natural gas on a 12-operating-month rolling average basis. We are not 
finalizing the proposed emission standards for modified sources and are 
withdrawing those standards. We explain our rationale for these final 
decisions in Sections IX and XV of this preamble.

B. Best System of Emission Reduction

    We are finalizing BSER determinations for the three subcategories 
of stationary combustion turbines referred to above: base load natural 
gas-fired units, non-base load natural gas-fired units, and multi-fuel-
fired units. For newly constructed and reconstructed base load natural 
gas-fired stationary combustion turbines, the BSER is the use of 
efficient NGCC technology. For newly constructed and reconstructed non-
base load natural gas-fired stationary combustion turbines, the BSER is 
the use of clean fuels (i.e., natural gas with an allowance for a small 
amount of distillate oil). For multi-fuel-fired stationary combustion 
turbines, the BSER is also the use of clean fuels (e.g., natural gas, 
ethylene, propane, naphtha, jet fuel kerosene, fuel oils No. 1 and 2, 
biodiesel, and landfill gas).

C. Final Emission Standards

    For all newly constructed and reconstructed base load natural gas-
fired combustion turbines, we are finalizing an emission standard of 
1,000 lb CO2/MWh-g, calculated on a 12-operating-month 
rolling average basis. We are also finalizing an optional emission 
standard of 1,030 lb CO2/MWh-n, calculated on a 12-
operating-month rolling average basis, for stationary combustion 
turbines in this subcategory. For newly constructed and reconstructed 
non-base load natural gas-fired combustion turbines, we are finalizing 
a standard of 120 lb CO2/MMBtu, calculated on a 12-
operating-month rolling average basis. For newly constructed and 
reconstructed multi-fuel-fired combustion turbines, we are finalizing a 
standard of 120 to 160 lb CO2/MMBtu, calculated on a 12-
operating-month rolling average basis. The emission standard for multi-
fuel-fired combustion turbines co-firing natural gas with other fuels 
shall be determined at the end of each operating month based on the 
percentage of co-fired natural gas. Table 15 summarizes the 
subcategories, BSER determinations, and emission standards for 
combustion turbines.

[[Page 64602]]



           Table 15--Combustion Turbine Subcategories and BSER
------------------------------------------------------------------------
           Subcategory                   BSER          Emission standard
------------------------------------------------------------------------
Base load natural gas-fired       Efficient NGCC....  1,000 lb CO2/MWh-g
 combusiton turbines.                                  or 1,030 lb CO2/
                                                       MWh-n
Non-base load natural gas-fired   Clean fuels.......  120 lb CO2/MMBtu
 combustion turbines.
Multi-fuel-fired combustion       Clean fuels.......  120 to 160 lb CO2/
 turbines.                                             MMBtu \528\
------------------------------------------------------------------------

D. Significant Differences Between Proposed and Final Combustion 
Turbine Provisions

    As shown in Tables 16 and 17 below, the proposed rule included 
several general applicability criteria and two subcategorization 
criteria for combustion turbines. In addition to the proposed 
applicability and subcategorization framework, we solicited comment on 
a ``broad applicability approach'' that included most combustion 
turbines irrespective of the actual amount of electricity sold to the 
grid or the actual amount of natural gas burned (i.e., non-base load 
units and multi-fuel-fired units, respectively). The broad 
applicability approach changed the proposed ``percentage electric 
sales'' and ``natural gas-use'' criteria to distinguish among 
subcategory-specific emissions standards. Specifically, in the broad 
applicability approach, we solicited comment on subjecting non-base 
load units and multi-fuel-fired units to ``no emissions standard,'' 
while still including them in the general applicability. We also 
solicited comment on establishing a separate numerical standard for 
non-base load units. The final rule retains all of the proposed 
applicability criteria in some form, but most closely tracks the broad 
applicability approach by finalizing the percentage electric sales and 
natural gas-use criteria as thresholds that distinguish among three 
subcategories of combustion turbines with separate emissions standards.
---------------------------------------------------------------------------

    \528\ The emission standard for combustion turbines co-firing 
natural gas with other fuels shall be determined based on the amount 
of co-fired natural gas at the end of each operating month.
---------------------------------------------------------------------------

    The final rule also includes exceptions to the broad applicability 
approach that we solicited comment on, with some changes that are 
responsive to public comments. Categorical exceptions to the broad 
applicability criteria are the exclusions for CHP units, non-fossil 
fuel units, and combustion turbines not able to combust natural gas. 
First, the proposed applicability criteria did not include CHP units 
that were constructed for the purpose of or that actually sell one-
third or less of their potential electric output or 219,000 MWh, 
whichever is greater, to the grid. The final rule eliminates the 
``constructed for the purpose of'' and actual sales aspects of the 
proposal and replaces them with an exemption for CHP units that take 
federally enforceable permit conditions restricting net-electric sales 
to a percentage of potential electric sales based on the unit's design 
efficiency or 219,000 MWh, whichever is greater. Second, the proposed 
applicability criteria did not include non-fossil fuel units that burn 
10 percent or less fossil fuel on a 3-year rolling average. The final 
rule similarly replaces the actual fuel-use aspect of the proposal with 
an exemption for non-fossil fuel units that take federally enforceable 
permit conditions limiting fossil-fuel use to 10 percent or less of 
annual heat input capacity. Finally, the proposed applicability 
criteria did not include combustion turbines that burn 90 percent or 
less natural gas on a 3-year rolling average basis. In contrast, the 
final rule includes most fossil fuel-fired combustion turbines 
regardless of the amount of natural gas burned, with an exception for 
combustion turbines that are not connected to natural gas pipelines. 
Finally, in response to public comments, we are not finalizing the 
subcategories for large and small combustion turbines that were 
contained in the proposal. Instead, all base load natural gas-fired 
combustion turbines must meet an emission standard of 1,000 lb 
CO2/MWh-g.

  Table 16--Proposed Applicability Criteria versus Final Applicability
                                Criteria
------------------------------------------------------------------------
                                       Proposed              Final
     Applicability Criteria          Applicability       Applicability
------------------------------------------------------------------------
Base load rating criterion......  Base load rating >  Base load rating >
                                   73 MW (250 MMBtu/   260 GJ/h \529\
                                   h).                 (250 MMBtu/h)
Total electric sales criterion..  Constructed for     Ability to sell >
                                   purpose of and      25 MW-n to the
                                   actually selling    grid
                                   > 219,000 MWh-n
                                   to the grid.
Percentage electric sales         Constructed for     Changed to
 criterion.                        purpose of and      subcategorization
                                   having actual net-  criterion per
                                   sales to the grid   broad
                                   > one-third of      applicability
                                   potential           approach
                                   electric output.
Natural gas-use criterion.......  Actually burns >     Changed
                                   90 percent          to
                                   natural gas.        subcategorization
                                                       criterion per
                                                       broad
                                                       applicability
                                                       approach
                                                       Exemption
                                                       for combustion
                                                       turbines that are
                                                       not connected to
                                                       a natural gas
                                                       supply
Fossil fuel-use criterion.......  Actually burns >    Exemption based on
                                   10 percent fossil   permit condition
                                   fuel.               limiting amount
                                                       of fossil fuel
                                                       burned to <= 10
                                                       percent of annual
                                                       heat input
                                                       capacity
Combined Heat and Power (CHP)     NA................  Exemption based on
 exemption.                                            permit condition
                                                       limiting net-
                                                       electric sales to
                                                       <= design
                                                       efficiency
                                                       multiplied by
                                                       potential
                                                       electric output,
                                                       or 219,000 MWh-n,
                                                       whichever is
                                                       greater
Non-EGU exemption...............  Exemption for       Same as proposal
                                   municipal solid
                                   waste combustors
                                   and commercial or
                                   industrial solid
                                   waste
                                   incinerators.
------------------------------------------------------------------------


[[Page 64603]]


       Table 17--Proposed Subcategories versus Final Subcategories
------------------------------------------------------------------------
           Subcategory             Proposed Criteria    Final Criteria
------------------------------------------------------------------------
Small combustion turbine          Base load rating    NA
 subcategory.                      <= 850 MMBtu/h.
Large combustion turbine          Base load rating >  NA
 subcategory.                      850 MMBtu/h.
Base load natural gas-fired base  NA................   Actually
 load combustion turbine                               burns > 90
 subcategory.                                          percent natural
                                                       gas
                                                       Net-
                                                       electric sales >
                                                       design efficiency
                                                       (not to exceed 50
                                                       percent)
                                                       multiplied by
                                                       potential
                                                       electric output
Non-base load natural gas-fired   NA................   Actually
 combustion turbine subcategory.                       burns > 90
                                                       percent natural
                                                       gas
                                                       Net-
                                                       electric sales <=
                                                       design efficiency
                                                       (not to exceed 50
                                                       percent)
                                                       multiplied by
                                                       potential
                                                       electric output
Multi-fuel-fired combustion       NA................  Actually burns <=
 turbine subcategory.                                  90 percent
                                                       natural gas
------------------------------------------------------------------------

IX. Rationale for Final Standards for Newly Constructed and 
Reconstructed Stationary Combustion Turbines

    This section discusses the EPA's rationale for the final 
applicability criteria, BSER determinations, and standards of 
performance for newly constructed and reconstructed stationary 
combustion turbines. In this section, we present a summary of what we 
proposed, a selection of the significant comments we received, and our 
rationale for the final determinations, including how the comments 
influenced our decision-making.
---------------------------------------------------------------------------

    \529\ 73 MW is equivalent to 260 GJ/h. We changed units to avoid 
potential confusion of MW referring to electric output rather than 
heat input.
---------------------------------------------------------------------------

A. Applicability

    This section describes the proposed applicability criteria, 
applicability issues we specifically solicited comment on, the relevant 
significant comments, and the final applicability criteria. We also 
provide our rationale for finalizing applicability criteria based 
strictly on design and permit restrictions rather than actual operating 
characteristics. Finally, we explain why the proposed percentage 
electric sales and natural gas-use applicability criteria are being 
finalized instead as criteria to distinguish between separate 
subcategories of stationary combustion turbines.
1. Proposed Applicability Criteria
    In the January 2014 proposal, we proposed several applicability 
criteria for stationary combustion turbines. Specifically, to be 
subject to the proposed emission standards, we proposed that a unit 
must (1) be capable of combusting more than 73 MW (250 MMBtu/h) heat 
input of fossil fuel; (2) be constructed for the purpose of supplying 
and actually supply more than one-third of its potential electric 
output capacity to a utility power distribution system for sale (that 
is, to the grid) on a 3-year rolling average; (3) be constructed for 
the purpose of supplying and actually supply more than 219,000 MWh net-
electric output to the grid on a 3-year rolling average; (4) combust 
over 10 percent fossil fuel on a 3-year rolling average; and (5) 
combust over 90 percent natural gas on a 3-year rolling average. We 
proposed exempting municipal solid waste combustors and commercial and 
industrial solid waste incinerators.
    Under these proposed applicability criteria, two types of 
stationary combustion turbines that are currently subject to criteria 
pollutant standards under subpart KKKK would not have been subject to 
CO2 standards. The first type was stationary combustion 
turbines that are constructed for the purpose of selling and that 
actually sell one-third or less of their potential output or 219,000 
MWh or less to the grid on a 3-year rolling average basis (i.e., non-
base load units). The second type was combustion turbines that actually 
combust 90 percent or less natural gas on a 3-year rolling average 
basis (i.e., multi-fuel-fired units).
    We proposed the electric sales criteria in part because they 
already exist in other regulatory contexts (e.g., the coal-fired EGU 
criteria pollutant NSPS) and would promote consistency between 
regulations. Our understanding at proposal was that the percentage 
electric sales criterion would distinguish between non-base load units 
(e.g., low capital cost, flexible, but relatively inefficient simple 
cycle units) and base load units (i.e., higher capital cost, less 
flexible, but relatively efficient combined cycle units).
    While the proposed applicability criteria did not explicitly exempt 
simple cycle combustion turbines from the emission standards, we 
concluded that, as a practical matter, the vast majority of simple 
cycle turbines would be excluded because they historically have 
operated as peaking units and, on average, have sold less than five 
percent of their potential electric output on an annual basis, well 
below the proposed one-third electric sales threshold.
a. Solicitation of comment on applicability, generally
    We solicited comment on a range of issues related to applicability. 
In conjunction with the proposed one-third (i.e., 33.3 percent) 
electric sales threshold, we solicited comment on a threshold between 
20 to 40 percent of potential electric output. We also solicited 
comment on a variable percentage electric sales criterion, which would 
allow more efficient, lower emitting turbines to run for longer periods 
of operation before becoming subject to the standards of performance. 
Under this ``sliding scale'' approach, the percentage electric sales 
criterion would be based on the net design efficiency of the combustion 
turbine being installed. In this way, more efficient combustion 
turbines would be able to sell a greater portion of their potential 
electric output compared with less efficient combustion turbines before 
becoming subject to an emission standard. This approach had the benefit 
of incentivizing the development and installation of more efficient 
simple cycle combustion turbines to serve peak load.
    We also solicited comment on whether the percentage electric sales 
criterion for stationary combustion turbines should be defined on a 
single calendar year basis. In addition, we solicited comment on 
eliminating the 219,000 MWh aspect of the total electric sales 
criterion to eliminate any incentive for generators to install 
multiple, small, less-efficient stationary combustion turbines that 
would be exempt due to their lower output. We further solicited comment 
on whether to provide an explicit exemption for all simple cycle 
combustion turbines regardless of the amount of electricity sold. We 
additionally solicited comment on how to implement the proposed 
electric sales, fossil fuel-use, and natural

[[Page 64604]]

gas-use criteria given that they were to be evaluated as 3-year rolling 
averages during the first three years of operation, and we requested 
comment on appropriate monitoring, recordkeeping, and reporting 
requirements. We specifically solicited comment on whether these 
proposed requirements raised implementation issues because they were 
based on source operation after construction has occurred.
    We also solicited comment on excluding electricity sold during 
system emergencies from the calculation of percentage electric sales. 
The rationale for this exclusion was that simple cycle combustion 
turbines intended only for peaking applications might be required to 
operate above the proposed percentage electric sales threshold if a 
major power plant or transmission line became unexpectedly unavailable 
for an extended period of time. The EPA proposed that this flexibility 
would be appropriate if the unit were called upon to run after all 
other available generating assets were already running at full load.
b. Solicitation of comment on broad applicability approach
    In both the January 2014 proposal for newly constructed EGUs and 
the June 2014 proposal for modified and reconstructed EGUs, the EPA 
solicited comment on finalizing a broad applicability approach instead 
of the proposed approach. Under the proposed approach, a stationary 
combustion turbine could be an affected EGU one year, but not the next, 
depending on the unit's actual electric sales and the composition of 
fuel burned. The broad applicability approach is consistent with 
historical NSPS applicability approaches that are based on design 
criteria and include different emission standards for subcategories 
that are distinguished by operating characteristics. Specifically, we 
solicited comment on whether we should completely remove the electric 
sales and natural gas-use criteria from the general applicability 
framework. Instead, the percentage electric sales and natural gas-use 
thresholds would serve as subcategorization criteria for distinguishing 
among classes of EGUs and subcategory-specific emissions standards. 
Under this broad applicability approach, the ``constructed for the 
purpose of'' component of the percentage electric sales criterion would 
be completely eliminated so that applicability for combustion turbines 
would be determined only by a unit's base load rating (i.e., greater 
than 260 GJ/h (250 MMBtu/h)) and its capability to sell power to a 
utility distribution system (i.e., serving a generator capable of 
selling more than 25 MW). In contrast to the proposed applicability 
criteria, under the broad applicability approach, non-base load (e.g., 
simple cycle) and multi-fuel-fired (e.g., oil-fired) combustion 
turbines would remain subject to the rule regardless of their electric 
sales or fuel use. We solicited comment on all aspects of this ``broad 
applicability approach,'' including the extent to which it would 
achieve our policy objective of assuring that owners and operators 
install NGCC combustion turbines if they plan to sell more than the 
specified electric sales threshold to the grid.
2. Comments on Applicability
    This section summarizes the comments we received specific to each 
of the proposed applicability criteria. We also received more general 
comments on the scope of the proposed framework as compared to the 
scope of the broad applicability approach. Comments on applicability 
for dedicated non-fossil and CHP units are discussed in Section III.
a. Base load rating criterion
    Many commenters supported a base load rating of 260 GJ/h (250 
MMBtu/h) because it is generally consistent with the threshold used in 
states participating in the Regional Greenhouse Gas Initiative (RGGI) 
and under Title IV programs. Other commenters opposed the proposed 
applicability thresholds and stated that all new, modified, and 
reconstructed units that sell electricity to the grid, including small 
EGUs and simple cycle combustion turbines, should be affected EGUs 
because they would otherwise have a competitive advantage in energy 
markets as they would not be required to internalize the costs of 
compliance.
b. Total electric sales criterion
    Commenters noted that the 219,000 MWh total electric sales 
threshold put larger combustion turbines at a competitive disadvantage 
by distorting the market and could have the perverse impact of 
increasing CO2 emissions. These commenters noted that the 
219,000 MWh total electric sales threshold would allow combustion 
turbines smaller than approximately 80 MW to sell more than one-third 
of their potential electric output, but larger, more efficient 
combustion turbines would still be restricted to selling one-third of 
their potential electric output to avoid triggering the NSPS. They 
argued that this would result in a regulatory incentive for generators 
to install multiple, less-efficient combustion turbines instead of 
fewer, more-efficient combustion turbines and could have the unintended 
consequence of increasing CO2 emissions.
c. Percentage electric sales criterion
    Commenters from the power sector generally supported a complete 
exemption for simple cycle turbines. These commenters stated that 
simple cycle turbines are uniquely capable of achieving the ramp rates 
(the rate at which a power plant can increase or decrease output) 
necessary to respond to emergency conditions and hourly variations in 
output from intermittent renewables. Commenters noted that simple cycle 
combustion turbines serve a different purpose than NGCC power blocks. 
In addition, commenters noted that electricity generation dispatch is 
based on the incremental cost to generate electricity and that because 
NGCC units have a lower incremental generation cost than simple cycle 
units, economics will drive the use of NGCC technologies over simple 
cycle units. However, commenters also stated that historic simple cycle 
operating data may not be representative of future system requirements 
as coal units retire, generation from intermittent renewable generation 
increases, and numerous market and regulatory drivers impact plant 
operations. In the absence of a complete exemption, these commenters 
supported a percentage electric sales threshold between 40 to 60 
percent of a unit's potential electric output.
    Some commenters said that because the proposed percentage electric 
sales criterion applied over a three-year period, it would adversely 
affect grid reliability because operators conservatively would hedge 
short-term operating decisions to ensure that they have sufficient 
capacity to respond to unexpected scenarios during future compliance 
periods when the demand for electricity is higher. These commenters 
were concerned that such compliance decisions would drive up the cost 
of electricity as the most efficient new units are taken out of service 
to avoid triggering the NSPS and older, less efficient units with no 
capacity factor limitations are ramped up instead.
    Some commenters supported the sliding-scale approach (i.e., a 
percentage electric sales threshold based on the design efficiency of 
the combustion turbine) and stated that incentives for manufacturers to 
develop (and end users to purchase) higher efficiency combustion 
turbines could help mitigate concerns about a monolithic national 
constraint on simple cycle capacity factors.

[[Page 64605]]

    In contrast, others commented that fast-start NGCC units intended 
for peaking and intermediate load applications can achieve comparable 
ramp rates to simple cycle combustion turbines, but with lower 
CO2 emission rates. These commenters said that simple cycle 
turbines should be restricted to their historical role as true peaking 
units and that the proposed one-third electric sales threshold provided 
sufficient flexibility. Some commenters suggested that the one-third 
electric sales threshold could be reduced to 20 percent or lower 
without adverse impacts on grid reliability.
    Commenters noted that a complete exclusion for simple cycle 
turbines would create a regulatory incentive for generators to install 
and operate less efficient unaffected units instead of more efficient 
affected units, thereby increasing CO2 emissions. According 
to these commenters, any applicability distinctions should be based on 
utilization and function rather than purpose or technology.
    Commenters in general supported the use of 3-year rolling averages 
instead of a single-year average for the percentage and total electric 
sales criteria because, in their view, the 3-year rolling averages 
would provide a better overall picture of normal operations. Some 
commenters stated that a rolling 12-month or calendar-year average 
could be severely skewed in a given year because of unforeseen or 
unpredicted events. They said that using a 3-year averaging methodology 
would provide system operators with needed flexibility to dispatch 
simple cycle units at higher than normal capacity factors. In contrast, 
some commenters stated that, because capacity is forward-looking (e.g., 
payments for capacity are often made several years in advance), the 3-
year averaging period provides limited benefit because owner/operators 
need to reserve the ability to respond to unforeseen events.
    Commenters noted that potential compliance issues could result from 
the inconsistent time frame between the 3-calendar-year applicability 
period and the 12-operating-month compliance period. For example, a 
facility could sell more than one-third of its potential electric 
output over a 3-year period, but sell less than one-third of its 
potential electric output during any given 12-operating-month 
compliance period within that 3-year period. During a 12-operating-
month period with electric sales of less than one-third of potential 
electric output, a unit could be operating for long periods at part 
load and have multiple starts and stops. These operating conditions 
have the potential to increase CO2 emissions, regardless of 
the deign efficiency of the turbine. Therefore, a unit could have an 
emission rate in excess of the proposed standard.
    Regarding the relationship between the percentage electric sales 
criterion and system emergencies, multiple commenters supported 
exclusion of electricity generated as a result of a system emergency 
from counting towards net sales. These commenters stated that the 
exclusion was appropriate because the benefits of operating these units 
to generate electrical power during emergency conditions would outweigh 
any adverse impacts from short-term increases in CO2 
emissions. One commenter stated that, in addition to declared grid 
emergencies, other circumstances might warrant emergency exemption 
under the rule, including extreme market conditions, limitations on 
fuel supply, and reliability responses.
    Multiple commenters opposed the exclusion of system emergencies 
when calculating a source's percentage electric sales for applicability 
purposes because NSPS must apply continuously, even during system 
emergencies. These commenters stated that the EPA does not have the 
authority under the CAA to suspend the applicability of a standard 
during periods of system emergency. Some commenters stated that an 
exclusion would be unnecessary because the EPA Assistant Administrator 
for Enforcement has the authority to advise a source that the 
government will not sue the source for taking certain actions during an 
emergency. Commenters said that this enforcement discretion approach 
has provided prompt, flexible relief that is tailored to the needs of 
the particular emergency and the communities being served and is only 
utilized where the relief will address the particular emergency at 
hand.
    Commenters added that this enforcement discretion approach is 
consistent with the CAA's mandate that emission limits apply 
continuously and provide safeguards against abuse. One commenter stated 
that emergencies happen rarely and typically last for short periods, 
that the proposed percentage electric sales threshold would allow a 
source to operate at its full rated capacity for up to 2,920 hours per 
year without triggering applicability, and that the potential 
occurrence of grid emergencies would represent a tiny fraction of this 
time. Another commenter stated that no emergency short of large scale 
destruction of power generating capacity by terrorism, war, accident, 
or natural disaster could justify operating a peaking unit above a 10-
percent capacity factor on a 3-year rolling average.
d. Broad applicability approach
    In response to the EPA's request for comments on whether the 
proposed applicability requirements that retrospectively look back at 
actual events (i.e., the electric sales and fuel use criteria) would 
create implementation issues, several permitting authorities opposed 
the provisions because units could be subject to coverage one year but 
not the next, resulting in compliance issues and difficulties in 
determining proper pre-construction and operating permit conditions. 
These permitting authorities suggested that in order for a source to 
avoid applicability, the source should be subject to a federally 
enforceable permit condition with associated monitoring, recordkeeping, 
and reporting conditions for assessing applicability on an ongoing 
basis. Other commenters stated that an applicability test that 
concludes after construction and operation have commenced is 
inconsistent with the general purpose of an applicability test--to 
provide clear and predictable standards of performance for new sources 
that would apply when they begin operations.
    Some commenters opposed the proposed retrospective applicability 
criteria related to actual output supplied during a preceding 
compliance period because EGUs must know what performance standards 
will apply to them during the licensing process, and such criteria do 
not allow the permitting authority and the public to know in advance 
whether an emission standard applies to a proposed new unit. Other 
commenters said that EGUs undergoing permitting should be allowed to 
request limits in their operating permit conditions in order to remain 
below the applicability thresholds, as this methodology is consistent 
with the pre-construction permitting requirements in many federally 
approved SIPs and the current approach under the Title V permitting 
program.
    Many commenters stated a preference for the ``proposed 
applicability approach'' over the ``broad applicability approach.'' 
These commenters did not think it was necessary to require non-base 
load or multi-fuel-fired combustion turbines to be subject to emission 
standards. They stated that there is no justification for imposing 
burdensome monitoring, reporting, and recordkeeping requirements that 
would have no environmental benefit (i.e., would not reduce 
CO2 emissions) because these units would be subject to

[[Page 64606]]

``no emissions standards.'' Other commenters supported the broad 
applicability approach and stated that all new, modified, and 
reconstructed units that sell electricity to the grid, including small 
EGUs, oil-fired combustion turbines, and simple cycle combustion 
turbines should be affected EGUs because they would otherwise have a 
competitive advantage in energy markets as they would not be required 
to internalize the costs of compliance.
    In contrast, to preserve the discretion of state planners under 
section 111(d), many other commenters supported the broad applicability 
approach and the inclusion of new simple cycle units within the scope 
of the section 111(b) emission standards so that similar, existing 
simple cycle units could be subject to the 111(d) standards. Numerous 
other commenters stated that all units that sell electricity to the 
grid should be subject to a standard, including simple cycle units, 
because they view the utility grid as a single integrated system and 
that doing so may simplify development of future frameworks for cost-
effective carbon reductions from existing units, such as frameworks 
based on system-wide approaches.
3. Final Applicability Criteria and Rationale
    Based on our consideration of the comments received related to the 
proposed applicability criteria and practical implementation issues, we 
are revising how those criteria will be implemented. The final 
applicability criteria for combustion turbines are generally consistent 
with the broad applicability approach on which we solicited comment. 
Section VIII of this preamble presents each proposed applicability 
criterion together with the form of the criterion in the final rule. 
The final general applicability framework includes the proposed 
criteria based on the combustion turbine's base load rating and the 
combustion turbine's total electric sales capacity. The final general 
applicability framework also includes multiple exemptions that are 
relevant to combustion turbines: combustion turbines that are not 
connected to natural gas pipelines; CHP facilities with federally 
enforceable limits on total electric sales; dedicated non-fossil units 
with federally enforceable limits on the use of fossil fuels; and 
municipal waste combustors and incineration units.
    The final applicability framework reflects multiple variations from 
the proposal that are responsive to public comments. First, consistent 
with the broad applicability approach, we are finalizing the percentage 
electric sales and natural gas-use thresholds as subcategorization 
criteria instead of as applicability criteria. In addition, for non-CHP 
combustion turbines, we are eliminating the proposed 219,000 MWh total 
electric sales criterion. Finally, we are eliminating the proposed 
``constructed for the purpose of'' qualifier for the total and 
percentage electric sales criteria. We are also not finalizing 
CO2 standards for dedicated non-fossil fuel-fired or 
industrial CHP combustion turbines. The rationale for not finalizing 
CO2 standards for dedicated non-fossil and industrial CHP 
units is discussed in more detail in Section III.
    The EPA agrees with commenters that the NSPS applicability 
framework should be structured so that permitting authorities, the 
regulated community, and the public can determine what standards apply 
prior to a unit having commenced construction. With this in mind, the 
EPA has concluded that the proposed fossil fuel-use, natural gas-use, 
percentage electric sales, and total electric sales applicability 
criteria for combustion turbines are not ideal approaches. Because 
applicability determinations based on these criteria could change from 
year to year (i.e., units could move in and out of coverage each year 
depending on actual operating parameters), some operators would not 
know the extent of their compliance obligations until after the 
compliance period.
    Further, from a practical implementation standpoint, existing 
permitting rules generally require pre-construction permitting 
authorities to include enforceable conditions limiting operations such 
that unaffected units will not trigger applicability thresholds. Such 
conditions are often called ``avoidance'' or ``synthetic minor'' 
conditions, and these conditions typically include ongoing monitoring, 
recordkeeping, and reporting requirements to ensure that operations 
remain below a particular regulatory threshold.
    The following sections provide further discussion of the final 
general applicability criteria and the rationale for changing certain 
proposed applicability criteria to subcategorization criteria.
a. Base load rating criterion
    We are retaining the applicability criterion that a combustion 
turbine must be capable of combusting more than 260 GJ/h (250 MMBtu/h) 
heat input of fossil fuel. We revised the proposed 73 MW form of the 
base load rating criterion to 260 GJ/h because some commenters 
misinterpreted the 73 MW form (which is mathematically equivalent to 
250 MMBtu/h) as the electrical output rating of the generator. This 
change is a non-substantive unit conversion intended to limit 
misinterpretation. While some commenters suggested that we expand this 
applicability criterion to cover smaller EGUs as well, we did not 
propose to cover smaller units. Because smaller units emit relatively 
few CO2 emissions compared to larger units and because we 
currently do not have enough information to identify an appropriate 
BSER for these units, we are not finalizing CO2 standards 
for smaller units.
b. Total electric sales criterion
    The proposed 219,000 MWh total sales criterion was based on a 25 MW 
unit operating at base load the entire year (i.e., 25 MW * 8,760 h/y = 
219,000 MWh/y). This criterion was included in the original subpart Da 
coal-fired EGU criteria pollutant NSPS. Coal-fired EGUs tend to be much 
larger than 25 MW, and the criterion's primary purpose was to exempt 
industrial CHP facilities from the criteria pollutant NSPS. In the 
context of combustion turbines, however, commenters expressed concerns 
that the 219,000 MWh electric sales threshold would actually encourage 
owners and operators to install multiple, smaller, less-efficient 
simple cycle combustion turbines instead of a single, larger, more-
efficient simple cycle turbine. The reason for this is that the 219,000 
MWh threshold would allow smaller simple cycle combustion turbines of 
less than 80 MW to sell significantly more electricity relative to 
their potential electric output than larger turbines. Many commenters 
also indicated that having the flexibility to operate a simple cycle 
turbine at a higher capacity factor is important because it allows for 
capacity payments from the transmission authority. In light of these 
comments, we are not finalizing the 219,000 MWh total electric sales 
criterion for non-CHP combustion turbines. Instead, we are finalizing a 
criterion that will exempt combustion turbines that do not have the 
ability to sell at least 25 MW to the grid. This approach will maintain 
our goal of exempting smaller EGUs, while avoiding the perverse 
environmental incentives mentioned by the commenters. As explained in 
Section III, however, industrial CHP units are sized based on demand 
for useful thermal output, so there is less of an incentive for owners 
and operators to install multiple smaller units. Therefore, we are 
maintaining the 219,000 MWh

[[Page 64607]]

total electric sales criterion for CHP units.
c. Percentage electric sales criterion
    Commenters generally opposed the proposed percentage electric sales 
criterion approach because it was based in part on actual electric 
sales, meaning applicability could change periodically (i.e., a unit's 
electric sales may change over time, rising above and falling below the 
electric sales threshold). The EPA agrees this situation is not ideal. 
To avoid situations in which applicability changes from year to year, 
we first considered two approaches using permit restrictions. Under the 
first approach, a standard would apply to all sources with permit 
restrictions mandating electric sales above a threshold (i.e., an 
approach that closely mirrors the proposed percentage electric sales 
criterion). Under the second approach, a standard would apply to all 
sources without permit restrictions limiting electric sales to a level 
below that threshold (i.e., effectively identifying non-base load units 
and excluding them from applicability). As stated in the proposal, we 
did not think it was critical to include peaking and cycling units 
because peaking turbines operate less and because it would be much more 
expensive to lower their emission profile to that of a combined cycle 
power plant or a coal-fired plant with CCS.
    The first approach is not practical, however, because new 
combustion turbines could avoid applicability by simply not having a 
permit restriction at all. Moreover, even if a combustion turbine were 
subject to the restriction, it could violate its permit if it did not 
operate enough to sell the requisite amount of electricity. This would 
be nonsensical, especially because system demand would not always be 
sufficient to allow all permitted units to operate above the threshold. 
Therefore, we rejected the first permitting approach.
    In contrast, the second approach would be a viable method for 
identifying and exempting peaking units from applicability. However, 
there are multiple drawbacks to such an applicability approach. First, 
this approach would subject those turbines without a permit restricting 
electric sales to the final emission standards, which raises concerns 
as to whether turbines with lower actual sales could achieve the 
standards. For example, new NGCC units tend to dispatch prior to older 
existing units and will generally operate for extended periods of time 
near full load and sell electricity above the percentage electric sales 
threshold. However, as NGCC units age, they tend to start and stop more 
frequently and operate at part load. Yet, even if these units sell 
below the percentage electric sales threshold, they would still be 
affected units if they did not take a permit restriction. As commenters 
noted, part-load operation and frequent starts and stops can reduce the 
efficiency of a combustion turbine. While we are confident that our 
final standards for base load natural gas-fired combustion turbines can 
be achieved by units serving either base or intermediate load, we are 
not as confident that affected NGCC units that might someday be 
operated as non-base load units (e.g., as NSPS units age, their 
incremental generating costs will tend to be higher than newer units 
and they will dispatch less) could achieve the standards.
    More importantly, however, we are concerned that using a permitting 
approach for the percentage electric sales criterion would create 
problems due to the interaction between 111(b) and 111(d). Under the 
second permitting approach we considered, units with low electric sales 
would be excluded from applicability, while units with high electric 
sales would be included. While these low-electric sales units would 
generally be simple cycle combustion turbines and the high-electric 
sales units would generally be NGCC combustion turbines, this would not 
always be the case. In contrast, we are finalizing an applicability 
approach in the 111(d) emission guidelines that is based on a 
combustion turbine's design characteristics rather than electric sales. 
Simple cycle combustion turbines are excluded from applicability, while 
NGCC units are included. As a result, the universe of sources covered 
by the 111(b) standards would not necessarily be the same universe of 
sources covered by the 111(d) standards.
    To resolve this issue, we considered whether we could change the 
111(d) applicability criteria to be based on historical operation 
rather than design characteristics. For example, if an existing 
combustion turbine had historically sold less than one-third of its 
potential output to the grid, then it would be exempt from the emission 
guidelines. However, many existing NGCC units have historically sold 
less than this amount of electricity, meaning that they would not be 
subject to the rule. We ran into similar issues when considering other 
thresholds. For example, a percentage electric sales threshold of 10 
percent would still exempt roughly 5 percent of existing NGCC units 
from 111(d), while simultaneously raising achievability concerns with 
the 111(b) standard. Moreover, even if we had finalized 111(d) 
applicability criteria based on historical operations, existing NGCC 
units could have decided to take a permit restriction limiting their 
electric sales going forward to avoid applicability. Under any of these 
scenarios, our goals with respect to 111(d) would not be accomplished.
    To avoid this result, the EPA has concluded that it is appropriate 
to finalize the broad applicability approach and set standards for 
combustion turbines regardless of what percentage of their potential 
electric output they sell to the grid. To accommodate the continued use 
of simple cycle and fast-start NGCC combustion turbines for peaking and 
cycling applications, however, the EPA has subcategorized natural gas-
fired combustion turbines based on a variation of the proposed 
percentage electric sales criterion. Specifically, and as explained in 
more detail in Section IX.B.2, we are finalizing the sliding-scale 
approach on which we solicited comment.
d. Natural gas-use criterion
    Similar to the proposed electric sales criteria, commenters 
generally opposed the proposed natural gas-use criterion being based on 
actual operating parameters. As with the electric sales criteria, the 
EPA agrees that applicability that can switch periodically due to 
operating parameters is not ideal. The EPA evaluated two approaches for 
implementing the intent of the proposed natural gas-use criterion 
(i.e., to exclude non-natural gas-fired combustion turbines) through 
operating permit restrictions. Under the first approach, an emission 
standard would apply to all combustion turbines with a permit 
restriction mandating that natural gas contribute over 90 percent of 
total heat input.\530\ Under the second approach, an emission standard 
would apply to all combustion turbines without a permit restriction 
limiting natural gas use to 90 percent or less of total heat 
input.\531\ As with the percentage electric sales criterion, the first 
approach is not practical because combustion turbines could avoid

[[Page 64608]]

applicability by simply not having a permit that requires the use of 
more than 90 percent natural gas, even if they intend to only burn 
natural gas. We disregarded this approach because it would essentially 
provide a pathway for all NGCC units to avoid applicability under both 
111(b) and 111(d). The second approach is problematic because operating 
permit restrictions to improve air quality are typically written to 
limit high emission activities (e.g., limiting the use of distillate 
oil to 500 hours annually), not to limit lower emitting activities. 
This approach could lead to perverse environmental impacts by 
incentivizing the use of non-natural gas fuels, which would typically 
result in higher CO2 emissions. Furthermore, the second 
approach would not limit the fuels that can be burned by affected units 
(i.e., combustion turbines not required to use non-natural gas fuels) 
and would continue to cover combustion turbines even when they burn 
over 10 percent non-natural gas fuels. Because all non-natural gas 
fuels except H2 have CO2 emission rates higher 
than natural gas, this approach would exacerbate the concerns raised by 
commenters about the achievability of the 111(b) requirements when 
burning back up fuels.
---------------------------------------------------------------------------

    \530\ This approach could also be written as ``an emission 
standard would apply to all combustion turbines with a permit 
restriction limiting the use of non-natural gas fuels to 10 percent 
or less of the total heat input.'' Applicability could then be 
avoided by simply being permitted to burn non-natural gas fuels for 
more than 876 hours per year even if they actually intended to 
seldom, if ever, combust the alternate fuels.
    \531\ This approach could also be written as ``an emission 
standard would apply to all combustion turbines without permit 
restrictions mandating that non-natural gas use contribute over 10 
percent or more of total heat input.''
---------------------------------------------------------------------------

    In light of these issues, the EPA has concluded that permit 
restrictions are not an ideal approach to distinguishing between 
natural gas-fired and multi-fuel-fired combustion turbines and are 
finalizing a variation of the broad applicability approach. The EPA has 
concluded that the only practical approach to implement the natural 
gas-use criterion is to look at the turbine's physical ability to burn 
natural gas. Therefore, we are not finalizing CO2 standards 
for combustion turbines that are not capable of firing any natural gas 
(i.e., not connected to a natural gas pipeline). From a practical 
standpoint, the burners of most combustion turbines can be modified to 
burn natural gas, so this exemption is essentially limited to 
combustion turbines that are built in remote or offshore locations 
without access to natural gas. Consistent with the broad applicability 
approach, we are finalizing standards for all other combustion 
turbines, but are subcategorizing between natural gas-fired turbines 
and multi-fuel-fired turbines. Specifically, and as explained in more 
detail in Section IX.B.3, we are distinguishing between these classes 
of turbines based on whether they burn greater than 90 percent natural 
gas or not.

B. Subcategories

    We are finalizing a variation of the broad applicability approach 
for combustion turbines where the percentage electric sales and natural 
gas-use criteria serve as thresholds that distinguish between three 
subcategories. These subcategories are base load natural gas-fired 
units, non-base load natural gas-fired units, and multi-fuel-fired 
units. Under the final subcategorization approach, multi-fuel-fired 
combustion turbines are distinguished from natural gas-fired turbines 
if fuels other than natural gas (e.g., distillate oil) supply 10 
percent or more of heat input. Natural gas-fired turbines are further 
subcategorized as base load or non-base load units based on the 
percentage electric sales criterion. The percentage electric sales 
threshold that distinguishes base load and non-base load units is based 
on the specific turbine's design efficiency (i.e., the sliding-scale 
approach). The percentage electric sales threshold is capped at 50 
percent.
    This section describes comments we received regarding the proposed 
size-based subcategories and our rationale for not finalizing them. In 
addition, it describes comments we received regarding sales-based 
subcategories and our rationale for adopting the sliding scale to 
distinguish between subcategories. Finally, it describes comments we 
received regarding fuel-based subcategories and our rationale for 
adopting fuel-based subcategories.
1. Size-Based Subcategories
    At proposal, the EPA identified two size-based subcategories: (1) 
large natural gas-fired stationary combustion turbines with a base load 
rating greater than 850 MMBtu/h and (2) small natural gas-fired 
stationary combustion turbines with a base load rating of 850 MMBtu/h 
or less. The EPA received numerous comments regarding our proposal to 
subcategorize combustion turbines by size. Some commenters agreed with 
the 850 MMBtu/h cut-point between large and small units, some suggested 
increasing it to 1,500 MMBtu/h, and others suggested eliminating size-
based subcategorization altogether. For example, some commenters stated 
that the 850 MMBtu/h cut-point was inappropriate because it was 
originally calculated based on NOX performance, not 
CO2 performance. These commenters stated that 850 MMBtu/h 
was not a logical demarcation between more efficient and less efficient 
combustion turbines, but rather would divide the units into arbitrary 
size classifications. These commenters suggested that 1,500 MMBtu/h 
would be a better cut-point because data reported to Gas Turbine World 
(GTW) showed that new combustion turbines are not currently offered 
with a heat input rating between 1,300 MMBtu/h and 1,800 MMBtu/h, so 
the higher cut-point would more accurately reflect when more efficient 
technologies are available.
    In contrast, other commenters said that differentiation between 
small and large combustion turbines was not justified at all because 
many of the same efficiency technologies that reduce the emission rates 
of larger units could be incorporated into smaller units (e.g., 
upgrades that increase the turbine engine operating temperature, 
increase the turbine engine pressure ratio, or add multi-pressure steam 
and a steam reheat cycle). These commenters also said that separate 
standards for small and large turbines would undermine the incentive 
for technology innovation, which they described as a key purpose of the 
NSPS program, and that relaxing standards for smaller units would 
discourage investment in more efficient technologies, resulting in 
increased CO2 emissions. These commenters recommended that 
the limit for both large and small units be no higher than 1,000 lb 
CO2/MWh-g.
    After evaluating these comments, the EPA has decided not to 
subcategorize combustion turbines based on size for several reasons. 
First, the heat input values listed in Gas Turbine World do not include 
potential heat input from duct burners.\532\ Because the heat input 
from duct burners is necessary to accurately determine potential 
electric output, our definition of ``base load rating'' includes the 
heat input from any installed duct burners. The EPA reviewed the heat 
input data for existing NGCC units that has been submitted to CAMD. 
These data include the heat input from duct burners and show that 
multiple NGCC power blocks have been built in the past with heat input 
capacities that fall within the range that commenters suggested new 
turbines are not offered. Therefore, the EPA has concluded that the 
regulated community uses various sizes of NGCC turbines and when the 
heat input from duct burners is included, there is no clear break 
between the NGCC unit sizes that could distinguish between small and 
large units. In fact, subcategorizing

[[Page 64609]]

by size could unduly influence the development of future NGCC offerings 
because manufacturers could be incentivized to design new products at 
the top end of the small subcategory to take advantage of the less 
stringent emission standard.
---------------------------------------------------------------------------

    \532\ Duct burners are optional supplemental burners located in 
the HRSG that are used to generate additional steam. Heat input to 
duct burners could in theory be twice that of the combustion turbine 
engine, but are more commonly sized at 10 to 30 percent of the heat 
input to the combustion turbine engine.
---------------------------------------------------------------------------

    Second, commenters suggested that a cut-point of 1,500 MMBtu/h 
reflects when more efficient technologies become available. However, 
when we reviewed actual operating data and design data, we only found a 
relatively weak correlation between turbine size and CO2 
emission rates and did not see a dramatic drop in CO2 
emission rates at 1,500 MMBtu/h. The variability of emission rates 
among similar size units far exceeds any difference that could be 
attributed to a difference in size. In addition, the most efficient 
one-to-one configuration NGCC power block with a base load rating of 
1,500 MMBtu/h or less has a design emission rate of the 767 lb 
CO2/MWh-n (984 MMBtu/h). The most efficient one-to-one 
configuration NGCC power block with a base load rating just greater 
than 1,500 MMBtu/h has a design emission rate of 772 lb CO2/
MWh-n (1,825 MMBtu/h). Because the smaller unit has a lower design 
emission rate than the larger unit, increasing the cut-point does not 
make sense.
    Finally, the EPA has concluded that, while certain smaller NGCC 
designs may be less efficient than larger NGCC designs, most existing 
small units have demonstrated emission rates below the range of 
emission rates on which we solicited comment. We have concluded that 
the lower design efficiencies of some small NGCC units are primarily 
related to model-specific design choices in both the turbine engine and 
HRSG, not an inherent limitation in the ability of small NGCC units to 
have comparable efficiencies to large NGCC units. Specifically, 
manufacturers could improve the efficiency of the turbine engine by 
using turbine engines with higher firing temperatures and high 
compression ratios and could improve the efficiency of the steam cycle 
by switching from single or double-pressure steam to triple-pressure 
steam and adding a reheat cycle. For all of these reasons, we have 
decided against subcategorizing combustion turbines based on size. Our 
rationale for setting a single standard for small and large combustion 
turbines is explained in more detail in Section IX.D.3.a below.
2. Sales-Based Subcategories
    As described above in Section IX.A.3.c, the final applicability 
criteria do not include an exemption for non-CHP units based on actual 
electric sales or permit restrictions limiting the amount of 
electricity that can be sold. Instead, we are finalizing the percentage 
electric sales criterion as a threshold to distinguish between two 
natural gas-fired combustion turbine subcategories. The industry uses a 
number of terms to describe combustion turbines with different 
operating characteristics based on electric sales (e.g., capacity 
factors). Combustion turbines that operate at near-steady, high loads 
are generally referred to as ``base load'' or ``intermediate load'' 
units, depending on how many hours the units operate annually. 
Combustion turbines that operate continuously with variable loads that 
correspond to variable demand are referred to as ``load following'' or 
``cycling'' units. Combustion turbines that only operate during periods 
with the highest electricity demand are referred to as ``peaking'' 
units. However, it is difficult to characterize a particular unit using 
just one of these terms. For example, a particular unit may serve as a 
load following unit during winter, but serve as a base load unit during 
summer. In addition, none of these terms has a precise universal 
definition. In this preamble, we refer to the subcategory of combustion 
turbines that sell a significant portion of their potential electric 
output as ``base load units.'' This subcategory includes units that 
would colloquially be referred to as base load units, as well as some 
intermediate load and load following units. We refer to all other units 
as ``non-base load units.'' This subcategory includes peaking units, as 
well as some load following and intermediate load units. The threshold 
that distinguishes between these two subcategories is determined by a 
unit's design efficiency and varies from 33 to 50 percent, hence the 
term ``slide scale'' approach.
    Numerous commenters supported three sales-based subcategories for 
peaking, intermediate load, and base load units. These commenters said 
that each subcategory should be distinguished by annual hours of 
operation and that each should have a different BSER and emission 
standard. Other commenters opposed the tiered approach. These 
commenters said that separate standards for different operating 
conditions would be complicated to implement and enforce, while 
providing few benefits. These commenters said that a tiered approach 
could also have the unintended consequence of encouraging less 
efficient technologies because it would create a regulatory incentive 
to install lower-capital-cost, less-efficient units that would operate 
under the percentage electric sales threshold instead of higher-
capital-cost, more-efficient units that would operate above the 
threshold.
    After evaluating these comments, the EPA has concluded that it is 
appropriate to adopt a two-tiered subcategorization approach based on a 
percentage electric sales threshold to distinguish between non-base 
load and base load units. While we agree with commenters that separate 
standards for peaking, intermediate, and base load units is attractive 
on the surface, we ultimately concluded that a three-tiered approach is 
not appropriate for several reasons. First, the increased generation 
from renewable sources that is anticipated in the coming years makes it 
very difficult to determine appropriate thresholds to distinguish among 
peaking, intermediate, and base load subcategories. Indeed, the 
boundaries between these demand-serving functions may blur or shift in 
the years to come. The task is further complicated because each 
transmission region has a different mix of generation technologies and 
load profiles with different peaking, intermediate, and base load 
requirements.
    Second, there are only two distinct combustion turbine 
technologies--simple cycle units and NGCC units. In theory, the BSER 
for the intermediate load subcategory could be based on high-efficiency 
simple cycle units or fast-start NGCC units, but these are variations 
on traditional technologies and not necessarily distinct. Moreover, we 
do not have specific cost information on either high-efficiency simple 
cycle turbines or fast-start NGCC units, so our ability to make cost 
comparisons to conventional designs is limited.
    Finally, even if we could identify appropriate sales thresholds to 
distinguish between peaking, intermediate load, and base load 
subcategories, we do not have sufficient information to establish a 
meaningful output-based standard for an intermediate load subcategory 
at this time. In the transition zone from peaking to base load 
operation (i.e., cycling and intermediate load), combustion turbines 
may have similar electric sales, but very different operating 
characteristics. For example, despite having similar sales, one unit 
might have relatively steady operation for a short period of time, 
while another could have variable operation throughout the entire year. 
The latter unit would likely have a higher CO2 emission 
rate. For all of these reasons, the EPA has concluded that we do not 
have sufficient information at this time

[[Page 64610]]

to establish three sales-based subcategories.
    Instead, as we explained above, we are finalizing two sales-based 
subcategories. To determine an appropriate threshold to distinguish 
between base load and non-base load units, the EPA considered the 
important characteristics of the combustion turbines that serve each 
type of demand. For non-base load units, low capital costs and the 
ability to start, stop, and change load quickly are key. Simple cycle 
combustion turbines meet these criteria and thus serve the bulk of peak 
demand. In contrast, for base load units, efficiency is the key 
consideration, while capital costs and the ability to start and stop 
quickly are less important. While NGCC units have relatively high 
capital costs and are less flexible operationally, they are more 
efficient than simple cycle units. NGCC units recover the exhaust heat 
from the combustion turbine with a HRSG to power a steam turbine, which 
reduces fuel use and CO2 emissions by approximately one-
third compared to a simple cycle design. Consequently, base load units 
use NGCC technology. Because simple cycle turbines have historically 
been non-base load units, we have concluded that it is appropriate to 
distinguish between the non-base load and base load subcategories in a 
way that recognizes the distinct roles of the different turbine designs 
on the market.
    The challenge, however, is setting a threshold that will not 
distort the market. The future distinction between non-base load and 
base load units is unclear. For example, some commenters indicated that 
increased generation from intermittent renewable sources has created a 
perceived need for additional cycling and load following generation 
that will operate between the traditional roles of peaking and base 
load units. To fulfill this perceived need, some manufacturers have 
developed high-efficiency simple cycle turbines. These high-efficiency 
turbines have higher capital costs than traditional simple cycle 
turbine designs, but maintain similar flexibilities, such as the 
ability to start, stop, and change load rapidly. Other manufacturers 
have developed fast-start NGCC turbines to fill the same role. These 
newer NGCC designs have lower design efficiencies than NGCC designs 
intended to only operate as base load units, but are able to startup 
more quickly to respond to rapid changes in electricity demand. As a 
result of these new technological developments, both high-efficiency 
simple cycle and fast-start NGCC units can be used for traditional 
peaking applications, as well as for higher capacity applications, such 
as supporting the growth of intermittent renewable generation.
    With the changing electric sector in mind, we set out to identify 
an appropriate percentage electric sales threshold to distinguish 
between non-base load and base load natural gas-fired units. Two 
factors were of primary importance to our decision. First, the 
threshold needed to be high enough to address commenters' concerns 
about the need to maintain flexibility for simple cycle units to 
support the growth of intermittent renewable generation. Second, the 
threshold needed to be low enough to avoid creating a perverse 
incentive for owners and operators to avoid the base load subcategory 
by installing multiple, less efficient turbines instead of fewer, more 
efficient turbines.
    To determine the potential impact of intermittent renewable 
generation on the operation of simple cycle units, we examined the 
average electric sales of simple cycle turbines in the lower 48 states 
between 2005 and 2014 using information submitted to CAMD. We combined 
this data with information reported to the EIA on total in-state 
electricity generation, including wind and solar, from 2008 through 
2014. We focused on data from the Southwest Power Pool (data 
approximated by EGUs in Nebraska, Kansas, and Oklahoma), Texas, and 
California. All of these regions have relatively large amounts of 
generation from wind and solar and experienced increases in the portion 
of total electric generation provided by wind and solar during the 
2008-2014 period.
a. Southwest Power Pool
    The portion of in-state generation from wind and solar in the 
Southwest Power Pool increased from 3 to 16 percent between 2008 and 
2014. The average growth rate of wind and solar was 28 percent, while 
overall electricity demand grew 1 percent annually on average. Based on 
statements in some of the comments, we expected to see a large change 
in the operation of simple cycle turbines in this region. However, the 
average electric sales from simple cycle turbines only increased at an 
annual rate of 1.7 percent, and remained essentially unchanged at 3 
percent of potential electric output between 2008 and 2014. Total 
generation from simple cycle turbines in the Southwest Power Pool 
increased slightly more, at an annual rate of 2.5 percent, which was 
the result of additional simple cycle capacity being added to address 
increased electricity demand.
    This lack of a significant change in the operation of simple cycle 
turbines could be explained by the Southwest Power Pool's relatively 
large amount of exported power. If most of the region's renewable 
generation was being exported, the intermittent nature of this power 
would primarily impact other transmission regions. An alternate 
explanation, however, is that other generating assets are flexible 
enough to respond to the intermittent nature of wind and solar 
generation and that simple cycle turbines are not necessary to back up 
these assets to the degree some commenters suggested. If this is the 
case, then new simple cycle turbines may primarily continue to fill 
their historical role as peaking units going forward, while other 
technologies, such as fast-start NGCC units, may provide the primary 
back up capacity for new wind and solar.
b. Texas
    The portion of in-state generation from wind and solar in Texas 
increased from 4 to 9 percent between 2008 and 2014. The average growth 
rate of wind and solar was 13 percent, while overall demand grew at an 
average rate of 2 percent annually. Similar to the Southwest Power 
Pool, the average electric sales of simple cycle turbines has remained 
relatively unchanged. In fact, the average electric sales of these 
turbines decreased at an annual rate of 1.1 percent. Total generation 
from simple cycle turbines increased at an annual rate of 6.6 percent, 
however, due to simple cycle capacity additions that occurred at 
approximately four times the rate one would expect from the growth in 
overall demand.
    The most likely technologies to back up intermittent renewable 
generation have low incremental generating costs and can start up and 
stop quickly. Highly efficient simple cycle units meet these criteria. 
As such, the EPA has concluded that the most efficient simple cycle 
turbines in a given region are the most likely to support intermittent 
renewable generation. Focusing on these simple cycle turbines will 
address concerns raised by commenters about the future percentage 
electric sales of highly efficient simple cycle turbines and give an 
indication of the impact of increased renewable generation on non-base 
load units intended to back up wind and solar. There are two highly 
efficient intercooled simple cycle turbines installed in Texas. These 
two combustion turbines sell an average of 10 percent of their 
potential electric output annually, compared to an average of 3 percent 
for the remaining simple cycle turbines. No simple cycle

[[Page 64611]]

turbine in Texas sold more than 25 percent of its potential electric 
output annually. The rapid growth in simple cycle capacity, but not 
overall capacity factors, could indicate that the additional generation 
assets are providing firm capacity for intermittent generation sources 
such as wind and solar, but that capacity is infrequently required. 
Based on the data, even highly efficient simple cycle turbines are 
expected to continue to sell less than one-third of their potential 
electric output.
c. California
    The portion of in-state generation from wind and solar in 
California increased from 3 to 11 percent between 2008 and 2014. The 
average growth rate of wind and solar was 25 percent, while overall 
demand has remained stable. The operation of simple cycle turbines in 
California has changed more significantly than in the other evaluated 
regions. The average electric sales from simple cycle turbines 
increased from 5.1 to 5.9 percent, an annual rate increase of 4.5 
percent. As in Texas, considerable additional simple cycle capacity has 
been added in recent years. The total capacity of simple cycle turbines 
is increasing at 15 percent annually even though overall demand has 
remained relatively steady. In addition, the newest simple cycle 
turbines are operating at higher capacity factors than the existing 
fleet of simple cycle turbines, resulting in an average increase in 
generation from simple cycle turbines of 21 percent. Many of the new 
additions are intercooled simple cycle turbines that may have been 
installed with the specific intent to back up wind and solar 
generation.
    The average electric sales for the intercooled turbines ranged from 
3 to 25 percent, with a 7 percent average. No simple cycle turbines in 
California have sold more than one-third of their potential electric 
output on an annual basis. The operation of simple cycle turbines that 
existed prior to 2008 has not changed significantly. Average electric 
sales for these turbines increased at an annual rate of 0.1 percent. 
This indicates that support for new renewable generation is being 
provided by new units and not by the installed base of simple cycle 
units. These units are still serving their historical role of providing 
power during peak periods of demand.
    Based on our data analysis, the proposed one-third electric sales 
threshold would appear to offer sufficient operational flexibility for 
new simple cycle turbines. Existing NGCC units, other generation 
assets, and demand-response programs are currently providing adequate 
back up to intermittent renewable generation. In the future, however, 
existing NGCC units will likely operate at higher capacity factors. 
They will therefore be less available to provide back up power for 
intermittent generation. In addition, the amount of power generated by 
intermittent sources is expected to increase in the future. Both of 
these factors could require additional flexibility from the remaining 
generation sources to maintain grid reliability.
    Even though fast-start NGCC units, reciprocating internal 
combustion engines, energy storage technologies, and demand-response 
programs are promising technologies for providing back up power for 
renewable generation, none of them historically have been deployed in 
sufficient capacity to provide the potential capacity needed in the 
future to facilitate the continued growth of renewable generation. 
While we anticipate that state and federally issued permits for new 
electric generating sources will consider the CO2 benefits 
of these technologies compared to simple cycle turbines, the EPA has 
concluded at this time that it is appropriate to finalize a percentage 
electric sales threshold that provides additional flexibility for 
simple cycle turbines.
    Specifically, we have concluded that a percentage electric sales 
threshold based on a unit's design net efficiency at standard 
conditions is appropriate. This is the sliding-scale approach on which 
we solicited comment. Several commenters supported this approach 
because it provides sufficient operational flexibility for new simple 
cycle and fast-start NGCC combustion turbines and simultaneously 
promotes the installation of the most efficient generating 
technologies. By allowing more efficient turbines to sell more 
electricity before becoming subject to the standard for the base load 
subcategory, the sliding scale should reduce the perverse incentive for 
owners and operators to install more lower-capital-cost, less-efficient 
units instead of fewer higher-capital-cost, more-efficient units. At 
the same time, the sliding scale should incentivize turbine 
manufacturers to design higher efficiency simple cycle turbines that 
owners and operators can run more frequently.
    The net design efficiencies for aeroderivative simple cycle 
combustion turbines range from approximately 32 percent for smaller 
designs to 39 percent for the largest intercooled designs. The net 
design efficiencies of industrial frame units range from 30 percent for 
smaller designs to 36 percent for the largest designs. These efficiency 
values follow the methodology the EPA has historically used and are 
based on the higher heating value (HHV) of the fuel. In contrast, 
combustion turbine vendors in the U.S. often quote efficiencies based 
on the lower heating value (LHV) of the fuel. The LHV of a fuel is 
determined by subtracting the heat of vaporization of water vapor 
generated during combustion of fuel from the HHV. For natural gas, the 
LHV is approximately 10 percent lower than the HHV. Therefore, the 
corresponding LHV efficiency ranges would be 35 to 44 percent for 
aeroderivative designs and 33 to 40 percent for frame designs. We 
considered basing the percentage electric sales threshold on both the 
HHV and LHV. The EPA typically uses the HHV, but in light of 
commenters' concerns regarding uncertainty in the operation of non-base 
load units in the future, we opted to be conservative and use the LHV 
efficiency.
    We anticipate that high-efficiency simple cycle and fast-start NGCC 
turbines will make up the majority of new capacity intended for non-
base load applications. Based on the sliding-scale approach, owners and 
operators of new simple cycle combustion turbines will be able to sell 
between 33 to 44 percent of the turbine's potential electric output. 
Our analysis showed that 99.5 percent of existing simple cycle turbines 
have not sold more than one-third of their potential electric output on 
an annual basis. In addition, 99.9 percent of existing simple cycle 
turbines have not sold more than 36 percent of their potential electric 
output on an annual basis. The two simple cycle turbines that exceeded 
the 36 percent threshold had annual electric sales of 39 and 45 percent 
and are located in Montana and New York, respectively. As noted 
earlier, the most efficient simple cycle turbine currently available is 
44 percent efficient and would accommodate the operations at the 
Montana facility. The only existing simple cycle turbine that exceeded 
the maximum allowable percentage electric sales threshold of 44 
percent, which is based on current simple cycle designs, sold an 
abnormally high amount of electricity in 2014. It is possible that this 
unit was operating under emergency conditions. As explained below, the 
incremental generation due to the emergency would not have counted 
against the percentage electric sales threshold.
    We are capping the percentage electric sales threshold at 50 
percent of potential electric output for multiple reasons. First, NGCC 
emission rates are

[[Page 64612]]

relatively steady above 50 percent electric sales, so there is no 
reason that a NGCC unit with sales greater than this amount should not 
have to comply with the output-based standard for the base load 
subcategory. Second, the net design efficiency of the fast-start NGCC 
units intended for peaking and intermediate load applications is 49 
percent. As described earlier, this technology can serve the same 
purpose as high-efficiency simple cycle turbines. If we were to set a 
cap any lower than 50 percent, it could create a disincentive for 
owners and operators to choose this promising new technology.
    Finally, the EPA solicited comment on excluding electricity sold 
during system emergencies from counting towards the percentage electric 
sales threshold. After considering the comments, we have concluded that 
this exclusion is necessary to provide flexibility, maintain system 
reliability, and minimize overall costs to the sector. We disagree with 
commenters that suggested that the EPA's existing enforcement 
discretion would be a viable alternative. An enforcement discretion-
based approach would not provide certainty to the regulated community, 
public, and regulatory authorities on the applicability of the emission 
standards, which is a primary reason why we are finalizing the broad 
applicability approach. Moreover, system emergencies are defined 
events, so commenters' fears that the exclusion will be subject to 
abuse are overstated. Therefore, electricity sold during hours of 
operation when a unit is called upon to operate due to a system 
emergency will not be counted toward the percentage electric sales 
threshold. However, electricity sold by units that are not called upon 
to operate due to a system emergency (e.g., units already operating 
when the system emergency is declared) will be counted toward the 
percentage electric sales threshold.
    In summary, the EPA is finalizing the percentage electric sales 
criterion as a threshold to distinguish between two natural gas-fired 
combustion turbine subcategories. Specifically, all units that have 
electric sales greater than their net LHV design efficiencies (as a 
percentage of potential electric output) are base load units. All units 
that have electric sales less than or equal to their net LHV design 
efficiencies are non-base load units. We are capping the percentage 
electric sales threshold at 50 percent of potential electric output. 
This sliding-scale approach will limit the operation of the least 
efficient units, provide flexibility for renewable energy growth, and 
incentivize the development of more efficient simple cycle units.
3. Fuel-Based Subcategories
    As described in Section IX.A.3.d, we are finalizing a version of 
the broad applicability approach. Under the broad applicability 
approach, the EPA solicited comment on a subcategorization approach 
based in part on natural gas-use. We received few comments on this 
issue. One of the comments we did receive was that combustion turbines 
that burn fuels other than natural gas have higher CO2 
emissions due to the higher relative carbon content of alternate fuels. 
Besides hydrogen,\533\ natural gas has the lowest CO2 
emission rate on a lb/MMBtu basis of any fossil fuel. Therefore, 
burning fuels other than natural gas will result in a higher 
CO2 emission rate. We interpret this comment to mean that, 
if we were to subcategorize based on fuel use, turbines that burn non-
natural gas fuels should receive a less stringent emission standard.
---------------------------------------------------------------------------

    \533\ Hydrogen would only be considered a fossil fuel if it were 
derived for the purpose of creating useful heat from coal, oil, or 
natural gas.
---------------------------------------------------------------------------

    For the reasons described in the applicability section, we have 
decided to set emission standards for all combustion turbines capable 
of burning natural gas, regardless of the actual fuel burned, to avoid 
the practical problems that would have arisen under the proposed 
approach. However, as commenters explained, multi-fuel-fired combustion 
turbines cannot achieve the emission standards achieved by natural-gas 
fired turbines. For this reason, it would not be reasonable to require 
affected EGUs to comply with a standard based on the use of natural gas 
during periods when significant quantities of non-natural gas fuels are 
being burned. If we did not subcategorize, owners and operators would 
not be able to combust other fuels in their turbines, including process 
gas, blast furnace gas, and petroleum-based liquid wastes, which might 
otherwise be wasted. In addition, without the ability to burn back up 
fuels during natural gas curtailments, grid reliability could be 
jeopardized. Therefore, we are finalizing a separate fuel-based 
subcategory for multi-fuel-fired combustion turbines. To distinguish 
between this subcategory and the natural gas-fired subcategories, we 
are using the same threshold as proposed. Specifically, combustion 
turbines that burn ninety percent or less natural gas on a 12-
operating-month rolling average basis will be included in this 
subcategory and subject to a separate emission standard, which is 
discussed in Section IX.D.3.d.

C. Identification of the Best System of Emission Reduction

    This section summarizes the EPA's proposed BSER determinations for 
stationary combustion turbines, provides a summary of the comments we 
received, and explains our final BSER determinations for each of the 
three subcategories we are now finalizing. For natural gas-fired 
stationary combustion turbines operating as base load units, we 
proposed and are finalizing the use of NGCC technology as the BSER. For 
the other two subcategories of affected combustion turbines--non-base 
load natural gas-fired combustion turbines and multi-fuel-fired 
combustion turbines--we are finalizing the use of clean fuels as the 
BSER.
1. Proposed BSER
    We considered three alternatives in evaluating the BSER for base 
load natural gas-fired combustion turbines: (1) Partial CCS, (2) high-
efficiency simple cycle aeroderivative turbines, and (3) modern, 
efficient NGCC turbines. We rejected partial CCS as the BSER because we 
concluded that we did not have sufficient information to determine 
whether implementing CCS for combustion turbines was technically 
feasible. We rejected high-efficiency simple cycle aeroderivative 
turbines as the BSER because this standalone technology does not 
provide emission reductions and generally is more expensive than NGCC 
technology for base load applications. In contrast, NGCC is the most 
common type of new fossil fuel-fired EGU currently being planned and 
built for generating base load power. NGCC is technically feasible, and 
NGCC units are currently the lowest-cost, most efficient option for new 
base load fossil fuel-fired power generation. After considering the 
options, the EPA proposed to find that modern, efficient NGCC 
technology is the BSER for base load natural gas-fired combustion 
turbines.
    For non-base load natural gas-fired units and multi-fuel-fired 
units, we did not propose a specific BSER or associated numeric 
emission standards, but instead solicited comment on these issues.
2. Comments on the Proposed BSER for Base Load Natural Gas-Fired 
Combustion Turbines
    This section summarizes the differing comments submitted on the 
proposed BSER for base load natural gas-fired combustion turbines. Some 
commenters supported partial CCS as the BSER, others supported advanced 
NGCC

[[Page 64613]]

designs as the BSER, and others supported the proposed BSER.
a. Partial CCS
    Some commenters stated that our proposed BSER analysis for 
stationary combustion turbines was inconsistent with our proposed BSER 
analysis for coal-fired units. They stated that the EPA had determined 
that the use of CCS was feasible for coal-fired generation based on 
current CCS projects under development at coal-fired generating 
stations, but did not come to the same conclusion for combustion 
turbines. These commenters stated that CO2 removal is just 
as technologically feasible and economically reasonable for a natural 
gas-fired EGU as for a coal-fired EGU. While some of these commenters 
wanted the EPA to reconsider CCS as the BSER for NGCC, many of these 
commenters were attempting to prove that if the agency did not choose 
CCS as the BSER for NGCC units, then the agency should not for coal-
fired units either.
    Some commenters referenced the Northeast Energy Association NGCC 
plant in Bellingham, MA, which operated from 1991-2005 with 85-95 
percent carbon capture on a 320 MW unit for use in the food and 
beverage industry, that was referred to in the proposal. This plant 
captured 330 tons of CO2 per day from a 40 MW slip stream 
and was decommissioned as a result of financial difficulties, including 
rising gas prices and discontinuation of tax credits. According to 
these commenters, this plant provided sufficient proof that CCS 
technology is adequately demonstrated for NGCC units. Additionally, 
these commenters referred to other NGCC plants that are planned or in 
development that will incorporate CCS. The plants mentioned were the 
Sumitomo Chemical Plant in Japan, the Peterhead CCS project in 
Scotland, and the GE-Sargas Plant in Texas. The Sumitomo Chemical Plant 
has a base load NGCC unit with CCS operating on an 8 MW slip-stream 
that captures about 150 tons of CO2 per day for commercial 
use in the food and beverage industry. This carbon capture system has 
been operating since 1994. The Peterhead CCS project in Scotland is in 
the planning stages. It is a collaboration between Shell and SSE to 
provide 320 MW of electricity to its customers from a base load NGCC 
unit with 90 percent carbon capture. The CO2 will be 
transported to the depleted Goldeneye reservoir in the ocean where it 
will be stored and continuously monitored. The GE-Sargas Plant in Texas 
is a planned joint venture that does not currently have a location 
selected, but is intended to be a base load NGCC unit with CCS used for 
EOR.
    These commenters also referenced reports authored by DOE, NETL, the 
Clean Air Task Force (CATF), CCS Task Force, ICF Inc., and Global CCS 
Institute, suggesting that, because CCS technology for NGCC is included 
in these reports, it is adequately demonstrated. Some commenters 
referred to a DOE/NETL study that suggested that the cost of CCS for 
NGCC units would be more cost-effective than for coal-fired EGUs. One 
non-industry commenter emphasized that a technology does not have to be 
in use to be considered adequately demonstrated.
    In addition, some commenters disagreed with the EPA's decision to 
treat combustion turbines differently than coal-fired units with 
respect to CCS on the basis that combustion turbines startup, shutdown, 
and cycle load more frequently than coal-fired units. According to 
these commenters, the operating characteristics of combustion turbines 
do fluctuate, but so do those of coal-fired units. Another commenter 
said that even if NGCC operations vary more than they do for coal-fired 
units, it is not an impediment to using CCS because combustion turbine 
operators could bypass the carbon capture system during startup and 
shutdown modes (which are typically shorter and less intensive efforts 
compared to the startup or shutdown of a coal facility) and then employ 
the carbon capture system when operating normally. One commenter stated 
that most future base load fossil fuel-fired generation will be NGCC 
and that not making CCS the BSER for NGCC would result in significant 
CO2 emissions.
    Other commenters supported the EPA's determination that CCS is not 
the BSER for combustion turbines. These commenters said that CCS is not 
adequately demonstrated for combustion turbines because none are 
currently operating, under construction, or in the advanced stages of 
development. They also noted that CCS would have to be demonstrated for 
the range of facilities included in the regulated source category, 
which they alleged includes both simple cycle and NGCC units. They 
specifically noted that the Bellingham, MA demonstration facility was 
not a full-scale commercial NGCC power plant operating with CCS.
    These commenters agreed with the EPA that CCS does not match well 
with the operating flexibilities of NGCC and simple cycle units. They 
agreed with the EPA that frequent cycling restricts the efficacy of CCS 
on these units, a problem which would only get worse as more renewable 
energy sources are integrated into the grid. These commenters added 
that NGCC units operate differently than coal-fired units because the 
former start, stop, and cycle frequently, whereas the latter tend to 
operate at relatively steady loads and do not start and stop 
frequently. They stated that even if technical barriers could be 
overcome, the application of CCS to combustion turbines would be more 
costly (compared to the application of CCS to coal-fired units) on a 
dollars-per-ton basis. In addition, these commenters said that other 
industries' experience with CCS could not be transferred to NGCC units 
due to differences in flue gas CO2 concentration.
    Some commenters stated that CAA section 111(a) requires the EPA to 
account not only for the cost of achieving emission reductions, but 
also for impacts on energy requirements and the environment. The 
commenters cited to Sierra Club v. Costle, where the D.C. Circuit 
observed that the EPA ``must exercise its discretion to choose an 
achievable emission level which represents the best balance of 
economic, environmental, and energy considerations.'' \534\ The 
commenters stated that requiring CCS on combustion turbines would 
adversely affect the nation's energy needs and the environment because 
imposing CCS on combustion turbines would invariably delay the emission 
reductions that can be obtained from new NGCC projects that displace 
load from older, less efficient generating technologies. In addition, 
the commenters stated that, because combustion turbines are projected 
to provide a significant share of new power generation, the EPA should 
recognize that requiring CCS on these units would have a 
disproportionally higher impact on electricity prices when compared to 
the projected number of new coal-fired projects. These commenters 
concluded that the EPA could not determine that CCS is the BSER for 
combustion turbines without producing severe and unacceptable 
consequences for the availability of affordable electricity in the U.S.
---------------------------------------------------------------------------

    \534\ Sierra Club v. Costle, 657 F.2d 298, 330 (D.C. Cir. 1981).
---------------------------------------------------------------------------

b. NGCC Turbines
    Some commenters stated that the proposed BSER analysis should have 
reflected the emission rates achieved by the latest designs deployed at 
advanced, state-of-the-art NGCC installations. These commenters stated 
that advanced NGCC technologies are the best system

[[Page 64614]]

for reducing CO2 emissions with no negative environmental 
impacts and no negative economic impacts on rate payers. They stated 
that advanced NGCC technologies are capable of achieving emission rates 
that are 8 percent lower than conventional NGCC facilities. They also 
said that the majority of existing sources that do not deploy these 
advanced technologies are currently able to meet the standard and that 
the proposal failed to explain why these lower-emitting advanced 
technologies that are more than adequately demonstrated were not 
selected as the BSER.
c. Simple Cycle Turbines
    Many commenters opposed the EPA's proposal to set emission 
standards for combustion turbines based on their function rather than 
based on their design. These commenters stated that the EPA's 
determination that NGCC technology is the BSER for base load natural 
gas-fired combustion turbines would apply equally to simple cycle 
turbines if they sell electricity in excess of the percentage electric 
sales threshold. They pointed to the word ``achievable'' in CAA section 
111(a)(1) and stated that applying an emission standard based on NGCC 
technology to simple cycle units was legally indefensible because 
simple cycle units cannot achieve emission rates as low as NGCC units. 
In contrast, many other commenters agreed with the EPA's basic approach 
and stated that NGCC technology should be the BSER for base-load 
functions, while simple cycle technology should be the BSER for peak-
load functions.
3. Comments on Non-Base Load and Multi-Fuel-Fired Combustion Turbines
    Multiple commenters suggested that high efficiency simple cycle or 
fast-start NGCC technologies should be the BSER for non-base natural 
gas-fired load units. They explained that high efficiency simple cycle 
units and fast-start NGCC units are actually more efficient when 
serving non-base load demand than NGCC units that are designed strictly 
for base load operation. Some commenters also suggested that we should 
subcategorize multi-fuel-fired combustion turbines, but did not provide 
any specific technologies that should be considered in the BSER 
analysis.
4. Identification of the BSER
    After our evaluation of the comments and additional analysis, we 
identified the BSER for each subcategory of combustion turbine that we 
are finalizing: base load natural gas-fired units, non-base load 
natural gas-fired units, and multi-fuel-fired units.
a. Base Load Natural Gas-Fired Units
    As described in the proposal, we evaluated CCS, NGCC, and high-
efficiency simple cycle combustion turbines as the potential BSER for 
this subcategory. We selected NGCC as the BSER because it met all the 
BSER criteria. This section describes our response to issues raised by 
commenters and our rationale for maintaining that NGCC is the BSER for 
base load natural gas-fried combustion turbines.
(1) Partial CCS
    Some commenters stated that CCS could be applied equally to both 
coal-fired and natural gas-fired EGUs. To support this conclusion, the 
commenters pointed to a retired NGCC-with-CCS demonstration project, as 
well as a few overseas projects and projects in the early stages of 
development. While we have concluded that these commenters made strong 
arguments that the technical issues we raised at proposal could in many 
instances be overcome, we have concluded that there is not sufficient 
information at this time for us to determine that CCS is adequately 
demonstrated for all base load natural-gas fired combustion turbines.
    While the commenters make a strong case that the existing and 
planned NGCC-with-CCS projects demonstrate the feasibility of CCS for 
NGCC units operating at steady state conditions, many NGCC units do not 
operate this way. For example, the Bellingham, MA and Sumitomo NGCC 
units cited by the commenters operated at steady load conditions with a 
limited number of starts and stops, similar to the operation of coal-
fired boilers.\535\ In contrast, our base load natural gas-fired 
combustion turbine subcategory includes not only true base load units, 
but also some intermediate units that cycle more frequently, including 
fast-start NGCC units that sell more than 50 percent of their potential 
output to the grid. Fast-start NGCC units are designed to be able to 
start and stop multiple times in a single day and can ramp to full load 
in less than an hour. In contrast, coal-fired EGUs take multiple hours 
to start and ramp relatively slowly. These differences are important 
because we are not aware of any pilot-scale CCS projects that have 
demonstrated how fast and frequent starts, stops, and cycling will 
impact the efficiency and reliability of CCS. Furthermore, for those 
periods in which a NGCC unit is operating infrequently, the CCS system 
might not have sufficient time to startup. During these periods, no 
CO2 control would occur. Thus, if the NGCC unit is intended 
to operate for relatively short intervals for at least a portion of the 
year, the owner or operator could have to oversize the CCS to increase 
control during periods of steady-state operation to make up for those 
periods when no control is achieved by the CCS, leading to increased 
costs and energy penalties. While we are optimistic that these hurdles 
are surmountable, it is simply premature at this point to make a 
finding that CCS is technically feasible for the universe of combustion 
turbines that are covered by this rule.
---------------------------------------------------------------------------

    \535\ As explained in Section V.J above, a new fossil fuel-fired 
steam generating EGU would, most likely, be built to serve base load 
power demand exclusively and would not be expected to routinely 
startup, shut down, or ramp its capacity factor in order to follow 
load demand. Thus, planned start-up and shutdown events would only 
be expected to occur a few times during the course of a 12-
operating-month compliance period.
---------------------------------------------------------------------------

    Notably, the Department of Energy has not yet funded a CCS 
demonstration project for a NGCC unit, and no NGCC-with-CCS 
demonstration projects are currently operational or being constructed 
in the U.S. In contrast, multiple CCS demonstration projects for coal-
fired units are in various stages of development throughout the U.S., 
and a full-capture system is in operation at the Boundary Dam facility 
in Canada. See Sections V.E and D above.
    One commenter suggested that not having CCS as the BSER for 
combustion turbines would ultimately halt the development of CCS in the 
U.S. We disagree. A number of coal-fired power plants are currently 
being built with CSS, while some existing plants are considering CCS 
retrofits. Moreover, the NSPS sets the minimum level of control for new 
sources. We expect that state air agencies and other air permitting 
authorities will evaluate CCS when permitting new NGCC power plants, 
taking into consideration case-specific parameters, like operating 
characteristics, to determine whether CCS could be BACT or LAER in 
specific instances. While the NGCC-with-CCS units that currently are in 
the planning stages do not provide us with enough assurance to 
determine that CCS is adequately demonstrated for combustion turbines, 
it is our expectation that these units and others to come will provide 
additional information for both permitting reviews and the next NSPS 
review in eight years.
(2) NGCC Turbines
    Regarding the advanced NGCC technologies advocated by several 
commenters, the EPA has concluded

[[Page 64615]]

that the term ``advanced'' simply refers to incremental improvements to 
traditional NGCC designs, not a new and unique technology. These 
incremental improvements include higher firing temperatures in the 
turbine engine, increasing the number of steam pressures, and adding a 
reheat cycle to the steam cycle. The emission rates achieved by these 
so-called ``advanced'' technologies were included within the data set 
of newer NGCC designs that we used to establish the final emission 
standards. In addition, our review of the operating data for NGCC power 
blocks installed since 2000 indicates that a unit's mode of operation 
in response to system demand (e.g., capacity factor) affects 
efficiencies achieved to the extent that we cannot evaluate the impact 
of particular subcomponents used within the power block. As a result, a 
conventional NGCC power block located in a region of the country where 
system demand requires the power block to run continuously at a steady 
high load can achieve higher efficiencies than an ``advanced'' NGCC 
power block located in a region where system demand requires the power 
block to cycle on and off to match system demand. For this reason, our 
data set included a large population of technologies and load 
conditions to ensure that new NGCC power blocks can achieve the final 
emission standards in all regions of the country.
    As we explained in the proposal, NGCC technology meets all of the 
BSER criteria. For base load functions, NGCC units are technically 
feasible, cost-effective (indeed, less expensive than simple cycle 
combustion turbines), and have no adverse energy or environmental 
impacts. Moreover, NGCC units reduce emissions because they have a 
lower CO2 emission rate than simple cycle units. Finally, 
selecting NGCC as the BSER will promote the development of new 
technology, such as the incremental improvements advocated by the 
commenters, which will further reduce emissions in the future.
    Some commenters suggested that the costs and efficiency impacts of 
startup and shutdown events are higher for NGCC units than for simple 
cycle units. Consequently, we refined the LCOE costing approach used at 
proposal by adding these additional costs and efficiency impacts to our 
cost comparison. Even accounting for these new costs and impacts, we 
found that NGCC technology results in a lower cost of electricity than 
simple cycle technology when a unit's electric sales exceed 
approximately one-third of its potential electric output. The final 
percentage electric sales criterion for the base load natural gas-fired 
combustion turbine subcategory is based on the sliding scale. This 
means that the dividing line between the base load subcategory and the 
non-base load subcategory will change depending on a unit's nameplate 
design efficiency. For a conventional simple cycle turbine, the base 
load subcategory will begin at around 33 percent electric sales, while 
for a newer fast-start NGCC turbine, the base load subcategory will 
begin at approximately 50 percent electric sales. Anywhere within this 
range, our cost calculations have shown that NGCC technology is more 
cost-effective than simple cycle technology. Therefore, we are 
finalizing our determination that modern, efficient NGCC technology is 
the BSER for base load natural-gas fired combustion turbines.
(3) Simple Cycle Turbines
    Many commenters mistakenly thought that the EPA proposed to require 
some simple cycle combustion turbines to meet an emission standard of 
1,000 lb CO2/MWh-g, a level that they assert is 
unachievable. On the contrary, the EPA is not finding that NGCC 
technology and a corresponding emission standard of 1,000 lb 
CO2/MWh-g is the BSER for simple cycle turbines. Instead, 
the EPA is finding that NGCC technology is the BSER for base load 
turbine applications. This means that if an owner or operator wants to 
sell more electricity to the grid than the amount derived from a unit's 
nameplate design efficiency calculated as a percentage of potential 
electric output, then the owner or operator should install a NGCC unit. 
If the owner or operator elects to install a simple cycle turbine 
instead, then the practical effect of our final standards will be to 
limit the electric sales of that unit so that it serves primarily peak 
demand, not to subject it to an unachievable emission standard.
b. Non-base Load Natural Gas-Fired Load Units
    To identify the BSER for non-base load natural gas-fired units, we 
evaluated a range of technologies, including partial CCS, high-
efficiency NGCC technology designed for base load applications, fast-
start NGCC, high-efficiency simple cycle units (i.e., aeroderivative 
turbines), and clean fuels. For each of these technologies, we 
considered technical feasibility, costs, energy and non-air quality 
impacts, potential for emission reductions, and ability to promote 
technology.
    While CCS would result in emission reductions and promote the 
development of new technology, we concluded that CCS does not meet the 
BSER criteria because the low capacity factors and irregular operating 
patterns (e.g., frequent starting and stopping and operating at part 
load) of non-base load units make the technical challenges associated 
with CCS even greater than those associated with base load units. In 
addition, because the CCS system would remain idle for much of the time 
while these units are not running, CCS would be less cost-effective for 
these units than for base load units.
    We have also concluded that the high-efficiency NGCC units designed 
for base load applications do not meet any of the BSER criteria for 
non-base load units. First, non-base load units need to be able to 
start and stop quickly, and NGCC units designed for base load 
applications require relatively long startup and shutdown periods. 
Therefore, conventional NGCC designs are not technically feasible for 
the non-base load subcategory. Also, non-base load units operate less 
than 10 percent of the time on average. As a result, conventional NGCC 
units designed for base load applications, which have relatively high 
capital costs, will not be cost-effective if operated as non-base load 
units. In addition, it is not clear that a conventional NGCC unit will 
lead to emission reductions if used for non-base load applications. As 
some commenters noted, conventional NGCC units have relatively high 
startup and shutdown emissions and poor part-load efficiency, so 
emissions may actually be higher compared with simple cycle 
technologies that have lower overall design efficiencies but better 
cycling efficiencies. Finally, requiring conventional NGCC units as the 
BSER for non-base load combustion turbines would not promote technology 
because these units would not be fulfilling their intended role. In 
fact, it could hamper the development of technologies with lower design 
efficiencies that are specifically designed to operate efficiently as 
non-base load units (i.e., high-efficiency simple cycle and fast-start 
NGCC units). For all these reasons, we have concluded that conventional 
NGCC units designed for base load applications are not the BSER for 
non-base load natural gas-fired units.
    Compared to conventional NGCC technology, fast-start NGCC units 
have lower design efficiencies, but are able to start and ramp to full 
load more quickly. Therefore, it is possible that requiring fast-start 
NGCC as the BSER for non-base load units would result in emission 
reductions and further promote the development of fast-start NGCC 
technology, which is relatively new and advanced. However, because the

[[Page 64616]]

majority of non-base load combustion turbines operate less than 10 
percent of the time, it would be cost-prohibitive to require fast-start 
NGCC, which have relatively high capital costs compared to simple cycle 
turbines, as the BSER for all non-base load applications. Also, as we 
explained above in Section IX.B.2, we do not have sufficient emissions 
data for fast-start NGCC units operating over the full range of non-
base load conditions (e.g., peaking, cycling, etc.), so we would not be 
able to establish a reasonable emission standard.
    High-efficiency simple cycle turbines are primarily used for 
peaking applications. High-efficiency simple cycle turbines often 
employ aeroderivative designs because they are more efficient at a 
given size and are able to startup and ramp to full load more quickly 
than industrial frame designs. Requiring high-efficiency simple cycle 
turbines as the BSER could result in some emission reductions compared 
with conventional simple cycle turbines. It would also promote 
technology development by incentivizing manufacturers to increase the 
efficiency of their simple cycle turbine models. However, 
aeroderivative designs have higher initial costs that must be weighed 
against the specific peak-load profiles anticipated for a particular 
new non-base load unit. Many utility companies have elected to install 
the heavier industrial frame turbines because the ramping capabilities 
of aeroderivative turbines are not required for their system demand 
profiles (i.e., the speed and durations of daily changes in electricity 
demand), and the fuel savings do not justify the higher initial costs. 
We currently do not have precise enough costing information to compare 
the cost-effectiveness of aeroderivative turbines and industrial frame 
turbines for all non-base load applications. Determining cost-
effectiveness is further complicated because the efficiencies of the 
available aeroderivative and industrial frame technologies 
significantly overlap. For example, the efficiencies of aeroderivative 
turbines range from 32 to 39 percent, while the efficiencies of 
industrial frame turbines range from 30 to 36 percent. Based on these 
cost uncertainties, we cannot conclude that high-efficiency simple 
cycle turbines are the BSER for natural gas-fired non-base load 
applications at this time.
    The final option that we considered for the BSER was clean fuels, 
specifically natural gas with a small allowance for distillate oil. The 
use of clean fuels is technically feasible for non-base load units. 
Based on available EIA data,\536\ natural gas comprises more than 96 
percent of total heat input for simple cycle combustion turbines. In 
addition, natural gas is frequently the lowest cost fossil fuel used in 
combustion turbines, so it is cost-effective. Clean fuels will also 
result in some emission reductions by limiting the use of fuels with 
higher carbon content, such as residual oil. Finally, the use of clean 
fuels will not have any significant energy or non-air quality impacts. 
Based on these factors, the EPA has determined that the BSER for non-
base load natural gas-fired units is the use of clean fuels, 
specifically natural gas with a small allowance for distillate oil. 
Natural gas has approximately thirty percent lower CO2 
emissions per million Btu than other fossil fuels commonly used by 
utility sector non-base load units.
---------------------------------------------------------------------------

    \536\ http://www.eia.gov/electricity/data/eia923/.
---------------------------------------------------------------------------

c. Multi-Fuel-Fired Units
    To identify the BSER for multi-fuel-fired units, we again evaluated 
CCS, NGCC technology, high-efficiency simple cycle units (i.e., 
aeroderivative turbines), and clean fuels. For each of these 
technologies we considered technical feasibility, costs, energy and 
non-air quality impacts, emission reductions, and technology promotion. 
For many of the same reasons we provided above in our discussion of the 
BSER for non-base load natural gas-fired combustion turbines, only 
clean fuels meets the BSER criteria for multi-fuel-fired units.
    While CCS would result in emission reductions and the promotion of 
technology, we concluded that CCS does not meet the BSER criteria 
because multi-fuel-fired units tend to start, stop, and operate at part 
load frequently. Also, there are impurities and contaminants in some 
alternate fuels which make the technical challenges of applying CCS to 
multi-fuel-fired units greater than for natural gas-fired units.
    In regards to NGCC technology, we have concluded that it is 
technically feasible, would result in emission reductions, is cost-
effective, and would promote the development of technology. However, a 
BSER determination based on the use of NGCC technology could pose 
challenges for facilities operating in remote locations and certain 
industrial facilities. In remote locations, the construction of a NGCC 
facility is often not practical because it requires larger capital 
investments and significant staffing for construction and operation. In 
contrast, simple cycle turbines are cheaper and can be operated with 
minimal staffing. Also, many industrial facilities do not have the 
space available to build a HRSG and the associated cooling tower. 
Therefore, requiring NGCC as the BSER could have unforeseen energy 
impacts at these types of facilities. Moreover, these same kinds of 
facilities also burn by-product fuels. Faced with a decision to install 
an NGCC unit, these facilities might seek alternative energy options, 
which could lead to increased flaring or venting of by-product fuels 
because they are no longer being burned onsite for energy recovery. 
Therefore, in light of these potential energy and non-air quality 
impacts, we have concluded that NGCC technology is not the BSER for 
multi-fuel-fired combustion turbines.
    Similarly, while high-efficiency simple cycle turbines would result 
in emission reductions and promote the advancement of this technology, 
we are not confident that high-efficiency simple cycle units are 
technically feasible or cost-effective for this subcategory. 
Aeroderivative turbines are not as flexible with regards to what fuels 
that can be burned. Because by-product fuels vary in composition, it is 
not clear that all by-products fuels could be burned in a high-
efficiency simple cycle turbine. In addition, even if a by-product fuel 
could be burned in an aeroderivative turbine, we do not have 
information on the potential for increased maintenance costs, so we 
cannot determine whether using high-efficiency simple cycle turbines 
would be cost-effective.
    The final option that we considered for the BSER was clean fuels. 
The use of clean fuels is technically feasible and cost-effective. The 
use of clean fuels also provides an environmentally beneficial 
alternative to the flaring or venting of by-product fuels and limits 
the use of dirtier fuels with higher CO2 emission rates, 
such as residual oils. Clean fuels also promote technology development 
by allowing manufacturers to develop new combustion turbine designs 
that are capable of burning by-product fuels that currently cannot be 
burned in combustion turbines. Finally, the use of clean fuels does not 
have any significant energy or non-air quality impacts. Based on these 
factors, the EPA has determined that the BSER for multi-fuel-fired 
combustion turbines is the use of clean fuels.

D. Achievability of the Final Standards

    We are finalizing emission standards for three subcategories of 
combustion turbines. Specifically, units that sell electricity in 
excess of a threshold based on their design efficiency and that burn 
more than 90 percent natural gas (i.e., base load natural gas-fired 
units) will be

[[Page 64617]]

subject to an output- based standard. The output-based standard is 
based on the performance of existing NGCC units and takes into account 
a range of operating conditions, future degradation, etc. Units not 
meeting either the percentage electric sales or natural gas-use 
criteria (i.e., non-base load natural gas-fired and multi-fuel units, 
respectively) will be subject to an input-based standard based on the 
use of clean fuels. This section summarizes what emission standards we 
proposed and related issues we solicited comment on, describes the 
comments we received regarding the proposed emission standards and our 
responses to those comments, and provides our rationale for the final 
emission standards.
1. Proposed Standards
    For large newly constructed, modified, and reconstructed stationary 
combustion turbines (base load rating greater than 850 MMBtu/h), we 
proposed an emission standard of 1,000 lb CO2/MWh-g. For 
small stationary combustion turbines (base load rating of 850 MMBtu/h 
or less), we proposed an emission standard of 1,100 lb CO2/
MWh-g. We also solicited comment on a range of 950-1,100 lb 
CO2/MWh-g for large stationary combustion turbines and a 
range of 1,000-1,200 lb CO2/MWh-g for small stationary 
combustion turbines.
    In addition, we solicited comment on increasing the size 
distinction between large and small stationary combustion turbines to 
900 MMBtu/h to account for larger aeroderivative designs; increasing 
the size distinction to 1,000 MMBtu/h to account for future incremental 
increases in base load ratings; increasing the size distinction to 
between 1,300 to 1,800 MMBtu/h; and eliminating the size subcategories 
altogether. To account for potential reduced efficiencies when units 
are not operating at base load, we also solicited comment on whether a 
separate, less stringent standard should be established for non-base 
load combustion turbines.
2. Comments
    As described previously, we are not finalizing the size-based 
subcategories that we proposed and instead are finalizing emission 
standards for sales- and fuel-based subcategories. Specifically, we are 
finalizing emission standards for three subcategories of stationary 
combustion turbines: base load natural-gas fired units, non-base load 
natural gas-fired units and multi-fuel-fired units. The relevant 
comments concerning the emission standards for the first two 
subcategories are discussed below. Any comments we received supporting 
tiered emission standards are included in the discussion of non-base 
load natural gas-fired units. We did not receive comments on an 
appropriate emission standard for multi-fuel-fired units.
a. Emission standards for Base Load Natural Gas-Fired Units
    Many commenters stated that the proposed emission standards did not 
properly take into account the losses in efficiency that occur due to 
long-term degradation over multiple decades, operation at non-base load 
conditions (load cycling, frequent startups and shutdowns, and part-
load operations), site-specific factors such as ambient conditions and 
cooling technology, and secondary fuel use (e.g., distillate oil). 
These commenters stated that the EPA should conduct a more 
comprehensive analysis that addresses worst-case conditions for each of 
these factors. They also stated that all of the units included in the 
analysis supporting the proposal were relatively new and therefore have 
experienced limited degradation. The commenters stated that, while some 
degradation in efficiency can be recovered during periodic maintenance 
outages, it is not always possible or feasible to repair a degraded 
component immediately because repairs often involve extended outages 
that must be scheduled well in advance. They stated that a new unit 
that initially could meet the standard at base load conditions can 
experience increasing heat rates with age even when adhering to the 
manufacturer's recommended maintenance program.
    Some commenters stated that the proposed standards were derived by 
looking at emissions data from years with historically low natural gas 
prices. They surmised that the NGCC units were taking advantage of 
these prices by running at historically high capacity factors and 
concluded that the efficiencies and CO2 emission rates 
underlying the proposed standards were not representative of periods 
with higher natural gas prices. Other commenters said that many NGCC 
units are increasingly required to cycle and operate at lower 
capacities (compared to the proposal's baseline) to accommodate hourly 
variations in intermittent renewable generation. They anticipated that 
this type of generation will increase, requiring NGCC units to start, 
stop, and operate at part load more frequently than in the past, 
increasing CO2 emissions.
    Some commenters indicated that, during startup, combustion turbines 
must be operated at low load for extended periods to gradually warm up 
the HRSG to minimize thermal stresses on pressure vessels and boiler 
tubes. During these startup periods, significant CO2 
emissions occur, but steam production is not sufficient for the steam 
turbine generator to produce electricity. They also stated that a 
similar situation occurs during shutdown when the steam cycle does not 
generate electricity, but the combustion turbine is still combusting 
fuel as it proceeds through the shutdown process. These commenters 
recommended that the EPA could address these issues by creating a 
subcategory for NGCC units that cycle and operate at intermediate load.
    Many commenters said that site-specific factors can often preclude 
operators from achieving design efficiencies based on ISO conditions. 
These factors include high elevations, high ambient temperatures, and 
cooling system constraints. They stated that local water temperatures 
can impact condenser operating pressure and heat rates. They also said 
that areas with limited water resources could require systems that rely 
on air-cooled condensers, which cannot achieve thermal efficiencies 
comparable to water-cooled plants. These commenters stated that the 
final rule should include provisions for addressing site-specific 
constraints that preclude individual affected EGUs from achieving the 
emissions rates achieved on average by other sources.
    Some commenters stated that the proposed standards for modified and 
reconstructed combustion turbines would foreclose future opportunities 
for operators to undertake projects to restore the performance of both 
degraded units subject to the NSPS and existing, pre-NSPS units. They 
said that it is not possible to bring older combustion turbines (built 
prior to the year 2000) up to the efficiency levels of modern units 
because many newer technological options that deploy higher 
temperatures are not available for pre-2000 combustion turbines.
    Commenters from the power sector generally supported increasing the 
standards to 1,100 lb CO2/MWh-g and 1,200 lb CO2/
MWh-g for the newly constructed large and small turbines, respectively. 
They also advocated finalizing standards for modified and reconstructed 
standards that are 10 percent higher than the final standards for new 
sources because combustion turbines constructed prior to 2000 were not 
included in the EPA's analysis.
    Conversely, some commenters stated that the proposed standards for 
combustion turbines do not reflect the emission rates that are 
achievable by

[[Page 64618]]

modern, efficient NGCC power blocks. These commenters stated that the 
appropriate standard, consistent with Congressional objectives under 
CAA section 111, should be 800 lb CO2/MWh-g based on the 
performance of the lowest emitters in the CAMD database. Some 
commenters stated that a standard of 850 lb CO2/MWh-g 
reflects BSER for high-capacity factor units because half of the NGCC 
units in the CAMD database are achieving this level of emissions. One 
commenter from the power sector who operates NGCC power plants stated 
that the final standard for new large combustion turbines should be 925 
lb CO2/MWh-g. Another commenter also supported an emission 
standard of 925 lb CO2/MWh-g, which is consistent with 
recent BACT determinations in the state of New York. Several other 
commenters stated that a reasonable standard for new large combustion 
turbines should be 950 lb CO2/MWh-g and that the final 
standard for new small combustion turbines should be 1,000 lb 
CO2/MWh-g. Numerous commenters stated that the final 
standards for new sources should not exceed 1,000 lb CO2/
MWh-g for either large or small combustion turbines. Other commenters 
stated that, because the standards were developed based on emission 
rates that are being achieved by the majority of existing units, the 
final standards should be the same for new, modified, and reconstructed 
units.
b. Emission Standards for Non-Base Load Natural Gas-Fired Units and 
Multi-Fuel-Fired Units
    Many commenters stated that the EPA cannot finalize ``no emission 
standard'' for non-base load units, which the EPA solicited comment on 
in the broad applicability approach. They argued that this approach was 
not consistent with the definition of ``standard of performance'' in 
CAA section 111(a)(1), which requires there to be an ``emission 
limitation'' that reflects a ``system of emission reduction.'' Some 
commenters recommended that non-base load units should be subject to 
work practice standards, such as operating safely with good air 
pollution control practices, including CO2 monitoring and 
reporting requirements. Other commenters pointed to recent PSD permits 
that include tiered emission limits for the different roles served by 
combustion turbines. They cited BACT limits from 1,328 to 1,450 lb 
CO2/MWh-g for peaking units. One commenter supported tiered 
limits consistent with recent BACT determinations in the state of New 
York, which include limits for simple cycle combustion turbines of 
1,450 lb CO2/MWh-g. An air quality regulator from a state 
with rapidly increasing renewable generation supported a limit of 825 
lb CO2/MWh-g for all base load NGCC units; 1,000 lb 
CO2/MWh-g for large intermediate load NGCC units; 1,100 lb 
CO2/MWh-g for small intermediate load NGCC units. This 
commenter also recommended that the EPA set a numerical limit 
specifically for peaking units after the completion of a peaking unit-
specific BSER analysis. Several commenters supported tiered standards 
based on capacity factor. They proposed 825 lb CO2/MWh-g for 
base load units (those operating over 4,000 hours annually), 875 lb 
CO2/MWh-g for intermediate and load-following units (those 
operating between 1,200 and 4,000 hours annually), and 1,100 lb 
CO2/MWh-g for peaking units (those operating less than 1,200 
hours per year).
3. Final Standards
a. Newly Constructed Base Load Natural Gas-Fired Units
    In evaluating the achievability of the base load natural gas-fired 
emission standard, we focused on three types of data. Specifically, we 
looked at existing NGCC emission rates, recent PSD permit limits for 
CO2 emissions, and NGCC design efficiency data and 
specifications. Based on this analysis, we have concluded that an 
emission rate of 1,000 lb CO2/MWh-g is appropriate for all 
base load natural gas-fired combustion turbines, regardless of size.
    Since the standards were proposed, the EPA has expanded the NGCC 
emission rate analysis that supported the proposed emission standards 
to include emissions information for NGCC units that commenced 
operation in 2011, 2012, and 2013, and updated the emissions data to 
include emissions through 2014. In our analysis, we evaluated 345 NGCC 
units with online dates ranging from 2000 to 2013. The analysis 
included emissions data from 2007 to 2014 as submitted to the EPA's 
CAMD. The average maximum 12-operating-month CO2 emission 
rate for all NGCC units was 897 lb CO2/MWh-g, with 
individual unit maximums ranging from 751 to 1,334 lb CO2/
MWh-g.
    Consistent with our proposed size-based subcategories, we also 
reviewed the emissions data for small and large NGCC units separately. 
For small units, we evaluated emissions data from 17 NGCC units with 
heat input ratings of 850 MMBtu/h or less. These units had an average 
maximum 12-operating-month CO2 emission rate of 953 lb/MWh-
g. Individual unit maximum emission rates ranged from 898 to 1,175 lb 
CO2/MWh-g. Two of the units had a maximum emissions rate 
equal to or greater than 1,000 lb CO2/MWh-g.\537\ However, 
one of the units with a maximum emission rate above 1,000 lb 
CO2/MWh-g was only selling approximately 20 percent of its 
potential electric output (significantly below the design-specific 
percentage electric sales threshold) when the emission rate occurred. 
If this unit were a new unit, the applicable emission standard would be 
the heat input-based clean fuels standard, and the unit would not be 
out of compliance. Therefore, 16 of the 17 existing small NGCC units 
have demonstrated that an emission rate of 1,000 lb CO2/MWh-
g is achievable. In addition, the six newest units, which commenced 
construction between 2007 and 2012, all have maximum 12-operating-month 
emission rates of less than 950 lb CO2/MWh-g. While these 
units might not be old enough to have experienced degradation, their 
maximum emission rates demonstrate that the final standard of 1,000 lb 
CO2/MWh-g includes a significant compliance margin for any 
future degradation.
---------------------------------------------------------------------------

    \537\ For emission standards of 1,000 lb CO2/MWh-g 
and above, the emission standard uses three significant figures. See 
Section X.D.
---------------------------------------------------------------------------

    For large units, the average maximum 12-operating-month emission 
rate was 895 lb CO2/MWh-g, with individual unit maximum 
emission rates ranging from 751 to 1,334 lb CO2/MWh-g. 
Twenty-three of the 328 large NGCC units had maximum 12-operating-month 
emission rates greater than 1,000 lb CO2/MWh-g. While we do 
not have precise design efficiency information for each of these units, 
and thus cannot calculate the precise percentage electric sales 
threshold to which each unit would be subject, it appears that all of 
the emission rates in excess of 1,000 lb CO2/MWh-g occurred 
during periods when electric sales were low and would be below the 
threshold. Thus, if these units were new units, they would only have to 
comply with the heat input-based clean fuels standard. Therefore, 
essentially all existing NGCC units would have been in compliance with 
the final emission standard. We note also that there are 51 new NGCC 
units that have started operation since 2010, and the average maximum 
12-operating-month emission rate for these units is 833 lb 
CO2/MWh-g. Therefore, the final emission standard includes a 
very significant compliance margin to account for any potential future 
degradation of large units.

[[Page 64619]]

    To evaluate degradation further, the EPA reviewed the emission rate 
information for the 55 oldest NGCC units in our data set (i.e., units 
that came online in 2000 and 2001). According to the commenters, we 
should expect to see degradation when reviewing the annual emissions 
data for these turbines because they are 14 to 15 years old. However, 
we did not see any sign of degradation. The CO2 rates for 
these turbines have little standard deviation between 2007 and 2014. In 
addition, there were many instances where the CO2 emission 
rate of a unit actually decreased with age. This indicates that the 
efficiency of the unit is increasing, possibly as a result of good 
operating and maintenance procedures or upgrades to equipment that 
improved efficiency beyond the original design. Based on these 
findings, we have concluded that our analysis adequately accounts for 
potential degradation.
    We also evaluated the impact of elevation, ambient temperature, 
cooling type, and operating conditions (startups, shutdowns, and 
average run time per start) because commenters indicated that these 
could affect a unit's ability to achieve the standard. We saw little 
correlation between elevation or ambient temperature and emission rate. 
In addition, any correlation was relatively small and would have an 
insignificant impact on the ability of a unit to achieve the final 
standard. We identified 32 large NGCC units with dry cooling towers. 
The average maximum 12-operating-month emission rate for this group of 
units was 875 lb CO2/MWh. This rate was actually lower than 
the average rate for the large NGCC group as a whole. Based on these 
findings, we have concluded that the final emission standard will not 
limit the use of dry cooling technologies. Finally, the EPA evaluated 
the impact of run time per start, average duty cycle, and number of 
starts on emission rates. While these factors do influence emission 
rates, the non-base load natural gas-fired subcategory inherently 
addresses efficiency issues related to operating conditions.
    In addition to evaluating existing NGCC emissions data, the EPA 
reviewed the CO2 emission limits included in PSD 
preconstruction permits issued since January 1, 2011. We evaluated all 
permit limits over an annual period. In total, we identified 31 major 
source PSD permits with 39 discrete limits on CO2 emissions. 
Eight of the limits were expressed in terms of lb/h or tons per year, 
so we did not include them in the analysis. In addition, one CHP unit 
that generates electricity and supplies steam to a chemical plant was 
in the data set. This facility had a permit limit of 1,362 lb 
CO2/MWh based only on gross electrical output and does not 
account for useful thermal output. Therefore, we did not include it in 
the analysis either. Finally, we excluded two permits that did not 
clearly specify if the output-based standard was on a gross or net 
basis.
    The remaining 28 permit limits were expressed in lb CO2/
MWh or a heat rate basis that could be converted to lb CO2/
MWh. Eight permit limits were based on net output, ranging from 774-936 
lb CO2/MWh-n. The lowest emission limit was for a hybrid 
power plant with a solar component that could contribute up to 50 MW. 
Twenty permit limits were based on gross output, ranging from 833-1,100 
lb CO2/MWh-g. Of these 28 permit limits, the only limit in 
excess of our final emission standard of 1,000 lb CO2/MWh-g 
is for a relatively small NGCC unit (base load rating of 366 MMBtu/h) 
that commenced construction prior to the proposal and thus will not be 
subject to the requirements of this final rule.
    Each of the permit limits discussed above that is 1,000 lb 
CO2/MWh or less includes all periods of operation, including 
startup, shutdown, and malfunction events. In addition, each permit 
limit was set after back up and additional fuel use were taken into 
consideration. While some permits restrict fuel use to only natural 
gas, others allow limited usage (duration and type) of back up and 
other fuels. For example, the Pioneer Valley Energy Center has 
unrestricted use of natural gas, but can burn ultra-low sulfur diesel 
(ULSD) for up to 1,440 hours per 12-month period. This permit requires 
the unit to comply with a limit of 895 lb CO2/MWh-n even 
when burning up to 16 percent distillate oil. Each permit limit takes 
into account the mode of operation for the combustion turbine. For 
example, the permit for the Lower Colorado River Authority's Ferguson 
plant evaluated emission limits for the plant at 50, 75, and 100 
percent gross load. The emission limit of 918 lb CO2/MWh-n 
accounts for the unit's expected operation at 50 percent gross load. 
For NGCC units with duct burners on their HRSGs, the permit limits 
account for the hours of operation with duct burners firing. Finally, 
most of these permits include compliance margins to account for 
efficiency losses due to degradation and other factors (e.g., actual 
operating parameters, site-specific design considerations, and the use 
of back up fuel). In total, these compliance margins result in a 10 to 
13 percent increase in the permitted CO2 emission limits, 
yet all of the limits except one were still below 1,000 lb 
CO2/MWh-g.
    Finally, we also reviewed NGCC design efficiency data and 
specifications submitted to Gas Turbine World. Specifically, we 
reviewed the reported efficiency data for 88 different 60 Hz NGCC units 
manufactured by Alstom, GE Energy Aeroderivative and Heavy Duty, 
Mitsubishi Heavy Industries, Pratt & Whitney, Rolls-Royce, and Siemens 
Energy. The designs ranged in model year from 1977 to 2011, capacities 
ranged from 31 to 1,026 MW, and base load ratings ranged from 236 to 
3,551 MMBtu/h. The average reported design emission rate for these 
units was 834 lb CO2/MWh-n and ranged from 725 to 941 lb 
CO2/MWh-n. Therefore, our optional standard of 1,030 lb 
CO2/MWh-n would allow for an average compliance margin of 24 
percent, with a range from 10 to 42 percent, over the design rate. 
Ninety-five percent of designs would have a compliance margin of 13 
percent or more, the top end of the range of compliance margins 
determined to be appropriate in the PSD permits we reviewed.
    Because some commenters were concerned that smaller NGCC units will 
not be able to achieve the emission standard, we specifically 
considered the design rates for smaller units. For the 52 small units 
(base load rating of 850 MMBtu/h or less), the average design emission 
rate was 865 lb CO2/MWh and ranged from 796 to 941 lb 
CO2/MWh-n. Therefore, our optional standard of 1,030 lb 
CO2/MWh-n would allow for an average compliance margin of 19 
percent, with a range of 10 to 29 percent, over the design rate. 
Ninety-five percent of small NGCC designs would have a compliance 
margin of 13 percent or more.
    We further refined our analysis by only considering the most 
efficient design for a given combustion turbine engine. For example, GE 
Energy Aeroderivative offers four design options for its LM2500 model-
type, all with a rating of approximately 45 MW. The design emission 
rates for these various options range from 827 to 914 lb 
CO2/MWh-n. When only the most efficient models for a 
particular combustion turbine engine design are considered, all NGCC 
models have over a 13 percent compliance margin. In other words, 
developers of new base load natural gas-fired combustion turbines 
concerned about the achievability of the final standard have multiple 
more efficient options offered by the same manufacturer. Therefore, we 
have concluded that the final emission standard allows sufficient 
flexibility for end users to select an

[[Page 64620]]

NGCC design appropriate for their specific requirements.
    After considering these three sources of information--actual NGCC 
emission rate data, PSD permit limits for NGCC facilities, and NGCC 
design information--we have concluded that a standard of 1,000 lb 
CO2/MWh is both achievable and appropriate for newly 
constructed base load natural gas-fired combustion turbines. While we 
anticipate that the large majority of new NGCC units will operate well 
below this emission rate, this standard provides flexibility for 
developers to take into account site-specific conditions (e.g., ambient 
conditions and cooling system), operating characteristics (e.g., part-
load operation and frequent starting and stopping), and reduced 
efficiency due to degradation. The standard also accommodates the full 
size range of turbines.
    We also expect multiple technology developments to further increase 
the performance of new base load natural gas-fired stationary 
combustion turbines. Vendors continue to improve the single cycle 
efficiency of combustion turbines. The use of more efficient combustion 
turbine engines improves the overall efficiency of NGCC facilities. In 
addition, existing smaller NGCC facilities were likely designed using 
single or dual pressure HRSGs without a reheat cycle. New designs can 
incorporate three pressure steam generators with a reheat cycle to 
improve the overall efficiency of the NGCC facility. Finally, 
additional technologies to reduce emission rates for new combustion 
turbines include CHP and integrated non-emitting technologies. For 
example, an NGCC unit that is designed as a CHP unit where ten percent 
of the overall output is useful thermal output would have an emission 
rate approximately five percent less than an electric-only NGCC. In 
sum, we believe that our final emission standards of 1,000 lb 
CO2/MWh-g and 1,030 lb CO2/MW-n are not only 
readily achievable, but likely conservative.
b. Reconstructed Base Load Natural Gas-Fired Units
    We disagree with commenters that stated that reconstructed 
combustion turbines will not be able to achieve the proposed emission 
standards. For the reasons listed below, we have concluded that an 
existing base load natural-gas fired unit that reconstructs can achieve 
an emission rate of 1,000 lb CO2/MWh-g, regardless of its 
size.
    Highly efficient NGCC units include (1) an efficient combustion 
turbine engine, (2) an efficient steam cycle, and (3) a combustion 
turbine exhaust system that is ``matched'' to the steam cycle for 
maximum efficiency. In order for an existing NGCC unit to trigger the 
reconstruction provisions, the unit would have to essentially be 
entirely rebuilt. This would involve extensive upgrades to both the 
combustion turbine engine and the HRSG. Therefore, a reconstructed NGCC 
unit will be able to maximize the efficiency of the turbine engine and 
the steam cycle and match the two for maximum efficiency.
    According to comments submitted in response to the proposal for 
existing sources under CAA section 111(d), there are various options 
available to improve the efficiency of existing combustion turbines. 
One combustion turbine manufacturer provided comments describing 
specific technology upgrades for the compressor, combustor, and gas 
turbine components. This manufacturer stated that operators of existing 
turbines can replace older internal components along the gas path with 
state-of-the-art components that have higher aerodynamic efficiencies 
and improved seal designs. These gas-path enhancements enable existing 
sources to both improve the efficiency of the turbine engine and 
improve the systems used for cooling the metal parts along the hot-gas 
path to allow existing systems to achieve higher operating 
temperatures. In total, the manufacturer stated that utilities 
deploying these gas-path improvements on reconstructed industrial frame 
combustion turbines with nominal output ratings of 170 to 180 MW can 
increase their output by 10 MW while reducing CO2 emissions 
by more than 2.6 percent compared to baseline. In addition to gas-path 
and software improvements, the manufacturer stated that the newest low-
NOX combustor designs can be retrofitted on modified and 
reconstructed turbines to achieve lower NOX emissions, which 
improves turndown (i.e., to enable stable operations at lower loads 
compared to the lowest stable load achievable at baseline conditions) 
and efficiencies across all load conditions. The manufacturer indicated 
that operators of existing combustion turbines deploying both state-of-
the-art gas-path and software upgrades and combustor upgrades can 
increase output on frame-style turbines with nominal output ratings of 
170 to 180 MW by 14 MW, while reducing CO2 emissions by 2.8 
percent. In addition to the preceding upgrades, the manufacturer stated 
that existing combustion turbines can achieve the largest efficiency 
improvements by upgrading existing compressors with more advanced 
compressor technologies, potentially improving the combustion turbine's 
efficiency by an additional 3.8 percent. Thus, the total potential 
CO2 emissions reductions for just the combustion turbine 
portion of a combined cycle unit is 6.6 percent.
    In addition to upgrades to the combustion turbine engine, an 
operator reconstructing a NGCC unit will have the opportunity to 
improve the efficiency of the HRSG and steam cycle. For example, a 
steam turbine manufacturer identified three retrofit technologies 
available for reducing the CO2 emissions rate of existing 
steam turbines by 1.5 to 3 percent: (1) Steam-path upgrades can 
minimize aerodynamic and steam leakage losses; (2) replacement of the 
existing high pressure turbine stages with state-of-the-art stages 
capable of extracting more energy from the same steam supply; and (3) 
replacement of low-pressure turbine stages with larger diameter 
components that extract additional energy and that reduce velocities, 
wear, and corrosion.
    In addition, an operator reconstructing a NGCC unit could upgrade 
the entire steam cycle. For example, combined cycle units originally 
constructed with only a single pressure level can be upgraded to also 
include second and third pressure levels. Studies 
538 539 540 show that converting a single pressure HRSG with 
steam reheat to a double pressure configuration with steam reheat can 
reduce the CO2 emission rate of a NGCC unit by 1.5 to 1.7 
percent. These same studies show that converting from a single pressure 
configuration with reheat to a triple pressure configuration with 
reheat can yield a 1.8 to 2 percent reduction in the CO2 
emission rate. Similarly, units constructed with only a double pressure 
configuration without reheat can obtain a 0.4 percent reduction by 
adding a reheat cycle or a 0.9 percent reduction by converting to a 
triple pressure configuration and adding a reheat cycle. Existing NGCC 
turbines that convert to these advanced HRSG configurations and that 
deploy the previously discussed combustion turbine and steam turbine 
upgrades can

[[Page 64621]]

realize CO2 emission rate reductions ranging from 6 to 10 
percent, depending on their baseline design and condition. Based on the 
available options to improve the efficiency of existing NGCC units and 
the fact that the vast majority of existing NGCC units are already 
achieving emission rates of 1,000 lb CO2/MWh-g or less, we 
have concluded that all reconstructed NGCC units can achieve this 
emission rate.
---------------------------------------------------------------------------

    \538\ ``Exergetic and Economic Evaluation of the Effects of HRSG 
Configurations on the Performance of Combined Cycle Power Plants.'' 
M. Mansouri, et al. Energy Conversion and Management 58:47-58, 2012.
    \539\ ``Combined Cycle Power Plant Performance Analyses Based on 
Single-Pressure and Multipressure Heat Recovery Steam Generator.'' 
M. Rahim, Journal of Energy Engineering, 138:136-145, 2012.
    \540\ ``Thermodynamic Evaluation of Combined Cycle Plants.'' N. 
Woudstras et al. Energy Conversion and Management 51:1099-1110, 
2010.
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    Finally, we note that an owner or operator that is considering 
reconstructing an existing simple cycle turbine should decide how they 
wish to operate that turbine in the future. If they anticipate 
operating above the percentage electric sales threshold, then they 
should install a HRSG and steam turbine and convert to a NGCC power 
block in accordance with our determination that NGCC is the BSER for 
base load applications. If they intend to operate the turbine below the 
percentage electric sales threshold, however, then the clean fuels 
standard, described below, will apply.
c. Newly Constructed and Reconstructed Non-Base Load Natural Gas-Fired 
Units
    The EPA agrees with the commenters who stated that ``no emission 
limit'' would be inconsistent with the requirements of CAA 111(a)(1). 
We therefore are finalizing an input-based standard based on the use of 
clean fuels for non-base load natural gas-fired combustion turbines in 
recognition that efficiency can be reduced due to operation at low 
loads, cycling, and frequent startups. The EPA has concluded that, at 
this time, we do not have sufficient information to set a meaningful 
output-based standard for non-base load natural gas-fired combustion 
turbines. The input-based standard requires non-base load units to burn 
fuels with an average emission rate of 120 lb CO2/MMBtu or 
less. This standard is readily achievable because the CO2 
emission rate of natural gas is 117 lb CO2/MMBtu. The most 
common back up fuel is distillate oil, which has a CO2 
emission rate of 163 lb CO2/MMBtu. A non-base load natural 
gas-fired combustion turbine burning 9 percent distillate oil and 91 
percent natural gas has an emission rate of 121 lb CO2/
MMBtu, which rounds to 120 lb CO2/MMBtu using two 
significant digits. Therefore, the vast majority of owners and 
operators of non-base load natural gas-fired combustion turbines will 
be able to achieve the standard using business-as-usual fuels.
    While the emission reductions that will result from restricting the 
use of fuels with higher CO2 emission rates is minor, the 
compliance burden is also minimal. Owners and operators of non-base 
load natural gas-fired combustion turbines burning fuels with 
consistent chemical compositions that meet the clean fuels requirement 
(e.g., natural gas, ethane, ethylene, propane, naphtha, jet fuel 
kerosene, fuel oils No. 1 and 2, and biodiesel) will only need to 
maintain records that they burned these fuels in the combustion 
turbine. No additional recordkeeping or reporting will be required. 
Owners and operators burning fuels with higher CO2 emission 
rates and/or chemical compositions that vary (e.g., residual oil, non-
jet fuel kerosene, landfill gas) will have to follow the procedures in 
part 98 of this part to determine the average CO2 emission 
rate of the fuels burned during the applicable 12-operating-month 
compliance period and submit quarterly reports to verify that they are 
in compliance with the required emission standard.
d. Newly Constructed and Reconstructed Multi-Fuel-Fired Units
    We also are finalizing an input-based standard based on the use of 
clean fuels, as opposed to an output-based standard, for multi-fuel 
units for several reasons. Specifically, we do not currently have 
continuous CO2 emissions data for multi-fuel-fired units, we 
have not evaluated the potential efficiency impacts of different fuels, 
and the range of carbon content of non-natural gas fuels complicates 
establishing an appropriate output-based standard. Based on this lack 
of data, we have concluded that we cannot establish an output-based 
emission standard for multi-fuel-fired combustion turbines at this 
time.
    The input-based emissions standard for this subcategory is based on 
the use of clean fuels. The use of clean fuels will ensure that newly 
constructed and reconstructed combustion turbines minimize 
CO2 emissions during all periods of operation by limiting 
the use of fuels with higher CO2 emission rates. To 
accurately represent the BSER and limit the ability of units to co-fire 
higher CO2 emitting fuels with natural gas, we have 
concluded that it is necessary to use an equation based on the heat 
input from natural gas to determine the applicable emission standard. 
The 12-operating-month standard will vary from 120 lb CO2/
MMBtu to 160 lb CO2/MMBtu depending on the fraction of heat 
input from natural gas. The standard will be calculated by adding the 
product of the percent of heat input from natural gas and 120 with the 
product of the heat input from non-natural gas fuels and 160. For 
example, a combustion turbine that burns 80 percent natural gas and 20 
percent distillate oil would be subject to an emission standard of 130 
lb CO2/MMBtu (rounded to two significant figures), which is 
equivalent to the actual emission rate of a unit burning this 
combination of fuels. On the other hand, a combustion turbine that 
burns 100 percent residual oil would be subject to an emission standard 
of 160 lb CO2/MMBtu, but would have a higher actual emission 
rate, and would thus be out of compliance. In this way, the standard 
will restrict higher carbon fuels from being burned in multi-fuel-fired 
units, but will be readily achievable by units burning clean fuels.
    According to information submitted to the EIA, the primary, non-
natural gas fuels used by combustion turbines today for the production 
of electricity should all meet our definition of a clean fuel. Thus, 
while the emission reductions that will result from restricting the use 
of fuels with higher CO2 emission rates is minor, the 
compliance burden is also minimal. Owners and operators of multi-fuel-
fired combustion turbines burning fuels with consistent chemical 
compositions that meet the clean fuels requirement (e.g., natural gas, 
ethylene, propane, naphtha, jet fuel kerosene, fuel oils No. 1 and 2, 
and biodiesel) will only need to maintain records that they burned 
these fuels in the combustion turbine. No additional recordkeeping or 
reporting will be required. Owners and operators burning fuels with 
higher CO2 emission rates and/or chemical compositions that 
vary (e.g., residual oil, non-jet fuel kerosene, landfill gas) will 
have to follow the procedures in part 98 of this part to determine the 
average CO2 emission rate of the fuels burned during the 
applicable 12-operating-month compliance period and submit quarterly 
reports to verify that they are in compliance with the required 
emission standard.
e. Modified Units
    The EPA is not finalizing the proposed emission standards for 
stationary combustion turbines that conduct modifications. As explained 
in Section XV below, we are withdrawing the June 2014 proposal with 
respect to these sources. We received a significant number of comments 
asserting that modified combustion turbines could not meet the proposed 
emission standards of 1,000 lb/MWh-g for large turbines and 1,100 lb/
MWh-g for small turbines. For the reasons explained in Section IX.B.1 
above, we have decided not to subcategorize combustion turbines based 
on size for a number of reasons and are setting a single standard of

[[Page 64622]]

1,000 lb/MWh-g for all base load natural gas-fired turbines instead. 
While we are confident that all new and reconstructed units will be 
able to achieve this standard, we are less confident that all smaller 
combustion turbines that undertake a modification, specifically those 
that were constructed prior to 2000, will be able to do so. Until we 
have the opportunity to further investigate the full range of 
modifications that turbine owners and operators might undertake, we 
consider it premature to finalize emission standards for these sources.
    Combustion turbines have unique characteristics that make 
determining an appropriate emission standard for modified sources a 
more challenging task than for coal-fired boilers. For example, each 
combustion turbine engine has a specific corresponding combustor. The 
development of more efficient combustor upgrades for existing turbine 
designs typically requires manufacturers to expend considerable 
resources. Consequently, not all manufacturers offer combustor upgrades 
for smaller or older designs because it would be difficult to recoup 
their investment. In contrast, efficiency upgrades for boilers can 
generally be installed regardless of the specific boiler's 
characteristics.
    In addition, natural gas has the lowest CO2 emission 
rate (in terms of lb CO2/MMBtu) of any fossil fuel. As a 
result, an owner or operator that adds the ability to burn a back up 
fuel, such as distillate oil, to an existing turbine would likely 
trigger an NSPS modification. This is a relatively low-capital-cost 
upgrade that would significantly increase a unit's potential hourly 
emission rate, even though the annual emissions increase would be 
relatively minor because operating permits generally limit the amount 
of distillate oil that a unit can burn. We need to conduct additional 
analysis to determine an appropriate emission standard for units that 
undertake this type of modification, which does not involve any of the 
combustion turbine components that impact efficiency.
    To be clear, the EPA is not reaching a final decision that 
modifications should be subject to different requirements than we are 
finalizing in this rule for new and reconstructed sources. We have made 
no decisions, and this matter is not concluded. We plan to continue to 
gather information, consider the options for modifications, and develop 
a new proposal for modifications in the future. Therefore, the EPA is 
withdrawing the proposed standards for all combustion turbines that 
conduct modifications and is not issuing final standards for those 
sources at this time. See Section XV below. We note that the effect of 
this withdrawal is that modified combustion turbines will continue to 
be existing sources subject to section 111(d).\541\
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    \541\ As discussed above in Section VI.A of this preamble, a 
modified source that is not covered by a final or pending proposed 
standard continues to be an ``existing source'' and so will be 
covered by requirements under section 111(d). Under the definition 
of ``existing source'' in section 111(a)(6), an existing source is 
any source that is not a new source. Under the definition of ``new 
source'' in section 111(a)(2), a modified source is a new source 
only if the modification occurs after the publication of regulations 
(or proposed regulations, if earlier) that will be applicable to 
that source. Because we are not finalizing regulations with respect 
to modified steam turbines, and are withdrawing the proposal with 
respect to such sources, there are neither final regulations nor 
pending proposed regulations which will be applicable to such 
modifications.
---------------------------------------------------------------------------

X. Summary of Other Final Requirements for Newly Constructed, Modified, 
and Reconstructed Fossil Fuel-Fired Electric Utility Steam Generating 
Units and Stationary Combustion Turbines

    This section describes the final action's requirements regarding 
startup, shutdown, and malfunction; continuous monitoring; emissions 
performance testing; continuous compliance; and notification, 
recordkeeping, and reporting for newly constructed, modified, and 
reconstructed affected steam generating units and combustion turbines. 
We also explain final decisions regarding several of these 
requirements.

A. Startup, Shutdown, and Malfunction Requirements

    In its 2008 decision in Sierra Club v. EPA, 551 F.3d 1019 (D.C. 
Cir. 2008), the D.C. Circuit vacated portions of two provisions in the 
EPA's CAA section 112 regulations governing the emissions of hazardous 
air pollutants (HAP) during periods of startup, shutdown, and 
malfunction (SSM). Specifically, the Court vacated the SSM exemption 
contained in 40 CFR 63.6(f)(1) and 40 CFR 63.6(h)(1), holding that 
under section 302(k) of the CAA, emissions standards or limitations 
must be continuous in nature and that the SSM exemption violates the 
CAA's requirement that some CAA section 112 standards apply 
continuously.
    Consistent with Sierra Club v. EPA, the EPA has established 
standards in this rule that apply at all times. In establishing the 
standards in this rule, the EPA has taken into account startup and 
shutdown periods and, for the reasons explained below as well as in 
Section V.J.1 above, has not established alternate standards for those 
periods. Specifically, startup and shutdown periods are included in the 
compliance calculation as periods of partial load. The final method to 
calculate compliance is to sum the emissions for all operating hours 
and to divide that value by the sum of the electric energy output (and 
useful thermal energy output, where applicable for affected CHP EGUs), 
over a rolling 12-operating-month period. In their compliance 
determinations, sources must incorporate emissions from all periods, 
including startup or shutdown, during which fuel is combusted and 
emissions are being monitored, in addition to all power produced over 
the periods of emissions measurements. As explained in Section V.J.1, 
given that the duration of startup or shutdown periods is expected to 
be small relative to the duration of periods of normal operation and 
that the fraction of power generated during periods of startup or 
shutdown is expected to be very small, the impact of these periods on 
the total average over a 12-operating-month period is expected to be 
minimal.
    Periods of startup, normal operations, and shutdown are all 
predictable and routine aspects of a source's operations. Malfunctions, 
in contrast, are neither predictable nor routine. Instead they are, by 
definition sudden, infrequent and not reasonably preventable failures 
of emissions control, process or monitoring equipment. (40 CFR 60.2). 
The EPA interprets CAA section 111 as not requiring emissions that 
occur during periods of malfunction to be factored into development of 
section 111 standards. Nothing in CAA section 111 or in case law 
requires that the EPA consider malfunctions when determining what 
standards of performance reflect the degree of emission limitation 
achievable through ``the application of the best system of emission 
reduction'' that the EPA determines is adequately demonstrated. While 
the EPA accounts for variability in setting emissions standards, 
nothing in CAA section 111 requires the agency to consider malfunctions 
as part of that analysis. A malfunction should not be treated in the 
same manner as the type of variation in performance that occurs during 
routine operations of a source. A malfunction is a failure of the 
source to perform in a ``normal or usual manner'' and no statutory 
language compels the EPA to consider such events in setting CAA section 
111 standards of performance.
    Further, accounting for malfunctions in setting emission standards 
would be difficult, if not impossible, given the myriad different types 
of malfunctions that can occur across all sources in the

[[Page 64623]]

category and given the difficulties associated with predicting or 
accounting for the frequency, degree, and duration of various 
malfunctions that might occur. As such, the performance of units that 
are malfunctioning is not ``reasonably'' foreseeable. See, e.g., Sierra 
Club v. EPA, 167 F.3d 658, 662 (D.C. Cir. 1999) (``The EPA typically 
has wide latitude in determining the extent of data-gathering necessary 
to solve a problem. We generally defer to an agency's decision to 
proceed on the basis of imperfect scientific information, rather than 
to `invest the resources to conduct the perfect study.' '') See also, 
Weyerhaeuser v Costle, 590 F.2d 1011, 1058 (D.C. Cir. 1978) (``In the 
nature of things, no general limit, individual permit, or even any 
upset provision can anticipate all upset situations. After a certain 
point, the transgression of regulatory limits caused by `uncontrollable 
acts of third parties,' such as strikes, sabotage, operator 
intoxication or insanity, and a variety of other eventualities, must be 
a matter for the administrative exercise of case-by-case enforcement 
discretion, not for specification in advance by regulation.''). In 
addition, emissions during a malfunction event can be significantly 
higher than emissions at any other time of source operation. For 
example, if an air pollution control device with 99 percent removal 
goes off-line as a result of a malfunction (as might happen if, for 
example, the bags in a baghouse catch fire) and the emission unit is a 
steady state type unit that would take days to shut down, the source 
would go from 99 percent control to zero control until the control 
device was repaired. The source's emissions during the malfunction 
would be 100 times higher than during normal operations. As such, the 
emissions over a 4-day malfunction period would exceed the annual 
emissions of the source during normal operations. As this example 
illustrates, accounting for malfunctions could lead to standards that 
are not reflective of (and significantly less stringent than) levels 
that are achieved by a well-performing, non-malfunctioning source. It 
is reasonable to interpret CAA section 111 to avoid such a result. The 
EPA's approach to malfunctions is consistent with CAA section 111 and 
is a reasonable interpretation of the statute.
    Given that compliance with the emission standard is determined on a 
12-operating-month rolling average basis, the impact of periods of 
malfunctions on the total average over a 12-operating-month period is 
expected to be minimal. Thus, malfunctions over that period are not 
likely to result in a violation of the standard.
    In the unlikely event that a source fails to comply with the 
applicable CAA section 111 standards as a result of a malfunction 
event, the EPA would determine an appropriate response based on, among 
other things, the good faith efforts of the source to minimize 
emissions during malfunction periods, including preventative and 
corrective actions, as well as root cause analyses to ascertain and 
rectify excess emissions. The EPA would also consider whether the 
source's failure to comply with the CAA section 111 standard was, in 
fact, sudden, infrequent, not reasonably preventable and was not 
instead caused in part by poor maintenance or careless operation. 40 
CFR 60.2 (definition of malfunction).
    If the EPA determines in a particular case that an enforcement 
action against a source for violation of an emission standard is 
warranted, the source can raise any and all defenses in that 
enforcement action and the federal district court will determine what, 
if any, relief is appropriate. The same is true for citizen enforcement 
actions. Similarly, the presiding officer in an administrative 
proceeding can consider any defense raised and determine whether 
administrative penalties are appropriate.
    In summary, the EPA interpretation of the CAA and, in particular, 
CAA section 111 is reasonable and encourages practices that will avoid 
malfunctions. Administrative and judicial procedures for addressing 
exceedances of the standards fully recognize that violations may occur 
despite good faith efforts to comply and can accommodate those 
situations.
    In the January 2014 proposal for newly constructed EGUs, the EPA 
had proposed to include an affirmative defense to civil penalties for 
violations caused by malfunctions in an effort to create a system that 
incorporates some flexibility, recognizing that there is a tension, 
inherent in many types of air regulation, to ensure adequate compliance 
while simultaneously recognizing that despite the most diligent of 
efforts, emission standards may be violated under circumstances 
entirely beyond the control of the source. Although the EPA recognized 
that its case-by-case enforcement discretion provides sufficient 
flexibility in these circumstances, it included the affirmative defense 
to provide a more formalized approach and more regulatory clarity. See 
Weyerhaeuser Co. v. Costle, 590 F.2d 1011, 1057-58 (D.C. Cir. 1978) 
(holding that an informal case-by-case enforcement discretion approach 
is adequate); but see Marathon Oil Co. v. EPA, 564 F.2d 1253, 1272-73 
(9th Cir. 1977) (requiring a more formalized approach to consideration 
of ``upsets beyond the control of the permit holder''). Under the EPA's 
regulatory affirmative defense provisions, if a source could 
demonstrate in a judicial or administrative proceeding that it had met 
the requirements of the affirmative defense in the regulation, civil 
penalties would not be assessed. Recently, the U.S. Court of Appeals 
for the District of Columbia Circuit vacated an affirmative defense in 
one of the EPA's CAA section 112 regulations. NRDC v. EPA, 749 F.3d 
1055 (D.C. Cir., 2014) (vacating affirmative defense provisions in CAA 
section 112 rule establishing emission standards for Portland cement 
kilns). The court found that the EPA lacked authority to establish an 
affirmative defense for private civil suits and held that under the 
CAA, the authority to determine civil penalty amounts in such cases 
lies exclusively with the courts, not the EPA. Specifically, the Court 
found: ``As the language of the statute makes clear, the courts 
determine, on a case-by-case basis, whether civil penalties are 
`appropriate.''' See NRDC at 1063 (``[U]nder this statute, deciding 
whether penalties are `appropriate' in a given private civil suit is a 
job for the courts, not EPA.'').\542\ In light of NRDC, the EPA is not 
including a regulatory affirmative defense provision in this final 
rule. As explained above, if a source is unable to comply with 
emissions standards as a result of a malfunction, the EPA may use its 
case-by-case enforcement discretion to provide flexibility, as 
appropriate. Further, as the D.C. Circuit recognized, in an EPA or 
citizen enforcement action, the court has the discretion to consider 
any defense raised and determine whether penalties are appropriate. Cf. 
NRDC, at 1064 (arguments that violations were caused by unavoidable 
technology failure can be made to the courts in future civil cases when 
the issue arises). The same is true for the presiding officer in EPA 
administrative enforcement actions.\543\
---------------------------------------------------------------------------

    \542\ The court's reasoning in NRDC focuses on civil judicial 
actions. The court noted that ``EPA's ability to determine whether 
penalties should be assessed for Clean Air Act violations extends 
only to administrative penalties, not to civil penalties imposed by 
a court.'' Id.
    \543\ Although the NRDC case does not address the EPA's 
authority to establish an affirmative defense to penalties that is 
available in administrative enforcement actions, the EPA is not 
including such an affirmative defense in the final rule. As 
explained above, such an affirmative defense is not necessary. 
Moreover, assessment of penalties for violations caused by 
malfunctions in administrative proceedings and judicial proceedings 
should be consistent. Cf. CAA section 113(e) (requiring both the 
Administrator and the court to take specified criteria into account 
when assessing penalties).

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[[Page 64624]]

B. Continuous Monitoring Requirements

    The majority of comments received on the proposal supported the 
EPA's use of existing monitoring requirements under the Acid Rain 
Program, which are contained in 40 CFR part 75 requirements. In 
response to this, the EPA is finalizing monitoring requirements that 
incorporate and reference the part 75 monitoring requirements for the 
majority of the CO2 and energy output monitoring 
requirements while ensuring accuracy and stringency required under the 
program.
    This final rule requires owners or operators of EGUs that combust 
solid fossil fuel to install, certify, maintain, and operate continuous 
emission monitoring systems (CEMS) to measure CO2 
concentration, stack gas flow rate, and (if needed) stack gas moisture 
content in accordance with 40 CFR part 75, in order to determine hourly 
CO2 mass emissions rates (tons/hr).
    The rule allows owners or operators of affected EGUs that burn 
exclusively gaseous or liquid fuels to install fuel flow meters as an 
alternative to CEMS and to calculate the hourly CO2 mass 
emissions rates using Equation G-4 in appendix G of part 75. To 
implement this option, hourly measurements of fuel flow rate and 
periodic determinations of the gross calorific value (GCV) of the fuel 
are also required, in accordance with appendix D of part 75.
    In addition to requiring monitoring of the CO2 mass 
emission rate, the rule requires EGU owners or operators to monitor the 
hourly unit operating time and ``gross output'', expressed in megawatt 
hours (MWh). The gross output includes electrical output plus any 
mechanical output, plus 75 percent of any useful thermal output.
    The rule requires EGU owners or operators to prepare and submit a 
monitoring plan that includes both electronic and hard copy components, 
in accordance with 40 CFR 75.53(g) and (h). The electronic portion of 
the monitoring plan should be submitted to the EPA's CAMD using the 
Emissions Collection and Monitoring Plan System (ECMPS) Client Tool. 
The hard copy portion of the plan should be sent to the applicable 
state and EPA Regional office. Further, all monitoring systems used to 
determine the CO2 mass emission rates have to be certified 
according to 40 CFR 75.20 and section 6 of part 75, appendix A within 
the 180-day window of time allotted under 40 CFR 75.4(b), and are 
required to meet the applicable on-going quality assurance procedures 
in appendices B and D of part 75.
    The rule requires all valid data collected and recorded by the 
monitoring systems (including data recorded during startup, shutdown, 
and malfunction) to be used in assessing compliance. Failure to collect 
and record required data is a violation of the monitoring requirements, 
except for periods of monitoring system malfunctions, repairs 
associated with monitoring system malfunctions, and required monitoring 
system quality assurance or quality control activities that temporarily 
interrupt the measurement of stack emissions (e.g., calibration error 
tests, linearity checks, and required zero and span adjustments).
    The rule requires only those operating hours in which valid data 
are collected and recorded for all of the parameters in the 
CO2 mass emission rate equation to be used for calculating 
compliance with applicable emission limits. Additionally for EGUs using 
CO2 CEMS, only unadjusted stack gas flow rate values should 
be used in the emissions calculations. In this rule, part 75 bias 
adjustment factors (BAFs) should not be applied to the flow rate data. 
These restrictions on the use of part 75 data for part 60 compliance 
are consistent with previous NSPS regulations and revisions. 
Additionally if an affected EGU combusts natural gas and/or fuel oil 
and the CO2 mass emissions rate are measured using Equation 
G-4 in appendix G of part 75, then determination of site-specific 
carbon-based F-factors using Equation F-7b in section 3.3.6 of appendix 
F of part 75 is allowed, and use of these Fc values in the 
emissions calculations instead of using the default Fc 
values in the Equation G-4 nomenclature is also allowed.
    This final rule includes the following special compliance 
provisions for units with common stack or multiple stack 
configurations; these provisions are consistent with 40 CFR 60.13(g):
     If two or more EGUs share a common exhaust stack, are 
subject to the same emission limit, and the operator is required to (or 
elects to) determine compliance using CEMS, then monitoring the hourly 
CO2 mass emission rate at the common stack instead of 
monitoring each EGU separately is allowed. If this option is chosen, 
the hourly gross electrical load (or steam load) is the sum of the 
hourly loads for the individual EGUs and the operating time is 
expressed as ``stack operating hours'' (as defined in 40 CFR 72.2). 
Then, if compliance with the applicable emission limit is attained at 
the common stack, each EGU sharing the stack will be in compliance with 
the CO2 emissions limit.
     If the operator is required to (or elects to) determine 
compliance using CEMS and the effluent from the EGU discharges to the 
atmosphere through multiple stacks (or, if the effluent is fed to a 
stack through multiple ducts and is monitored in the ducts), then 
monitoring the hourly CO2 mass emission rate and the ``stack 
operating time'' at each stack or duct separately is required. In this 
case, compliance with the applicable emission limit is determined by 
summing the CO2 mass emissions measured at the individual 
stacks or ducts and dividing by the total gross output for the unit.
    The rule requires 95 percent of the operating hours in each 
compliance period (including the compliance periods for the 
intermediate emission limits) to be valid hours, i.e., operating hours 
in which quality-assured data are collected and recorded for all of the 
parameters used to calculate CO2 mass emissions. EGU owners 
or operators have the option to use back up monitoring systems, as 
provided in 40 CFR 75.10(e) and 75.20(d), to help meet this data 
capture requirement. This requirement is separate from the requirement 
for a source to demonstrate compliance with an applicable emission 
standard. When demonstrating compliance with an emission standard the 
calculation must use all valid data to calculate a compliance average 
even if the percent of valid hours recorded in the period is less than 
the 95 percent requirement.

C. Emissions Performance Testing Requirements

    Similarly to the comments received on monitoring for the proposal, 
commenters in general supported the use of current testing requirements 
required under the Acid Rain Program 40 CFR part 75 requirements. Thus 
the EPA is finalizing requirements for performance testing as 
consistent with part 75 requirements where appropriate to ensure the 
quality and accuracy of data and measurements as required by the final 
rule.
    In accordance with 40 CFR 75.64(a), the final rule requires an EGU 
owner or operator to begin reporting emissions data when monitoring 
system certification is completed or when the 180-day window in 40 CFR 
75.4(b) allotted for initial certification of the monitoring systems 
expires (whichever date is earlier). For EGUs subject to the

[[Page 64625]]

1,400 lb CO2/MWh-g) emission standard, the initial 
performance test consists of the first 12 operating months of data, 
starting with the month in which emissions are first required to be 
reported. The initial 12-operating-month compliance period begins with 
the first month of the first calendar year of EGU operation in which 
the facility exceeds the capacity factor applicability threshold.
    The traditional 3-run performance tests (i.e., stack tests) 
described in 40 CFR 60.8 are not required for this rule. Following the 
initial compliance determination, the emission standard is met on a 12-
operating-month rolling average basis.

D. Continuous Compliance Requirements

    Commenters supported the use of a 12-operating-month rolling 
average for the compliance period for the final standards. In response, 
this final rule specifies that compliance with the 1,400 lb 
CO2/MWh-g emission limit is determined on a 12-operating-
month rolling average basis, updated after each new operating month. 
For each 12-operating-month compliance period, quality-assured data 
from the certified Part 75 monitoring systems is used together with the 
gross output over that period of time to calculate the average 
CO2 mass emissions rate.
    The rule specifies that the first operating month included in the 
initial 12-operating-month compliance period is the month in which 
reporting of emissions data is required to begin under 40 CFR 75.64(a), 
i.e., either the month in which monitoring system certification is 
completed or the month in which the 180-day window allotted to finish 
certification testing expires (whichever month is earlier).
    Initial compliance with the applicable emissions limit in kg/MWh is 
calculated by dividing the sum of the hourly CO2 mass 
emissions values by the total gross output for the 12-operating-month 
period. Affected EGUs continue to be subject to the standards and 
maintenance requirements in the CAA section 111 regulatory general 
provisions contained in 40 CFR part 60, subpart A.
    Several commenters stated that the final rule should require 
operators to round their calculated emissions rates to three 
significant figures when comparing their actual rates to the standard. 
These commenters said that allowing use of only two significant digits 
when calculating the 12-operating-month rolling average emission rate 
would constitute relaxation of the standard by 5 percent because an 
actual emission rate of 1,049.9 lb CO2/MWh rounds to 1,000 
lb of CO2 per MWh when only two significant figures are 
required in the final step of compliance calculations. Commenters also 
suggested that the emission limits be written in scientific notation 
(e.g., 1.10 x 10-3 lb CO2/MWh) to clarify the number of 
significant digits that should be used when evaluating compliance. 
Other commenters suggested that the final step in compliance 
calculations should reflect rounding the emission rate to the nearest 
whole number using the ASTM rounding convention (ASTM E29).
    The General Provisions of Part 60 specify the rounding conventions 
for compliance calculations at 40 CFR 60.13(h)(3) including the 
provision that ``after conversion into units of the standard, the data 
may be rounded to the same number of significant digits used in the 
applicable subpart to specify the emission limit.''
    The final rule requires that the 12-operating-month rolling average 
emission rate must be rounded to three significant figures if the 
applicable emissions standard is greater than or equal to 1,000 (e.g., 
an actual emission rate of 1,004.9 lb CO2/MWh is rounded to 
1,000 lb CO2/MWh); for standards of 1000 or less, the final 
rule requires rounding the actual emission rate to two significant 
figures (e.g., an actual emission rate of 454.9 kg CO2/MWh 
is rounded to 450 kg CO2/MWh). Historically, many of the 
emissions limits under part 60 have been expressed to two significant 
digits (e.g., the original SO2 emission standard for coal-
fired units under Subpart D was 1.2 lb SO2/MMBtu). The 
rounding conventions under the General Provisions allow the reporting 
of all emission rates in the range from 1.15 to 1.249 as 1.2 lb 
SO2/MMBtu. During compliance periods with emissions at the 
lower end of this range, the operator is required to report higher 
emissions than actually occurred; during compliance periods at the 
upper end of this range the operator is allowed to report lower 
emissions than actually occurred. In either case the absolute error 
remains small because the emission rate in this example is a relatively 
small numerical value. In addition, the required emission reductions 
typically are large enough that rounding does not impact the emission 
control strategy of affected units. However, the final standards for 
CO2 emissions include numerical values that are larger than 
many historical emissions standards and require a relatively small 
percent reduction in emissions. Accordingly, it is appropriate to 
require the use of three significant digits when completing compliance 
calculations resulting in numerical values larger than 1,000. This is 
particularly important when considering the relatively small emission 
rate changes that may be required for compliance with the unit-specific 
emission standards being finalized for modified steam generating and 
IGCC units because a rounding error of 5 percent may be larger than the 
percent difference between the affected unit's historically best 
emission rate and the emission rate immediately preceding the 
modification.
    The final rule requires rounding of emission rates with numerical 
values greater than or equal to 1,000 to three significant figures and 
rounding of rates with numerical values less than 1,000 to two 
significant figures.

E. Notification, Recordkeeping, and Reporting Requirements

    Commenters supported the coordination of notification, 
recordkeeping, and reporting required under this rule in conjunction 
with the requirements already in place under part 75, so the EPA has 
made the requirements as efficient and streamlined as possible with the 
current requirements under part 75. The final rule requires an EGU 
owner or operator to comply with the applicable notification 
requirements in 40 CFR 75.61, 40 CFR 60.7(a)(1) and (a)(3), and 40 CFR 
60.19. The rule also requires the applicable recordkeeping requirements 
in subpart F of part 75 to be met. For EGUs using CEMS, the data 
elements that are recorded include, among others, hourly CO2 
concentration, stack gas flow rate, stack gas moisture content (if 
needed), unit operating time, and gross electric generation. For EGUs 
that exclusively combust liquid and/or gaseous fuel(s) and elect to 
determine CO2 emissions using Equation G-4 in appendix G of 
part 75, the key data elements in subpart F that are recorded include 
hourly fuel flow rates, fuel usage times, fuel GCV, gross electric 
generation.
    The rule requires EGU owners or operators to keep records of the 
calculations they perform to determine the total CO2 mass 
emissions and gross output for each operating month. Records of the 
calculations performed to determine the average CO2 mass 
emission rate (kg/MWh) and the percentage of valid CO2 mass 
emission rates in each compliance period are required to be kept. The 
rule also requires sources to keep records of calculations performed to 
determine site-specific carbon-based F-factors for

[[Page 64626]]

use in Equation G-4 of part 75, appendix G (if applicable).
    Sources are required to keep all records for a period of 3 years. 
All required records must be kept on-site for a minimum of two years, 
after which the records can be maintained off-site.
    The rule requires all affected EGU owners/operators to submit 
quarterly electronic emissions reports in accordance with subpart G of 
part 75. The reports in appendix G that do not include data required to 
calculate compliance with the applicable CO2 emission 
standard are not required to be reported under this rule. The rule 
requires the reports in 40 CFR 60.5555 to be submitted using the ECMPS 
Client Tool. Except for a few EGUs that may be exempt from the Acid 
Rain Program (e.g., oil-fired units), this is not a new reporting 
requirement. Sources subject to the Acid Rain Program are already 
required to report the hourly CO2 mass emission rates that 
are needed to assess compliance with this rule.
    Additionally, in the final rule and as part of an agency-wide 
effort to streamline and facilitate the reporting of environmental 
data, the rule requires selected data elements that pertain to 
compliance under this rule, and that serve the purpose of identifying 
violations of an emission standard, to be reported periodically using 
ECMPS.
    Specifically, EGU owners/operators must submit quarterly electronic 
reports within 30 days after the end of each quarter consistent with 
current part 75 reporting requirements. The first report is for the 
quarter that includes the final (12th) operating month of the initial 
12-operating-month compliance period. For that initial report and any 
subsequent report in which the 12th operating month of a compliance 
period (or periods) occurs during the calendar quarter, the average 
CO2 mass emissions rate (kg/MWh) is reported for each 
compliance period, along with the dates (year and month) of the first 
and twelfth operating months in the compliance period and the 
percentage of valid CO2 mass emission rates obtained in the 
compliance period. The dates of the first and last operating months in 
the compliance period clearly bracket the period used in the 
determination, which facilitates auditing of the data. Reporting the 
percentage of valid CO2 mass emission rates is necessary to 
demonstrate compliance with the requirement to obtain valid data for 95 
percent of the operating hours in each compliance period. Any 
violations that occur during the quarter are identified. If there are 
no compliance periods that end in the quarter, a definitive statement 
to that effect must be included in the report. If one or more 
compliance periods end in the quarter but there are no violations, a 
statement to that effect must be included in the report.
    Currently, ECMPS is not programmed to receive the additional 
information included in the report required under 40 CFR 60.5555(a)(2) 
for affected EGUs. However, we will make the necessary modifications to 
the system in order to fully implement the reporting requirements of 
this rule upon promulgation.

XI. Consistency Between BSER Determinations for This Rule and the Rule 
for Existing EGUs

    In the CAA section 111(d) rule for existing steam units and 
combustion turbines that the EPA is promulgating at the same time as 
this CAA section 111(b) rule, the EPA is identifying as part of the 
BSER for those sources, building block 1 (for steam units, efficient 
operation), building block 2 (for steam units, dispatch shift to 
existing NGCC units), and building block 3 (for steam units and 
combustion turbines, substitution of generation with new renewable 
energy). In this section, we explain why the EPA is not identifying 
building blocks 1, 2, or 3 as part of the BSER for new, modified, or 
reconstructed steam generators or combustion turbines.

A. Newly Constructed Steam Generating Units

1. Preference for Technological Controls as the BSER for New EGUs
    As discussed in this preamble and in more detail in the preamble to 
the CAA section 111(d) rule for existing sources, the phrase ``system 
of emission reduction'' is undefined and provides the EPA with 
discretion in setting a standard of performance under CAA section 
111(b) or emission guidelines under CAA section 111(d). Because the 
phrase by its plain language does not limit our review of potential 
systems in either context, the same systems could be considered for 
application in new and existing sources. That said, many other factors 
and considerations direct us to focus on different systems when 
establishing a standard of performance under CAA section 111(b) and an 
emission guideline under CAA section 111(d). Thus, it is useful to 
describe part of the underlying basis for the BSER--partial CCS--that 
the EPA has determined for new steam units before discussing the 
building blocks that form the BSER for existing units.
    For new steam generating units, the EPA is identifying, as the 
BSER, systems of emission reduction that assure that these sources are 
inherently low-emitting at the time of construction. The following 
reasons support this approach to the BSER.
    New sources are expected to have long operating lives over which 
initial capital costs can be amortized. Thus, new construction is the 
preferred time to drive capital investment in emission controls. In 
this case, the BSER for new steam generators, partial CCS, requires 
substantial capital expenditures, which new sources are best able to 
accommodate.
    While CAA section 111(b)(1)(B) and (a)(1) by their terms do not 
mandate that the BSER assure that new sources are inherently low 
emitting, that approach to the BSER is consistent with the legislative 
history.\544\ See Section III.H.3.b.4 above. For instance, the 1970 
Senate Committee Report explains that ``[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.'' \545\ Existing sources, on the other hand, 
would be regulated through emission standards, which were broadly 
understood at the time to reflect available technology, alternative 
methods of prevention and control, alternative fuels, processes, and 
operating methods.\546\ \547\
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    \544\ Although Congress expressed a clear preference that new 
sources would be ``designed, built, equipped, operated, and 
maintained so as to reduce emissions to a minimum,'' the Senate 
Committee Report also makes clear that the term 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.'' Sen. Rep. No. 91-1196 at 15-17, 1970 
CAA Legis. Hist. at 415-17 (emphasis added).
    \545\ Sen. Rep. No. 91-1196 at 15-16, 1970 CAA Legis. Hist. at 
416 (emphasis added).
    \546\ See 1970 CAA Amendments, Pub. L. 91-604, section 4, 84 
Stat. 1676, 1679 (Dec. 31, 1970) (describing information that the 
EPA must issue to the states and appropriate air pollution control 
agencies along with the issuance of ambient air quality criteria 
under Section 4 of the 1970 CAA titled ``Ambient Air Quality and 
Emission Standards'').
    \547\ In the 1977 CAA Amendments, Congress revised section 
111(a)(1) to mandate that the EPA base standards for new sources on 
technological controls, but, at the same time, made clear that the 
EPA was not required to base the emission guidelines for existing 
sources on technological controls. In the 1990 CAA Amendments, 
Congress repealed the section 111(a)(1) requirements that 
distinguished between new and existing sources and largely restored 
the 1970 CAA Amendments version of section 111(a)(1).

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[[Page 64627]]

2. Practical Implications of Including the Building Blocks
    Several practical considerations make the building blocks 
inappropriate for new sources. Thus, for the following reasons, the EPA 
does not consider it appropriate to include the building blocks as part 
of the BSER for new sources:
a. Additional Cost
    Partial CCS will impose substantial (albeit reasonable) costs on 
new steam-generating EGUs, and, as a result, the EPA does not believe 
that including additional measures as part of the BSER would be 
appropriate. One disadvantage in adding additional costs is that doing 
so would make it more difficult for new steam-generating EGUs to 
compete with new nuclear units. Because the BSER is selected after 
considering cost (among other factors), the EPA is not required 
to,\548\ and in this case believes it would not be appropriate to, 
select the most stringent adequately demonstrated system of emission 
reduction (through the combination of partial CCS and the building 
blocks) for purposes of setting a standard of performance under CAA 
section 111(b).
---------------------------------------------------------------------------

    \548\ For example, as early as a 1979 NSPS rulemaking for 
affected EGUs, the EPA recognized that it was not required to 
establish as the BSER the most stringent adequately demonstrated 
system of emission reduction available, and instead could weigh the 
amount of additional emission reductions against the costs. See 44 
FR 52792, 52798 (Sept. 10, 1979) (``Although there may be emission 
control technology available that can reduce emissions below those 
levels required to comply with standards of performance, this 
technology might not be selected as the basis of standards of 
performance due to costs associated with its use. Accordingly, 
standards of performance should not be viewed as the ultimate in 
achievable emission control. In fact, the Act requires (or has 
potential for requiring) the imposition of a more stringent emission 
standard in several situations.'').
---------------------------------------------------------------------------

    Building block 1 measures are not appropriate (or would be 
redundant) because the BSER for new steam generating units is based on 
highly efficient supercritical technology, i.e., state-of-the-art, 
efficient equipment. See Section V.K above. Accordingly, there is 
little improvement in efficiency that can be justified as part of the 
BSER.
    Building block 2 and 3 measures are not appropriate for the BSER 
because new steam units would have a significantly limited range of 
options to implement building blocks 2 and 3. The new source 
performance standard was proposed and is being finalized as a rate-
based standard. Thus, if building blocks 2 and 3 were included in the 
BSER, a more stringent rate-based standard would be applicable to all 
new sources. However, it is conceivable that the EPA could propose a 
hybrid standard that would include both an emission-rate limit that 
reflects partial CCS and a requirement for allowances that reflects 
building blocks 2 and 3. Accordingly, the following discussion assumes 
either a rate-based or mass-based standard, or part of a hybrid 
standard.
    In both a rate-based program and a mass-based program, building 
blocks 2 and 3 measures can be implemented through a range of methods, 
including trading with other EGUs. While it is not necessarily the case 
that every existing source will be able to implement each of the 
methods, in general, existing sources will have a range of measures to 
choose from. However, at least some of those methods may not be 
available to new sources, which would render compliance with their 
emission limits more challenging and potentially more costly.
    One example is emission trading with other affected EGUs. For 
existing sources, emission trading is an important option for 
implementing the building blocks. There are large numbers of existing 
sources, and they will become subject to the section 111(d) standards 
of performance at the same time. It may be more cost-effective for some 
to implement the building blocks than others, and, as a result, some 
may over-comply and some may under-comply, and the two groups may trade 
with each other. Because of the large numbers of existing sources, the 
trading market can be expected to be robust. Trading optimizes 
efficiency. As a result, existing sources have more flexibility in the 
overall amount of their investment in building blocks 2 and 3 and can 
adjust investment obligations among themselves through emissions 
trading.
    In contrast, new sources construct one at a time, and it is unknown 
how many new sources there will be. Without a sizeable number of new 
sources, there will not be a robust trading market. Thus, a new source 
cannot count on being able to find a new source trading partner. In 
addition, it is not possible to count on new sources being able to 
trade with existing sources, for several reasons. First, as noted, 
there are indications in the legislative history that new sources 
should be well-controlled at the source, which casts doubt on whether 
new sources should be allowed to meet their standards through the 
purchase of emission credits. Second, new sources must meet their 
standards of performance as soon as they begin operations. If they do 
so before the year 2022, when existing sources become subject to 
section 111(d) state plan standards of performance, no existing sources 
will be available as trading partners.
    In addition, for section 111(d) sources, we are granting a 7-year 
period of lead-time for the implementation of the building blocks. This 
is due, in part, to the benefits of allowing the ERC and allowance 
markets to develop. However, the new source standards take effect 
immediately, so new sources would not have the advantage of this lead 
time were they subject to more stringent standards that also reflected 
the building blocks.\549\
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    \549\ At least in theory, we could consider promulgating a 
standard of performance for new affected EGUs that becomes more 
stringent beginning in 7 years, based on a more stringent BSER. We 
are not inclined to adopt that approach because section 111(b)(1)(B) 
requires that we review and, if necessary, revise the section 111(b) 
standards of performance no later than every 8 years anyway.
---------------------------------------------------------------------------

    In addition, if there are an unexpectedly large number of new 
sources, then they would be obliged to invest in greater amounts of 
building blocks 2 and 3, and that could reduce the amounts of building 
blocks 2 and 3 available for existing sources, and thereby raise the 
costs of building blocks 2 and 3 for existing sources. This could 
compromise the BSER under section 111(d) and undermine the ability of 
existing sources to comply with their section 111(d) obligations.\550\
---------------------------------------------------------------------------

    \550\ The EPA is authorized to consider the BSER for new and 
existing sources in conjunction with each other. In the 1977 CAA 
Amendments, Congress revised section 111(a)(1) to require 
technological controls for new combustion sources at least in part 
because this requirement would preclude new sources from relying on 
low-sulfur coal to achieve their emission limits, which, in turn, 
would free up low-sulfur coal for existing sources.
---------------------------------------------------------------------------

B. New Combustion Turbines

    For new combustion turbines, the building blocks are not 
appropriate as part of the BSER either. Building block 1 is limited to 
steam generating units, and therefore has no applicability to new 
combustion turbines. Measures comparable to those in building block 1 
would not be appropriate because new highly efficient NGCC construction 
already entails high efficiency equipment and operation. Building block 
2 is also limited to steam generating units and is not appropriate as 
part of the BSER for new NGCC units because it would not result in any 
emission reductions.
    The reasons why building block 3 are not appropriate are the same 
as discussed above for why building blocks 2 and 3 are not appropriate 
for new steam generating units (limited range of options for 
implementation (including lack of availability of trading), lack of

[[Page 64628]]

lead-time for implementation, and the possibility of reducing the 
availability of renewable energy for existing sources).

C. Modified and Reconstructed Steam and NGCC Units

    For modified and reconstructed steam generators, the EPA identified 
the BSER as maintenance of high efficiency or implementation of a 
highly efficient unit. The resulting emission limit must be met over 
the specified time period and cannot be deviated from or averaged. As a 
result, a modified or reconstructed steam generator generally will 
require ongoing maintenance and may find it prudent to operate below 
its limit as a safety margin. This represents a substantial commitment 
of resources. For these units, the additional costs of implementing the 
building blocks would not be appropriate.
    In addition, building block 1 is not appropriate for modified or 
reconstructed steam generating units because the BSER for these units 
is already based on highly efficient performance. For the same reasons, 
it does not make sense to attempt to develop the analogue to building 
block 1 for reconstructed NGCC units--the BSER for them, too, is 
already based on highly efficient performance.
    Building block 2 is not appropriate for reconstructed NGCC units 
because it would not yield any reductions.
    Building blocks 2 and 3 are not appropriate for modified or 
reconstructed steam generators, and building block 3 is not appropriate 
for reconstructed NGCC units, for the same reasons that they are not 
appropriate for new EGUs, as described above (limited range of options 
for implementation (including lack of availability of trading), lack of 
lead-time for implementation, and the possibility of reducing the 
availability of renewable energy for existing sources).

XII. Interactions With Other EPA Programs and Rules

A. Overview

    This final rule will, for the first time, regulate GHGs under CAA 
section 111. In Section IX of the preamble to the proposed rule, the 
EPA addressed how regulation of GHGs under CAA section 111 could have 
implications for other EPA rules and for permits written under the CAA 
Prevention of Significant Deterioration (PSD) preconstruction permit 
program and the CAA Title V operating permit program. The EPA proposed 
to adopt provisions in the regulations that explicitly addressed some 
of these implications.
    For purpose of the PSD program, the EPA is finalizing provisions in 
part 60 of its regulations that make clear that the threshold for 
determining whether a PSD source must satisfy the BACT requirement for 
GHGs continues to apply after promulgation of this rule. This rule does 
not require any additional revisions to State Implementation Plans. As 
discussed further below, this final rule may have bearing on the 
determination of BACT for new, modified, and reconstructed EGUs that 
require PSD permits. With respect to the Title V operating permits 
program, this rule does not affect whether sources are subject to the 
requirement to obtain a Title V operating permit based solely on 
emitting or having the potential to emit GHGs above major source 
thresholds. However, this rule does have some implications for Title V 
fees, which the EPA is addressing in this final rule.
    Finally, the fossil fuel-fired EGUs covered in this rule are or 
will be potentially impacted by several other recently finalized or 
proposed EPA rules, and such potential interactions with other EPA 
rules are discussed below.

B. Applicability of Tailoring Rule Thresholds Under the PSD Program

    In our January 8, 2014 proposal, the EPA proposed to adopt 
regulatory language in 40 CFR part 60 that would ensure the 
promulgation of this NSPS would not undercut the application of rules 
that limit the application of the PSD permitting program requirements 
to only the largest sources of GHGs. An intervening decision of the 
United States Supreme Court has, to a large extent, resolved the legal 
issue that led the EPA to propose these part 60 provisions. The Supreme 
Court has since clarified that the PSD program does not apply to 
smaller sources based on the amount of GHGs they emit. However, because 
the largest sources emitting GHGs remain subject to the PSD permitting 
requirements, the EPA has concluded that it remains appropriate to 
adopt the proposed regulatory provisions in 40 CFR part 60 in this 
rule. We discuss our reasons for this action in detail below.
    Under the PSD program in part C of title I of the CAA, in areas 
that are classified as attainment or unclassifiable for NAAQS 
pollutants, a new or modified source that emits any air pollutant 
subject to regulation at or above specified thresholds is required to 
obtain a preconstruction permit. This permit assures that the source 
meets specific requirements, including application of BACT to each 
pollutant subject to regulation under the CAA. Many states (and local 
districts) are authorized by the EPA to administer the PSD program and 
to issue PSD permits. If a state is not authorized, then the EPA issues 
the PSD permits for facilities in that state.
    To identify the pollutants subject to the PSD permitting program, 
EPA regulations contain a definition of the term ``regulated NSR 
pollutant.'' 40 CFR 52.21(b)(50); 40 CFR 51.166(b)(49). This definition 
contains four subparts, which cover pollutants regulated under various 
parts of the CAA. The second subpart covers pollutants regulated under 
section 111 of the CAA. The fourth subpart is a catch-all provision 
that applies to ``[a]ny pollutant that is otherwise subjection to 
regulation under the Act.''
    This definition and the associated PSD permitting requirements 
applied to GHGs for the first time on January 2, 2011, by virtue of the 
EPA's regulation of GHG emissions from motor vehicles, which first took 
effect on that same date. 75 FR 17004 (Apr. 2, 2010). As such, GHGs 
became subject to regulation under the CAA and the fourth subpart of 
the ``regulated NSR pollutant'' definition became applicable to GHGs.
    On June 3, 2010, the EPA issued a final rule, known as the 
Tailoring Rule, which phased in permitting requirements for GHG 
emissions from stationary sources under the CAA PSD and Title V 
permitting programs (75 FR 31514). Under its understanding of the CAA 
at the time, the EPA believed the Tailoring Rule was necessary to avoid 
a sudden and unmanageable increase in the number of sources that would 
be required to obtain PSD and Title V permits under the CAA because the 
sources emitted GHGs emissions over applicable major source and major 
modification thresholds. In Step 1 of the Tailoring Rule, which began 
on January 2, 2011, the EPA limited application of PSD or Title V 
requirements to sources of GHG emissions only if the sources were 
subject to PSD or Title V ``anyway'' due to their emissions of non-GHG 
pollutants. These sources are referred to as ``anyway sources.'' In 
Step 2 of the Tailoring Rule, which began on July 1, 2011, the EPA 
applied the PSD and Title V permitting requirements under the CAA to 
sources that were classified as major, and, thus, required to obtain a 
permit, based solely on their potential GHG emissions and to 
modifications of otherwise major sources that required a PSD permit 
because they increased only GHG emissions above applicable levels in 
the EPA regulations.
    In the PSD program, the EPA implemented the steps of the Tailoring 
Rule by adopting a definition of the

[[Page 64629]]

term ``subject to regulation.'' The limitations in Step 1 of the 
Tailoring Rule are reflected in 40 CFR 52.21(b)(49)(iv) and 40 CFR 
51.166(b)(48)(iv). With respect to ``anyway sources'' covered by PSD 
during Step 1, this provision established that GHGs would not be 
subject to PSD requirements unless the source emitted GHGs in the 
amount of 75,000 tons per year (tpy) of carbon dioxide equivalent 
(CO2e) or more. The primary practical effect of this 
paragraph is that the PSD BACT requirement does not apply to GHG 
emissions from an ``anyway source'' unless the source emits GHGs at or 
above this threshold. The Tailoring Rule Step 2 limitations are 
reflected in 40 CFR 52.21(b)(49)(v) and 51.166(b)(48)(v). These 
provisions contain thresholds that, when applied through the definition 
of ``regulated NSR pollutant,'' function to limit the scope of the 
terms ``major stationary source'' and ``major modification'' that 
determine whether a source is required to obtain a PSD permit. See e.g. 
40 CFR 51.166(a)(7)(i) and (iii); 40 CFR 51.166(b)(1); 40 CFR 
51.166(b)(2).
    This structure of the EPA's PSD regulations created questions 
regarding the extent to which the limitations in the Tailoring Rule 
would continue to apply to GHGs once they became regulated, through 
this final rule, under section 111 of the CAA. 79 FR 1487-1488. As 
discussed above, the definition of ``regulated NSR pollutant'' in the 
PSD regulations contains a separate PSD trigger for air pollutants 
regulated under the NSPS, 40 CFR 51.166(b)(49)(ii) (the ``NSPS trigger 
provision''). Thus, when GHGs become subject to a standard promulgated 
under CAA section 111 for the first time under this rule, PSD 
requirements would presumably apply for GHGs on an additional basis 
besides through the regulation of GHGs from motor vehicles. However, 
the Tailoring Rule, on the face of its regulatory provisions, 
incorporated the revised thresholds it promulgated into only the fourth 
subpart of the PSD definition of regulated NSR pollutant (``[a]ny 
pollutant that otherwise is subject to regulation under the Act''). The 
regulatory text does not clearly incorporate the thresholds into the 
NSPS trigger provision in the second subpart (``[a]ny pollutant that is 
subject to any standard promulgated under section 111 of the Act''). 
For this reason, a question arose as to whether the Tailoring Rule 
limitations would continue to apply to the PSD requirements after they 
are independently triggered for GHGs by the NSPS that the EPA is now 
promulgating. Stakeholders questioned whether the EPA must revise its 
PSD regulations --and, by the same token, whether states must revise 
their SIPs--to assure that the Tailoring Rule thresholds will continue 
to apply to sources potentially subject to PSD under the CAA based on 
GHG emissions.
    In the January 8, 2014 proposed rule, the EPA explained that the 
agency had included an interpretation in the Tailoring Rule preamble, 
which means that the Tailoring Rule thresholds continue to apply if and 
when the EPA promulgates requirements under CAA section 111. 79 FR 1488 
(citing 75 FR 31582). Nevertheless, to ensure there would be no 
uncertainty as to this issue, the EPA proposed to adopt explicit 
language in 40 CFR 60.46Da(j), 40 CFR 60.4315(b), and 40 CFR 60.5515 of 
the agency's regulations. The proposed language makes clear that the 
thresholds for GHGs in the EPA's PSD definition of ``subject to 
regulation'' apply through the second subpart of the definition of 
``regulated NSR pollutant'' to GHGs regulated under this rule.
    The EPA received comments supporting the adoption of this proposed 
language, but several commenters also expressed concern that adding 
this language to part 60 alone would not be sufficient. Several 
commenters urged the EPA to instead revise the PSD regulations in parts 
51 and 52. In addition, commenters expressed concern that further steps 
were needed to amend the SIPs before there would be certainty that the 
Tailoring Rule limitations continued to apply after the adoption of 
CO2 standards under CAA section 111 in this final rule.
    On June 23, 2014, the United States Supreme Court, in Utility Air 
Regulatory Group v. Environmental Protection Agency, issued a decision 
addressing the application of PSD permitting requirements to GHG 
emissions. The Supreme Court held that the EPA may not treat GHGs as an 
air pollutant for purposes of determining whether a source is a major 
source (or modification thereof) for the purpose of PSD applicability. 
The Court also said that the EPA could continue to require that PSD 
permits, otherwise required based on emissions of pollutants other than 
GHGs, contain limitations on GHG emissions based on the application of 
BACT. The Supreme Court decision effectively upheld PSD permitting 
requirements for GHG emissions under Step 1 of the Tailoring Rule for 
``anyway sources'' and invalidated application of PSD permitting 
requirements to Step 2 sources based on GHG emissions. The Court also 
recognized that, although the EPA had not yet done so, it could 
``establish an appropriate de minimis threshold below which BACT is not 
required for a source's greenhouse gas emissions.'' 134 S. Ct. at 2449.
    In accordance with the Supreme Court decision, on April 10, 2015, 
the U.S. Court of Appeals for the District of Columbia Circuit (the 
D.C. Circuit) issued an amended judgment vacating the regulations that 
implemented Step 2 of the Tailoring Rule, but not the regulations that 
implement Step 1 of the Tailoring Rule. The court specifically vacated 
40 CFR 51.166(b)(48)(v) and 40 CFR 52.21(b)(49)(v) of the EPA's 
regulations, but did not vacate 40 CFR 51.166(b)(48)(iv) or 40 CFR 
52.21(b)(48)(iv). The court 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 such revisions.
    The practical effect of the Supreme Court's clarification of the 
reach of the CAA is that it eliminates the need for Step 2 of the 
Tailoring Rule and subsequent steps of the GHG permitting phase in that 
the EPA had planned to consider under the Tailoring Rule. This also 
eliminates the possibility that the promulgation of GHG standards under 
section 111 could result in additional sources becoming subject to PSD 
based solely on GHGs, notwithstanding the limitations the EPA adopted 
in the Tailoring Rule. However, for an interim period, the EPA and the 
states will need to continue applying parts of the PSD definition of 
``subject to regulation'' to ensure that sources obtain PSD permits 
meeting the requirements of the CAA.
    The CAA continues to require that PSD permits issued to ``anyway 
sources'' satisfy the BACT requirement for GHGs. Based on the language 
that remains applicable under 40 CFR 51.166(b)(48)(iv) and 40 CFR 
52.21(b)(49)(iv), the EPA and states may continue to limit the 
application of BACT to GHG emissions in those circumstances where a 
source emits GHGs in the amount of at least 75,000 tpy on a 
CO2e basis. The EPA's intention is for this to serve as an 
interim approach while the EPA moves forward to propose a GHG 
Significant Emission Rate (SER) that would establish a de minimis 
threshold level for permitting GHG emissions under PSD. Under this 
forthcoming rule, the EPA intends to propose restructuring the GHG 
provisions in its PSD regulations so that the de minimis threshold for 
GHGs will not reside within the definition of ``subject to 
regulation.'' This restructuring will be designed to make the PSD 
regulatory provisions on GHGs universally

[[Page 64630]]

applicable, without regard to the particular subparts of the definition 
of ``regulated NSR pollutant'' that may cover GHGs. Upon promulgation 
of this PSD rule, it will then provide a framework that states may use 
when updating their SIPs consistent with the Supreme Court decision.
    While the PSD rulemaking described above is pending, the EPA and 
approved state, local, and tribal permitting authorities will still 
need to implement the BACT requirement for GHGs. In order to enable 
permitting authorities to continue applying the 75,000 tpy 
CO2e threshold to determine whether BACT applies to GHG 
emissions from an ``anyway source'' after GHGs are subject to 
regulation under CAA section 111, the EPA has concluded that it 
continues to be appropriate to adopt the proposed language in 40 CFR 
60.5515 (subpart TTTT). Because the EPA is not finalizing the proposed 
regulations in subparts Da and KKKK, it is not necessary to adopt the 
comparable provisions that the EPA proposed in 40 CFR 60.46Da(j) and 40 
CFR 60.4315(b).
    The EPA has evaluated 40 CFR 60.5515 in light of the Supreme Court 
decision and the comments received on the question of whether this CAA 
section 111 standard will undermine the application of the Tailoring 
Rule limitations. While most of the Tailoring Rule limitations are no 
longer needed to avoid triggering the requirement to obtain a PSD 
permit based on GHGs alone, the limitation in 40 CFR 51.166(b)(48)(iv) 
and 40 CFR 52.21(b)(49)(iv) will remain important to provide an interim 
applicability level for the GHG BACT requirement in ``anyway source'' 
PSD permits. Thus, there continues to be a need to ensure that the 
regulation of GHGs under CAA section 111 does not make this BACT 
applicability level for anyway sources effectively inoperable. The 
language in 40 CFR 60.5515 will continue to be effective at avoiding 
this result after the judicial actions described above and the adoption 
of this final rule. The provisions in part 60 reference 40 CFR 
51.166(b)(48) and 40 CFR 52.21(b)(49) of the EPA's regulations. 
However, the courts have now vacated 40 CFR 51.166(b)(48)(v) and 40 CFR 
52.21(b)(49)(v), and the EPA will take steps soon to eliminate these 
subparts from the CFR. As a result of these steps, the language of 
final 40 CFR 60.5515 will not incorporate the vacated parts of 40 CFR 
51.166(b)(48) and 40 CFR 52.21(b)(49), but these provisions in part 60 
will continue to apply to those subparts of the PSD rules that are 
needed on an interim basis to limit application of BACT to GHGs only 
when emitted by an anyway source in amounts of 75,000 tpy 
CO2e or more. Thus, in this final rule, the EPA is adopting 
the proposed text of 40 CFR 60.5515 for this purpose without 
substantial change.
    As to the concern expressed by some commenters that revisions to 
part 60 alone are not sufficient, the GHG SER rulemaking described 
above will include proposed revisions to the PSD regulations in parts 
51 and 52 that should ultimately address this concern. The EPA 
acknowledges that the commenters concern will not be fully addressed 
for an interim period of time, but (for the reasons discussed above) 
the part 60 provisions adopted in this rule are sufficient to make 
explicit that the 75,000 tpy CO2e BACT applicability level 
for GHGs will apply to GHGs that are subject to regulation under the 
CAA section 111 standards adopted in this rule.
    Rather than adopting a temporary patch in its PSD regulations in 
this rule to address the implications for PSD of regulating GHGs under 
CAA section 111, the EPA believes it will be most efficient for the EPA 
and the states if the EPA completes a comprehensive PSD rule that will 
address all the implications of the Supreme Court decision. The 
revisions the EPA will consider based on the Supreme Court decision 
will inherently address the commenters concerns about the definition of 
the ``subject to regulation'' and the proposed part 60 provisions. To 
the extent this PSD rule is not complete before the EPA proposes 
additional CAA section 111 standards for GHGs, the EPA will need to 
consider adding provisions like 40 CFR 60.5515 to other subparts of 
part 60. In a separate rulemaking finalized concurrently with this 
rule, the EPA is also finalizing corresponding edits to 40 CFR 60.5705 
in subpart UUUU to clarify that the regulated pollutant is the same for 
both the CAA section 111(b) and section 111(d) rules. As of this time, 
the EPA has not proposed GHG standards for other source categories 
under CAA section 111. To the extent needed, this approach of adding 
provisions to a few subparts in part 60 would be less burdensome to 
states and more efficient than revising 40 CFR 51.166 at this time 
solely to address the implications of regulating GHGs under CAA section 
111.
    The EPA understands that many commenters expressed concern that PSD 
SIPs would also have to be amended to address the implications of 
regulating GHGs under CAA section 111. However, the language in 40 CFR 
60.5515 is designed to avoid the need for states to make revisions to 
the PSD regulations in their SIPs at this time. The EPA has previously 
observed that the form of each pollutant regulated under the PSD 
program is derived from the form of the pollutant described in 
regulations, such as an NSPS, that make the pollutant regulated under 
the CAA. 56 FR 24468, 24470 (May 30, 1991); 61 FR 9905, 9912-18 (Mar. 
12, 1996); 75 FR 31522.
    Moreover, it is more likely that states would need to consider a 
SIP revision if the EPA were to revise 40 CFR 51.166 in this rule. 
Revisions to 51.166 can trigger requirements for states to revise their 
PSD program provisions under 40 CFR 51.166(a)(6).
    Given the process required in states to review their SIPs and 
submit them to the EPA for approval, it is most efficient for all 
concerned when the EPA is able to consolidate its revisions to 40 CFR 
51.166. The EPA, thus, believes it will be less work for states if we 
issue a comprehensive set of rules addressing regulation of GHGs under 
the PSD program after the Supreme Court decision.
    In comments on the proposed rules, states generally did not express 
concern that the proposed revisions to part 60 were insufficient to 
avoid the need for SIP revisions. In our proposal, we addressed any 
state with an approved PSD SIP program that applies to GHGs which 
believed that this final rule would require the state to revise its SIP 
so that the Tailoring Rule thresholds continue to apply. First, the EPA 
encouraged any state that considered such revisions necessary to make 
them as soon as possible. Second, if the state could do so promptly, 
the EPA said it would assess whether to proceed with a separate 
rulemaking action to narrow its approval of that state's SIP so as to 
assure that, for federal purposes, the Tailoring Rule thresholds will 
continue to apply as of the effective date of the final NSPS rule. 79 
FR 1487. The EPA did not receive any comments or other feedback from 
states requesting that the EPA narrow their program to ensure the 
Tailoring Rule thresholds continue to apply after promulgating this 
rule. We do not believe such action will be necessary in any state 
after the Supreme Court decision and our action in this rule is to 
adopt the proposed part 60 provisions for purposes of ensuring the Step 
1 BACT applicability level for GHGs continues to apply on an interim 
basis.

C. Implications for BACT Determinations Under PSD

    New major stationary sources and major modifications at existing 
major stationary sources are required by the

[[Page 64631]]

CAA to, among other things, obtain a permit under the PSD program 
before commencing construction. The emission thresholds that define PSD 
applicability can be found in 40 CFR parts 51 and 52, and the PSD 
thresholds specific to GHGs are explained in the preceding section of 
this preamble.
    Sources that are subject to PSD must obtain a preconstruction 
permit that contains emission limitations based on application of BACT 
for each regulated NSR pollutant. The BACT requirement is set forth in 
section 165(a)(4) of the CAA, and in EPA regulations under 40 CFR parts 
51 and 52. These provisions require that BACT determinations be made on 
a case-by-case basis. CAA section 169(3) defines BACT, in general, as:

``an emissions limitation . . . based on the maximum degree of 
reduction for each pollutant . . . emitted from any proposed major 
stationary source or major modification which the Administrator . . 
. [considering energy, environmental, and economic impacts] . . . 
determines is achievable for such facility . . .''

Furthermore, this definition in the CAA specifies that

``[i]n no event shall application of [BACT] result in emissions of 
any pollutants which will exceed the emissions allowed by any 
applicable standard established pursuant to section 111 or 112 of 
the Act.''

This condition of CAA section 169(3) has historically been interpreted 
to mean that BACT cannot be less stringent than any applicable standard 
of performance under the NSPS. See, e.g., U.S. EPA, PSD and Title V 
Permitting Guidance for Greenhouse Gases, EPA-457/B-11-001 (March 2011) 
(``GHG Permitting Guidance'' or ``Guidance'') at 20-21. Thus, upon 
completion of an NSPS, the NSPS establishes a ``BACT Floor'' for PSD 
permits that are issued to affected facilities covered by the NSPS.
    BACT is a case-by-case review that considers a number of factors. 
These factors include the availability, technical feasibility, control 
effectiveness, and the economic, environmental and energy impacts of 
the control option. See GHG Permitting Guidance at 17-46. The fact that 
a minimum control requirement (i.e., the BACT Floor) is established by 
the EPA through an applicable NSPS does not bar a permitting agency 
from justifying a more stringent control level as BACT for a specific 
PSD permit.
    It is important to understand how this NSPS may relate to 
determining BACT for new and existing EGUs that require PSD permits. 
PSD generally applies to major sources, while this NSPS applies to 
units that may be within a source. Under this NSPS, an affected 
facility is a new EGU or a modified or reconstructed EGU. The new 
source NSPS requirements apply, in general, to any stationary source 
that adds a new EGU that is an affected facility under this NSPS. This 
could, for example, include a proposed brand new (``greenfield'') power 
plant or an existing power plant that proposes to add a new EGU (e.g., 
to increase its generating capacity). While this latter scenario is 
considered a ``new affected facility'' under the NSPS, it is generally 
viewed under PSD as a ``modification'' of an existing stationary 
source. Thus, the new source NSPS requirements could apply to a 
modification, as that term is defined under PSD.
    In addition, this NSPS will apply to some modified and 
reconstructed units, as those terms are defined under part 60. 
Consequently, this NSPS could establish a BACT floor for existing 
stationary sources that are modifying an existing EGU and experience an 
emissions increase that makes the source subject to PSD review. 
However, a physical change that triggers the NSPS modification or 
reconstruction requirements does not necessarily subject the source to 
PSD requirements, and vice versa. In general, in order to trigger the 
NSPS modification or reconstruction requirements, a physical change 
must increase the maximum hourly emission rate of the pollutant (to be 
an NSPS modification) or the fixed capital cost of the change must 
exceed 50 percent of the fixed capital cost of a comparable entirely 
new facility (to be an NSPS reconstruction). See 40 CFR 60.2, 60.14, 
60.15. Under the PSD program, however, a physical change (or change in 
the method of operation) must result in an increase in annual emissions 
of the pollutant by a specified emission threshold in order to be 
subject to PSD requirements. This emission calculation considers the 
unit's past annual emissions and its projected annual emissions. See, 
e.g., 40 CFR 52.21(a)(2)(iv)(C). In addition, the PSD emissions test 
for a modification allows the existing source to consider qualifying 
emission reductions and increases at the source within a 
contemporaneous period to ``net out'' of, or avoid, triggering PSD 
review. Thus, it is important to understand the differences in how the 
term ``modification'' is used in the NSPS and PSD programs, and that a 
physical change that is a modification under one program may not 
necessarily be a modification under the other program.
    In the preamble to the proposed NSPS for new sources, the EPA 
discussed whether a standard of performance for the new source NSPS, 
specifically the BSER for solid fuel-fired EGUs that is based on 
partial CCS, could become the BACT floor when permitting a modified or 
reconstructed EGU or non-EGU source. As noted above, BACT is a case-
specific review by a permitting agency. In evaluating BACT, the 
permitting authority should consider all available control technologies 
that have the potential for practical application to the facility or 
emission unit under evaluation. See GHG Permitting Guidance at 24. This 
BACT review must include any technologies that are part of an 
applicable NSPS for the specific type of source and would therefore 
establish the minimum level of stringency for the BACT. Thus, it is 
possible that partial CCS could be considered in a BACT review as an 
available control option for a modified or reconstructed EGU facility, 
or for another type of source (e.g., natural gas processing plant), but 
this NSPS is not an applicable standard to such sources so it would not 
establish a requirement that partial CCS is a minimum level of 
stringency for the BACT for those sources.
    Some commenters expressed concern that, if the EPA finalizes a BSER 
for utility boilers and IGCC units that is based on partial CCS, it 
would establish a BACT Floor for new EGUs that would be inconsistent 
with prior BACT determinations for EGUs in both permits issued by EPA 
Regions and permits issued by state agencies on which the EPA has 
commented. Many of these comments were more directed at the development 
and deployment of CCS (i.e., the commenter did not believe CCS should 
be the basis for BSER) rather than examining whether an NSPS should 
establish the BACT floor for applicable sources, which is the legal 
consequence of setting an NSPS under the terms of the CAA. 
Consequently, we respond to these comments in other sections of this 
preamble that support the selection of partial CCS as the basis for the 
BSER for fossil fuel-fired electric utility steam generating units.
    With regard to the commenters who stated that a BSER for EGUs that 
is based on partial CCS would be inconsistent with BACT determinations 
in previous GHG PSD permits, it is important to recognize that a BACT 
determination is a case-by-case analysis and that technological 
capabilities and costs evolve over time.\551\ In addition, to

[[Page 64632]]

date the EPA has not issued a PSD permit with GHG BACT for a source 
that would be an affected facility requiring partial CCS under this 
NSPS (i.e., a fossil fuel-fired steam generating unit), so one cannot 
determine whether the EPA--as a PSD permitting authority--has been 
either consistent or inconsistent by setting a BSER of partial CCS in 
this NSPS. Although, in the course of a BACT review, some permitting 
authorities may have determined that CCS is not technologically 
feasible or economically achievable for a gas-fired EGU, because of the 
case-by-case nature of the BACT analysis it does not automatically 
follow that the same conclusion is appropriate for a solid fuel-fired 
EGU. Furthermore, PSD permitting requirements first applied to GHGs in 
January 2011 and more information about GHG control technology has been 
gained in this four-and-a-half year period. Thus, we would expect BACT 
decisions to evolve as well, such that a GHG BACT review for a coal-
fired EGU in 2015 may look very different from a review that was done 
in 2011.
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    \551\ In this regard, the 2011 GHG Permitting Guidance states 
that ``although CCS is not in widespread use at this time, EPA 
generally considers CCS to be an `available' add-on pollution 
control technology for facilities emitting CO2 in large 
amounts and industrial facilities with high-purity CO2 
streams.'' GHG Permitting Guidance at 35. The Guidance goes on to 
note that CCS may not be technically feasible at modified sources 
(citing possible issues with ``space for CO2 capture 
equipment at an existing facility''), or in other specific 
circumstances. Id. at 36 (``Logistical hurdles for CCS may include 
obtaining contracts for offsite land acquisition . . ., the need for 
funding . . ., timing of available transportation infrastructure, 
and developing a site for secure long term storage. Not every source 
has the resources to overcome the offsite logistical barriers 
necessary to apply CCS technology to its operations, and smaller 
sources will likely be more constrained in this regard''). Id. at 
42-3 EPA also noted that CCS may be expensive in individual 
instances and thus eliminated as a control option for that reason 
under step 4 of the BACT analysis, noting further that revenues from 
EOR may offset other costs. Id. at 42-3. See also UARG v. EPA, 134 
S.Ct. 2427, 2448 (2014) (noting that EPA's GHG Permitting Guidance 
states that carbon capture is reasonably comparable to more 
traditional, end-of-stack BACT technologies, and that petitioners do 
not dispute that).
    As explained at Section V.I.5 above, in determining that partial 
CCS is BSER for new fossil fuel steam electric plants, the EPA has 
carefully considered the issue of logistics (including cost 
estimates for land acquisition, transportation, and sequestration) 
and costs generally. Nor would new plants face the same types of 
constraints as modified or reconstructed sources in a BACT 
determination, since a new source has more leeway in choosing where 
to site. See text at V.G.3. above. Moreover, the GHG Permitting 
Guidance considered BACT determinations for all types of sources, 
not just those for which the EPA has determined in this rule that 
partial CCS is the BSER, and the concerns expressed in the Guidance 
thus must be considered in that broader context.
---------------------------------------------------------------------------

    Additionally, if a state agency is processing a permit application 
for a solid fuel-fired EGU and does not propose CCS as BACT (or does 
not even consider CCS as an available control for BACT), the EPA is not 
necessarily required to comment negatively on the draft permit, or to 
otherwise request or require that the state agency amend the BACT to 
include CCS. For state agencies that have their own EPA-approved state 
implementation plan, the state has primacy over their permitting 
actions and discretion to interpret their approved rules and to apply 
the applicable federal and state regulatory requirements that are in 
place at the time for the facility in question. The EPA's role is to 
provide oversight to ensure that the state operates their PSD program 
in accordance with the CAA and applicable rules. If the EPA does not 
adversely comment on a certain draft permit or BACT determination, it 
does not necessarily imply EPA endorsement of the proposed permit or 
determination.
    Some commenters also felt that the determination of partial CCS as 
BSER is inconsistent with the agency's position on CCS in the EPA's GHG 
Permitting Guidance, which they say supports the notion that additional 
work is required before CCS can be integrated at full-scale electric 
utility applications. It is important to recognize that the EPA's 
Permitting Guidance is guidance, so it does not contain any final 
determination of BACT for any source. Furthermore, we disagree with the 
commenters' characterization of the GHG Permitting Guidance. The 
Guidance specifically states ``[f]or the purposes of a BACT analysis 
for GHGs, the EPA classifies CCS as an add-on pollution control 
technology that is ``available'' for facilities emitting CO2 
in large amounts, including fossil fuel-fired power plants, and for 
industrial facilities with high-purity CO2 streams (e.g., 
hydrogen production, ammonia production, natural gas processing, 
ethanol production, ethylene oxide production, cement production, and 
iron and steel manufacturing). For these types of facilities, CCS 
should be listed in Step 1 of a top-down BACT analysis for GHGs.'' GHG 
Permitting Guidance at 32. As discussed elsewhere in the Guidance, 
technologies that should be listed in Step 1 are those that ``have the 
potential for practical application to the emissions unit and regulated 
pollutant under evaluation.'' GHG Permitting Guidance at 24. The EPA 
continues to stand by its position on the availability of CCS in this 
context, as expressed in the GHG Permitting Guidance.
    The GHG Permitting Guidance continues on to discuss case-specific 
factors and potential limitations with applying CCS, and it 
acknowledges that CCS may not be ultimately selected as BACT in 
``certain cases'' based on technology feasibility and cost. GHG 
Permitting Guidance at 36, 43. While acknowledging these potential 
challenges when it was issued in March 2011, the Guidance clearly does 
not rule out the selection of CCS as BACT for any source category and 
it is forward looking. GHG Permitting Guidance at 43 (``. . . as a 
result of ongoing research and development, . . . CCS may become less 
costly and warrant greater consideration . . . in the future'') Nothing 
in the Guidance is inconsistent with EPA's present position that CCS is 
adequately demonstrated for the types of sources covered by this NSPS, 
as articulated elsewhere in this preamble.
    A commenter asserted that the GHG Permitting Guidance should be 
amended because it calls for consideration of CCS in BACT 
determinations even though the proposed NSPS identified ``partial CCS'' 
as BSER for new boiler and IGCC EGUs. The Guidance explains that ``the 
purpose of Step 1 of the process is to cast a wide net and identify all 
control options with potential application to the emissions unit under 
review.'' GHG Permitting Guidance at 26. The EPA agrees that the GHG 
Permitting Guidance only uses the term ``CCS'' and does not distinguish 
``partial CCS'' from ``full CCS.'' But considering the purpose of Step 
1 of the process, we believe that the term ``CCS'', as it is used in 
the GHG Permitting Guidance, adequately describes the varying levels of 
CO2 capture. A BACT review should analyze all available 
technologies in order to adequately support the BACT determination, and 
may require evaluation of partial CCS, full CCS, and/or no 
CO2 capture. The specific facility type and CO2 
capture conditions will dictate the level(s) of CO2 capture 
that are most appropriate to consider as ``available'' in a BACT 
review.

D. Implications for Title V Program

    Under the Title V program, certain stationary sources, including 
``major sources'' are required to obtain an operating permit. This 
permit includes all of the CAA requirements applicable to the source, 
including adequate monitoring, recordkeeping, and reporting 
requirements to assure sources' compliance. These permits are generally 
issued through EPA-approved state Title V programs.
    In the January 8, 2014 proposal, the EPA discussed whether this 
rulemaking would impact the applicability of Title V requirements to 
major sources of GHGs. 79 FR 1489-90. The relevant issue for Title V 
purposes was, in essence, whether promulgation of CAA section 111 
requirements for GHGs

[[Page 64633]]

would undermine the Tailoring Rule, which, as explained above, phased 
in permitting requirements for GHG emissions for stationary sources 
under the CAA PSD and Title V permitting programs. Based on the EPA's 
understanding of the CAA at that time, the proposal discussed this 
issue in the context of the regulatory and statutory definitions of 
``major source,'' focusing on revisions that had been made in the 
Tailoring Rule to the definitions in the Title V regulations of ``major 
source'' and ``subject to regulation.'' 79 FR 1489-90 (quoting 75 FR 
31583). Under the Title V regulations, as revised by the Tailoring 
Rule, ``major source'' is defined to include, in relevant part, ``a 
major stationary source . . . that directly emits, or has the potential 
to emit, 100 tpy or more of any air pollutant subject to regulation.'' 
The proposal further explained that the GHG threshold that had been 
established in the Tailoring Rule had been incorporated into the 
definition of ``subject to regulation'' under 40 CFR 70.2 and 71.2, 
such that those definitions specify `` `that GHGs are not subject to 
regulation for purposes of defining a major source, unless as of July 
1, 2011, the emissions of GHGs are from a source emitting or having the 
potential to emit 100,000 tpy of GHGs on a CO2e basis.' '' 
Id. (quoting 75 FR 31583). The proposal thus concluded that the Title V 
definition of ``major source,'' as revised by the Tailoring Rule, did 
not on its face distinguish among types of regulatory triggers for 
Title V. It further noted that the Title V program had already been 
triggered for GHGs, and thus concluded that the promulgation of CAA 
section 111 requirements would not further impact Title V applicability 
requirements for major sources of GHGs. 79 FR 1489-90.
    As noted elsewhere in this section, after the proposal for this 
rulemaking was published, the United States 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, though for 
different reasons.
    With respect to Title V, the Supreme Court said in UARG v. EPA that 
the 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 in Coalition for Responsible Regulation, 
Inc. v. Environmental Protection Agency, 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 decisions make clear that promulgation of CAA section 111 
requirements for GHGs will not result in the 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.\552\
---------------------------------------------------------------------------

    \552\ As explained elsewhere in this notice, the EPA intends to 
conduct future rulemaking action to make the appropriate revisions 
to the operating permit rules to respond to the Supreme Court 
decision and the D.C. Circuit's amended judgment. To the extent 
there are any issues related to the potential interaction between 
the promulgation of CAA section 111 requirements for GHGs and Title 
V applicability based on emissions above major source thresholds, 
the EPA expects there would be an opportunity to consider those 
during that rulemaking.
---------------------------------------------------------------------------

    To be clear, however, unless exempted by the Administrator through 
regulation under CAA section 502(a), any source, including an area 
source (a ``non-major source''), subject to an NSPS is required to 
apply for, and operate pursuant to, a Title V permit that assures 
compliance with all applicable CAA requirements for the source, 
including any GHG-related applicable requirements. This aspect of the 
Title V program is not affected by UARG v. EPA, as the EPA does not 
read that decision to affect either the grounds other than those 
described above on which a Title V permit may be required or the 
applicable requirements that must be addressed in Title V permits.\553\ 
Consistent with the proposal, the EPA has concluded that this rule will 
not affect non-major sources and there is no need to consider whether 
to exempt non-major sources. Thus, sources that are subject to the CAA 
section 111 standards promulgated in this rule are required to apply 
for, and operate pursuant to, a Title V permit that assures compliance 
with all applicable CAA requirements, including any GHG-related 
applicable requirements.
---------------------------------------------------------------------------

    \553\ See Memorandum from Janet G. McCabe, Acting Assistant 
Administrator, Office of Air and Radiation, and Cynthia Giles, 
Assistant Administrator, Office of Enforcement and Compliance 
Assurance, to Regional Administrators, Regions 1-10, Next Steps and 
Preliminary Views on the Application of Clean Air Act Permitting 
Programs to Greenhouse Gases Following the Supreme Court's Decision 
in Utility Regulatory Group v. Environmental Protection Agency (July 
24, 2014) at 5.
---------------------------------------------------------------------------

E. Implications for Title V Fee Requirements for GHGs

1. Why is the EPA revising Title V fee rules as part of this action?
    The January 8, 2014 notice of proposed rulemaking (79 FR 1430) (the 
``EGU GHG NSPS proposal'' or ``NSPS proposal'') proposed the first 
section 111 standards to regulate GHGs at EGUs. That notice also 
included proposed revisions to the fee requirements of the 40 CFR part 
70 and part 71 operating permit rules under Title V of the CAA to avoid 
inadvertent consequences for fees that would be triggered by the 
promulgation of the first CAA section 111 standard to regulate GHGs. If 
we do not revise the fee rules by the time of the promulgation of the 
NSPS standards for GHGs, then approved part 70 programs implemented by 
state, local and tribal permitting authorities \554\ that rely on the 
``presumptive minimum'' approach and the part 71 program implemented by 
the EPA would be required to account for GHGs in emissions-based fee 
calculations at the same dollar per ton ($/ton) rate as other air 
pollutants. The EPA believes this would result in the collection of 
fees in excess of what is required to cover the reasonable costs of an 
operating permit program. See NSPS proposal 79 FR 1490.
---------------------------------------------------------------------------

    \554\ Hereafter, for the sake of simplicity, we will generally 
refer to part 70 permitting authorities as ``state'' permitting 
authorities and refer to part 70 programs as ``state'' programs.
---------------------------------------------------------------------------

    In response to these concerns, the EPA proposed regulatory changes 
to limit the fees collected based on GHG emissions and proposed two fee 
adjustment options to increase the fees collected based on the costs 
for permitting authorities to conduct certain review activities related 
to GHG emissions, while still providing sufficient funding for an 
operating permit program. Also, we proposed an option that would have 
provided for no fee adjustments to recover the costs of conducting 
review activities related to GHG emissions. Id. 79 FR 1490. The EPA did 
not propose any action related to state and local permitting 
authorities that do not use the presumptive minimum approach.
    Most commenters on the proposal, including state and local 
permitting authorities, were supportive of exempting GHGs from the 
emissions-based fee calculations of the permit

[[Page 64634]]

rules, but support for the fee adjustment options was mixed, with state 
and local permitting authorities generally supporting either of the two 
fee adjustments, and other commenters generally supporting the option 
that provides for no fee adjustment.
2. Background on the Fee Requirements of Title V
    In the NSPS proposal, the EPA explained the statutory and 
regulatory background related to the requirement that permitting 
authorities collect fees from the owner or operator of Title V sources 
that are sufficient to cover the costs of the operating permit program. 
CAA section 502(b)(3)(A) requires an operating permit program to 
include a requirement that sources ``pay an annual fee, or the 
equivalent over some other period, sufficient to cover all reasonable 
(direct and indirect) costs required to develop and administer the 
permit program.'' See also 40 CFR 70.9(a). CAA section 502(b)(3)(B)(i) 
requires that, in order to have an approvable operating permit program, 
the permitting authority must show that ``the program will result in 
the collection, in the aggregate, from all sources [required to get an 
operating permit]'' of either ``an amount not less than $25 per ton of 
each regulated pollutant [adjusted annually for changes in the consumer 
price index], or such other amount as the Administrator may determine 
adequately reflects the reasonable costs of the permit program.'' See 
also 40 CFR 70.9(b)(2). This has been generally referred to as the 
``presumptive minimum'' approach. If a permitting authority does not 
wish to use the presumptive minimum approach, it may demonstrate ``that 
collecting an amount less than the [presumptive minimum amount] will'' 
result in the collection of funds sufficient to cover the costs of the 
program. CAA section 503(b)(3)(B)(iv); see also 40 CFR 70.9(b)(5). This 
has been generally referred to as the ``detailed accounting'' approach. 
CAA section 502(b)(3)(B)(ii) sets forth a definition of ``regulated 
pollutant'' for purposes of calculating the presumptive minimum that 
includes each pollutant regulated under section 111 of the CAA. See 
also 40 CFR 70.2.
3. What fee rules did we propose to revise?
    In the NSPS proposal, to exempt GHGs from emissions-based fee 
calculations, we proposed to exempt GHGs from the definition of 
``regulated pollutant'' for purposes of operating permit fee 
calculations (``the GHG exemption''). The EPA then proposed two 
alternative ways to account for the costs of addressing GHGs in 
operating permits through a cost adjustment. First, we proposed a 
modest additional cost for each GHG-related activity of certain types 
that a permitting authority would process (``the GHG adjustment option 
1''). Alternatively, we proposed a modest additional increase in the 
per ton rate used in the presumptive minimum calculation for all non-
GHG fee pollutants (``the GHG adjustment option 2''). The EPA also 
solicited comment on an option that would provide no additional cost 
adjustment to account for GHGs (``the GHG adjustment option 3''). All 
of the GHG adjustment options are based on the assumption that the GHG 
exemption is finalized. See NSPS Proposal 79 FR 1493-1495.
    The EPA additionally proposed two clarifications. The first was 
regulatory text in 40 CFR part 60, subparts Da, KKKK, and TTTT, to 
clarify that GHGs, as opposed to CO2, is the regulated 
pollutant for fee purposes (``the fee pollutant clarification''). Id. 
at 1505, 1506 and 1511. The second was a proposal to move the existing 
definition of ``Greenhouse gases (GHGs)'' within 40 CFR 70.2 and 71.2 
to promote clarity in the regulations (``the GHG clarification''). Id. 
79 FR 1490, 1517, 1518.
    For background purposes, below is a brief summary of each of the 
proposals.
a. The GHG Exemption
    To address the fee issues discussed in the NSPS proposal, the EPA 
proposed to exempt GHG emissions from the definition of ``regulated 
pollutant (for presumptive fee calculation)'' in 40 CFR 70.2 and the 
definition of ``regulated pollutant (for fee calculation)'' in 40 CFR 
71.2.\555\ See NSPS preamble 79 FR 1493, 1495.
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    \555\ Hereafter we will refer to these definitions as the ``fee 
pollutant'' definitions. Also, note that both fee pollutant 
definitions cross-reference the definitions of ``regulated air 
pollutant'' which includes air pollutants ``subject to any standard 
promulgated under section 111 of the Act.''
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b. The GHG Adjustment Option 1
    The first proposed ``GHG adjustment'' option (option 1) was to 
include an additional cost for each GHG-related activity of certain 
types that a permitting authority would process (an activity-based 
adjustment). The three activities identified for this option were ``GHG 
completeness determination (for initial permit or for updated 
application)'' at 43 hours of burden,\556\ ``GHG evaluation for a 
modification or related permit action'' at 7 hours of burden, and ``GHG 
evaluation at permit renewal'' at 10 hours of burden. See also 79 FR 
1494, fn. 280 (providing a description of each of these activities).
---------------------------------------------------------------------------

    \556\ Burden is the hours of staff time necessary to perform a 
task.
---------------------------------------------------------------------------

    For part 70, the burden hours per activity would be multiplied by 
the cost of staff time (in $/hour) specific to the state, including 
wages, benefits, and overhead, to determine the cost of each activity. 
All the activities for a given period would be totaled to determine the 
total GHG adjustment for the state. See 79 FR 1494.
    For part 71, we proposed a labor rate assumption of $52 per hour in 
2011 dollars. Using that labor rate, we proposed to determine the GHG 
fee adjustment for each GHG permitting program activity to be a 
specific dollar amount for each activity (``set fees'') that the source 
would pay for each activity performed. See 79 FR 1495. The EPA proposed 
to revise 40 CFR 70.9(b)(2)(v) and 40 CFR 71.9(c)(8) to implement this 
option.
c. The GHG Adjustment Option 2
    The second proposed GHG adjustment option (option 2) was to 
increase the dollar per ton ($/ton) rates used in the fee calculations 
for each non-GHG fee pollutant. The revised $/ton rates would be 
multiplied by the total tons of non-GHG fee pollutants actually emitted 
by any source to determine the applicable total fees. The EPA proposed 
to increase the $/ton rates by 7 percent.\557\ See NSPS proposal 79 FR 
1494, 1495.
---------------------------------------------------------------------------

    \557\ The EPA estimated that both options 1 and 2 would result 
in about a 7 percent increase in the fees collected by operating 
permit programs affected by the proposed rule. For example, the 
presumptive minimum fee rate in effect for September 1, 2014 through 
August 31, 2015 is $48.27/ton. A 7 percent increase under option 2 
would result in a revised fee of $51.65/ton.
---------------------------------------------------------------------------

d. The GHG Adjustment Option 3
    The EPA also solicited comment on not charging any fees related to 
GHGs (option 3). The basis for this proposed option was the observation 
that most sources that need to address GHGs in a permit would also emit 
non-GHG fee pollutants, and thus, the cost of permitting for any 
particular source may be accounted for adequately without charging any 
additional fees related to GHGs. Id. 79 FR 1494-1495.
e. The Fee Pollutant Clarification
    Another fee-related proposal was to add regulatory text to 40 CFR 
part 60, subparts Da, KKKK, and TTTT, to clarify that the fee pollutant 
for operating permit purposes would be considered to be ``GHGs,'' (as 
defined in

[[Page 64635]]

40 CFR 70.2 and 71.2),\558\ rather than solely CO2, which 
would be regulated under the section 111 standards and implemented 
through the EGU GHG NSPS. Id. 79 FR 1505, 1506, and 1511.
---------------------------------------------------------------------------

    \558\ Note that in 40 CFR 70.2 and 71.2, the term ``Greenhouse 
gases (GHGs)'' is defined as the ``aggregate group of six greenhouse 
gases: Carbon dioxide, nitrous oxide, methane, hydrofluorocarbons, 
perfluorocarbons, and sulfur hexafluoride.''
---------------------------------------------------------------------------

f. The GHG Clarification
    The EPA proposed to move the existing definition of ``Greenhouse 
gases (GHGs)'' within the definition of ``Subject to regulation'' in 40 
CFR 70.2 and 71.2 to a separate definition within those sections to 
promote clarity in the regulations. Id. 79 FR 1490, 1517, 1518.
4. What action is the EPA finalizing?
    In this action, the EPA is finalizing the following elements as 
proposed: (1) The GHG exemption, (2) the GHG adjustment option 1, and 
(3) the fee pollutant clarification.
    Public commenters on the proposal stated both support and 
opposition to using the NSPS rulemaking action to revise the Title V 
fee rules. Two commenters stated that proposing the Title V fee 
revisions within the NSPS rulemaking would result in fewer commenters, 
particularly state and local permitting authorities, having knowledge 
of the changes to the fee rules and sufficient opportunity to comment 
on the changes because the NSPS proposal is limited to a single source 
category, and one stated that a separate proposal for the fee rules 
would provide a sufficient opportunity for public comment. The EPA 
believes it is appropriate to move forward with final action amending 
the Title V fee regulations as part of this NSPS. As we explained in 
the preamble for the proposal and elsewhere in this final rule, the fee 
rules and the section 111 standards are interrelated because, if we do 
not revise the fee rules, promulgation of the final NSPS will trigger 
certain requirements related to Title V fees for GHG emissions that the 
EPA believes will result in the collection of excessive fees in states 
that implement the presumptive minimum approach and in the part 71 
program. Thus, it is important to finalize the revisions to the fee 
rules at the same time or prior to this NSPS, and it is within the 
EPA's discretion to address the NSPS and the fee rules at the same time 
as part of the same rulemaking action. In response to the commenters 
who were concerned that including the fee rule proposal as part of the 
NSPS proposal would result in the public not having sufficient public 
comment opportunities, the EPA believes sufficient public comment 
opportunities were provided on the fee rule changes because the 
proposal met all public participation requirements and we provided 
additional public outreach, including to state and local permitting 
authorities, which discussed the fee rule proposal. In addition to the 
publication of the proposed rulemaking in the Federal Register, the EPA 
held numerous hearings, reached out to state partners and the public, 
and developed numerous fact sheets and other information to support 
public comment on this rule. The EPA has complied with the applicable 
public participation requirements and executive orders. The proposal 
met all the requirements for public notice--it contained a clear and 
detailed explanation of how the part 70 and 71 rules would be affected 
by the promulgation of the CAA section 111 standard for EGUs and how 
the EPA proposed to revise the related regulatory provisions. We 
received many comments on the proposal to revise the fee rule for 
operating permits programs, and we are taking those comments into 
consideration in the finalization of the rulemaking action.
a. The GHG Exemption
    The EPA is taking final action to revise the definition of 
regulated pollutant (for presumptive fee calculation) in 40 CFR 70.2 
and regulated pollutant (for fee calculation) in 40 CFR 71.2 to exempt 
GHG emissions. This regulatory amendment will have the effect of 
excluding GHG emissions from being subject to the statutory ($/ton) fee 
rate set for the presumptive minimum calculation requirement of part 70 
and the fee calculation requirements of part 71. We received supportive 
comments from the majority of public commenters, including state and 
local permitting authorities and others, on revising the operating 
permit rules to exempt GHGs from the emission-based calculations that 
use the statutory fee rates. We are finalizing this portion of the 
proposal for the same reasons we explained in the proposal notice, 
including that leaving these regulations unchanged would have resulted 
in the collection of fee revenue far beyond the reasonable costs of an 
operating permit program. The EPA believes that these revisions (in 
conjunction with the GHG adjustment, see below) are consistent with the 
CAA requirements for fees pursuant to the authority of section 
502(b)(3)(B)(i).
    Some members of the public opposed the proposed GHG exemption for 
reasons including that it may limit permitting authorities' ability to 
charge sufficient fees to cover the cost of GHG permitting \559\ if the 
state is barred from exceeding minimum requirements set by the EPA. 
Despite this adverse comment, the EPA believes it is appropriate to 
finalize the GHG exemption because we are not finalizing any 
requirements that would require states to charge any particular fees to 
any particular sources. The changes we are finalizing to part 70 
concern the presumptive minimum approach, which sets a minimum fee 
target for states that have decided to follow the presumptive minimum 
approach. Neither the statute nor the final rule require any state 
following the presumptive minimum approach (or any other approach) to 
charge fees to sources using any particular method. Thus, the GHG 
exemption will not limit states' ability to structure their individual 
fee programs however they see fit in order to meet the requirement that 
they collect revenue sufficient to cover all reasonable costs of their 
permitting program. See CAA section 502(b)(3); 40 CFR 70.9(b)(3).
---------------------------------------------------------------------------

    \559\ We use the term ``GHG permitting'' in this section of the 
notice to refer to measures undertaken by permitting authorities to 
ensure that GHGs and any applicable requirements related to GHGs are 
appropriately addressed in Title V permitting.
---------------------------------------------------------------------------

b. The GHG Adjustment Option 1
    The EPA is finalizing GHG adjustment option 1 because we believe it 
will result in a system for the calculation of costs for part 70 and 
fees for part 71 that is most directly related to the costs of GHG 
permitting. The EPA has determined that some adjustment to cost and fee 
accounting is important because the recent addition of GHG emissions to 
the operating permitting program does add new burdens for permitting 
authorities. Although GHG adjustment option 3 (no GHG permitting fee 
adjustments) was supported by many industrial commenters, the EPA 
rejected it because it is in tension with the statutory requirement 
that permitting authorities collect sufficient fees to cover all the 
reasonable costs of permitting. See CAA section 502(b)(3)(A). Some 
state and local permitting authorities provided comments supporting 
option 1, while others supported option 2, and some supported either 
option, stating no preference. Also, a few state and local permitting 
authorities supported finalizing no adjustment and a few others asked 
for flexibility to set fee adjustments not proposed by the EPA, but 
that they believed would be appropriate for their program.

[[Page 64636]]

    The EPA is finalizing option 1 instead of option 2 because the 
option 1 adjustments are based on the actual costs for permitting 
authorities to process specific actions that require GHG reviews. The 
option 2 approach, which would have added a 7 percent surcharge to the 
$/ton rate used in the fee-related calculations, may have been 
administratively easier to implement, but is tied to the emissions of 
non-GHG air pollutants, which are not directly related to the costs of 
GHG permitting.
    Consistent with CAA section 502(b)(3)(B)(i), the Administrator has 
determined that the final rule's approach of exempting GHG emissions 
from fee-related calculations and accounting for the GHG permitting 
costs through option 1 will result in fees that will cover the 
reasonable costs of the permitting programs.
    The EPA is revising the part 70 regulations through this final 
action, specifically 40 CFR 70.9(b)(2), to modify the presumptive 
minimum approach to add the activity-based cost of GHG permitting 
activities, outlined in the revised 40 CFR 70.9(b)(2)(v), to the 
emissions-based calculation of 40 CFR 70.9(b)(2)(i), which is being 
revised to now exclude GHG emissions. To determine the activity-based 
GHG adjustment under 40 CFR 70.9(b)(2)(v), the permitting authority 
will multiply the burden hours for each activity (set forth in the 
regulation) by the cost of staff time (in $ per hour), including wages, 
benefits, and overhead, as determined by the state, for the particular 
activities undertaken during the particular time period.
    States that implement the presumptive minimum approach will need to 
follow the final rule's option 1 approach.\560\ States that use the 
detailed accounting approach are not directly affected by this 
rulemaking, but they must ensure that their fee collection programs are 
sufficient to fully fund all reasonable costs of the operating permit 
program, including costs attributable to GHG-related permitting. The 
EPA suggests states that use the detailed accounting approach consider 
the 7 percent assumption for the costs of GHG permitting in any such 
analysis, consistent with the EPA analysis of options 1 and 2 in the 
proposal.
---------------------------------------------------------------------------

    \560\ A presumptive minimum state may require various changes to 
its approved operating permit program before it may begin to 
implement the option 1 approach. For example, its regulations, and/
or program procedures and practices, may need to be revised, 
depending on the structure of the fee provisions in the state's 
program; thus, the exact response necessary to address this final 
action may vary from state to state.
---------------------------------------------------------------------------

    Consistent with 40 CFR 70.4(i), a state that wishes to change its 
operating permit program as a result of this final rule must apprise 
the EPA. The EPA will review the materials submitted concerning the 
change and decide if a formal program revision process is needed and 
will inform the state of next steps. The communication apprising the 
EPA of any such changes should include at least a narrative description 
of the change and any other information that will assist the EPA in its 
assessment of the significance of the changes. Certain changes, such as 
switching from the presumptive minimum method to a detailed accounting 
method, will be considered substantial program revisions and be subject 
to the requirements of 40 CFR 70.4(i)(2).
    With respect to the part 71 program, in this final action the EPA 
is revising 40 CFR 71.9(c) to require each part 71 source to pay an 
annual fee which is the sum of the activity-based fee of 40 CFR 
71.9(c)(8) and the emissions-based fee of 40 CFR 71.9(c)(1)-(4),\561\ 
which excludes GHG emissions. To determine the activity-based fee, the 
revised 40 CFR 71.9(c)(8) requires the source to pay a ``set fee'' for 
each listed activity that has been initiated since the fee was last 
paid. Under part 71, fees are typically paid at the time of initial 
application submittal, and thereafter, annually on the anniversary of 
the initial fee payment, or on any other dates that may be established 
in the permit. These set fees would not change until such time as we 
may revise our part 71 rule to change the set fees.
---------------------------------------------------------------------------

    \561\ Note that the emissions-based fee calculation differs 
somewhat depending on whether the part 71 program is being 
implemented by the EPA (see 40 CFR 71.9(c)(1)); a state, local or 
tribal agency with delegated authority from the EPA (see Sec.  
71.9(c)(2)); the EPA with contractor assistance (see Sec.  
71.9(c)(3)); or an agency with partial delegation authority (see 
Sec.  71.9(c)(4)).
---------------------------------------------------------------------------

    The final rule implements the option 1 approach by listing three 
activities performed by permitting authorities that involve GHG 
reviews. The following describes the activities as described in our 
proposal and certain clarifications we are making in the final rule to 
ensure consistent implementation.
    The EPA is finalizing that the first listed activity under option 1 
is ``GHG completeness determination (for initial permit or updated 
application).'' This activity must be counted for each new initial 
permit application, even for applications that do not include GHGs 
emissions or applicable requirements, since an important part of any 
completeness determination will be to determine that GHG emissions and 
applicable requirements have been properly addressed, as needed, in the 
application. The fee for this activity is a one-time charge that covers 
the initial application and any supplements or updates. The EPA 
believes that a single charge for a GHG completeness determination will 
be adequate to cover the reasonable costs for a permitting authority to 
review an initial application and any subsequent application updates 
related to initial permit issuance; thus, any updates to an initial 
application are included in a single ``GHG completeness 
determination,'' rather than as a separate activity for which the 
source would be charged in addition to the completeness determination 
for the initial application. This is an important distinction because 
many sources submit multiple permit application updates, either 
voluntarily or as required by the permitting authority, during 
application review, many of which do not require a separate or 
comprehensive completeness determination.
    The EPA is finalizing regulatory text that would describe the 
second listed activity as ``GHG evaluation for a permit modification or 
related permit action.'' \562\ The EPA had proposed that the second 
listed activity under option 1 would be ``GHG evaluation for a 
modification or related permit action.'' For the final rule, we are 
clarifying that we are adding a cost for a ``permit modification'' 
rather than for a ``modification.'' The term ``modification'' may be 
interpreted to refer to any change at a source, even a change that 
would not be required to be processed as a ``permit modification,'' 
while ``permit modification'' refers to any revision to an operating 
permit that cannot be processed as an administrative permit amendment 
and thus requires a review by a permitting authority as either a 
significant or minor permit modification.
---------------------------------------------------------------------------

    \562\ The EPA notes that the term ``permit modification'' in 
this context refers to all significant permit modifications and 
minor permit modifications under operating permit rules, but not to 
``administrative permit amendments,'' as such amendments are not 
defined as ``permit modifications'' in the permit rules. See, e.g., 
40 CFR 70.7(d), (e), and (f).
---------------------------------------------------------------------------

    The EPA is finalizing the third activity as ``GHG evaluation at 
permit renewal.'' This activity covers the processing of all permit 
renewal applications and will involve evaluations of whether any GHG 
applicable requirements are properly included.
    Some members of the public commented that finalizing a GHG 
adjustment would inappropriately

[[Page 64637]]

increase sources' financial burdens. The EPA has explained, both in the 
proposal notice and elsewhere in this preamble, the importance of the 
fee-related revisions to account for the costs associated with GHG-
related permitting. The EPA believes that the revisions being finalized 
will result in modest and reasonable fee increases necessary to cover 
states' increased costs.\563\ To the extent that commenters intended to 
argue that the adjustments we proposed would exceed the actual costs of 
GHG permitting, no commenters provided any information or analysis to 
support that position. Some commenters did state that the costs 
associated with GHG-related permitting should be minimal because few 
applicable requirements will apply to GHGs. As stated earlier in this 
notice, the EPA's cost estimate for the proposal concerned the 
incremental costs of GHG permitting for any source, not just those that 
would have, at the time of the analysis, triggered the requirement to 
get a permit based on GHG emissions or applicable requirements.
---------------------------------------------------------------------------

    \563\ The EPA estimated in the proposal that option 1 would 
result in about a 7 percent overall increase in the annual part 70 
fees that are collected by all permitting authorities nationally. 
See 79 FR 1494.
---------------------------------------------------------------------------

    Despite some comments received to the contrary, the EPA does not 
believe it is appropriate to delay the finalization of the GHG 
adjustment. The EPA does not believe such delays would be consistent 
with CAA section 502(b)(3)(A) because states have been incurring costs 
attributable to GHG permitting for several years now and increased fees 
must be collected to cover the increased costs. The regulatory changes 
being finalized in this action provide the states with optimal 
flexibility and sufficient funding to implement their GHG permitting 
programs. Some commenters had specifically stated that the EPA should 
delay finalization of this rule until the completion of the next ICR 
renewal process. While we do not believe delaying this rule is 
appropriate, as explained above, the EPA notes that we remain committed 
to collecting and analyzing additional data on costs attributable to 
GHG permitting for operating permit programs. We may adjust the GHG 
cost adjustments in future rulemakings if necessary to comply with the 
requirements of the Act.
    As an alternative to the options proposed by the EPA, some 
commenters asserted that the EPA should make a GHG cost adjustment 
using a separate, but reduced fee rate ($/ton) for GHGs. We, however, 
believe that the option 1 approach of the final rule will be more 
equitable for sources and more representative of actual costs because 
option 1 considers the costs of the actual permitting activities 
performed by a particular permitting authority, while any emissions-
based approach would not be as directly related to actual costs 
incurred by permitting authorities.
    Some commenters alleged that the EPA's proposal on adjustments to 
the operating permit programs was vague. The EPA provided a thorough 
discussion of our rationale in the proposal, including the basis for 
the GHG adjustments, and we proposed regulatory text to implement our 
proposal. We explained in the proposal that support for the cost 
adjustment for GHGs under option 1 is contained in several analyses 
performed by the EPA and approved by the OMB related to the effect of 
the addressing GHG requirements in operating permits. These analyses 
have been placed in the docket for this rulemaking. The analyses 
include: The Regulatory Impact Assessment (RIA) for the Tailoring Rule 
(see Regulatory Impact Analysis for the Final Prevention of Significant 
Deterioration and Title V Greenhouse Gas Tailoring Rule, Final Report, 
May 2010); the part 70 ICR change request for the Tailoring Rule (which 
was based on the RIA for the Tailoring Rule); and the current ICR for 
part 70 (EPA ICR number 1587.12; OMB control number 2060-0243).
    Several commenters asked that we make changes to the option 1 
approach that we proposed, such as adding new activities or decreasing 
the costs we assumed for the proposal. In response to these comments, 
we note that we received no quantitative data or other information from 
commenters that we believe demonstrates the need to revise the list of 
activities we included under option 1 or the burden hour assumptions 
under option 1 for the activities. Note that to promote consistent 
implementation of the final option 1 approach, the preamble describes 
elsewhere a few clarifications concerning the activities under option 1 
and one minor revision to the regulatory text of one of the activities.
    Since the EPA's proposed rulemaking, the Supreme Court decided in 
UARG v. EPA that the 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.\564\ The EPA's review of the effect 
of the Supreme Court decision on the burden hour assumptions for the 
GHG review activities under proposed option 1 is that the effects are 
not significant enough to warrant revision of the burden hour 
assumptions in the final rule. Proposed option 1 was based on the 
assumption that permitting authorities would need to evaluate all 
permit applications for initial permit issuance, significant and minor 
permit modifications, and permit renewals for GHG issues (even if there 
are no applicable GHG requirements). Even after the UARG v. EPA 
decision, permitting authorities will continue to need to evaluate GHG 
issues for sources applying for a title V permit and for permit 
modifications and renewals for existing permits, and we do not 
anticipate that the decision will significantly affect the total number 
of such evaluations that will occur in any given year compared to the 
assumptions in our analysis, which as explained above, were based on 
the incremental costs of GHG permitting for any source. Thus, we are 
finalizing the burden hour assumptions as they were proposed. See NSPS 
proposal at 1494 and the supporting statement for the 2012 part 70 ICR 
renewal. Also, as discussed previously, we remain committed to 
collecting and analyzing additional data on costs and we may adjust the 
burden hour assumptions or other aspects of option 1 in a future 
rulemaking, if needed.
---------------------------------------------------------------------------

    \564\ The EPA does not, however, read the UARG decision to 
affect other grounds on which a Title V permit may be required or 
the applicable requirements that must be addressed in Title V 
permits. See Memorandum from Janet G. McCabe, Acting Assistant 
Administrator, Office of Air and Radiation, and Cynthia Giles, 
Assistant Administrator, Office of Enforcement and Compliance 
Assurance, to Regional Administrators, Regions 1-10, Next Steps and 
Preliminary Views on the Application of Clean Air Act Permitting 
Programs to Greenhouse Gases Following the Supreme Court's Decision 
in Utility Regulatory Group v. Environmental Protection Agency (July 
24, 2014) at 5.
---------------------------------------------------------------------------

c. The Fee Pollutant Clarification
    We are also finalizing the proposed 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). We are 
finalizing these provisions 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 section 111 for the 
first time. The proposal was to add this clarifying text to 40 CFR part 
60, subparts Da, KKKK, and TTTT. The final rule adds the clarification 
text only to subpart TTTT because the EPA is

[[Page 64638]]

codifying all of the requirements for the affected EGUs in a new 
subpart TTTT and including all CO2 emission standards for 
the affected EGUs (electric utility steam generating units, as well as 
natural gas-fired stationary combustion turbines) in that newly created 
subpart. See Section III.B of this preamble for more on this subject.
d. The GHG Clarification
    The EPA is taking no action at this time on the proposal to move 
the definitions of ``Greenhouse gases (GHG)'' within the definition of 
``Subject to regulation'' in 40 CFR parts 70 and 71. No public comments 
were received on this proposed clarification; however, subsequent to 
the proposal, on June 23, 2014, the Supreme Court in UARG v. EPA 
decided that GHG emissions could not be used in making certain 
applicability determinations under the operating permit rules. More 
specifically with respect to title V, as described above, the Supreme 
Court said that the 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 the Supreme Court 
decision, on April 10, 2015, the D.C. Circuit 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), which, among other things, 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.
    In response to the Supreme Court decision and the D.C. Circuit's 
amended judgment, the EPA intends to conduct future rulemaking action 
to make the appropriate revisions to the operating permit rules. As 
part of any such future rulemaking action, the EPA may consider 
finalizing the proposal to move the definitions of GHGs within the 
operating permit rules.

F. Interactions With Other EPA Rules

    Fossil fuel-fired EGUs are, or potentially will be, impacted by 
several other recently finalized or proposed EPA rules.\565\ Many of 
the rules that impact fossil fuel-fired EGUs apply to existing 
facilities as well as newly constructed, modified, or reconstructed 
facilities. In fact, the rules described below are more applicable to 
existing EGUs than to newly constructed, modified, or reconstructed 
EGUs. Although those rules will affect EGUs as existing sources, 
because we expect that there will be few NSPS modifications or 
reconstructions, we don't anticipate those rules affecting EGUs as 
modified or reconstructed sources. In constructing new EGUs, sources 
can take all applicable requirements of the various rules into 
consideration.
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    \565\ 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.
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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 (Hg), arsenic (As), chromium (Cr), and nickel 
(Ni); and acid gases, including hydrochloric acid (HCl) and 
hydrofluoric acid (HF). 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.\566\
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    \566\ 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). The decision was unanimous on 
all issues except a dissent was filed because the EPA did not 
consider cost when determining regulation of EGUs is appropriate. In 
Michigan v. EPA, case no. 14-46, the Supreme Court reversed the D.C. 
Circuit decision upholding the MATS rule finding that EPA erred by 
not considering cost when determining that regulation of EGUs was 
``appropriate'' pursuant to section 112(n)(1). The Supreme Court 
considered only the narrow question of cost and did not review the 
other holdings of the D.C. Circuit, nor did the Supreme Court vacate 
the MATS rule.
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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 (33 U.S. Code section 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.\567\ 
The 316(b)

[[Page 64639]]

rule subjects existing power plants and manufacturing facilities that 
withdraw in excess of 2 million gallons per day (MGD) 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 entrainment. 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. Additional information regarding the 316(b) rule 
for existing sources is included in Section IX.C of the preamble to the 
CAA section 111(d) emission guidelines for existing EGUs that the EPA 
is finalizing simultaneously with this rule. Although the recently 
issued 316(b) rule discussed here applies to existing sources, there 
are also 316(b) technology-based standards for new sources with cooling 
water intake structures.
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    \567\ 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 establishes technical 
requirements for existing and new CCR landfills and surface 
impoundments under Subtitle D of the Resource Conservation and Recovery 
Act (RCRA), the nation's primary law for regulating solid waste. New 
CCR landfills and surface impoundments are required to meet the 
technical criteria before any CCR is placed into the unit. Existing CCR 
surface impoundments and landfills are subject to implementation 
timeframes established in the rule for the individual technical 
criteria. For additional information regarding the CCR rule, see 
Section IX.C of the preamble to the CAA section 111(d) emission 
guidelines for existing EGUs that the EPA is finalizing along with this 
rule.
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 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 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. Section IX.C of the preamble to the CAA section 
111(d) emission guidelines for existing EGUs that the EPA is finalizing 
simultaneously with this rule includes additional information regarding 
the SE ELG rule.
    The EPA recognizes the importance of assuring that each of the 
rules described above 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 (E.O.) 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.'' E.O. 13563 further states that ``[e]ach 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.
    As discussed in earlier sections of this preamble, the EPA has 
identified potential alternative compliance pathways for affected newly 
constructed, modified, and reconstructed fossil fuel-fired steam 
generating units. We are finalizing an emission standard for newly 
constructed highly efficient fossil fuel-fired steam generating units 
that can be met by capturing and storing approximately 16 to 23 percent 
of the CO2 produced from the facility or by utilizing other 
technologies such as natural gas co-firing. For a subcategory of steam 
generating units that conduct ``large'' modifications according to 
definitions in this final rule, we are finalizing an emission standard 
that is based on a unit-specific emission limitation consistent with 
each modified unit's best one-year historical performance and can be 
met through a combination of best operating practices and equipment 
upgrades. For reconstructed steam generating units, the EPA is 
finalizing standards of performance based on the performance of the 
most efficient generation technology available, which we concluded is 
the use of the best available subcritical steam conditions for small 
units and the use of supercritical steam conditions for large units. 
The standards can also be met through other technology options such as 
natural gas co-firing. In light of these potential alternative 
compliance pathways, we believe that sources will have ample 
opportunity to coordinate their response to this rule with 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--and to do so in a manner that will help reduce 
cost and ensure reliability, while also ensuring that all applicable 
environmental requirements are met.\568\
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    \568\ 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.
---------------------------------------------------------------------------

    The EPA is also 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. Section IX.C of 
the preamble to the CAA section 111(d) emission guidelines for existing 
EGUs that the EPA is finalizing simultaneously with this rule describes 
such an example with respect to the SE ELG and CCR rules.
    In light of the compliance flexibilities we are offering in this 
action, we believe that sources will have ample opportunity to use 
cost-effective regulatory strategies and 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.

[[Page 64640]]

XIII. Impacts of This Action

    As explained in the ``Regulatory Impact Analysis for the Standards 
of Performance for Greenhouse Gas Emissions for New, Modified, and 
Reconstructed Stationary Sources: Electric Utility Generating Units'' 
(EPA-452/R-15-005, August 2015) (RIA), available data indicate that, 
even in the absence of the standards of performance for newly 
constructed EGUs, existing and anticipated economic conditions will 
lead electricity generators to choose new generation technologies that 
will meet the standards without installation of additional controls. 
Therefore, based on the analysis presented in Chapter 4 of the RIA, the 
EPA projects that this final rule will result in negligible 
CO2 emission changes, quantified benefits, and costs on 
owners and operators of newly constructed EGUs by 2022.\569\ This 
conclusion is based on the EPA's own modeling as well as projections by 
EIA. While the primary conclusion of the analysis presented in the RIA 
is that the standards for newly constructed EGUs will result in 
negligible costs and benefits, the EPA has also performed several 
illustrative analyses that show the potential impacts of the rule if 
certain key assumptions were to change. This includes an analysis of 
the impacts under a range of natural gas prices and the costs and 
benefits associated with building an illustrative coal-fired EGU with 
CCS. These are presented in Chapter 5 of the RIA.
---------------------------------------------------------------------------

    \569\ Conditions in the analysis year of 2022 are represented by 
a model year of 2020.
---------------------------------------------------------------------------

    As also explained in the RIA for this final rule, the EPA also 
expects that few sources will trigger either the NSPS modification or 
reconstruction provisions that we are finalizing in this rule. In 
Chapter 6 of the RIA, we discuss factors that limit our ability to 
quantify the costs and benefits of the standards for modified and 
reconstructed sources.

A. What are the air impacts?

    As explained immediately above, the EPA does not anticipate that 
this final rule will result in notable CO2 emission changes 
by 2022 as a result of the standards of performance for newly 
constructed EGUs. The owners of newly constructed EGUs will likely 
choose technologies, primarily NGCC, which meet the standards even in 
the absence of this rule due to existing economic conditions as normal 
business practice.
    As also explained immediately above, the EPA expects few EGUs to 
trigger the NSPS modification or reconstruction provisions in the 
period of analysis.
    New steam generating EGUs that choose to comply with the final 
standard of performance by implementing partial post-combustion CCS are 
likely to use commercially-available amine-based capture systems. Some 
concern has been raised regarding emissions of amines and amine 
degradation by-products (e.g., NH3) from the capture 
process. To reduce the amine emissions, MHI introduced the first 
optimized washing system within an absorber column in 1994, and 
developed a proprietary washing system in 2003. In that system, a 
proprietary reagent is added to the water washing section to capture 
amine impurities such as amine, degraded amine, ammonia, formaldehyde, 
acetaldehyde, carbonic acids and nitrosamines.\570\ MHI has continued 
to improve this technology for further reduction of amine emissions and 
established an ``advanced amine emission reduction system''.
---------------------------------------------------------------------------

    \570\ Sharma, S.; Azzi, M.; ``A critical review of existing 
strategies for emission control in the monoethanolamine-based carbon 
capture process and some recommendations for improved strategies'', 
Fuel, 121, 178 (2014).
---------------------------------------------------------------------------

    Research performed by MHI at Alabama Power's Plant Barry indicated 
that an increasing SO3 content in the flue gas caused a 
significant increase of amine emissions. During testing, at Plant 
Barry, MHI applied its proprietary washing system and confirmed that 
the amine emission were drastically reduced.\571\ Others have also 
studied emissions and control strategies and have determined that a 
conventional multi-stage water wash and mist eliminator at the exit of 
the CO2 scrubber is effective at removal of gaseous amine 
and amine degradation products emissions.572 573 Additional 
research continues in this area.
---------------------------------------------------------------------------

    \571\ Kamijo, T.; et al., ``SO3 Impact on Amine 
Emission and Emission Reduction Technology'', Energy Procedia, 
Volume 37, 1793 (2013).
    \572\ Sharma, S. (2014).
    \573\ Mertens, J.; et al., ``Understanding ethanolamine (MEA) 
and ammonia emissions from amine based post combustion carbon 
capture: Lessons learned from field tests'', Int'l J. of GHG 
Control, 13, 72 (2013).
---------------------------------------------------------------------------

B. Endangered Species Act

    Consistent with the requirements of section 7(a)(2) of the 
Endangered Species Act (ESA), the EPA has also considered the effects 
of this rule and has reviewed applicable ESA regulations, case law, and 
guidance to determine what, if any, impact there may be to listed 
endangered or threatened species or the designated critical habitat of 
such species and 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. Section 7(a)(2) of the ESA requires 
federal agencies, in consultation with the Service(s), 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, ESA 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.\574\ 
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.
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    \574\ 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).
---------------------------------------------------------------------------

    The EPA notes that the projected environmental effects of this 
final action are positive: Reductions in overall GHG emissions, and 
reductions in PM and ozone-precursor emissions (SOX 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

[[Page 64641]]

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 notes that the emission reductions achieved by the rule are 
projected to be minor. See Section XIII.F and G. below, and RIA chapter 
4. Although the final rule imposes substantial controls on 
CO2 emissions, we project few if any new fossil fuel-fired 
steam generating units to be built. Emissions reductions from turbines 
are likewise projected to be minimal. Moreover, we reasonably project 
that capacity additions during the analysis period out to 2022 would 
already be compliant with the rule's requirements (e.g., natural gas 
combined cycle units, low capacity factor natural gas combustion 
turbines, and small amounts of coal-fired units with CCS supported by 
federal and state funding). See RIA chapter 4.
    With respect to the projected GHG emission reductions, the EPA does 
not believe that such minor reductions trigger ESA consultation 
requirements under section 7(a)(2). In reaching this conclusion, the 
EPA is 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.\575\ 
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.
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    \575\ 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).
---------------------------------------------------------------------------

    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. The EPA evaluated 
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 GHG emission reductions many orders of magnitude greater over 
the lifetimes of the model years in question \576\ 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.'' EPA, 
Light Duty Vehicle Greenhouse Gas Standards and Corporate Average Fuel 
Economy Standards, Response to Comment Document for Joint Rulemaking at 
4-102 (Docket EPA-OAR-HQ-2009-4782). 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 
conclusions apply to the present action, given that the projected 
CO2 emission reductions are far less than those projected 
for either of the light duty vehicle rules. 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 context of federal actions 
involving GHG emissions.\577\
---------------------------------------------------------------------------

    \576\ See 75 FR at 25438 Table I.C 2-4 (May 7, 2010); 77 FR at 
62894 Table III-68 (Oct. 15, 2012).
    \577\ The EPA has received correspondence from Members of 
Congress asserting that the Services have identified several listed 
species affected by global climate change. The 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, the 
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 the EPA.
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    The EPA received a comment on the proposal referencing a prior 
letter sent to the EPA by three U.S. Senators,\578\ which asserted that 
the rule will cause a shift to alternative sources of energy such as 
wind and solar and that such facilities may have impacts on listed 
species. The comment inquired regarding ESA consultation in connection 
with the rule. We reiterate that no consultation is required for a rule 
without potential for a specific impact on listed species in their 
habitats.
---------------------------------------------------------------------------

    \578\ See Letter from David Vitter, James M. Inhofe, and Mike 
Crapo, United States Senate Committee on Environment and Public 
Works, to Gina McCarthy, Administrator, U.S. Environmental 
Protection Agency, and Dan Ashe, Director, U.S. Fish and Wildlife 
Service, dated March 6, 2014.
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C. What are the energy impacts?

    This final rule is not anticipated to have a notable effect on the 
supply, distribution, or use of energy. As previously stated, the EPA 
believes that electric power companies will choose to build new EGUs 
that comply with the regulatory requirements of this rule even in its 
absence, primarily NGCC units, because of existing and expected market 
conditions. As also previously stated, the EPA expects few EGUs to 
trigger the NSPS modification or reconstruction provisions in the 
period of analysis.

D. What are the water and solid waste impacts?

    This final rule is not anticipated to have notable impacts on water 
or solid waste. As we have noted, the EPA believes that utilities and 
project developers will choose to build new EGUs that comply with the 
regulatory requirements of this rule even in its absence, primarily 
through the construction of new NGCC units. As also previously stated, 
the EPA expects few EGUs to trigger the NSPS modification or 
reconstruction provisions in the period of analysis. Still there are 
expected to be a small number of coal plants with CCS and the use of 
CCS systems (especially post-combustion system) will increase the 
amount of water used at the facility. If those plants utilize partial 
CCS to meet the final standard of performance (i.e., approximately 16 
to 23 percent capture), the increased water use will not be 
significant. See Section V.O.2. The EPA is unaware of any solid waste 
impact resulting from this rule.\579\
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    \579\ Estimated costs for the rule include costs for fly ash and 
bottom ash disposal and for spent solvent recovery and handling. See 
``Cost and Performance Baseline for Fossil Energy Plants Volume 1a: 
Bituminous Coal (PC) and Natural Gas to Electricity, Revision 3'', 
DOE/NETL-2015/1723 (July 2015) at pp. 43, 130.
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E. What are the compliance costs?

    For steam generating EGUs, the EPA has carefully analyzed the costs 
of meeting the promulgated standard of performance for a highly 
efficient SCPC

[[Page 64642]]

using partial CCS and found these costs to be reasonable. See Sections 
V.H and I above. This analysis assumes new capacity not otherwise 
compliant with the standards would be constructed. Based on the 
analysis in chapter 4 of the RIA, the EPA believes the standards of 
performance for newly constructed EGUs will have no notable compliance 
costs, because electric power companies are expected to build new EGUs 
that comply with the regulatory requirements of this final rule even in 
the absence of the rule, primarily NGCC units, due to existing and 
expected market conditions. While the EPA's analysis and projections 
from EIA continue to show that the rule is likely to result in 
negligible costs and benefits due to existing generation choices, the 
EPA recognizes that some companies may choose to construct coal or 
other fossil fuel-fired units and has set standards for these units 
accordingly. For this reason, the RIA also analyzes project-level costs 
of a unit with and without CCS, to quantify the potential cost for a 
fossil fuel-fired unit with CCS.
    In addition, the EPA believes the standards of performance for 
modified and reconstructed EGUs will have minimal associated compliance 
costs, because, as previously stated, the EPA expects few EGUs to 
trigger the NSPS modification or reconstruction provisions in the 
period of analysis.

F. What are the economic and employment impacts?

    The EPA does not anticipate that this final rule will result in 
notable CO2 emission changes, energy impacts, monetized 
benefits, costs, or economic impacts by 2022 as a result of the 
standards of performance for newly constructed EGUs. The owners of 
newly constructed EGUs will likely choose technologies that meet the 
standards even in the absence of this rule, due to existing economic 
conditions as normal business practice. Likewise, the EPA believes this 
rule will not have any impacts on the price of electricity, employment 
or labor markets, or the U.S. economy. See RIA chapter 4.6.\580\
---------------------------------------------------------------------------

    \580\ The employment analysis in the RIA is part of the EPA's 
ongoing effort to ``conduct continuing evaluations of potential loss 
or shifts of employment which may result from the administration or 
enforcement of [the Act]'' pursuant to CAA section 321(a).
---------------------------------------------------------------------------

    As previously stated, the EPA anticipates few units will trigger 
the NSPS modification or reconstruction provisions. As with the new 
source standards, the EPA does not expect macroeconomic or employment 
impacts as a result of the standards.

G. What are the benefits of the final standards?

    We are not projecting direct monetized climate benefits in terms of 
CO2 emission reductions associated with these standards of 
performance. This is because, as stated above, the EPA believes that 
electric power companies will choose to build new EGUs that comply with 
the regulatory requirements of this rule even in its absence, primarily 
NGCC units, because of existing and expected market conditions. See RIA 
chapter 4. Moreover, a cost-reasonable standard is, in fact, what will 
drive new technology deployment and provide a path forward for new 
coal-fired capacity. See Section V.L above.
    As also previously stated, the EPA anticipates few units will 
trigger the NSPS modification or reconstruction provisions. In Chapter 
6 of the RIA, we discuss factors that limit our ability to quantify the 
costs and benefits of the standards for modified and reconstructed 
sources.

XIV. 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 a significant regulatory action that was 
submitted to the Office of Management and Budget (OMB) for review. It 
is a significant regulatory action because it raises novel legal or 
policy issues arising out of legal mandates. Any changes made in 
response to OMB recommendations have been documented in the established 
dockets for this action under Docket ID No. EPA-HQ-OAR-2013-0495 
(Standards of Performance for Greenhouse Gas Emissions from New 
Stationary Sources: Electric Utility Generating Units) and Docket ID 
No. EPA-HQ-OAR-2013-0603 (Carbon Pollution Standards for Modified and 
Reconstructed Stationary Sources: Electric Utility Generating Units). 
The EPA prepared an economic analysis of the potential costs and 
benefits associated with this action. This analysis, which is contained 
in the ``Regulatory Impact Analysis for the Standards of Performance 
for Greenhouse Gas Emissions for New, Modified, and Reconstructed 
Stationary Sources: Electric Utility Generating Units'' (EPA-452/R-15-
005, August 2015), is available in both dockets.
    The EPA does not anticipate that this final action will result in 
any notable compliance costs. Specifically, we believe that the 
standards for newly constructed fossil fuel-fired EGUs (electric 
utility steam generating units and natural gas-fired stationary 
combustion turbines) will have negligible costs associated with it over 
a range of likely sensitivity conditions because electric power 
companies will choose to build new EGUs that comply with the regulatory 
requirements of this action even in the absence of the action, because 
of existing and expected market conditions. (See the RIA for further 
discussion of sensitivities). The EPA does not project any new coal-
fired steam generating units without CCS to be built in the absence of 
this action. However, because some companies may choose to construct 
coal or other fossil fuel-fired EGUs, the RIA also analyzes project-
level costs of a unit with and without CCS, to quantify the potential 
cost for a fossil fuel-fired EGU with CCS.
    The EPA also believes that the standards for modified and 
reconstructed fossil fuel-fired EGUs will result in minimal compliance 
costs, because, as previously stated, the EPA expects few EGUs to 
trigger the NSPS modification or reconstruction provisions in the 
period of analysis (through 2022). In Chapter 6 of the RIA, we discuss 
factors that limit our ability to quantify the costs and benefits of 
the standards for modified and reconstructed sources.

B. Paperwork Reduction Act (PRA)

    The information collection activities in this final action have 
been submitted for approval to OMB under the PRA. The Information 
Collection Request (ICR) document that the EPA prepared has been 
assigned EPA ICR number 2465.03. Separate ICR documents were prepared 
and submitted to OMB for the proposed standards for newly constructed 
EGUs (EPA ICR number 2465.02) and the proposed standards for modified 
and reconstructed EGUs (EPA ICR number 2506.01). Because the 
CO2 standards for newly constructed, modified, and 
reconstructed EGUs will be included in the same new subpart (40 CFR 
part 60, subpart TTTT) and are being finalized in the same action, the 
ICR document for this action includes estimates of the information 
collection burden on owners and operators of newly constructed, 
modified, and reconstructed EGUs. Estimated cost burden is based on 
2013 Bureau of Labor Statistics (BLS) labor cost data.

[[Page 64643]]

Thus, all burden estimates are in 2013 dollars. Burden is defined at 5 
CFR 1320.3(b). You can find a copy of the ICR in the dockets for this 
action (Docket ID Numbers EPA-HQ-OAR-2013-0495 and EPA-HQ-OAR-2013-
0603), and it is briefly summarized here. The information collection 
requirements are not enforceable until OMB approves them.
    The recordkeeping and reporting requirements in this final action 
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.
    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 action.
1. Newly Constructed EGUs
    This final action will impose minimal new information collection 
burden on owners and operators of affected newly constructed fossil 
fuel-fired EGUs (steam generating units and stationary combustion 
turbines) beyond what those sources would already be subject to under 
the authorities of CAA parts 75 and 98. OMB has previously approved the 
information collection requirements contained in the existing part 75 
and 98 regulations (40 CFR part 75 and 40 CFR part 98) under the 
provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. and 
has assigned OMB control numbers 2060-0626 and 2060-0629, respectively. 
Apart from certain reporting costs to comply with the emission 
standards under the rule, there are no new information collection 
costs, as the information required by the standards for newly 
constructed EGUs is already collected and reported by other regulatory 
programs.
    The EPA believes that electric power companies will choose to build 
new EGUs that comply with the regulatory requirements of the rule 
because of existing and expected market conditions. The EPA does not 
project any newly constructed coal-fired steam generating units that 
commenced construction after proposal (January 8, 2014) to commence 
operation over the 3-year period covered by this ICR. We estimate that 
12 affected newly constructed NGCC units and 25 affected newly 
constructed natural gas-fired simple cycle combustion turbines will 
commence operation during that time period. As a result of this final 
action, owners or operators of those newly constructed units will be 
required to prepare a summary report, which includes reporting of 
emissions and downtime, every 3 months.
2. Modified and Reconstructed EGUs
    This final action is not expected to impose an information 
collection burden under the provisions of the PRA on owners and 
operators of affected modified and reconstructed fossil fuel-fired EGUs 
(steam generating units and stationary combustion turbines). As 
previously stated, the EPA expects few EGUs to trigger the NSPS 
modification or reconstruction provisions in the period of analysis. 
Specifically, the EPA believes it unlikely that fossil fuel-fired 
electric utility steam generating units or stationary combustion 
turbines will take actions that would constitute modifications or 
reconstructions as defined under the EPA's NSPS regulations. 
Accordingly, the standards for modified and reconstructed EGUs are not 
anticipated to impose any information collection burden over the 3-year 
period covered by this ICR. We have estimated, however, the information 
collection burden that would be imposed on an affected EGU if it was 
modified or reconstructed.
    Although not anticipated, if an EGU were to modify or reconstruct, 
this final action would impose minimal information collection burden on 
those affected EGUs beyond what they would already be subject to under 
the authorities of CAA 40 CFR parts 75 and 98. As described above, the 
OMB has previously approved the information collection requirements 
contained in the existing part 75 and 98 regulations. Apart from 
certain reporting costs to comply with the emission standards under the 
rule, there would be no new information collection costs, as the 
information required by the final rule is already collected and 
reported by other regulatory programs.
    As stated above, although the EPA expects few sources will trigger 
either the NSPS modification or reconstruction provisions, if an EGU 
were to modify or reconstruct during the 3-year period covered by this 
ICR, the owner or operator of the EGU will be required to prepare a 
summary report, which includes reporting of emissions and downtime, 
every 3 months. The annual reporting burden for such a unit is 
estimated to be $1,333 and 16 labor hours. There are no annualized 
capital costs or O&M costs associated with burden for modified or 
reconstructed EGUs.
3. Information Collection Burden
    The annual information collection burden for newly constructed, 
modified, and reconstructed EGUs consists only of reporting burden as 
explained above. The annual reporting burden for this collection 
(averaged over the first 3 years after the effective date of the 
standards) is estimated to be $60,977 and 651 labor hours. There are no 
annualized capital costs or O&M costs associated with burden for newly 
constructed, modified, or reconstructed EGUs. Average burden hours per 
response are estimated to be 7 hours. The total number of respondents 
over the 3-year ICR period is estimated to be 62.

C. Regulatory Flexibility Act (RFA)

    I certify that this final action will not have a significant 
economic impact on a substantial number of small entities under the 
RFA. In making this determination, the impact of concern is any 
significant adverse economic impact on small entities. An agency may 
certify that a rule will not have a significant economic impact on a 
substantial number of small entities if the rule relieves regulatory 
burden, has no net burden or otherwise has a positive economic effect 
on the small entities subject to the rule.
1. Newly Constructed EGUs
    The EPA believes that electric power companies will choose to build 
new fossil fuel-fired electric utility steam generating units or 
natural gas-fired stationary combustion turbines that comply with the 
regulatory requirements of the final rule because of existing and 
expected market conditions. RIA Chapter 4. The EPA does not project any 
new coal-fired steam generating units without CCS to be built. We 
expect that any newly constructed natural gas-fired stationary 
combustion turbines will meet the standards. We do not include an 
analysis of the illustrative impacts on small entities that may result 
from implementation of the final rule because we anticipate negligible 
compliance costs over a range of likely sensitivity conditions as a 
result of the standards for newly constructed EGUs. Thus the cost-to-
sales ratios for any affected small entity would be zero costs as 
compared to annual sales revenue for the entity. Accordingly, there are 
no anticipated

[[Page 64644]]

economic impacts as a result of the standards for newly constructed 
EGUs. (See the ``Regulatory Impact Analysis for the Standards of 
Performance for Greenhouse Gas Emissions for New, Modified, and 
Reconstructed Stationary Sources: Electric Utility Generating Units'' 
(EPA-452/R-15-005, August 2015) for further discussion of 
sensitivities.) We have therefore concluded that this final action will 
have no net regulatory burden for all directly regulated small 
entities.
2. Modified and Reconstructed EGUs
    The EPA expects few fossil fuel-fired electric utility steam 
generating units to trigger the NSPS modification provisions in the 
period of analysis. An NSPS modification is defined as a physical or 
operational change that increases the source's maximum achievable 
hourly rate of emissions. The EPA does not believe that there are 
likely to be EGUs that will take actions that would constitute 
modifications as defined under the EPA's NSPS regulations.
    In addition, the EPA expects few reconstructed fossil fuel-fired 
electric utility steam generating units or natural gas-fired stationary 
combustion turbines in the period of analysis. Reconstruction occurs 
when a single project replaces components or equipment in an existing 
facility and exceeds 50 percent of the fixed capital cost that would be 
required to construct a comparable entirely new facility.
    In Chapter 6 of the RIA, we discuss factors that limit our ability 
to quantify the costs and benefits of the standards for modified and 
reconstructed sources. However, we do not anticipate that the rule 
would impose significant costs on those sources, including any that are 
owned by small entities. (See the ``Regulatory Impact Analysis for the 
Standards of Performance for Greenhouse Gas Emissions for New, 
Modified, and Reconstructed Stationary Sources: Electric Utility 
Generating Units'' (EPA-452/R-15-005, August 2015).

D. Unfunded Mandates Reform Act (UMRA)

    This final 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 EPA believes the final rule will have negligible compliance 
costs on owners and operators of newly constructed EGUs over a range of 
likely sensitivity conditions because electric power companies will 
choose to build new fossil fuel-fired electric utility steam generating 
units or natural gas-fired stationary combustion turbines that comply 
with the regulatory requirements of the rule because of existing and 
expected market conditions. The EPA does not project any new coal-fired 
steam generating units without CCS to be built and expects that any 
newly constructed natural gas-fired stationary combustion turbines will 
meet the standards. (See the ``Regulatory Impact Analysis for the 
Standards of Performance for Greenhouse Gas Emissions for New, 
Modified, and Reconstructed Stationary Sources: Electric Utility 
Generating Units'' (EPA-452/R-15-005, August 2015) for further 
discussion of sensitivities.)
    As previously stated, the EPA expects few fossil fuel-fired 
electric utility steam generating units or natural gas-fired stationary 
combustion turbines to trigger the NSPS modification or reconstruction 
provisions in the period of analysis. In Chapter 6 of the RIA, we 
discuss factors that limit our ability to quantify the costs and 
benefits of the standards for modified and reconstructed sources. 
However, we do not anticipate that the rule would impose significant 
costs on those sources. (See the ``Regulatory Impact Analysis for the 
Standards of Performance for Greenhouse Gas Emissions for New, 
Modified, and Reconstructed Stationary Sources: Electric Utility 
Generating Units'' (EPA-452/R-15-005, August 2015).)
    We have therefore concluded that the standards for newly 
constructed, modified, and reconstructed EGUs do not impose enforceable 
duties on any state, local or tribal governments, or the private 
sector, that may result in expenditures by state, local and tribal 
governments, in the aggregate, or to the private sector, of $100 
million or more in any one year. We have also concluded that this 
action does not have regulatory requirements that might significantly 
or uniquely affect small governments. The threshold amount established 
for determining whether regulatory requirements could significantly 
affect small governments is $100 million annually and, as stated above, 
we have concluded that the final action will not result in expenditures 
of $100 million or more in any one year. Specifically, the EPA does not 
project any new coal-fired steam generating units without CCS to be 
built and expects that any newly constructed natural gas-fired 
stationary combustion turbines will meet the standards. Further, the 
EPA expects few fossil fuel-fired electric utility steam generating 
units or natural gas-fired stationary combustion turbines to trigger 
the NSPS modification or reconstruction provisions in the period of 
analysis.

E. Executive Order 13132: Federalism

    This final action does not have federalism implications. It will 
not have substantial direct effects on the states, on the relationship 
between the national government and the states, or on the distribution 
of power and responsibilities among the various levels of government. 
The EPA believes that electric power companies will choose to build new 
fossil fuel-fired electric utility steam generating units or natural 
gas-fired stationary combustion turbines that comply with the 
regulatory requirements of the final rule because of existing and 
expected market conditions. In addition, as previously stated, the EPA 
expects few fossil fuel-fired electric utility steam generating units 
or natural gas-fired stationary combustion turbines to trigger the NSPS 
modification or reconstruction provisions in the period of analysis. 
We, therefore, anticipate that the final rule will impose minimal 
compliance costs.

F. Executive Order 13175: Consultation and Coordination With Indian 
Tribal Governments

    This final action does not have tribal implications as specified in 
Executive Order 13175. The final rule will impose requirements on 
owners and operators of newly constructed, modified, and reconstructed 
EGUs. The EPA is aware of three facilities with coal-fired steam 
generating units, as well as one facility with natural gas-fired 
stationary combustion turbines, located in Indian Country, but is not 
aware of any EGUs owned or operated by tribal entities. We note that 
because the rule addresses CO2 emissions from newly 
constructed, modified, and reconstructed EGUs, it will affect existing 
EGUs such as those located at the four facilities in Indian Country 
only if those EGUs were to take actions constituting modifications or 
reconstructions as defined under the EPA's NSPS regulations. As 
previously stated, the EPA expects few EGUs to trigger the NSPS 
modification or reconstruction provisions in the period of analysis. 
Thus, the rule will neither impose substantial direct compliance costs 
on tribal governments nor preempt Tribal law. Accordingly, Executive 
Order 13175 does not apply to this action.
    Nevertheless, because the EPA is aware of Tribal interest in carbon 
pollution standards for the power sector and, consistent with the EPA 
Policy on Consultation and Coordination with Indian Tribes, the EPA 
offered consultation with tribal officials during

[[Page 64645]]

development of this rule. Prior to the April 13, 2012 proposal (77 FR 
22392), the EPA sent consultation letters to the leaders of all 
federally recognized tribes. Although only newly constructed, modified, 
and reconstructed EGUs will be affected by this action, the EPA's 
consultation regarded planned actions for new and existing sources. The 
letters provided information regarding the EPA's development of NSPS 
and emission guidelines for EGUs and offered consultation. A 
consultation/outreach meeting was held on May 23, 2011, with the Forest 
County Potawatomi Community, the Fond du Lac Band of Lake Superior 
Chippewa Reservation, and the Leech Lake Band of Ojibwe. A description 
of that consultation is included in the preamble to the proposed 
standards for new EGUs (79 FR 1501, January 8, 2014).
    The EPA also offered consultation to the leaders of all federally 
recognized tribes after the proposed action for newly constructed EGUs 
was signed on September, 20, 2013. On November 1, 2013, the EPA sent 
letters to tribal leaders that provided information regarding the EPA's 
development of carbon pollution standards for new, modified, 
reconstructed and existing EGUs and offered consultation. No tribes 
requested consultation regarding the standards for newly constructed 
EGUs.
    In addition to offering consultation, the EPA also conducted 
outreach to tribes during development of this rule. The EPA held a 
series of listening sessions prior to proposal of GHG standards for 
newly constructed EGUs. Tribes participated in a session on February 
17, 2011, with the state agencies, as well as in a separate session 
with tribes on April 20, 2011. The EPA also held a series of listening 
sessions prior to proposal of GHG standards for modified and 
reconstructed EGUs and GHG emission guidelines for existing EGUs. 
Tribes participated in a session on September 9, 2013, together with 
the state agencies, as well as in a separate tribe-only session on 
September 26, 2013. In addition, an outreach meeting was held on 
September 9, 2013, with tribal representatives from some of the 
federally recognized tribes. The EPA also met with tribal environmental 
staff with the National Tribal Air Association, by teleconference, on 
July 25, 2013, and December 19, 2013. Additional detail regarding this 
stakeholder outreach is included in the preamble to the proposed 
emission guidelines for existing EGUs (79 FR 34830, June 18, 2014).

G. Executive Order 13045: Protection of Children From Environmental 
Health Risks and Safety Risks

    This action is not subject to Executive Order 13045 because it is 
not economically significant as defined in Executive Order 12866. While 
the action is not subject to Executive Order 13045, 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. As stated above, the EPA believes the final rule will have 
negligible effects on owners and operators of newly constructed EGUs 
over a range of likely sensitivity conditions because electric power 
companies will choose to build new fossil fuel-fired electric utility 
steam generating units or natural gas-fired stationary combustion 
turbines that comply with the regulatory requirements of the rule 
because of existing and expected market conditions. However, the RIA 
also analyzes project-level costs of a unit with and without CCS, to 
quantify the potential cost for a fossil fuel-fired unit with CCS. RIA 
chapter 5. Under these scenarios, the rule would result in substantial 
reductions of both CO2, and also fine particulate matter 
(sulfate PM 2.5) such that net quantifiable benefits exceed regulatory 
costs under a range of assumptions. Under these same scenarios, this 
rule would have a positive effect for 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.

H. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use

    This final action is not a ``significant energy action'' because it 
is not likely to have a significant adverse effect on the supply, 
distribution, or use of energy. See Section V.O.3 above. The EPA 
believes that electric power companies will choose to build new fossil 
fuel-fired electric utility steam generating units or natural gas-fired 
stationary combustion turbines that comply with the regulatory 
requirements of the final rule because of existing and expected market 
conditions. In addition, as previously stated, the EPA expects few 
fossil fuel-fired electric utility steam generating units or natural 
gas-fired stationary combustion turbines to trigger the NSPS 
modification or reconstruction provisions in the period of analysis. 
Thus, this action is not anticipated to have notable impacts on 
emissions, costs or energy supply decisions for the affected electric 
utility industry.

I. National Technology Transfer and Advancement Act (NTTAA) and 1 CFR 
Part 51

    This final action involves technical standards. The EPA has decided 
to use 10 voluntary consensus standards (VCS) in the final rule.
    One VCS, American National Standards Institute (ANSI) Standard 
C12.20, ``American National Standard for Electricity Meters--0.2 and 
0.5 Accuracy Classes,'' is cited in the final rule to assure consistent 
monitoring of electric output. This standard establishes the physical 
aspects and acceptable performance criteria for 0.2 and 0.5 accuracy 
class electricity meters. This standard is available at http://www.ansi.org or by mail at American National Standards Institute 
(ANSI), 25 W. 43rd Street, 4th Floor, New York, NY 10036.
    Six VCS, ASTM Methods D388-99, ``Standard Classification of Coals 
by Rank''; D396-98, ``Standard Specification for Fuel Oils''; D975-08a, 
``Standard Specification for Diesel Fuel Oils''; D3699-08, ``Standard 
Specification for Kerosine''; D6751-11b,

[[Page 64646]]

``Standard Specification for Biodiesel Fuel Blend Stock (B100) for 
Middle Distillate Fuels''; and D7467-10, ``Standard Specification for 
Diesel Fuel Oil, Biodiesel Blend (B6 to B20)'' are cited in the final 
rule to identify the different fuel types. ASTM D388 covers the 
classification of coals by rank, that is, according to their degree of 
metamorphism, or progressive alteration, in the natural series from 
lignite to anthracite. ASTM D396 covers grades of fuel oil intended for 
use in various types of fuel-oil-burning equipment under various 
climatic and operating conditions. These include Grades 1 and 2 (for 
use in domestic and small industrial burners), Grade 4 (heavy 
distillate fuels or distillate/residual fuel blends used in commercial/
industrial burners equipped for this viscosity range), and Grades 5 and 
6 (residual fuels of increasing viscosity and boiling range, used in 
industrial burners). ASTM D975 covers seven grades of diesel fuel oils 
based on grade, sulfur content, and volatility. These grades range from 
Grade No. 1-D S15 (a special-purpose, light middle distillate fuel for 
use in diesel engine applications requiring a fuel with 15 ppm sulfur 
(maximum) and higher volatility than that provided by Grade No. 2-D S15 
fuel) to Grade No. 4-D (a heavy distillate fuel, or a blend of 
distillate and residual oil, for use in low- and medium-speed diesel 
engines in applications involving predominantly constant speed and 
load). ASTM D3699 covers two grades of kerosene suitable for use in 
critical kerosene burner applications: No. 1-K (a special low-sulfur 
grade kerosene suitable for use in non-flue-connected kerosene burner 
appliances and for use in wick-fed illuminating lamps) and No. 2-K (a 
regular grade kerosene suitable for use in flue-connected burner 
appliances and for use in wick-fed illuminating lamps). ASTM D6751 
covers biodiesel (B100) Grades S15 and S500 for use as a blend 
component with middle distillate fuels. ASTM D7467 covers fuel blend 
grades of 6 to 20 volume percent biodiesel with the remainder being a 
light middle or middle distillate diesel fuel, collectively designated 
as B6 to B20. These standards are available at http://www.astm.org or 
by mail at ASTM International, 100 Barr Harbor Drive, P.O. Box CB700, 
West Conshohocken, PA 19428-2959.
    Two VCS, American Society of Mechanical Engineers (ASME) 
Performance Test Codes PTC 22-2014, ``Performance Test Codes on Gas 
Turbines'' and PTC 46-1996, ``Performance Test Codes on Overall Plant 
Performance'' are cited in the final rule for their guidance on 
measuring the performance of stationary combustion turbines. PTC-22 
provides directions and rules for conduct and report of results of 
thermal performance tests for open cycle simple cycle combustion 
turbines. The object is to determine the thermal performance of the 
combustion turbine when operating at test conditions, and correcting 
these test results to specified reference conditions. PTC 22 provides 
explicit procedures for the determination of the following performance 
results: corrected power, corrected heat rate (efficiency), corrected 
exhaust flow, corrected exhaust energy, and corrected exhaust 
temperature. Tests may be designed to satisfy different goals, 
including absolute performance and comparative performance. The 
objective of PTC 46 is to provide uniform test methods and procedures 
for the determination of the thermal performance and electrical output 
of heat-cycle electric power plants and combined heat and power units 
(PTC 46 is not applicable to simple cycle combustion turbines). Test 
results provide a measure of the performance of a power plant or 
thermal island at a specified cycle configuration, operating 
disposition and/or fixed power level, and at a unique set of base 
reference conditions. PTC 46 provides explicit procedures for the 
determination of the following performance results: corrected net 
power, corrected heat rate, and corrected heat input. These standards 
are available at http://www.asme.org or by mail at American Society of 
Mechanical Engineers (ASME), Two Park Avenue, New York, NY 10016-5990.
    One VCS, International Organization for Standardization method ISO 
2314:2009, ``Gas Turbines--Acceptance Tests'' is cited in the final 
rule for its guidance on determining performance characteristics of 
stationary combustion turbines. ISO 2314 specifies guidelines and 
procedures for preparing, conducting and reporting thermal-acceptance 
tests in order to determine and/or verify electrical power output, 
mechanical power, thermal efficiency (heat rate), turbine exhaust gas 
energy and/or other performance characteristics of open-cycle simple 
cycle combustion turbines using combustion systems supplied with 
gaseous and/or liquid fuels as well as closed-cycle and semi-closed-
cycle simple cycle combustion turbines. It can also be applied to 
simple cycle combustion turbines in combined cycle power plants or in 
connection with other heat recovery systems. ISO 2314 includes 
procedures for the determination of the following performance 
parameters, corrected to the reference operating parameters: electrical 
or mechanical power output (gas power, if only gas is supplied), 
thermal efficiency or heat rate; and combustion turbine engine exhaust 
energy (optionally exhaust temperature and flow). This standard is 
available at http://www.iso.org/iso/home.htm or by mail at 
International Organization for Standardization (ISO), 1, ch. de la 
Voie-Creuse, Case postale 56, CH-1211 Geneva 20, Switzerland.
    Since no EPA Methods were used, there was no need for a NTTAA 
search. The rule also requires use of appendices A, B, D, F and G to 40 
CFR part 75 and the procedures under 40 CFR 98.33; these appendices 
contain standards that have already been reviewed under the NTTAA.

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. 
As part of the Endangerment Finding, the Administrator considered 
climate change risks to minority or low-income populations, finding 
that certain parts of the population may be especially vulnerable based 
on their circumstances. Populations that were found to be particularly 
vulnerable to

[[Page 64647]]

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 XIV.F and 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.
    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 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 and low-income 
populations in the United States.\581\ 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 provides new information on how some 
communities of color may be uniquely vulnerable to climate change 
health impacts in the United States. 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 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, wellbeing, and ways of life 
of indigenous peoples in the United States.
---------------------------------------------------------------------------

    \581\ 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.
    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.
---------------------------------------------------------------------------

    As the scientific literature presented above and in the 
Endangerment Finding illustrates, low income communities and some 
communities of color are especially vulnerable to the health and other 
adverse impacts of climate change.
    The EPA believes the human health or environmental risk addressed 
by this final action will not have potential disproportionately high 
and adverse human health or environmental effects on minority, low-
income or indigenous populations. The final rule limits GHG emissions 
from newly constructed, modified, and reconstructed fossil fuel-fired 
electric utility steam generating units and newly constructed and 
modified stationary combustion turbines by establishing national 
emission standards for CO2.
    The EPA has determined that the final rule will not result in 
disproportionately high and adverse human health or environmental 
effects on minority, low-income or indigenous populations because the 
rule is not anticipated to notably affect the level of protection 
provided to human health or the environment. The EPA believes that 
electric power companies will choose to build new fossil fuel-fired 
electric utility steam generating units and natural gas-fired 
stationary combustion turbines that comply with the regulatory 
requirements of the final rule because of existing and expected market 
conditions. The EPA does not project any new coal-fired steam 
generating units without CCS to be built and expects that any newly 
built natural gas-fired stationary combustion turbines will meet the 
standards. In addition, as previously stated, the EPA expects few 
fossil fuel-fired electric utility steam generating units or natural 
gas-fired stationary combustion turbines to trigger the NSPS 
modification or reconstruction provisions in the period of analysis. 
This final rule will ensure that, to whatever extent there are newly 
constructed, modified, and reconstructed EGUs, they will use the best 
performing technologies to limit emissions of CO2.

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 not a ``major rule'' as 
defined by 5 U.S.C. 804(2).

XV. Withdrawal of Proposed Standards for Certain Modified Sources

    In this action, as discussed above in Sections IV and VI, the EPA 
is issuing final standards of performance for affected fossil fuel-
fired steam generating EGUs that implement modifications resulting in 
an increase of CO2 emissions (in lb/hr) of more than 10 
percent. In addition, the EPA is withdrawing the proposed standards of 
performance for emissions of carbon dioxide (CO2) from 
modified fossil fuel-fired EGUs not covered by those final standards. 
Specifically, the EPA is withdrawing the proposed standards for fossil 
fuel-fired steam generating EGUs that implement modifications resulting 
in an increase of CO2 emissions (in lb/hr) of less than or 
equal to 10 percent. A detailed rationale for the withdrawal of these 
proposed standards is provided in Section VI above.
    The EPA is also, in this action, withdrawing proposed standards for 
modified stationary combustion turbines. A detailed rationale for the 
withdrawal of these proposed standards is provided in Section IX above.
    The proposed standards for modified fossil fuel-fired EGUs that the 
EPA is withdrawing in this action were published in the Federal 
Register on June 18, 2014 (79 FR 34960).

[[Page 64648]]

XVI. 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

40 CFR Part 60

    Environmental protection, Administrative practice and procedure, 
Air pollution control, Incorporation by reference, Intergovernmental 
relations, Reporting and recordkeeping requirements.

40 CFR Part 70

    Environmental protection, Administrative practice and procedure, 
Air pollution control, Intergovernmental relations, Reporting and 
recordkeeping requirements.

40 CFR Part 71

    Environmental protection, Administrative practice and procedure, 
Air pollution control, Reporting and recordkeeping requirements.

40 CFR Part 98

    Environmental protection, Greenhouse gases and monitoring, 
Reporting and recordkeeping requirements.

    Dated: August 3, 2015.
Gina McCarthy,
Administrator.
    For the reasons stated in the preamble, title 40, chapter I, parts 
60, 70, 71, and 98 of the Code of the Federal Regulations are 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. Section 60.17 is amended by:
0
a. Redesignating paragraphs (d) through (t) as paragraphs (e) through 
(u) and adding paragraph (d);
0
b. In newly redesignated paragraph (g), further redesignating paragraph 
(g)(15) as paragraph (g)(17) and adding paragraphs (g)(15) and (16);
0
c. In newly redesignated paragraph (h), revising paragraphs (h)(37), 
(42), (46), (138), (187), and (190); and
0
c. In newly redesignated paragraph (m), further redesignating paragraph 
(m)(1) as paragraph (m)(2) and adding paragraph (m)(1).
    The revisions and additions read as follows:


Sec.  60.17  Incorporations by reference.

* * * * *
    (d) The following material is available for purchase from the 
American National Standards Institute (ANSI), 25 W. 43rd Street, 4th 
Floor, New York, NY 10036, Telephone (212) 642-4980, and is also 
available at the following Web site: http://www.ansi.org.
    (1) ANSI No. C12.20-2010 American National Standard for Electricity 
Meters--0.2 and 0.5 Accuracy Classes (Approved August 31, 2010), IBR 
approved for Sec.  60.5535(d).
    (2) [Reserved]
* * * * *
    (g) * * *
    (15) ASME PTC 22-2014, Gas Turbines: Performance Test Codes, 
(Issued December 31, 2014), IBR approved for Sec.  60.5580.
    (16) ASME PTC 46-1996, Performance Test Code on Overall Plant 
Performance, (Issued October 15, 1997), IBR approved for Sec.  60.5580.
* * * * *
    (h) * * *
    (37) ASTM D388-99 (Reapproved 2004) [epsiv]1 Standard 
Classification of Coals by Rank, IBR approved for Sec. Sec.  60.41, 
60.45(f), 60.41Da, 60.41b, 60.41c, 60.251, and 60.5580.
* * * * *
    (42) ASTM D396-98, Standard Specification for Fuel Oils, IBR 
approved for Sec. Sec.  60.41b, 60.41c, 60.111(b), 60.111a(b), and 
60.5580.
* * * * *
    (46) ASTM D975-08a, Standard Specification for Diesel Fuel Oils, 
IBR approved for Sec. Sec.  60.41b 60.41c, and 60.5580.
* * * * *
    (138) ASTM D3699-08, Standard Specification for Kerosine, including 
Appendix X1, (Approved September 1, 2008), IBR approved for Sec. Sec.  
60.41b, 60.41c, and 60.5580.
* * * * *
    (187) ASTM D6751-11b, Standard Specification for Biodiesel Fuel 
Blend Stock (B100) for Middle Distillate Fuels, including Appendices X1 
through X3, (Approved July 15, 2011), IBR approved for Sec. Sec.  
60.41b, 60.41c, and 60.5580.
* * * * *
    (190) ASTM D7467-10, Standard Specification for Diesel Fuel Oil, 
Biodiesel Blend (B6 to B20), including Appendices X1 through X3, 
(Approved August 1, 2010), IBR approved for Sec. Sec.  60.41b, 60.41c, 
and 60.5580.
* * * * *
    (m) * * *
    (1) ISO 2314:2009(E), Gas turbines-Acceptance tests, Third edition 
(December 15, 2009), IBR approved for Sec.  60.5580.
* * * * *

0
3. Part 60 is amended by adding subpart TTTT to read as follows:
Subpart TTTT--Standards of Performance for Greenhouse Gas Emissions for 
Electric Generating Units

Applicability

Sec.
60.5508 What is the purpose of this subpart?
60.5509 Am I subject to this subpart?

Emission Standards

60.5515 Which pollutants are regulated by this subpart?
60.5520 What CO2 emissions standard must I meet?

General Compliance Requirements

60.5525 What are my general requirements for complying with this 
subpart?

Monitoring and Compliance Determination Procedures

60.5535 How do I monitor and collect data to demonstrate compliance?
60.5540 How do I demonstrate compliance with my CO[ihel2] emissions 
standard and determine excess emissions?

Notifications, Reports, and Records

60.5550 What notifications must I submit and when?
60.5555 What reports must I submit and when?
60.5560 What records must I maintain?
60.5565 In what form and how long must I keep my records?

Other Requirements and Information

60.5570 What parts of the general provisions apply to my affected 
EGU?
60.5575 Who implements and enforces this subpart?
60.5580 What definitions apply to this subpart?
Table 1 of Subpart TTTT of Part 60--CO2 Emission 
Standards for Affected Steam Generating Units and Integrated 
Gasification Combined Cycle Facilities that Commenced Construction 
after January 8, 2014 and Reconstruction or Modification after June 
18, 2014
Table 2 of Subpart TTTT of Part 60--CO2 Emission 
Standards for Affected Stationary Combustion Turbines that Commenced 
Construction after January 8, 2014 and Reconstruction after June 18, 
2014 (Net Energy Output-based Standards Applicable as Approved by 
the Administrator)
Table 3 to Subpart TTTT of Part 60--Applicability of Subpart A of 
Part 60 (General Provisions) to Subpart TTTT

Applicability


Sec.  60.5508  What is the purpose of this subpart?

    This subpart establishes emission standards and compliance 
schedules for the control of greenhouse gas (GHG) emissions from a 
steam generating unit,

[[Page 64649]]

IGCC, or a stationary combustion turbine that commences construction 
after January 8, 2014 or commences modification or reconstruction after 
June 18, 2014. An affected steam generating unit, IGCC, or stationary 
combustion turbine shall, for the purposes of this subpart, be referred 
to as an affected EGU.


Sec.  60.5509  Am I subject to this subpart?

    (a) Except as provided for in paragraph (b) of this section, the 
GHG standards included in this subpart apply to any steam generating 
unit, IGCC, or stationary combustion turbine that commenced 
construction after January 8, 2014 or commenced reconstruction after 
June 18, 2014 that meets the relevant applicability conditions in 
paragraphs (a)(1) and (2) of this section. The GHG standards included 
in this subpart also apply to any steam generating unit or IGCC that 
commenced modification after June 18, 2014 that meets the relevant 
applicability conditions in paragraphs (a)(1) and (2) of this section.
    (1) Has a base load rating greater than 260 GJ/h (250 MMBtu/h) of 
fossil fuel (either alone or in combination with any other fuel); and
    (2) Serves a generator or generators capable of selling greater 
than 25 MW of electricity to a utility power distribution system.
    (b) You are not subject to the requirements of this subpart if your 
affected EGU meets any of the conditions specified in paragraphs (b)(1) 
through (10) of this section.
    (1) Your EGU is a steam generating unit or IGCC that is currently 
and always has been subject to a federally enforceable permit condition 
limiting annual net-electric sales to no more than one-third of its 
potential electric output or 219,000 MWh, whichever is greater.
    (2) Your EGU is capable of combusting 50 percent or more non-fossil 
fuel and is also subject to a federally enforceable permit condition 
limiting the annual capacity factor for all fossil fuels combined of 10 
percent (0.10) or less.
    (3) Your EGU is a combined heat and power unit that is subject to a 
federally enforceable permit condition limiting annual net-electric 
sales to no more than either 219,000 MWh or the product of the design 
efficiency and the potential electric output, whichever is greater.
    (4) Your EGU serves a generator along with other steam generating 
unit(s), IGCC, 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.
    (5) Your EGU is a municipal waste combustor that is subject to 
subpart Eb of this part.
    (6) Your EGU is a commercial or industrial solid waste incineration 
unit that is subject to subpart CCCC of this part.
    (7) Your EGU is a steam generating unit or IGCC that undergoes a 
modification resulting in an hourly increase in CO2 
emissions (mass per hour) of 10 percent or less (2 significant 
figures). Modified units that are not subject to the requirements of 
this subpart pursuant to this subsection continue to be existing units 
under section 111 with respect to CO2 emissions standards.
    (8) Your EGU is a stationary combustion turbine that is not capable 
of combusting natural gas (e.g., not connected to a natural gas 
pipeline).
    (9) The proposed Washington County EGU project described in Air 
Quality Permit No. 4911-303-0051-P-01-0 issued by the Georgia 
Department of Natural Resources, Environmental Protection Division, Air 
Protection Branch, effective April 8, 2010, provided that construction 
had not commenced for NSPS purposes as of January 8, 2014.
    (10) The proposed Holcomb EGU project described in Air Emission 
Source Construction Permit 0550023 issued by the Kansas Department of 
Health and Environment, Division of Environment, effective December 16, 
2010, provided that construction had not commenced for NSPS purposes as 
of January 8, 2014.

Emission Standards


Sec.  60.5515  Which pollutants are regulated by this subpart?

    (a) The pollutants regulated by this subpart are greenhouse gases. 
The greenhouse gas standard in this subpart is in the form of a 
limitation on emission of carbon dioxide.
    (b) PSD and title V thresholds for greenhouse gases. (1) For the 
purposes of 40 CFR 51.166(b)(49)(ii), with respect to GHG emissions 
from affected 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) of this chapter and in any SIP 
approved by the EPA that is interpreted to incorporate, or specifically 
incorporates, Sec.  51.166(b)(48).
    (2) For the purposes of 40 CFR 52.21(b)(50)(ii), with respect to 
GHG emissions from affected 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.  52.21(b)(49) of this chapter.
    (3) For the purposes of 40 CFR 70.2, with respect to greenhouse gas 
emissions from affected facilities, 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 40 CFR 70.2.
    (4) For the purposes of 40 CFR 71.2, with respect to greenhouse gas 
emissions from affected facilities, 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 40 CFR 71.2.


Sec.  60.5520  What CO2 emission standard must I meet?

    (a) For each affected EGU subject to this subpart, you must not 
discharge from the affected EGU any gases that contain CO2 
in excess of the applicable CO2 emission standard specified 
in Table 1 or 2 of this subpart, consistent with paragraphs (b), (c), 
and (d) of this section, as applicable.
    (b) Except as specified in paragraphs (c) and (d) of this section, 
you must comply with the applicable gross energy output standard, and 
your operating permit must include monitoring, recordkeeping, and 
reporting methodologies based on the applicable gross energy output 
standard. For the remainder of this subpart (for sources that do not 
qualify under paragraphs (c) and (d) of this section), where the term 
``gross or net energy output'' is used, the term that applies to you is 
``gross energy output.''
    (c) As an alternate to meeting the requirements in paragraph (b) of 
this section, an owner or operator of a stationary combustion turbine 
may petition the Administrator in writing to comply with the alternate 
applicable net energy output standard. If the Administrator grants the 
petition, beginning on the date the Administrator grants the petition, 
the affected EGU must comply with the applicable net energy output-
based standard included in this subpart. Your operating permit must 
include monitoring, recordkeeping, and reporting methodologies based on 
the applicable net energy output standard. For the remainder of this 
subpart, where the term ``gross or net energy output'' is used, the 
term that applies to you is ``net energy output.'' Owners or

[[Page 64650]]

operators complying with the net output-based standard must petition 
the Administrator to switch back to complying with the gross energy 
output-based standard.
    (d) Stationary combustion turbines subject to a heat input-based 
standard in Table 2 of this subpart that are only permitted to burn one 
or more uniform fuels, as described in paragraph (d)(1) of this 
section, are only subject to the monitoring requirements in paragraph 
(d)(1). All other stationary combustion turbines subject to a heat 
input based standard in Table 2 are subject to the requirements in 
paragraph (d)(2) of this section.
    (1) Stationary combustion turbines that are only permitted to burn 
fuels with a consistent chemical composition (i.e., uniform fuels) that 
result in a consistent emission rate of 160 lb CO2/MMBtu or 
less are not subject to any monitoring or reporting requirements under 
this subpart. These fuels include, but are not limited to, natural gas, 
methane, butane, butylene, ethane, ethylene, propane, naphtha, 
propylene, jet fuel kerosene, No. 1 fuel oil, No. 2 fuel oil, and 
biodiesel. Stationary combustion turbines qualifying under this 
paragraph are only required to maintain purchase records for permitted 
fuels.
    (2) Stationary combustion turbines permitted to burn fuels that do 
not have a consistent chemical composition or that do not have an 
emission rate of 160 lb CO2/MMBtu or less (e.g., non-uniform 
fuels such as residual oil and non-jet fuel kerosene) must follow the 
monitoring, recordkeeping, and reporting requirements necessary to 
complete the heat input-based calculations under this subpart.

General Compliance Requirements


Sec.  60.5525  What are my general requirements for complying with this 
subpart?

    Combustion turbines qualifying under Sec.  60.5520(d)(1) are not 
subject to any requirements in this section other than the requirement 
to maintain fuel purchase records for permitted fuel(s). For all other 
affected sources, compliance with the applicable CO2 
emission standard of this subpart shall be determined on a 12-
operating-month rolling average basis. See Table 1 or 2 of this subpart 
for the applicable CO2 emission standards.
    (a) You must be in compliance with the emission standards in this 
subpart that apply to your affected EGU at all times. However, you must 
determine compliance with the emission standards only at the end of the 
applicable operating month, as provided in paragraph (a)(1) of this 
section.
    (1) For each affected EGU subject to a CO2 emissions 
standard based on a 12-operating-month rolling average, you must 
determine compliance monthly by calculating the average CO2 
emissions rate for the affected EGU at the end of the initial and each 
subsequent 12-operating-month period.
    (2) Consistent with Sec.  60.5520(d)(2), if your affected 
stationary combustion turbine is subject to an input-based 
CO2 emissions standard, you must determine the total heat 
input in million Btus (MMBtu) from natural gas (HTIPng) and 
the total heat input from all other fuels combined (HTIPo) 
using one of the methods under Sec.  60.5535(d)(2). You must then use 
the following equation to determine the applicable emissions standard 
during the compliance period:
[GRAPHIC] [TIFF OMITTED] TR23OC15.002


Where:

CO2 emission standard = the emission standard during the 
compliance period in units of lb/MMBtu.
HTIPng = the heat input in MMBtu from natural gas.
HTIPo = the heat input in MMBtu from all fuels other than 
natural gas.
120 = allowable emission rate in lb of CO2/MMBtu for heat 
input derived from natural gas.
160 = allowable emission rate in lb of CO2/MMBtu for heat 
input derived from all fuels other than natural gas.

    (b) At all times you must operate and maintain each affected EGU, 
including associated equipment and monitors, in a manner consistent 
with safety and good air pollution control practice. The Administrator 
will determine if you are using consistent operation and maintenance 
procedures based on information available to the Administrator that may 
include, but is not limited to, fuel use records, monitoring results, 
review of operation and maintenance procedures and records, review of 
reports required by this subpart, and inspection of the EGU.
    (c) Within 30 days after the end of the initial compliance period 
(i.e., no more than 30 days after the first 12-operating-month 
compliance period), you must make an initial compliance determination 
for your affected EGU(s) with respect to the applicable emissions 
standard in Table 1 or 2 of this subpart, in accordance with the 
requirements in this subpart. The first operating month included in the 
initial 12-operating-month compliance period shall be determined as 
follows:
    (1) For an affected EGU that commences commercial operation (as 
defined in Sec.  72.2 of this chapter) on or after October 23, 2015, 
the first month of the initial compliance period shall be the first 
operating month (as defined in Sec.  60.5580) after the calendar month 
in which emissions reporting is required to begin under:
    (i) Section 63.5555(c)(3)(i), for units subject to the Acid Rain 
Program; or
    (ii) Section 63.5555(c)(3)(ii)(A), for units that are not in the 
Acid Rain Program.
    (2) For an affected EGU that has commenced COMMERCIAL operation (as 
defined in Sec.  72.2 of this chapter) prior to October 23, 2015:
    (i) If the date on which emissions reporting is required to begin 
under Sec.  75.64(a) of this chapter has passed prior to October 23, 
2015, emissions reporting shall begin according to Sec.  
63.5555(c)(3)(i) (for Acid Rain program units), or according to Sec.  
63.5555(c)(3)(ii)(B) (for units that are not subject to the Acid Rain 
Program). The first month of the initial compliance period shall be the 
first operating month (as defined in Sec.  60.5580) after the calendar 
month in which the rule becomes effective; or
    (ii) If the date on which emissions reporting is required to begin 
under Sec.  75.64(a) of this chapter occurs on or after October 23, 
2015, then the first month of the initial compliance period shall be 
the first operating month (as defined in Sec.  60.5580) after the 
calendar month in which emissions reporting is required to begin under 
Sec.  63.5555(c)(3)(ii)(A).
    (3) For a modified or reconstructed EGU that becomes subject to 
this subpart, the first month of the initial compliance period shall be 
the first operating month (as defined in Sec.  60.5580) after the 
calendar month in which emissions reporting is required to begin under 
Sec.  63.5555(c)(3)(iii).

[[Page 64651]]

Monitoring and Compliance Determination Procedures


Sec.  60.5535  How do I monitor and collect data to demonstrate 
compliance?

    (a) Combustion turbines qualifying under Sec.  60.5520(d)(1) are 
not subject to any requirements in this section other than the 
requirement to maintain fuel purchase records for permitted fuel(s). If 
your combustion turbine uses non-uniform fuels as specified under Sec.  
60.5520(d)(2), you must monitor heat input in accordance with paragraph 
(c)(1) of this section, and you must monitor CO2 emissions 
in accordance with either paragraph (b), (c)(2), or (c)(5) of this 
section. For all other affected sources, you must prepare a monitoring 
plan to quantify the hourly CO2 mass emission rate (tons/h), 
in accordance with the applicable provisions in Sec.  75.53(g) and (h) 
of this chapter. The electronic portion of the monitoring plan must be 
submitted using the ECMPS Client Tool and must be in place prior to 
reporting emissions data and/or the results of monitoring system 
certification tests under this subpart. The monitoring plan must be 
updated as necessary. Monitoring plan submittals must be made by the 
Designated Representative (DR), the Alternate DR, or a delegated agent 
of the DR (see Sec.  60.5555(c)).
    (b) You must determine the hourly CO2 mass emissions in 
kilograms (kg) from your affected EGU(s) according to paragraphs (b)(1) 
through (5) of this section, or, if applicable, as provided in 
paragraph (c) of this section.
    (1) For an affected coal-fired EGU or for an IGCC unit you must, 
and for all other affected EGUs you may, install, certify, operate, 
maintain, and calibrate a CO2 continuous emission monitoring 
system (CEMS) to directly measure and record hourly average 
CO2 concentrations in the affected EGU exhaust gases emitted 
to the atmosphere, and a flow monitoring system to measure hourly 
average stack gas flow rates, according to Sec.  75.10(a)(3)(i) of this 
chapter. As an alternative to direct measurement of CO2 
concentration, provided that your EGU does not use carbon separation 
(e.g., carbon capture and storage), you 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. If you measure CO2 
concentration on a dry basis, you must also install, certify, operate, 
maintain, and calibrate a continuous moisture monitoring system, 
according to Sec.  75.11(b) of this chapter. Alternatively, you 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.
    (2) For each continuous monitoring system that you use to determine 
the CO2 mass emissions, you 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.
    (3) You must use only unadjusted exhaust gas volumetric flow rates 
to determine the hourly CO2 mass emissions rate from the 
affected EGU; you must not apply the bias adjustment factors described 
in Section 7.6.5 of appendix A to part 75 of this chapter to the 
exhaust gas flow rate data.
    (4) You must select an appropriate reference method to setup 
(characterize) the flow monitor and to perform the on-going RATAs, in 
accordance with part 75 of this chapter. If you use a Type-S pitot tube 
or a pitot tube assembly for the flow RATAs, you must calibrate the 
pitot tube or pitot tube assembly; you may not use the 0.84 default 
Type-S pitot tube coefficient specified in Method 2.
    (5) Calculate the hourly CO2 mass emissions (kg) as 
described in paragraphs (b)(5)(i) through (iv) of this section. Perform 
this calculation only for ``valid operating hours'', as defined in 
Sec.  60.5540(a)(1).
    (i) Begin with the hourly CO2 mass emission rate (tons/
h), obtained 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).
    (ii) 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.
    (iii) Finally, multiply the result from paragraph (b)(5)(ii) of 
this section by 909.1 to convert it from tons of CO2 to kg. 
Round off to the nearest kg.
    (iv) The hourly CO2 tons/h 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) of this chapter. You 
must use these data to calculate the hourly CO2 mass 
emissions.
    (c) If your affected EGU exclusively combusts liquid fuel and/or 
gaseous fuel, as an alternative to complying with paragraph (b) of this 
section, you may determine the hourly CO2 mass emissions 
according to paragraphs (c)(1) through (4) of this section. If you use 
non-uniform fuels as specified in Sec.  60.5520(d)(2), you may 
determine CO2 mass emissions during the compliance period 
according to paragraph (c)(5) of this section.
    (1) If you are subject to an output-based standard and you do not 
install CEMS in accordance with paragraph (b) of this section, you must 
implement the applicable procedures in appendix D to part 75 of this 
chapter to determine hourly EGU heat input rates (MMBtu/h), based on 
hourly measurements of fuel flow rate and periodic determinations of 
the gross calorific value (GCV) of each fuel combusted.
    (2) 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/h). You 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 you may use 
these Fc values in the emissions calculations instead of 
using the default Fc values in the Equation G-4 
nomenclature.
    (3) For each ``valid operating hour'' (as defined in Sec.  
60.5540(a)(1), multiply the hourly tons/h CO2 mass emission 
rate from paragraph (c)(2) 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 
909.1 to convert from tons of CO2 to kg. Round off to the 
nearest two significant figures.
    (4) The hourly CO2 tons/h 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) of this chapter. You 
must use these data to calculate the hourly CO2 mass 
emissions.
    (5) If you operate a combustion turbine firing non-uniform fuels, 
as an alternative to following paragraphs (c)(1) through (4) of this 
section, you may determine CO2 emissions during the 
compliance period using one of the following methods:
    (i) Units firing fuel gas may determine the heat input during the 
compliance period following the procedure under Sec.  60.107a(d) and 
convert this heat input to CO2 emissions using Equation G-4 
in appendix G to part 75 of this chapter.
    (ii) You may use the procedure for determining CO2 
emissions during the compliance period based on the use of the Tier 3 
methodology under Sec.  98.33(a)(3) of this chapter.
    (d) Consistent with Sec.  60.5520, you must determine the basis of 
the emissions standard that applies to your

[[Page 64652]]

affected source in accordance with either paragraph (d)(1) or (2) of 
this section, as applicable:
    (1) If you operate a source subject to an emissions standard 
established on an output basis (e.g., lb of CO2 per gross or 
net MWh of energy output), you must install, calibrate, maintain, and 
operate a sufficient number of watt meters to continuously measure and 
record the hourly gross electric output or net electric output, as 
applicable, from the affected EGU(s). These measurements must be 
performed using 0.2 class electricity metering instrumentation and 
calibration procedures as specified under ANSI Standards No. C12.20 
(incorporated by reference, see Sec.  60.17). For a combined heat and 
power (CHP) EGU, as defined in Sec.  60.5580, you must also install, 
calibrate, maintain, and operate meters to continuously (i.e., hour-by-
hour) determine and record the total useful thermal output. For process 
steam applications, you will need to install, calibrate, maintain, and 
operate meters to continuously determine and record the hourly steam 
flow rate, temperature, and pressure. Your plan shall ensure that you 
install, calibrate, maintain, and operate meters to record each 
component of the determination, hour-by-hour.
    (2) If you operate a source subject to an emissions standard 
established on a heat-input basis (e.g., lb CO2/MMBtu) and 
your affected source uses non-uniform heating value fuels as delineated 
under Sec.  60.5520(d), you must determine the total heat input for 
each fuel fired during the compliance period in accordance with one of 
the following procedures:
    (i) Appendix D to part 75 of this chapter;
    (ii) The procedures for monitoring heat input under Sec.  
60.107a(d);
    (iii) If you monitor CO2 emissions in accordance with 
the Tier 3 methodology under Sec.  98.33(a)(3) of this chapter, you may 
convert your CO2 emissions to heat input using the 
appropriate emission factor in Table C-1 of part 98 of this chapter. If 
your fuel is not listed in Table C-1, you must determine a fuel-
specific carbon-based F-factor (Fc) in accordance with 
section 12.3.2 of EPA Method 19 of appendix A-7 to this part, and you 
must convert your CO2 emissions to heat input using Equation 
G-4 in appendix G to part 75 of this chapter.
    (e) Consistent with Sec.  60.5520, if two or more affected EGUs 
serve a common electric generator, you must apportion the combined 
hourly gross or 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 gross or net electrical load to the individual EGUs 
according to the fraction of the total heat input contributed by each 
EGU.
    (f) In accordance with Sec. Sec.  60.13(g) and 60.5520, if two or 
more affected EGUs that implement the continuous emission monitoring 
provisions in paragraph (b) of this section share a common exhaust gas 
stack and are subject to the same emissions standard in Table 1 or 2 of 
this subpart, you may monitor the hourly CO2 mass emissions 
at the common stack in lieu of monitoring each EGU separately. If you 
choose this option, the hourly gross or net energy output (electric, 
thermal, and/or mechanical, as applicable) must be the sum of the 
hourly loads for the individual affected EGUs and you must express the 
operating time as ``stack operating hours'' (as defined in Sec.  72.2 
of this chapter). If you attain compliance with the applicable 
emissions standard in Sec.  60.5520 at the common stack, each affected 
EGU sharing the stack is in compliance.
    (g) In accordance with Sec. Sec.  60.13(g) and 60.5520 if the 
exhaust gases from an affected EGU that implements the continuous 
emission monitoring provisions in paragraph (b) 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), you must monitor the hourly CO2 
mass emissions and the ``stack operating time'' (as defined in Sec.  
72.2 of this chapter) at each stack or duct separately. In this case, 
you must determine compliance with the applicable emissions standard in 
Table 1 or 2 of this subpart by summing the CO2 mass 
emissions measured at the individual stacks or ducts and dividing by 
the total gross or net energy output for the affected EGU.


Sec.  60.5540  How do I demonstrate compliance with my CO2 
emissions standard and determine excess emissions?

    (a) In accordance with Sec.  60.5520, if you are subject to an 
output-based emission standard or you burn non-uniform fuels as 
specified in Sec.  60.5520(d)(2), you must demonstrate compliance with 
the applicable CO2 emission standard in Table 1 or 2 of this 
subpart as required in this section. For the initial and each 
subsequent 12-operating-month rolling average compliance period, you 
must follow the procedures in paragraphs (a)(1) through (7) of this 
section to calculate the CO2 mass emissions rate for your 
affected EGU(s) in units of the applicable emissions standard (i.e., 
either kg/MWh or lb/MMBtu). You must use the hourly CO2 mass 
emissions calculated under Sec.  60.5535(b) or (c), as applicable, and 
either the generating load data from Sec.  60.5535(d)(1) for output-
based calculations or the heat input data from Sec.  60.5535(d)(2) for 
heat-input-based calculations. Combustion turbines firing non-uniform 
fuels that contain CO2 prior to combustion (e.g., blast 
furnace gas or landfill gas) may sample the fuel stream to determine 
the quantity of CO2 present in the fuel prior to combustion 
and exclude this portion of the CO2 mass emissions from 
compliance determinations.
    (1) Each compliance period shall include only ``valid operating 
hours'' in the compliance period, i.e., operating hours for which:
    (i) ``Valid data'' (as defined in Sec.  60.5580) are obtained for 
all of the parameters used to determine the hourly CO2 mass 
emissions (kg) and, if a heat input-based standard applies, all the 
parameters used to determine total heat input for the hour are also 
obtained; and
    (ii) The corresponding hourly gross or net energy output value is 
also valid data (Note: For hours with no useful output, zero is 
considered to be a valid value).
    (2) You must exclude operating hours in which:
    (i) The substitute data provisions of part 75 of this chapter are 
applied for any of the parameters used to determine the hourly 
CO2 mass emissions or, if a heat input-based standard 
applies, for any parameters used to determine the hourly heat input; or
    (ii) An exceedance of the full-scale range of a continuous emission 
monitoring system occurs for any of the parameters used to determine 
the hourly CO2 mass emissions or, if applicable, to 
determine the hourly heat input; or
    (iii) The total gross or net energy output (Pgross/net) 
or, if applicable, the total heat input is unavailable.
    (3) For each compliance period, at least 95 percent of the 
operating hours in the compliance period must be valid operating hours, 
as defined in paragraph (a)(1) of this section.
    (4) You must calculate the total CO2 mass emissions by 
summing the valid hourly CO2 mass emissions values from 
Sec.  60.5535 for all of the valid operating hours in the compliance 
period.
    (5) Sources subject to output based standards. For each valid 
operating hour of the compliance period that was used in paragraph 
(a)(4) of this section to calculate the total CO2 mass 
emissions, you must determine Pgross/net (the corresponding 
hourly gross or net energy output in MWh) according to the

[[Page 64653]]

procedures in paragraphs (a)(3)(i) and (ii) of this section, as 
appropriate for the type of affected EGU(s). For an operating hour in 
which a valid CO2 mass emissions value is determined 
according to paragraph (a)(1)(i) of this section, if there is no gross 
or net electrical output, but there is mechanical or useful thermal 
output, you must still determine the gross or net energy output for 
that hour. In addition, for an operating hour in which a valid 
CO2 mass emissions value is determined according to 
paragraph (a)(1)(i) of this section, but there is no (i.e., zero) gross 
electrical, mechanical, or useful thermal output, you must use that 
hour 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.
    (i) Calculate Pgross/net for your affected EGU using the 
following equation. All terms in the equation must be expressed in 
units of megawatt-hours (MWh). To convert each hourly gross or net 
energy output (consistent with Sec.  60.5520) value reported under part 
75 of this chapter to MWh, multiply by the corresponding EGU or stack 
operating time.
[GRAPHIC] [TIFF OMITTED] TR23OC15.003

Where:

Pgross/net = In accordance with Sec.  60.5520, gross or 
net energy output of your affected EGU for each valid operating hour 
(as defined in Sec.  60.5540(a)(1)) 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)FW = Electric energy used to power boiler feedwater 
pumps at steam generating units in MWh. Not applicable to stationary 
combustion turbines, IGCC EGUs, or EGUs complying with a net energy 
output based standard.
(Pe)A = Electric energy used for any auxiliary loads in 
MWh. Not applicable for determining Pgross.
(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)(ii) 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 gross or net energy output consists of useful thermal output 
on a 12-operating-month rolling average basis, or 1.0 for all other 
affected EGUs.

    (ii) 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] TR23OC15.004

Where:

Qm = Measured steam flow in kilograms (kg) (or pounds 
(lb)) 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.

    (6) Calculation of annual basis for standard. Sources complying 
with energy output-based standards must calculate the basis (i.e., 
denominator) of their actual annual emission rate in accordance with 
paragraph (a)(6)(i) of this section. Sources complying with heat input 
based standards must calculate the basis of their actual annual 
emission rate in accordance with paragraph (a)(6)(ii) of this section.
    (i) In accordance with Sec.  60.5520 if you are subject to an 
output-based standard, you must calculate the total gross or net energy 
output for the affected EGU's compliance period by summing the hourly 
gross or net energy output values for the affected EGU that you 
determined under paragraph (a)(5) of this section for all of the valid 
operating hours in the applicable compliance period.
    (ii) If you are subject to a heat input-based standard, you must 
calculate the total heat input for each fuel fired during the 
compliance period. The calculation of total heat input for each 
individual fuel must include all valid operating hours and must also be 
consistent with any fuel-specific procedures specified within your 
selected monitoring option under Sec.  60.5535(d)(2).
    (7) If you are subject to an output-based standard, you must 
calculate the CO2 mass emissions rate for the affected 
EGU(s) (kg/MWh) by dividing the total CO2 mass emissions 
value calculated according to the procedures in paragraph (a)(4) of 
this section by the total gross or net energy output value calculated 
according to the procedures in paragraph (a)(6)(i) of this section. 
Round off the result to two significant figures if the calculated value 
is less than 1,000; round the result to three significant figures if 
the calculated value is greater than 1,000. If you are subject to a 
heat input-based standard, you must calculate the CO2 mass 
emissions rate for the affected EGU(s) (lb/MMBtu) by dividing the total 
CO2 mass emissions value calculated according to the 
procedures in paragraph (a)(4) of this section by the total heat input 
calculated according to the procedures in paragraph (a)(6)(ii) of this 
section. Round off the result to two significant figures.
    (b) In accordance with Sec.  60.5520, to demonstrate compliance 
with the applicable CO2 emission standard, for the initial 
and each subsequent 12-operating-month compliance period, the 
CO2 mass emissions rate for your affected EGU must be 
determined according to the procedures specified in paragraph (a)(1) 
through (7) of this section and must be less than or equal to the 
applicable CO2 emissions standard in Table 1 or 2 of this 
part, or the emissions standard calculated in accordance with Sec.  
60.5525(a)(2).

Notification, Reports, and Records


Sec.  60.5550  What notifications must I submit and when?

    (a) You must prepare and submit the notifications specified in 
Sec. Sec.  60.7(a)(1) and (3) and 60.19, as applicable to your affected 
EGU(s) (see Table 3 of this subpart).

[[Page 64654]]

    (b) You must prepare and submit notifications specified in Sec.  
75.61 of this chapter, as applicable, to your affected EGUs.


Sec.  60.5555  What reports must I submit and when?

    (a) You must prepare and submit reports according to paragraphs (a) 
through (d) of this section, as applicable.
    (1) For affected EGUs that are required by Sec.  60.5525 to conduct 
initial and on-going compliance determinations on a 12-operating-month 
rolling average basis, you must submit electronic quarterly reports as 
follows. After you have accumulated the first 12-operating months for 
the affected EGU, you must submit a report for the calendar quarter 
that includes the twelfth operating month no later than 30 days after 
the end of that quarter. Thereafter, you must submit a report for each 
subsequent calendar quarter, no later than 30 days after the end of the 
quarter.
    (2) In each quarterly report you must include the following 
information, as applicable:
    (i) Each rolling average CO2 mass emissions rate for 
which the last (twelfth) operating month in a 12-operating-month 
compliance period falls within the calendar quarter. You must calculate 
each average CO2 mass emissions rate for the compliance 
period according to the procedures in Sec.  60.5540. You must report 
the dates (month and year) of the first and twelfth operating months in 
each compliance period for which you performed a CO2 mass 
emissions rate calculation. If there are no compliance periods that end 
in the quarter, you must include a statement to that effect;
    (ii) If one or more compliance periods end in the quarter, you must 
identify each operating month in the calendar quarter where your EGU 
violated the applicable CO2 emission standard;
    (iii) If one or more compliance periods end in the quarter and 
there are no violations for the affected EGU, you must include a 
statement indicating this in the report;
    (iv) The percentage of valid operating hours in each 12-operating-
month compliance period described in paragraph (a)(1)(i) of this 
section (i.e., the total number of valid operating hours (as defined in 
Sec.  60.5540(a)(1)) in that period divided by the total number of 
operating hours in that period, multiplied by 100 percent);
    (v) Consistent with Sec.  60.5520, the CO2 emissions 
standard (as identified in Table 1 or 2 of this part) with which your 
affected EGU must comply; and
    (vi) Consistent with Sec.  60.5520, an indication whether or not 
the hourly gross or net energy output (Pgross/net) values 
used in the compliance determinations are based solely upon gross 
electrical load.
    (3) In the final quarterly report of each calendar year, you must 
include the following:
    (i) Consistent with Sec.  60.5520, gross energy output or net 
energy output sold to an electric grid, as applicable to the units of 
your emission standard, over the four quarters of the calendar year; 
and
    (ii) The potential electric output of the EGU.
    (b) You must submit all electronic reports required under paragraph 
(a) of this section using the Emissions Collection and Monitoring Plan 
System (ECMPS) Client Tool provided by the Clean Air Markets Division 
in the Office of Atmospheric Programs of EPA.
    (c)(1) For affected EGUs under this subpart that are also subject 
to the Acid Rain Program, you must meet all applicable reporting 
requirements and submit reports as required under subpart G of part 75 
of this chapter.
    (2) For affected EGUs under this subpart that are not in the Acid 
Rain Program, you must also meet the reporting requirements and submit 
reports as required under subpart G of part 75 of this chapter, to the 
extent that those requirements and reports provide applicable data for 
the compliance demonstrations required under this subpart.
    (3)(i) For all newly-constructed affected EGUs under this subpart 
that are also subject to the Acid Rain Program, you must begin 
submitting the quarterly electronic emissions reports described in 
paragraph (c)(1) of this section in accordance with Sec.  75.64(a) of 
this chapter, i.e., beginning with data recorded on and after the 
earlier of:
    (A) The date of provisional certification, as defined in Sec.  
75.20(a)(3) of this chapter; or
    (B) 180 days after the date on which the EGU commences commercial 
operation (as defined in Sec.  72.2 of this chapter).
    (ii) For newly-constructed affected EGUs under this subpart that 
are not subject to the Acid Rain Program, you must begin submitting the 
quarterly electronic reports described in paragraph (c)(2) of this 
section, beginning with data recorded on and after:
    (A) The date on which reporting is required to begin under Sec.  
75.64(a) of this chapter, if that date occurs on or after October 23, 
2015; or
    (B) October 23, 2015, if the date on which reporting would 
ordinarily be required to begin under Sec.  75.64(a) of this chapter 
has passed prior to October 23, 2015.
    (iii) For reconstructed or modified units, reporting of emissions 
data shall begin at the date on which the EGU becomes an affected unit 
under this subpart, provided that the ECMPS Client Tool is able to 
receive and process net energy output data on that date. Otherwise, 
emissions data reporting shall be on a gross energy output basis until 
the date that the Client Tool is first able to receive and process net 
energy output data.
    (4) If any required monitoring system has not been provisionally 
certified by the applicable date on which emissions data reporting is 
required to begin under paragraph (c)(3) of this section, the maximum 
(or in some cases, minimum) potential value for the parameter measured 
by the monitoring system shall be reported until the required 
certification testing is successfully completed, in accordance with 
Sec.  75.4(j) of this chapter, Sec.  75.37(b) of this chapter, or 
section 2.4 of appendix D to part 75 of this chapter (as applicable). 
Operating hours in which CO2 mass emission rates are 
calculated using maximum potential values are not ``valid operating 
hours'' (as defined in Sec.  60.5540(a)(1)), and shall not be used in 
the compliance determinations under Sec.  60.5540.
    (d) For affected EGUs subject to the Acid Rain Program, the reports 
required under paragraphs (a) and (c)(1) of this section shall be 
submitted by:
    (1) The person appointed as the Designated Representative (DR) 
under Sec.  72.20 of this chapter; or
    (2) The person appointed as the Alternate Designated Representative 
(ADR) under Sec.  72.22 of this chapter; or
    (3) A person (or persons) authorized by the DR or ADR under Sec.  
72.26 of this chapter to make the required submissions.
    (e) For affected EGUs that are not subject to the Acid Rain 
Program, the owner or operator shall appoint a DR and (optionally) an 
ADR to submit the reports required under paragraphs (a) and (c)(2) of 
this section. The DR and ADR must register with the Clean Air Markets 
Division (CAMD) Business System. The DR may delegate the authority to 
make the required submissions to one or more persons.
    (f) If your affected EGU captures CO2 to meet the 
applicable emission limit, you must report in accordance with the 
requirements of 40 CFR part 98, subpart PP and either:

[[Page 64655]]

    (1) Report in accordance with the requirements of 40 CFR part 98, 
subpart RR, if injection occurs on-site, or
    (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.
    (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, with 
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.


Sec.  60.5560  What records must I maintain?

    (a) You must maintain records of the information you used to 
demonstrate compliance with this subpart as specified in Sec.  60.7(b) 
and (f).
    (b)(1) For affected EGUs subject to the Acid Rain Program, you must 
follow the applicable recordkeeping requirements and maintain records 
as required under subpart F of part 75 of this chapter.
    (2) For affected EGUs that are not subject to the Acid Rain 
Program, you must also follow the recordkeeping requirements and 
maintain records as required under subpart F of part 75 of this 
chapter, to the extent that those records provide applicable data for 
the compliance determinations required under this subpart. Regardless 
of the prior sentence, at a minimum, the following records must be 
kept, as applicable to the types of continuous monitoring systems used 
to demonstrate compliance under this subpart:
    (i) Monitoring plan records under Sec.  75.53(g) and (h) of this 
chapter;
    (ii) Operating parameter records under Sec.  75.57(b)(1) through 
(4) of this chapter;
    (iii) The records under Sec.  75.57(c)(2) of this chapter, for 
stack gas volumetric flow rate;
    (iv) The records under Sec.  75.57(c)(3) of this chapter for 
continuous moisture monitoring systems;
    (v) The records under Sec.  75.57(e)(1) of this chapter, except for 
paragraph (e)(1)(x), for CO2 concentration monitoring 
systems or O2 monitors used to calculate CO2 
concentration;
    (vi) The records under Sec.  75.58(c)(1) of this chapter, 
specifically paragraphs (c)(1)(i), (ii), and (viii) through (xiv), for 
oil flow meters;
    (vii) The records under Sec.  75.58(c)(4) of this chapter, 
specifically paragraphs (c)(4)(i), (ii), (iv), (v), and (vii) through 
(xi), for gas flow meters;
    (viii) The quality-assurance records under Sec.  75.59(a) of this 
chapter, specifically paragraphs (a)(1) through (12) and (15), for 
CEMS;
    (ix) The quality-assurance records under Sec.  75.59(a) of this 
chapter, specifically paragraphs (b)(1) through (4), for fuel flow 
meters; and
    (x) Records of data acquisition and handling system (DAHS) 
verification under Sec.  75.59(e) of this chapter.
    (c) You must keep records of the calculations you performed to 
determine the hourly and total CO2 mass emissions (tons) 
for:
    (1) Each operating month (for all affected EGUs); and
    (2) Each compliance period, including, each 12-operating-month 
compliance period.
    (d) Consistent with Sec.  60.5520, you must keep records of the 
applicable data recorded and calculations performed that you used to 
determine your affected EGU's gross or net energy output for each 
operating month.
    (e) You must keep records of the calculations you performed to 
determine the percentage of valid CO2 mass emission rates in 
each compliance period.
    (f) You must keep records of the calculations you performed to 
assess compliance with each applicable CO2 mass emissions 
standard in Table 1 or 2 of this subpart.
    (g) You must keep records of the calculations you performed to 
determine any site-specific carbon-based F-factors you used in the 
emissions calculations (if applicable).


Sec.  60.5565  In what form and how long must I keep my records?

    (a) Your records must be in a form suitable and readily available 
for expeditious review.
    (b) You must maintain each record for 3 years after the date of 
conclusion of each compliance period.
    (c) You must maintain each record on site for at least 2 years 
after the date of each occurrence, measurement, maintenance, corrective 
action, report, or record, according to Sec.  60.7. Records that are 
accessible from a central location by a computer or other means that 
instantly provide access at the site meet this requirement. You may 
maintain the records off site for the remaining year(s) as required by 
this subpart.

Other Requirements and Information


Sec.  60.5570  What parts of the general provisions apply to my 
affected EGU?

    Notwithstanding any other provision of this chapter, certain parts 
of the general provisions in Sec. Sec.  60.1 through 60.19, listed in 
Table 3 to this subpart, do not apply to your affected EGU.


Sec.  60.5575  Who implements and enforces this subpart?

    (a) This subpart can be implemented and enforced by the EPA, or a 
delegated authority such as your state, local, or tribal agency. If the 
Administrator has delegated authority to your state, local, or tribal 
agency, then that agency (as well as the EPA) has the authority to 
implement and enforce this subpart. You should contact your EPA 
Regional Office to find out if this subpart is delegated to your state, 
local, or tribal agency.
    (b) In delegating implementation and enforcement authority of this 
subpart to a state, local, or tribal agency, the Administrator retains 
the authorities listed in paragraphs (b)(1) through (5) of this section 
and does not transfer them to the state, local, or tribal agency. In 
addition, the EPA retains oversight of this subpart and can take 
enforcement actions, as appropriate.
    (1) Approval of alternatives to the emission standards.
    (2) Approval of major alternatives to test methods.
    (3) Approval of major alternatives to monitoring.
    (4) Approval of major alternatives to recordkeeping and reporting.
    (5) Performance test and data reduction waivers under Sec.  
60.8(b).

[[Page 64656]]

Sec.  60.5580  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 subpart A (general 
provisions of this part).
    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.
    Coal means all solid fuels classified as anthracite, bituminous, 
subbituminous, or lignite by ASTM International in ASTM D388-99 
(Reapproved 2004) [egr]1 (incorporated by reference, see 
Sec.  60.17), coal refuse, and petroleum coke. Synthetic fuels derived 
from coal for the purpose of creating useful heat, including, but not 
limited to, solvent-refined coal, gasified coal (not meeting the 
definition of natural gas), coal-oil mixtures, and coal-water mixtures 
are included in this definition for the purposes of this subpart.
    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 
(HRSG) to generate additional electricity.
    Combined heat and power unit or CHP unit, (also known as 
``cogeneration'') means an electric generating unit that that use 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.
    Design efficiency means the rated overall net efficiency (e.g., 
electric plus useful thermal output) on a lower heating value basis at 
the base load rating, at ISO conditions, and at the maximum useful 
thermal output (e.g., CHP unit with condensing steam turbines would 
determine the design efficiency at the maximum level of extraction and/
or bypass). Design efficiency shall be determined using one of the 
following methods: ASME PTC 22 Gas Turbines (incorporated by reference, 
see Sec.  60.17), ASME PTC 46 Overall Plant Performance (incorporated 
by reference, see Sec.  60.17) or ISO 2314 Gas turbines--acceptance 
tests (incorporated by reference, see Sec.  60.17).
    Distillate oil means fuel oils that comply with the specifications 
for fuel oil numbers 1 and 2, as defined by ASTM International in ASTM 
D396-98 (incorporated by reference, see Sec.  60.17); diesel fuel oil 
numbers 1 and 2, as defined by ASTM International in ASTM D975-08a 
(incorporated by reference, see Sec.  60.17); kerosene, as defined by 
ASTM International in ASTM D3699 (incorporated by reference, see Sec.  
60.17); biodiesel as defined by ASTM International in ASTM D6751 
(incorporated by reference, see Sec.  60.17); or biodiesel blends as 
defined by ASTM International in ASTM D7467 (incorporated by reference, 
see Sec.  60.17).
    Electric Generating units or EGU means any steam generating unit, 
IGCC unit, or stationary combustion turbine that is subject to this 
rule (i.e., meets the applicability criteria)
    Fossil fuel means natural gas, petroleum, coal, and any form of 
solid, liquid, or gaseous fuel derived from such material for the 
purpose of creating useful heat.
    Gaseous fuel means any fuel that is present as a gas at ISO 
conditions and includes, but is not limited to, natural gas, refinery 
fuel gas, process gas, coke-oven gas, synthetic gas, and gasified coal.
    Gross energy output means:
    (1) For stationary combustion turbines and IGCC, the gross electric 
or direct mechanical output from both the EGU (including, but not 
limited to, output from steam turbine(s), combustion turbine(s), and 
gas expander(s)) plus 100 percent of the useful thermal output.
    (2) For steam generating units, the gross electric or mechanical 
output from the affected EGU(s) (including, but not limited to, output 
from steam turbine(s), combustion turbine(s), and gas expander(s)) 
minus any electricity used to power the feedwater pumps plus 100 
percent of the useful thermal output;
    (3) For combined heat and power facilities where at least 20.0 
percent of the total gross energy output consists of electric or direct 
mechanical output and 20.0 percent of the total gross energy output 
consists of useful thermal output on a 12-operating-month rolling 
average basis, the gross electric or mechanical output from the 
affected EGU (including, but not limited to, output from steam 
turbine(s), combustion turbine(s), and gas expander(s)) minus any 
electricity used to power the feedwater pumps (the electric auxiliary 
load of boiler feedwater pumps is not applicable to IGCC facilities), 
that difference divided by 0.95, plus 100 percent of the useful thermal 
output.
    Heat recovery steam generating unit (HRSG) means an EGU 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.
    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 the affected EGU 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 EGU during operation.
    ISO conditions means 288 Kelvin (15[deg]C), 60 percent relative 
humidity and 101.3 kilopascals pressure.
    Liquid fuel means any fuel that is present as a liquid at ISO 
conditions and includes, but is not limited to, distillate oil and 
residual oil.
    Mechanical output means the useful mechanical energy that is not 
used to operate the affected EGU(s), generate electricity and/or 
thermal energy, or to enhance the performance of the affected EGU. 
Mechanical energy measured in horsepower hour should be converted into 
MWh by multiplying it by 745.7 then dividing by 1,000,000.
    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. 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 CO2 content or 
heating value.
    Net-electric sales means:
    (1) The gross electric sales to the utility power distribution 
system minus purchased power; or
    (2) For combined heat and power facilities where at least 20.0 
percent of the total gross energy output consists of electric or direct 
mechanical output and at least 20.0 percent of the total gross energy 
output consists of useful thermal output on an annual basis, the gross 
electric sales to the utility power

[[Page 64657]]

distribution system minus purchased power of the thermal host facility 
or facilities.
    (3) Electricity supplied to other facilities that produce 
electricity to offset auxiliary loads are included when calculating 
net-electric sales.
    (4) Electric sales that that result from a system emergency are not 
included when calculating net-electric sales.
    Net-electric output means the amount of gross generation the 
generator(s) produces (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 EGU 
plus 100 percent of the useful thermal output; or
    (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.
    Operating month means a calendar month during which any fuel is 
combusted in the affected EGU at any time.
    Petroleum means crude oil or a fuel derived from crude oil, 
including, but not limited to, distillate and residual oil.
    Potential electric output means 33 percent or the base load rating 
design efficiency at the maximum electric production rate (e.g., CHP 
units with condensing steam turbines will operate at maximum electric 
production), whichever is greater, multiplied by the base load rating 
(expressed in MMBtu/h) of the EGU, multiplied by 10\6\ Btu/MMBtu, 
divided by 3,413 Btu/KWh, divided by 1,000 kWh/MWh, and multiplied by 
8,760 h/yr (e.g., a 35 percent efficient affected EGU with a 100 MW 
(341 MMBtu/h) fossil fuel heat input capacity would have a 306,000 MWh 
12-month potential electric output capacity).
    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.
    Solid fuel means any fuel that has a definite shape and volume, has 
no tendency to flow or disperse under moderate stress, and is not 
liquid or gaseous at ISO conditions. This includes, but is not limited 
to, coal, biomass, and pulverized solid fuels.
    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 emission 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. A stationary 
combustion turbine that burns any solid fuel directly 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 EGU(s) or 
auxiliary equipment.
    System emergency means any abnormal system condition that the 
Regional Transmission Organizations (RTO), Independent System Operators 
(ISO) or control area Administrator determines requires immediate 
automatic or manual action to prevent or limit loss of transmission 
facilities or generators that could adversely affect the reliability of 
the power system and therefore call for maximum generation resources to 
operate in the affected area, or for the specific affected EGU to 
operate to avert loss of load.
    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 to part 75), and for on-
going quality assurance, the provisions in section 2.1.6 of appendix D 
to part 75 apply (except for qualifying commercial billing meters).
    Violation means a specified averaging period over which the 
CO2 emissions rate is higher than the applicable emissions 
standard located in Table 1 or 2 of this subpart.

[[Page 64658]]



  Table 1 of Subpart TTTT of Part 60--CO[ihel2] Emission Standards for
  Affected Steam Generating Units and Integrated Gasification Combined
 Cycle Facilities That Commenced Construction After January 8, 2014 and
           Reconstruction or Modification After June 18, 2014
     [Note: Numerical values of 1,000 or greater have a minimum of 3
   significant figures and numerical values of less than 1,000 have a
                    minimum of 2 significant figures]
------------------------------------------------------------------------
              Affected EGU                 CO[ihel2] Emission standard
------------------------------------------------------------------------
Newly constructed steam generating unit  640 kg CO2/MWh of gross energy
 or integrated gasification combined      output (1,400 lb CO2/MWh).
 cycle (IGCC).
Reconstructed steam generating unit or   910 kg of CO2 per MWh of gross
 IGCC that has base load rating of        energy output (2,000 lb CO2/
 2,100 GJ/h (2,000 MMBtu/h) or less.      MWh).
Reconstructed steam generating unit or   820 kg of CO2 per MWh of gross
 IGCC that has a base load rating         energy output (1,800 lb CO2/
 greater than 2,100 GJ/h (2,000 MMBtu/    MWh).
 h).
Modified steam generating unit or IGCC.  A unit-specific emission limit
                                          determined by the unit's best
                                          historical annual CO2 emission
                                          rate (from 2002 to the date of
                                          the modification); the
                                          emission limit will be no
                                          lower than:
                                            1. 1,800 lb CO2/MWh-gross
                                             for units with a base load
                                             rating greater than 2,000
                                             MMBtu/h; or
                                            2. 2,000 lb CO2/MWh-gross
                                             for units with a base load
                                             rating of 2,000 MMBtu/h or
                                             less.
------------------------------------------------------------------------


 Table 2 of Subpart TTTT of Part 60--CO2 Emission Standards for Affected
Stationary Combustion Turbines That Commenced Construction After January
 8, 2014 and Reconstruction After June 18, 2014 (Net Energy Output-Based
         Standards Applicable as Approved by the Administrator)
     [Note: Numerical values of 1,000 or greater have a minimum of 3
   significant figures and numerical values of less than 1,000 have a
                    minimum of 2 significant figures]
------------------------------------------------------------------------
              Affected EGU                    CO2 Emission standard
------------------------------------------------------------------------
Newly constructed or reconstructed       450 kg of CO2 per MWh of gross
 stationary combustion turbine that       energy output (1,000 lb CO2/
 supplies more than its design            MWh); or
 efficiency or 50 percent, whichever is  470 kilograms (kg) of CO2 per
 less, times its potential electric       megawatt-hour (MWh) of net
 output as net-electric sales on both a   energy output (1,030 lb/MWh).
 12-operating month and a 3-year
 rolling average basis and combusts
 more than 90% natural gas on a heat
 input basis on a 12-operating-month
 rolling average basis.
Newly constructed or reconstructed       50 kg CO2 per gigajoule (GJ) of
 stationary combustion turbine that       heat input (120 lb CO2/MMBtu).
 supplies its design efficiency or 50
 percent, whichever is less, times its
 potential electric output or less as
 net-electric sales on either a 12-
 operating month or a 3-year rolling
 average basis and combusts more than
 90% natural gas on a heat input basis
 on a 12-operating-month rolling
 average basis.
Newly constructed and reconstructed      50 kg CO2/GJ of heat input (120
 stationary combustion turbine that       lb/MMBtu) to 69 kg CO2/GJ of
 combusts 90% or less natural gas on a    heat input (160 lb/MMBtu) as
 heat input basis on a 12-operating-      determined by the procedures
 month rolling average basis.             in Sec.   60.5525.
------------------------------------------------------------------------


 Table 3 to Subpart TTTT of Part 60--Applicability of Subpart A of Part 60 (General Provisions) to Subpart TTTT
----------------------------------------------------------------------------------------------------------------
    General  provisions
         citation              Subject of citation         Applies to subpart TTTT             Explanation
----------------------------------------------------------------------------------------------------------------
Sec.   60.1...............  Applicability............  Yes............................
Sec.   60.2...............  Definitions..............  Yes............................  Additional terms defined
                                                                                         in Sec.   60.5580.
Sec.   60.3...............  Units and Abbreviations..  Yes............................
Sec.   60.4...............  Address..................  Yes............................  Does not apply to
                                                                                         information reported
                                                                                         electronically through
                                                                                         ECMPS. Duplicate
                                                                                         submittals are not
                                                                                         required.
Sec.   60.5...............  Determination of           Yes............................
                             construction or
                             modification.
Sec.   60.6...............  Review of plans..........  Yes............................
Sec.   60.7...............  Notification and           Yes............................  Only the requirements to
                             Recordkeeping.                                              submit the
                                                                                         notifications in Sec.
                                                                                         60.7(a)(1) and (3) and
                                                                                         to keep records of
                                                                                         malfunctions in Sec.
                                                                                         60.7(b), if applicable.
Sec.   60.8...............  Performance tests........  No.............................
Sec.   60.9...............  Availability of            Yes............................
                             Information.
Sec.   60.10..............  State authority..........  Yes............................
Sec.   60.11..............  Compliance with standards  No.............................
                             and maintenance
                             requirements.
Sec.   60.12..............  Circumvention............  Yes............................
Sec.   60.13..............  Monitoring requirements..  No.............................  All monitoring is done
                                                                                         according to part 75.

[[Page 64659]]

 
Sec.   60.14..............  Modification.............  Yes (steam generating units and
                                                        IGCC facilities).
                                                       No (stationary combustion
                                                        turbines.
Sec.   60.15..............  Reconstruction...........  Yes............................
Sec.   60.16..............  Priority list............  No.............................
Sec.   60.17..............  Incorporations by          Yes............................
                             reference.
Sec.   60.18..............  General control device     No.............................
                             requirements.
Sec.   60.19..............  General notification and   Yes............................  Does not apply to
                             reporting requirements.                                     notifications under
                                                                                         Sec.   75.61 or to
                                                                                         information reported
                                                                                         through ECMPS.
----------------------------------------------------------------------------------------------------------------

PART 70--STATE OPERATING PERMIT PROGRAMS

0
4. The authority citation for part 70 continues to read as follows:

    Authority:  42 U.S.C. 7401, et seq.


0
5. In Sec.  70.2, the definition of ``Regulated pollutant (for 
presumptive fee calculation)'' is amended by:
0
a. Revising the introductory text;
0
b. Removing ``or'' from the end of paragraph (2);
0
c. Removing the period at the end of paragraph (3) and adding ``; or'' 
in its place; and
0
d. Adding paragraph (4).
    The revision and additions read as follows:


Sec.  70.2  Definitions.

* * * * *
    Regulated pollutant (for presumptive fee calculation), which is 
used only for purposes of Sec.  70.9(b)(2), means any regulated air 
pollutant except the following:
* * * * *
    (4) Greenhouse gases.
* * * * *

0
6. Section 70.9 is amended by revising paragraph (b)(2)(i), and adding 
paragraph (b)(2)(v) to read as follows:


Sec.  70.9  Fee determination and certification.

* * * * *
    (b) * * *
    (2)(i) The Administrator will presume that the fee schedule meets 
the requirements of paragraph (b)(1) of this section if it would result 
in the collection and retention of an amount not less than $25 per year 
[as adjusted pursuant to the criteria set forth in paragraph (b)(2)(iv) 
of this section] times the total tons of the actual emissions of each 
regulated pollutant (for presumptive fee calculation) emitted from part 
70 sources and any GHG cost adjustment required under paragraph 
(b)(2)(v) of this section.
* * * * *
    (v) GHG cost adjustment. The amount calculated in paragraph 
(b)(2)(i) of this section shall be increased by the GHG cost adjustment 
determined as follows: For each activity identified in the following 
table, multiply the number of activities performed by the permitting 
authority by the burden hours per activity, and then calculate a total 
number of burden hours for all activities. Next, multiply the burden 
hours by the average cost of staff time, including wages, employee 
benefits and overhead.

------------------------------------------------------------------------
                                                                Burden
                          Activity                            hours  per
                                                                activity
------------------------------------------------------------------------
GHG completeness determination (for initial permit or                 43
 updated application).......................................
GHG evaluation for a permit modification or related permit             7
 action.....................................................
GHG evaluation at permit renewal............................          10
------------------------------------------------------------------------

* * * * *

PART 71--FEDERAL OPERATING PERMIT PROGRAMS

0
7. The authority citation for part 71 continues to read as follows:

    Authority:  42 U.S.C. 7401, et seq.


0
8. In Sec.  71.2, the definition of ``Regulated pollutant (for fee 
calculation)'' is amended by:
0
a. Removing ``or'' from the end of paragraph (2);
0
b. Removing the period at the end of paragraph (3) and adding ``; or'' 
in its place; and
0
b. Adding paragraph (4).
    The revisions and additions read as follows:


Sec.  71.2  Definitions.

* * * * *
    Regulated pollutant (for fee calculation), which is used only for 
purposes of Sec.  71.9(c), means any ``regulated air pollutant'' except 
the following:
* * * * *
    (4) Greenhouse gases.
* * * * *

0
9. Section 71.9 is amended by:
0
a. Revising paragraphs (c)(1), (c)(2)(i), (c)(3), and (c)(4); and
0
b. Adding paragraph (c)(8).
    The revisions and addition read as follows:


Sec.  71.9  Permit fees.

* * * * *
    (c) * * *
    (1) For part 71 programs that are administered by EPA, each part 71 
source shall pay an annual fee which is the sum of:
    (i) $32 per ton (as adjusted pursuant to the criteria set forth in 
paragraph (n)(1) of this section) times the total tons of the actual 
emissions of each regulated pollutant (for fee calculation) emitted 
from the source, including fugitive emissions; and
    (ii) Any GHG fee adjustment required under paragraph (c)(8) of this 
section.
    (2) * * *
    (i) Where the EPA has not suspended its part 71 fee collection 
pursuant to paragraph (c)(2)(ii) of this section, the annual fee for 
each part 71 source shall be the sum of:
    (A) $24 per ton (as adjusted pursuant to the criteria set forth in 
paragraph (n)(1) of this section) times the total tons of the actual 
emissions of each regulated pollutant (for fee calculation) emitted 
from the source, including fugitive emissions; and

[[Page 64660]]

    (B) Any GHG fee adjustment required under paragraph (c)(8) of this 
section.
* * * * *
    (3) For part 71 programs that are administered by EPA with 
contractor assistance, the per ton fee shall vary depending on the 
extent of contractor involvement and the cost to EPA of contractor 
assistance. The EPA shall establish a per ton fee that is based on the 
contractor costs for the specific part 71 program that is being 
administered, using the following formula:

Cost per ton = (E x 32) + [(1 - E) x $C]

    Where E represents EPA's proportion of total effort (expressed as a 
percentage of total effort) needed to administer the part 71 program, 1 
- E represents the contractor's effort, and C represents the contractor 
assistance cost on a per ton basis. C shall be computed by using the 
following formula:

C = [ B + T + N] divided by 12,300,000

    Where B represents the base cost (contractor costs), where T 
represents travel costs, and where N represents nonpersonnel data 
management and tracking costs. In addition, each part 71 source shall 
pay a GHG fee adjustment for each activity as required under paragraph 
(c)(8) of this section.
    (4) For programs that are delegated in part, the fee shall be 
computed using the following formula:

Cost per ton = (E x 32) + (D x 24) + [(1 - E - D) x $C]

    Where E and D represent, respectively, the EPA and delegate agency 
proportions of total effort (expressed as a percentage of total effort) 
needed to administer the part 71 program, 1 - E - D represents the 
contractor's effort, and C represents the contractor assistance cost on 
a per ton basis. C shall be computed using the formula for contractor 
assistance cost found in paragraph (c)(3) of this section and shall be 
zero if contractor assistance is not utilized. In addition, each part 
71 source shall pay a GHG fee adjustment for each activity as required 
under paragraph (c)(8) of this section.
* * * * *
    (8) GHG fee adjustment. The annual fee shall be increased by a GHG 
fee adjustment for any source that has initiated an activity listed in 
the following table since the fee was last paid. The GHG fee adjustment 
shall be equal to the set fee provided in the table for each activity 
that has been initiated since the fee was last paid:

------------------------------------------------------------------------
                          Activity                              Set fee
------------------------------------------------------------------------
GHG completeness determination (for initial permit or             $2,236
 updated application).......................................
GHG evaluation for a permit modification or related permit           364
 action.....................................................
GHG evaluation at permit renewal............................         520
------------------------------------------------------------------------

* * * * *

PART 98--MANDATORY GREENHOUSE GAS REPORTING

0
10. The authority citation for part 98 is revised to read as follows:

    Authority:  42 U.S.C. 7401-7671q.


0
11. Section 98.426 is amended by adding paragraph (h) to read as 
follows:


Sec.  98.426  Data reporting requirements.

* * * * *
    (h) If you capture a CO2 stream from an electricity 
generating unit that is subject to subpart D of this part and transfer 
CO2 to any facilities that are subject to subpart RR of this 
part, you must:
    (1) Report the facility identification number associated with the 
annual GHG report for the subpart D facility;
    (2) Report each facility identification number associated with the 
annual GHG reports for each subpart RR facility to which CO2 
is transferred; and
    (3) Report the annual quantity of CO2 in metric tons 
that is transferred to each subpart RR facility.

0
12. Section 98.427 is amended by adding paragraph (d) to read as 
follows:


Sec.  98.427  Records that must be retained.

* * * * *
    (d) Facilities subject to Sec.  98.426(h) must retain records of 
CO2 in metric tons that is transferred to each subpart RR 
facility.

[FR Doc. 2015-22837 Filed 10-22-15; 8:45 am]
 BILLING CODE 6560-50-P


