               EO 12866_111(b) New-Mods 2060-AQ91 Final_20150507
                                                                        6560-50

ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 60, 70, 71, and 98
[EPA-HQ-OAR-2013-0495; EPA-HQ-OAR-2013-0603; FRL-XXXX-XX-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.
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. 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 [insert date 60 days after date of publication in the federal register].
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
ASTM			American Society for Testing of Materials
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
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
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
SDWA			Safe Drinking Water Act
SF6			Sulfur Hexafluoride
SIP			State Implementation Plan
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. Carbon Pollution Standards for Fossil Fuel-Fired Electric Utility Generating Units
G. Stakeholder Engagement and Public Comments on the Proposals
III. Regulatory Authority, Affected Sources 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
   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. Partial CCS as the BSER for Newly Constructed Steam Generating Units
C. Rationale for the Final Emission Standards
D. Post-Combustion CCS
E. Pre-Combustion CCS
F. Vendor Guarantees, Industry Statements, Academic Literature, and Commercial Availability
G. Response to Key Comments
H. Consideration of Costs
I. Key Comments Regarding EPA's Consideration of Costs
J. Achievable Emission Reductions Utilizing Partial CCS
K. Further Development and Deployment of CCS Technology
L. Geologic and Geographic Considerations
M. Final Requirements for Disposition of Captured CO2
N. Options That Were Considered but Were Ultimately Not Determined to Be the BSER
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, Modified, and Reconstructed Stationary Combustion Turbines
A. Applicability Requirements
B. Best System of Emission Reduction
C. Final Emission Standards
IX. Rationale for Final Standards for Newly Constructed, Modified, and Reconstructed Stationary Combustion Turbines
A. Applicability
B. Identification of the Best System of Emission Reduction
C. Achievability of the Final Standards
X. Summary of Other Final Requirements for Newly Constructed, Modified, and Reconstructed Fossil Fuel-fired 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 Newly Constructed, Modified, and Reconstructed Fossil Fuel-fired Steam Generating Units and Natural Gas-fired Stationary Combustion Turbines
XI. 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
XII. 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?
XIII. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and Executive Order 13563: Improving Regulation and Regulatory Review
B. Paperwork Reduction Act (PRA)
C. Regulatory Flexibility Act (RFA)
D. Unfunded Mandates Reform Act (UMRA)
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation and Coordination with Indian Tribal Governments
G. Executive Order 13045: Protection of Children From Environmental Health Risks and Safety Risks
H. Executive Order 13211: Actions Concerning Regulations that Significantly Affect Energy Supply, Distribution, or Use
I. National Technology Transfer and Advancement Act (NTTAA)
J. Executive Order 12898: Federal Actions to Address Environmental Justice in Minority Populations and Low-Income Populations
K. Congressional Review Act (CRA)
   
XIV. Statutory Authority
 I. General Information
A. Executive Summary
1. Purpose of the Regulatory Action 
      This action finalizes regulatory requirements to 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 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, EPA Administrator Gina McCarthy signed 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"). 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. 
      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, Administrator McCarthy signed 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 34959 (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 greenhouse gas (GHG) pollution manifested as CO2 from newly constructed, modified, and reconstructed fossil fuel-fired electric utility steam generating units and from newly constructed, modified, 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.
      In a separate action that affects the same source category, 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. States must then 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 some 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 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.
Table 1. Summary of BSER and Final Standards for Affected Sources
                                Affected Source
                                     BSER
                                   Standard
Newly Constructed Fossil Fuel-Fired Steam Generating Units
Partial carbon capture and storage (CCS)
1,400 lb CO2/MWh-gross.
Modified Fossil Fuel-Fired Steam Generating Units
Most efficient generation at the affected source achievable through a combination of best operating practices and equipment upgrades 
Sources making modifications
resulting in an increase in potential CO2 hourly emissions of more than 10 percent are required to meet 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 sources with heat input > 2,000 MMBtu/h.
   OR
2.	2,000 lb CO2/MWh-gross for sources with heat input <= 2,000 MMBtu/h.
Reconstructed Fossil Fuel-Fired Steam Generating Units
Most efficient generating technology
at the 
affected
source (supercritical steam conditions for the larger; and subcritical conditions for the smaller) 
1. Sources with heat input > 2,000 MMBtu/h are required to meet an emission limit of 1,800 lb CO2/MWh-gross.
2. Sources with heat input <= 2,000 MMBtu/h are required to meet an emission limit of 2,000 lb CO2/MWh-gross.
Newly Constructed, Modified, and Reconstructed Fossil Fuel-Fired Stationary Combustion Turbines
Efficient NGCC technology 
   1.    1,000 lb CO2/MWh-gross or
   2.    1,080 lb CO2/MWh-net

a. Fossil fuel-fired electric utility steam generating units. 
      This action finalizes standards of performance for newly constructed fossil fuel-fired steam generating units based on partial carbon capture and storage (CCS) which the EPA determines to be the BSER for these sources. After consideration of the 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 remains convinced that CCS technology is available and technically feasible to implement at fossil fuel-fired steam generating units. However, the EPA's final standard does recognize that the proposed standards should be adjusted to address legitimate concerns regarding the cost to implement the 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-gross, a level that is less stringent than the proposed limitation (which was at 1,100 lb CO2/MWh-gross). This final standard reflects our identification of the BSER for such units to be a lower level of partial CCS than was the basis of the proposed standards  -  one that we conclude better represents the requirement that the BSER technology be implementable at reasonable costs. 
      The EPA proposed and reaffirms here that this system is the BSER because CCS has been demonstrated to be technically feasible and is in use or under construction in various industrial sectors including power generation. 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. In addition, partial CCS designed to meet the final emission standard will promote implementation and further development of CCS technologies. A newly constructed conventional coal-fired utility boiler burning bituminous coal will be able to meet this standard of performance by capturing and storing approximately 20 percent of the CO2 produced from the facility. Many IGCC units will be able to meet the final standard of performance by capturing and storing less than 10 percent of the CO2 produced by the facility. All steam generating sources may also be able to meet the standard through alternative actions, such as the use of natural gas co-firing. 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 greenhouse gas emissions and supports technological innovation. The standard of 1,400 lb CO2/MWh-gross is achievable by fossil fuel-fired steam generating units for all fuel types, under a wide range of conditions, and throughout the United States.
      We note that identifying CCS as BSER can provide a path forward for fossil steam generation in the current market context. Numerous studies have found that few new fossil-fuel fired steam generating units will be constructed in the future for multiple reasons, 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 steam units despite these market conditions: in particular, to achieve or maintain fuel diversity within generating fleets and hedge against the possibility of natural gas prices far exceeding projections or to generate both power and chemicals, including CO2 for use in enhanced oil recovery projects. As regulatory history has shown, identifying CCS as BSER in this rule will likely further boost research and developments in this technology, making its application even more efficacious and cost-effective  -  and providing a competitive, low emission future for fossil steam generation.
      The EPA is also issuing final standards for steam generating units that implement "large modifications", (i.e., modifications resulting in an increase in potential hourly CO2 emissions of more than 10 percent when compared to the source's potential in the previous 5 years). The EPA is not issuing standards, at this time, for steam generating units that implement "small modifications" (i.e., modifications resulting in an increase in potential hourly CO2 emissions of less than or equal to 10 percent when compared to the source's potential in the previous 5 years). 
      The standards of performance for the 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). 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 a 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-gross for units with heat input greater than 2,000 MMBtu/h and 2,000 lb CO2/MWh-gross for units with heat input less than or equal to 2,000 MMBtu/h).
      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 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, modified steam generating sources that make modifications resulting in an potential increase of hourly CO2 emissions of less than or equal to 10 percent. 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 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 that may result from these changes. In particular, we do not have sufficient information about the types of modifications 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 of performance 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.) The emission standard for these sources is 1,800 lb CO2/MWh-gross for large sources, (i.e. those with a heat input rating of greater than 2,000 MMBtu/h) or 2,000 lb CO2/MWh-gross 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 technology options such as natural gas co-firing.
b. Stationary combustion turbines. This action also finalizes standards of performance for newly constructed, modified, and reconstructed stationary combustion turbines. The EPA originally proposed that newly constructed, modified, or reconstructed stationary combustion turbines would be subject to a standard of performance if they are constructed for the purpose of and actually sell one-third or more of their potential electric output and 219,000 MWh to the grid. Later, in the June 2014 proposal for modified and reconstructed sources, the EPA solicited comment on alternative approaches, including eliminating the 219,000 MWh electric sales criterion, the constructed for the purpose of criterion, and replacing the one-third sales criterion with an approach that would allow net-electric sales up to the design efficiency of the combustion turbine being installed multiplied by its potential electric output before a standard would apply. These proposed applicability requirements were intended to exclude combustion turbines that are used for the purpose of meeting peak power demand (i.e., "peaking units") as opposed to those that are used to meet intermediate or base load power demand. 
      In this action, the EPA is finalizing a variation of the two approaches put forward in the June 2014 proposal. For newly constructed, modified, or reconstructed stationary combustion turbines the EPA is finalizing a standard of 1,000 lb CO2/MWh-gross based on modern, efficient natural gas combined cycled (NGCC) technology as the BSER. However, the final applicability excludes units subject to a federally enforceable permit that restrict annual net-electric sales to the design net efficiency of the combustion turbine (not to exceed 40 percent) multiplied by the potential electric output of the combustion turbine. For example, a stationary combustion turbine with a design net efficiency of 38 percent (on a higher heating value (HHV) basis) would be able to request a permit restriction to allow it to sell up to 38 percent of its potential electric output without becoming subject to this final standard.
      The EPA previously proposed to divide intermediate and base load stationary combustion turbines into two subcategories based on their size (as determined by heat input rating) and to set separate standards of performance for each of those subcategories. Based on our review of the comments on the proposed subcategories and standards and additional data analysis, however, we have determined that there is no need to set separate standards for different sizes of combustion turbines. The EPA has determined that all sizes of affected newly constructed, modified, and reconstructed stationary combustion turbines will be able to achieve the final standard.
      Stationary combustion turbines that are physically incapable of combusting natural gas, such as turbines in certain non-continental locations or in remote locations that lack access to a natural gas pipeline, will be exempt from the standard entirely.
      A more detailed discussion of the final standards of performance, 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 more likely to be NGCC and that any coal-fired steam generating units built between now and 2020 would have CCS, even in the absence of this rule. 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. However, 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. 
      As explained in the RIA for this final rule and further below, the EPA has been notified of few power sector NSPS modifications or reconstructions; and, 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]
                                        
                                   Category
                                        
                                  NAICS Code
                                        
                   Examples of Potentially Affected Entities
                                       
                                   Industry
                                        
                                    221112
                                        
                 Fossil fuel electric power generating units.
                                       
                              Federal Government
                                        
                                   221112[b]
                                        
 Fossil fuel electric power generating units owned by the federal government.
                                       
                            State/Local Government
                                       
                                        
                                   221112[b]
                                        
     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 40 CFR 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 [insert date 60 days after publication in federal register]. Under section 307(d)(7)(B) of the CAA, only an objection to this final rule that was raised with reasonable specificity during the period for public comment can be raised during judicial review. 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 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 for us to convene a proceeding for reconsideration, "[i]f the person raising an objection can demonstrate to the EPA 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 to us 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 natural gas-fired 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 authority to regulate CO2 and EGUs, identifies affected sources, 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, modified, and reconstructed combustion turbines. 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. Interactions with other EPA programs and rules are described in Section XI. Projected impacts of the final action are then described in Section XII, followed by a discussion of statutory and executive order reviews in Section XIII and the statutory authority for this action in Section XIV. We address major comments throughout this preamble and in greater detail in an accompanying response to comments document located in the docket.
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, explain the uniqueness of the utility power sector, and describe recent and continuing trends and transitions in this sector. 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." 
      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). 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. 
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., including 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 flooding damage to property or even loss of land due to inundation or erosion; as well as 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 21[st] century. Though some benefits may balance adverse effects on agriculture and forestry in the next few decades, the body of evidence points towards increasing risks of net adverse impacts on U.S. food production, agriculture and forest productivity as temperature continues to rise. These impacts are global and may exacerbate problems outside the U.S. that raise humanitarian, trade, and national security issues for the U.S.
3. New Scientific Assessments and Observations
      Since the administrative record concerning the Endangerment Finding closed following the EPA's 2010 Reconsideration Denial, the climate has continued to change, with new records being set for a number of climate indicators such as global average surface temperatures, Arctic sea ice retreat, CO2 concentrations, and sea level rise. Additionally, a number of major scientific assessments have been released that improve understanding of the climate system and strengthen the case that GHGs endanger public health and welfare both for current and future generations. These assessments, from the Intergovernmental Panel on Climate Change (IPCC), the U.S. Global Change Research Program (USGCRP), and the National Research Council (NRC), include: IPCC's 2012 Special Report on Managing the Risks of Extreme Events and Disasters to Advance Climate Change Adaptation (SREX) and the 2013-2014 Fifth Assessment Report (AR5), the USGCRP's 2014 National Climate Assessment, Climate Change Impacts in the United States (NCA3), and the NRC's 2010 Ocean Acidification: A National Strategy to Meet the Challenges of a Changing Ocean (Ocean Acidification), 2011 Report on Climate Stabilization Targets: Emissions, Concentrations, and Impacts over Decades to Millennia (Climate Stabilization Targets), 2011 National Security Implications for U.S. Naval Forces (National Security Implications), 2011 Understanding Earth's Deep Past: Lessons for Our Climate Future (Understanding Earth's Deep Past), 2012 Sea Level Rise for the Coasts of California, Oregon, and Washington: Past, Present, and Future, 2012 Climate and Social Stress: Implications for Security Analysis (Climate and Social Stress), and 2013 Abrupt Impacts of Climate Change (Abrupt Impacts) assessments. 
      The EPA has carefully reviewed these recent assessments in keeping with the same approach outlined in Section VIII.A. of the 2009 Endangerment Finding, which was to rely primarily upon the major assessments by the USGCRP, the IPCC, and the NRC of the National Academies to provide the technical and scientific information to inform the Administrator's judgment regarding the question of whether GHGs endanger public health and welfare. These assessments addressed the scientific issues that the EPA was required to examine, were comprehensive in their coverage of the GHG and climate change issues, and underwent rigorous and exacting peer review by the expert community, as well as rigorous levels of U.S. government review. 
      The findings of the recent scientific assessments confirm and strengthen the conclusion that GHGs endanger public health, now and in the future. The NCA3 indicates that human health in the 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."  In addition, increasing temperatures and loss of Arctic sea ice increases the risk of drowning for those engaged in traditional hunting and fishing.
       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. 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." Because of these unprecedented changes, several assessments state that we may be approaching critical, poorly understood thresholds: as stated in the NRC assessment Understanding Earth's Deep Past, "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." 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. Future temperature changes will depend on what emission path the world follows. In its high emission scenario, the IPCC AR5 projects that global temperatures by the end of the century will likely be 2.6 degrees Celsius (°C) to 4.8 °C (4.7 to 8.6 degrees Fahrenheit (°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 impacts 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 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 °C (1.8 °F) of warming. For 3 °C of warming, the assessment found that 9 out of 10 summers would be warmer than all but the 5 percent of warmest summers today, leading to increased frequency, duration, and intensity of heat waves. Extrapolations by the NCA also indicate that Arctic sea ice in summer may essentially disappear by mid-century. Retreating snow and ice, and emissions of carbon dioxide and methane released from thawing permafrost, will also amplify future warming. 
      Since the 2009 Endangerment Finding, the USGCRP NCA3, and multiple NRC assessments have projected future rates of sea level rise that are 40 percent larger to more than twice as large as the previous estimates from the 2007 IPCC 4[th] 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," and the NRC Climate Stabilization Targets assessment states that an increase of 3 °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." Also, because of the inertia of the oceans, sea level rise will continue for centuries after greenhouse gas 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 carbon dioxide levels could be sufficient to exceed that threshold.
      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 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 United States. 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." 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." 
      Carbon dioxide in particular has unique impacts on ocean ecosystems. The NRC Climate Stabilization Targets assessment found that coral bleaching will increase due both to warming and ocean acidification. Ocean surface waters have already become 30 percent more acidic over the past 250 years due to absorption of CO2 from the atmosphere. According to the NCA3, this acidification will reduce the ability of organisms such as corals, krill, oysters, clams, and crabs to survive, grow, and reproduce. The NRC Understanding Earth's Deep Past assessment notes four of the five major coral reef crises of the past 500 million years were caused by acidification and warming that followed GHG increases of similar magnitude to the emissions increases expected over the next hundred years. Similarly, the NRC Ocean Acidification assessment finds that "[t]he chemistry of the ocean is changing at an unprecedented rate and magnitude due to anthropogenic carbon dioxide emissions; the rate of change exceeds any known to have occurred for at least the past hundreds of thousands of years." 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."    
      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 cites Egypt and Pakistan as two case studies of potential security issues linked to climate change within the next 10 years; 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 °C (1.5 °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-20[th] 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 1,400 years. U.S. average temperatures have similarly increased by 1.3 to 1.9 degrees F since 1895, with most of that increase occurring since 1970. Global sea levels rose 0.19 m (7.5 inches) from 1901 to 2010. Contributing to this rise was the warming of the oceans and melting of land ice. It is likely that 275 Gt/year of ice melted from land glaciers (not including ice sheets) since 1993, and that the rate of loss of ice from the Greenland and Antarctic ice sheets increased substantially in recent years, to 215 Gt/year and 147 Gt/year respectively since 2002. 360 Gt of ice melt will 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 °C (5.4 °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. 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. 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 20[th] century prior to 1993. 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. The first months of 2015 have also been some of the warmest on record. 
      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." For example:
         *          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 8 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 °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 US region. 
      In the future, if emissions continue increasing, the Northeast is expected to experience 4.5 to 10 °F of warming by the 2080s. This will lead to more heat waves, coastal and river flooding, and intense precipitation events. 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 °F. There have been increasing numbers of days above 95 °F and nights above 75 °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. 
      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 °F or above) and decreases in freezing events, as well as exacerbated ground-level ozone in urban areas. Although projected warming for some parts of the region by the year 2100 are generally smaller than for other regions of the United States, projected warming for interior states of the region are larger than coastal regions by 1 °F to 2 °F. Projections further suggest that globally there will be fewer tropical storms, but that they will be more intense, with more Category 4 and 5 storms. The NCA identified New Orleans, Miami, Tampa, Charleston, and Virginia Beach as being specific cities that are at risk due to sea level rise, with additional impacts on coastal highways, wetlands, and energy and water supplies.
      In the Northwest, temperatures increased by about 1.3[o]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[o]F to 9.7[o]F by the end of the century (depending on future global greenhouse gas emissions), with the greatest warming is expected during the summer. Continued increases in global greenhouse gas emissions are projected to result in up to a 30 percent decrease in summer precipitation. Earlier snowpack melt and lower summer streamflows 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. Forest pests are expected to spread and wildfires burn larger areas. Other high-elevation ecosystems are projected to be lost because they can no longer survive the climatic conditions. Low lying coastal areas, including the cities of Seattle and Olympia, will experience heightened risks of sea level rise, erosion, seawater inundation and damage to infrastructure and coastal ecosystems.
      In Alaska, temperatures have changed faster than anywhere else in the United States. Annual temperatures increased by about 3 °F in the past 60 years. Warming in the winter has been even greater, rising by an average of 6 °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 greenhouse gas emissions are expected to increase temperatures by 10 to 12 °F in the northernmost parts of Alaska, by 8 to 10 °F in the interior, and by 6 to 8 °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 exten - sion 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 °F higher than the past century, and are already the warmest that region has experienced in at least 600 years. The NCA notes that there is evidence that climate-change induced warming on top of recent drought has influenced tree mortality, wildfire frequency and area, and forest insect outbreaks. Sea levels have risen about 7 or 8 inches in this region, contributing to inundation of Highway 101 and backup of seawater into sewage systems in the San Francisco area. 
      Projections indicate that the Southwest will warm an additional 5.5 to 9.5 °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. 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 °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 °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 °F in the Southern Plain and more than 95 °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 °F. As a result of current sea level rise, the coastline of Puerto Rico around Rincón 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 Pacific islands, future sea surface temperatures are projected to increase 2.3 °F by 2055 and 4.7 °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 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 electric utility generating units (EGUs) are by far the largest emitters of GHGs among stationary sources in the U.S., primarily in the form of CO2. 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 (the U.S. GHG Inventory). 
      The EPA implements a separate program under 40 CFR part 98 called the Greenhouse Gas Reporting Program (GHGRP) that requires emitting facilities over threshold amounts of GHGs to report their emissions to 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. 
      The EPA prepares the official U.S. GHG Inventory to comply with commitments under the United Nations Framework Convention on Climate Change (UNFCCC). This inventory, which includes recent trends, is organized by industrial sectors. It provides the information in Table 3 below, which presents total U.S. anthropogenic emissions and sinks of GHGs, including CO2 emissions, for the years 1990, 2005 and 2013.
Table 3. U.S. GHG Emissions and Sinks by Sector (million metric tons carbon dioxide equivalent (MMT CO2 Eq.))

      SECTOR
      1990
      2005
      2013
Energy
                                                                       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. 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. Table 4 below presents total CO2 emissions from fossil fuel-fired EGUs, for years 1990, 2005 and 2013.
Table 4. U.S. GHG Emissions from Generation of Electricity from Combustion of Fossil Fuels (MMT CO2)
                                       
      GHG EMISSIONS
      1990
      2005
      2013

Total CO2 from fossil fuel-fired EGUs
                                                                       1,820.8 
                                                                       2,400.9 
                                                                      2,039.8  
    - from coal
                                                                       1,547.6 
                                                                        1,983.8
                                                                        1,575.0
    - from natural gas
                                                                         175.3 
                                                                         318.8 
                                                                        441.9  
    - from petroleum
                                                                          97.5 
                                                                          97.9 
                                                                          22.4 
 
      In addition to preparing the official U.S. GHG Inventory to present comprehensive total U.S. GHG emissions and comply with commitments under the UNFCCC, the EPA collects detailed GHG emissions data from the largest emitting facilities in the U.S. through its Greenhouse Gas Reporting Program (GHGRP). Data collected by the GHGRP from large stationary sources in the industrial sector show that the utility power sector emits far greater CO2 emissions than any other industrial sector. Table 5 below presents total GHG emissions in 2013 for the largest emitting industrial sectors as reported to the GHGRP. As shown in Table 4 and Table 5, respectively, carbon dioxide 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.
Table 5. Direct GHG Emissions Reported to GHGRP by Largest Emitting Industrial Sectors (MMT CO2e)
Industrial Sector
                                                                           2013
Fossil Fuel-fired EGUs
                                                                      2,039.8  
Petroleum Refineries
Onshore Oil & Gas Production
                                                                          176.7
                                                                           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

	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.
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 provided by other types of generation including nuclear, and renewables such as wind, solar, and hydroelectric power. Coal provided the largest percentage of the fossil fuel generation. 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.. 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). 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. 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. In 2015, the U.S. Energy Information Administration's (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.    
      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. For example, the average age of U.S. coal steam units in 2015 is 45. 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." 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." However, innovative technologies have increasingly entered the electric energy space, helping to provide new answers to how to meet the electricity needs of the nation. These new technologies can enable the nation to answer not just questions as to how to reliably meet electricity demand, but also how to meet electricity demand reliably and cost-effectively with the lowest possible emissions and the greatest efficiency.    
      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. In 2014, natural gas accounted for approximately 27 percent of net generation. 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.
      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). QFs were either cogeneration facilities or small generation resources that use renewables such as wind, solar, biomass, geothermal, or hydroelectric power as their primary fuels. 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. In its AEO 2015 Reference case, EIA found that renewable energy will account for 38 percent of the overall growth in electricity generation from 2013 to 2040. 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. 
      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. 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."  Energy efficiency has been utilized to meet energy demand to varying levels since that time. As of April 2014, 25 states have "enacted long-term (3+ years), binding energy savings targets, or energy efficiency resource standards (EERS)."  Funding for energy efficiency programs has grown rapidly in recent years, with budgets for electric efficiency programs totaling $5.9 billion in 2012.
	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 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). 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 and hydrogen, 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. 
      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 adopted incentives for electric generation from renewable energy sources and loan guarantees for 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.
      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 2020, 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, Southern Company's Kemper County Energy Facility, deploys IGCC with partial CCS. Additionally, two other projects, Summit Power's Texas Clean Energy Project (TCEP) and the Hydrogen Energy California Project (HECA)  -  both of which will deploy IGCC with CCS  -  continue as viable projects. 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 would be built in this decade and that those that are built would have CCS. 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 there are standards in place to make sure that whatever fuel is burned is done so in a way that minimizes CO2 emissions and continues to encourage the development of innovative technologies into the future, as Congress intended with CAA section 111.
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 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. The current report, AEO 2015, (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, 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. 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 2020.
      Specifically, the AEO 2015 projects the need for 28.4 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 10.7 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 impacted by this notice). The AEO 2015 also projects an additional 8 GW of new base load capacity additions, which are model-projected (unplanned). This consists of 7.7 GW of new NGCC capacity, and 0.3 GW of new coal equipped with CCS (incentivized with some government funding). Therefore, the AEO 2015 projection suggests that this final rule would only impact small amounts of new power generating capacity through 2020, all of which is expected to already meet the emissions standards without incurring further control costs. In AEO 2015, 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 standard 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 predict 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. The EPA's projections from IPM can be found in the RIA.
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. These IRPs indicate that companies are focused on demand-side management programs to lower future electricity demand and 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.
      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 these IRPs, the EPA acknowledges that a small number of 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 greenhouse gases (GHGs) meet the definition of "air pollutant" in the CAA, and premised its decision in AEP v. Connecticut 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.
      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). 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. The EPA listed the two source categories at issue here in the 1970s: The EPA listed fossil fuel-fired electric steam generating units in 1971;  and combustion turbines in 1977.
      Once the EPA has listed a source category, the EPA proposes and then promulgates "standards of performance" for "new sources" in the category. 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. 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." The EPA, through regulations, has determined that certain types of changes are exempt from consideration as a modification.
      The The NSPS general provisions (40 CFR Part 60 Subpart A)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. 
      CAA section 111(a)(1) defines a "standard of performance" 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 and any nonair 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 which 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 which 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. Rather, sources generally may select any measure or combination of measures that will achieve the emissions level of the standard. In establishing standards of performance, the EPA has significant discretion to create subcategories based on source type, class or size. 
      The text and legislative history of CAA section 111, as well as relevant court decisions identify the factors for the EPA 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, the EPA must consider the amount of emissions reductions that the system would generate, along with considerations concerning energy and non-air quality pollutants. 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 that as a result, the EPA 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.
      For more than four decades, the EPA has used its authority under CAA section 111 to set cost-effective emission standards that ensure 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 sources and the standards of performance based on these BSER are based on that evaluation. 
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), and  promulgated the first set of standards of performance for sources in that category, which it codified in subpart D. 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), and the EPA promulgated standards of performance for that source category in 1979, which the EPA codified in subpart GG. 
      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. 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. None of these subsequent rulemakings, including the revised codifications, however, constituted a new listing under CAA section 111(b)(1)(A).
      The EPA promulgated amendments to subpart Da in 2006, which included new standards of performance for criteria pollutants for EGUs, but no standards of performance for GHG emissions. Petitioners sought judicial review of the rule by the D.C. Circuit, contending, among other issues, that the rule was required to include standards of performance for GHG emissions from EGUs. The January 8, 2014 preamble to the proposed CO2 standards for new EGUs includes a discussion of the GHG-related litigation of the 2006 Final Rule as well as other GHG-associated litigation.
F. 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 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 the 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), 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.
      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 34959; 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, many of which have been utilities and industry representatives directly related to the electricity sector. 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 the iron and steel and aluminum industries, to help 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, and religious organizations.
      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 our responses to the comments received by the agency.    
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 offered 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 partial CCS was the BSER for newly constructed fossil fuel-fired steam generating EGUs, the level of the CO2 standard based on partial CCS, the criteria that defines 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 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 Sources 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 for all new and modified 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), regulations "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 were previously listed and regulated for other pollutants and 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 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), 231(a)(2)(A).
      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 standard, it is appropriate for 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).  
      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 Fed. Reg. 35838, 35858 (col. 3)(June 24, 2008)(concluding 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 NOX, SO2 and CO from lime plants"); Standards of Performance for Petroleum Refineries, 73 Fed. Reg. 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-fired power plants, which are the major U.S. source of greenhouse gas air pollution, merits 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 denial of petitions to reconsider. In addition, assessments from the NRC, the IPCC, and other organizations published after 2010 lend further credence to the validity of the Endangerment Finding. As discussed below, no information that commenters have presented or that the EPA has reviewed provides a basis for rescinding that finding. 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. 
      Moreover, the high level of GHG emissions from the fossil-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. 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, even if CAA section 111 is interpreted to require that the EPA make endangerment and cause-or-contribute significantly findings as prerequisites for this rulemaking, then, so far as an endangerment finding is concerned, the fact that the EPA has recently made an endangerment finding for GHGs should suffice, and even if not, 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 GHGs 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 determine whether that information has any meaningful impact on our analysis and conclusions. 
      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). Accordingly, that approach would support an endangerment finding for this rulemaking.
      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. In particular, as noted, combustion turbines alone emit 401 million metric tonnes per year, which is more than any other source category except for steam generators, and steam generators emit 1,627 million metric tonnes per year. 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 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. 
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 proposed 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, 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 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 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 finding that the combination of the two categories causes or contributes significantly to air pollution which may reasonably be anticipated to endanger public health or welfare. 
      As discussed above in the regulatory background of CAA section 111(b) actions on EGUs, there are several subparts in the code of federal regulations addressing EGUs (i.e., D, Da, GG, KKKK). This final action codifies all of the requirements promulgated in this final rule for the affected EGUs in a new subpart TTTT of 40 CFR part 60 and includes all GHG emission standards for the affected sources  -  electric utility steam generating units, as well as natural gas-fired stationary combustion turbines -- in that newly created subpart. Combining the emission standards for affected sources into a new subpart TTTT is appropriate because many of the same requirements, including monitoring, reporting, and verification requirements, apply to all of the affected EGUs; and is consistent with the approach being taken for final existing source emission guidelines, in which we codify all of the requirements for the affected EGUs in new subpart UUUU of 40 CFR part 60.
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, integrated gasification combined cycle (IGCC) unit, or combustion turbine (in either simple cycle or combined cycle configuration) that meets the applicability criteria. Affected sources include EGUs 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 be (1) capable of combusting more than 250 MMBtu/h heat input of fossil fuel 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). However, we are not finalizing GHG standards for certain EGUs. The EGUs that are not covered by the standards we are finalizing in this rule include (1) non-fossil units subject to a federally enforceable permit that limits the use of fossil fuels to 10 percent or less of the heat input capacity on an annual basis; (2) combined heat and power units that are subject to a federally enforceable permit limiting annual net electric sales to the product of their design net efficiency times their potential electric output or limiting annual electric sales to 219,000 MWh or less; (3) stationary combustion turbines that are subject to a federally enforceable permit limiting annual net electric sales to the product of their design net efficiency times their potential electric output or less (4) utility boilers and IGCC units that have always been 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; (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. 
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-fired (e.g., biomass) units and industrial combined heat and power (CHP) units. This section discusses these sources and our rationale for not issuing standards for them. Since the rationale applies to both steam generating units and combustion turbines we are describing it here instead of 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 to for these sources.  
1. Dedicated Non-fossil and Biomass Units
      The proposed applicability for newly constructed EGUs included EGUs that primarily combust fossil fuels (e.g., coal, oil and natural gas). The specific applicability criteria was that affected units must burn fossil fuels for more than 10 percent of total heat input on average over a 3-year average. Under the proposed approach, applicability with the final NSPS for GHG emissions could change on an annual basis depending on the composition of fuel burned. We solicited multiple comments on applicability for non-fossil units. Specifically, we solicited comment on a broad applicability approach that would include non-fossil-fired units as affected units but that would impose an alternate standard when the unit fires 10 percent or less fossil fuels of the heat input during the applicable determination period. We solicited comment on whether, if such a subcategory 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."
      Many commenters supported an exclusion for biomass-fired units based on firing no more than 10 percent fossil fuels. Some commenters suggested that exclusion for biomass-fired units should be raised to a 25 percent fossil fuels threshold. Conversely, some commenters supported standards for biomass units because they are typically operated with higher heat rates than coal units and model results conducted by the EPA using IPM show that biomass generation is expected to quadruple over the next 10 years. These commenters said biomass units should be regulated consistently with coal units. One commenter supported the EPA's interest in ensuring that the CO2 standards issued pursuant to CAA section 111(d) continue to apply to existing EGUs when those EGUs modify or reconstruct in ways that cause the units to derive 10 percent or less of their heat input from fossil fuel because the commenter stated that allowing modified and reconstructed EGUs to escape 111(d) standards would undermine the coherence of the proposed 111(d) regulatory system. Some commenters supported a 3-year period for determining applicability; other commenters supported a 12-month rolling period while others supported a one-time determination.
      Some commenters stated that the standard was not developed to include biomass-fired units, and none of the analyses supporting the standard includes biomass-fired units. Commenters also stated that the proposed standard has not been adequately demonstrated as achievable by these units, and the rule offered no basis for regulating sources that combust insignificant amounts of fossil fuels. These commenters suggested that if biomass units must be included under these CAA section 111 standards for fossil fuel units, they should be included in a separate subcategory after a subsequent proposal and comment period based on relevant data from biomass-fired units.  
      Many commenters wanted CO2 emissions from biomass (when co-fired with fossil-fuels) to be excluded from applicability and compliance determinations. These commenters stated that the final national standard for CO2 emissions should encourage the use of biomass-fired units because this will encourage investments in forests which are natural sinks for atmospheric carbon. These commenters said that the EPA should provide a holistic document analyzing all issues relevant to sound policy for treatment of biomass units under GHG regulations after the Revised Framework for Assessing Biogenic CO2 Emissions from Stationary Sources is released and provide stakeholders additional time to comment. Some commenters said that biogenic CO2 from EGUs should be accounted for by adopting the current framework for biogenic emissions under 40 CFR part 98. Other commenters suggested that biomass-fired units should receive credits toward compliance since their biogenic CO2 can be considered sequestered within the forest product inventories and markets where they procure their fuels.
      The EPA has concluded that the proposed applicability based on the actual amount of fossil fuel burned is not a practical approach to define units subject to the rule. Facilities and permitting authorities would not know, when construction is commenced, whether the final NSPS is applicable, and after operation has commenced a unit could move in and out of applicability each year. The intent of this rulemaking is to establish GHG standards for fossil fuel-fired EGUs, not for non-fossil fuel-fired EGUs. Therefore, to clarify compliance and establish GHG standards for fossil fuel-fired EGUs, we have determined this rule will not set GHG emission standards for units subject to a federally enforceable permit that limits the use of fossil fuels to less than 10 percent of the heat input capacity on an annual basis. This approach allows existing fossil fuel-fired steam generating units to modify their operating permits to limit the use of fossil fuels such that the unit would no longer be considered fossil fuel-fired EGUs. The unit would not be subject to the 111(b) GHG requirements in this rulemaking and states would no longer be required to include them in their 111(d) plan. This is consistent with the intent to reduce GHG emissions from fossil fuel-fired EGUs. We considered the fossil use restriction on both an annual and 3-year average. We have concluded that the single year average fossil-fuel use based on the annual capacity factor, and not the actual percent of fossil burned, provides sufficient flexibility for dedicated non-fossil fuel-fired units to combust fossil fuels for flame stabilization and other ancillary purposes. A 3-year exemption based on capacity factor would not cover limited use fossil fuel EGUs, which is not the intent of the provision.
2. Industrial Combined Heat and Power
      Another approach to generating electricity is the use of combined heat and power (CHP) units. A CHP unit can use boiler, combustion turbine, reciprocating engine, and various 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 conventional power generation is recovered as useful thermal output. While the EPA did propose applicability provisions specific to CHP units (e.g., subtract purchased power of adjacent facilities when determining net electric sales), in general the proposed applicability for electric-only units and CHP units was similar. The intent of the proposed net electric sales applicability approach was to cover only utility, and not industrial, CHP. To the extent the proposal's applicability provisions had the effect of including industrial CHP, we solicited comment on an applicability exemption, and the criteria for that exemption, for highly efficient CHP facilities. We also solicited comment on eliminating the 219,000 MWh annual electric sales criterion for stationary combustion turbines based CHP. 
      Many commenters supported exclusion of CHP units as a means of encouraging capital investments in highly efficient and reliable distributed generation technologies. Commenters recommended incorporation of 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). Commenters 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. A commenter stated that the final rule should restrict the definition of affected facility to include 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 5 consecutive calendar years and that CHP units which have total thermal energy production that approaches or exceeds the unit's total electricity production should be exempted.
      Commenters offered a number of strategies for incorporating an exemption for CHP units including exempting CHP units by fuel type and exempting industrial CHP units based on the definition of potential electric output. It was suggested that the percent sales threshold be based on the net system efficiency (that includes useful thermal output) rather than just the rated net-electric-output efficiency, or that the applicability criteria use a default efficiency of 50 percent for CHP units. Some commenters suggested an exclusion where CHP units would not be considered to be affected EGUs if 20 percent or more of their total gross or net energy output consists of useful thermal output on a 3-year rolling average basis. Some commenters said an exemption for highly efficient CHPs that achieve an overall efficiency level of 60 or 70 percent and higher should be excluded. Some commenters opposed removal of the sales criterion (219,000 MWh) because it ensures that industrial CHP are not subject to the standards, and the commenter believes that these highly efficient operations should not be encumbered by the regulatory burdens of the proposed standard.
      In general, the inherent efficiency of CHP minimizes GHG emissions relative to separate generation of heat and power and since CHP would comply with the final GHG standards there is limited environmental benefit to including CHP with significant environmental benefits in this GHG NSPS. In addition, the intent of this rulemaking is to cover utility CHP since it serves essentially the same purpose as an electric-only EGU, but not industrial CHP units since they serve a different primary purpose. The EPA has concluded that it is important to consider both purpose and efficiency when determining the scope of this rulemaking. The EPA, therefore, concludes that it is appropriate to not include in the scope of this rulemaking CHP whose primary purpose is providing useful thermal output and CHP with significant environmental benefit. To distinguish by purpose, the EPA concludes that SIC code classification is not a sufficient measure of purpose for the purposes of this rulemaking since it is only randomly related to the electric sales of a particular CHP unit.
      The EPA concludes that percent of electric sales relative to the potential electric output is an appropriate measure of purpose since electric sales are inherent in the source category definition. The EPA considered multiple efficiency options to identify CHP with significant environmental benefit. We have concluded that overall design efficiency is not an appropriate method to determine environmental benefit. 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). CHP units with large amounts of useful thermal output relative to electric output tend to have higher efficiencies than CHP with lower amounts of relative useful thermal output. Therefore, an exemption based on overall efficiency without considering the relative amount of electricity to useful thermal output does not identify the relative GHG reductions of a CHP unit.
      Based on public comments and after further analysis, the EPA makes two adjustments to the definition of applicability of this rule to CHP. The first is to base the definition of potential electric output on overall net efficiency, instead of electric-only efficiency. Second, the GHG standard applicability would be based on the overall design efficiency multiplied by the potential electric output instead of one-third of the potential electric output as proposed. 
      We are defining utility CHP as a CHP unit that is: (1) technically capable of selling more electricity than the product of its design efficiency multiplied by its potential electric output and (2) not subject to a federally enforceable permit limiting annual net electric sales to less than this amount (design efficiency multiplied by potential electric output) or 219,000 MWh, whichever is greater. The net impact of these changes is to only cover CHP units that condense a large portion of steam generated by the unit for the purpose of supplying electric power to the grid. CHP facilities that do not have a condensing steam turbine (e.g., simple cycle combustion turbines with a HRSG and boiler based systems with a backpressure steam turbine) would generally not be physically capable of selling enough electricity to meet the applicability criteria  -  even if they sold 100 percent of the electricity generated and did not subtract out the electric used by the thermal host(s). The EPA has concluded that this is appropriate since these designs are industrial by design and provide mostly useful thermal output. CHP facilities with a steam extraction condensing steam turbine would determine their potential electric output based on their design efficiency on a net basis at the base load heat input rating. The owner/operator would be able to determine during the permitting process if the EGU GHG NSPS was applicable. New EGUs with only limited useful thermal output would be subject to the final standards, but the vast majority of new CHP would not be subject to the final standards. The EPA has concluded 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 the overall design efficiency. This approach both limits applicability to the intended CHP units and encourages the installation of the most efficient CHP systems since more efficient designs would be able to have higher permitted electric sales while not being subject to the GHG 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 have not been typically 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. 
E. Coal Refuse
      In the original proposal, we requested 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, in the January 2014 proposal, we sought additional comments regarding a subcategory for coal refuse-fired EGUs. 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 said that National Emission Standards for Hazardous Air Pollutants (NESHAPs) and work practice standards which have recently been passed do enough to limit emissions from coal refuse plants and 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 they 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 unnecessary. 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 EGUs. Specifically, we are not finalizing CO2 standards for industrial CHP units. Many existing coal refuse-fired EGUs are CHP units. A new coal refuse-fired EGU could be designed as an industrial CHP facility and the requirements of this rule would not apply. 
F. Format of the Output-Based Standard
      For a non-CHP EGU, gross output is the electricity generation measured at the generator terminals. Net output is the gross electrical output less the unit's total parasitic (i.e., auxiliary) power requirements. A parasitic load for an electric generating unit is a load or device powered by electricity, steam, hot water, or directly by the gross output of the electric generating unit 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 combined cycle station 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 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. 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. 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 combined cycle designs, the difference between a gross-output standard and a net-output standard has a limited 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. 
      Many commenters support gross-output-based standards because they believe a net output standard penalizes the operation of air pollution control equipment. Several commenters disagreed with the Agency's 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 appropriate incentives to properly manage all of these factors. Some commenters supported a gross-output basis 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, believe that the final rule should strictly require compliance on a net output-basis. They believe this is the only way for the standards to minimize the carbon footprint of the electricity delivered to consumers and are the only standards that are truly "technology forcing." These commenters believe that, at a minimum, net-output-based standards should be included as an option in the final rule.
      The EPA recognizes that evaluating compliance on a net-output basis more closely evaluates the environmental performance of the sector. However, the Agency also recognizes that the majority of EGU owners/operators currently use the data acquisition and handling technologies that have been developed and validated for Part 75 compliance. Currently, Part 75 only allows the reporting of gross energy output. In addition, many of the IGCC facilities are co-production facilities (i.e., they produce useful byproducts and chemicals along with electricity). As noted in the proposal, we have concluded that measuring the net electricity at these co-production facilities would be more challenging to implement.
      Based on further evaluation and review of issues raised by commenters, for combustion turbines the EPA is finalizing the CO2 standard for 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. However, many permitting authorities have concluded that the environmental benefits of using net-output-based standards outweigh any additional complexities for particular units and have required them in recent GHG operating permits. We expect this trend to continue. Therefore, owners/operators of combustion turbines may petition the permitting authority to use the alternate net-output-based standard. If the permitting authority grants the petition, owners/operators would comply with a net-output-based standard that we have concluded is essentially equivalent to the gross-output-based standard. This approach establishes a single applicable NSPS CO2 emission standard (i.e., units would not switch between the gross and net-output-based standards unless the Administrator grants a petition to switch) and supports the continued use of net-output-based standards in future GHG permits. 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. Finally, this approach accommodates potential future reporting of net output under part 75. 
      In contrast, 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, for combustion turbines the auxiliary load is relatively fixed and small, approximately 2.5 percent, so the choice between the gross and net-output-based standard will not substantially impact technology choices. However, in the case of utility boilers, we have concluded 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 utility boilers 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., integrated solar thermal for feedwater heating or steam augmentation) or a coal-fired EGU co-firing natural gas would have lower non-CCS related auxiliary loads and since the required amount of CCS 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 output-based standard.
      For combined heat and power units, useful thermal output is also used when determining the emission rate. Previous rulemakings issued by the EPA use various `discount factors' when determining how much of the measured useful thermal output is used when determining the emission rate. We proposed that 75 percent credit is the appropriate discount factor for useful thermal output, and we solicited 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 of a hypothetical CHP unit to the proposed emission rate.
      Many commenters said 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 one hundred percent credit for useful thermal output for all newly constructed, modified, and reconstructed CHP sources. This approach approximately matches the overall GHG emissions from a hypothetical CHP facility to separate heat and power and appropriately recognizes the environmental benefit of CHP.
G. CO2 Emissions Only
      This final action regulates only emissions of CO2, and not the other constituent gases of the air pollutant GHGs. We identify the pollutant we are regulating as GHGs, but are only setting standards for CO2 emissions. We are not establishing separate emission limits for other GHGs (such as methane (CH4) or nitrous oxide (N2O)) as they represent less than 1 percent of total estimated GHG emissions (as CO2e) from fossil fuel-fired electric power generating units. 
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 nonair quality health and environment impact and energy requirements (BSER). 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.
      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. 
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. 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." Section 111(b)(2). The term "standard of performance" is defined to "mean[] a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the best system of emission reduction which (taking into account the cost of achieving such reduction and any nonair quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated." Section 111(a)(1).
      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. 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, through which the Court has developed a body of case law that interprets the term "standard of performance." 
3. Key Elements of Interpretation
      By its terms, the definition of "standard of performance" under CAA [section] 111(a)(1) provides that the emissions limits that the EPA promulgates must be "achievable" by application of a system of emission reduction that the EPA determines to be the "best system" 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" reduced and the role of "technological innovation." 
      We discuss each of these elements below.
a. Achievability of the standard of 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'" based on performance of the BSER. 79 FR 1430, 1463 (January 8, 2014). A standard of performance 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.
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. In sections below, we show both that for new, modified, and reconstructed steam generators and combustion turbines, each BSER that we identify is technically feasible and adequately demonstrated, considering cost, nonair quality health and environmental impact and energy requirements; and that each of the standards for emissions that we promulgate is achievable.
b. 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).  
c. Amount of emissions reductions. In the January 2014 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 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"). 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," EPA must consider the amount of emission reductions that the system would yield. Even if the EPA were not required to consider the amount of emission reductions, the EPA has the discretion to do so, on grounds that either the term "system of emission" or the term "best" may reasonably be read under Chevron step 2 to allow that discretion
d. 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, in several cases the D.C. Circuit has elaborated on this cost factor and formulated the cost standard in various ways, stating that EPA may not adopt a standard the cost of which would be "exorbitant," "greater than the industry could bear and survive," "excessive," or "unreasonable." These formulations appear to be synonymous, and for convenience, in this rulemaking, we will use reasonableness as the standard, so that a control technology may be considered the "best system of emission reduction ... adequately demonstrated" if its costs are reasonable, but cannot be considered the best system if its costs are unreasonable.  
      The D.C. Circuit has never invalidated a standard of performance on grounds that it was too costly. 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." See Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427, 440 (D.C. Cir. 1973); Portland Cement Association v. Ruckelshaus, 486 F.2d 375, 387-88 (D.C. Cir. 1973); Sierra Club v. Costle, 657 F.2d 298, 313 (D.C. Cir. 1981) (upholding standard imposing controls on SO2 emissions from coal-fired power plants when the "cost of the new controls ...  is substantial").
      As discussed below, the EPA may consider costs on both a source-specific basis and a sector-wide, regional, or nationwide basis.
e. Non-air health and environmental impacts. Under CAA section 111(a)(1), the EPA is required to take into account "any nonair quality health and environmental impact" in determining the BSER and whether it is adequately demonstrated. This requirement makes explicit what was implicit in the initial version of section 111: a system cannot be "best" if it does more harm than good due to cross-media environmental impacts. 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.
f. Energy considerations. Under CAA section 111(a)(1), the EPA is required to take into account "energy requirements." As discussed below, the EPA may consider energy requirements on both a source-specific basis and a sector-wide, region-wide, or nationwide basis. Considered on a source-specific basis, "energy requirements" entails considering the amount of energy required to run the pollution control requirements. In this rulemaking, as discussed below, the EPA considered the parasitic load requirements of partial CCS.
g. Sector- or nationwide component of factors in determining the BSER. 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. The D.C. Circuit based this conclusion on a review of the legislative history, stating, 
      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.
	
The Court has upheld EPA rules that 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.
      
Some commenters objected that this case law did not excuse the EPA from justifying costs and energy considerations on the basis of their source-specific impacts, but rather, required the EPA to justify costs and energy considerations on both a source-specific basis and a sector-wide, regional, or national basis. The EPA has in fact done so here, as discussed below.
h. 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 EPA is required to consider technological innovation as one of the factors in determining the "best system of emission reduction." 
      The Court grounded its reading in the statutory text. We added that the Court's interpretation finds firm support as well  in the legislative history, and 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. Even if the EPA were not required to consider technological innovation as part of its determination of the BSER, it would be reasonable for the EPA to consider it, either because technological innovation may be considered an element of the term "best," or because the term "best system of emission reduction" is ambiguous as to whether technological innovation may be considered, and it is reasonable for the EPA to interpret it to authorize consideration of technological innovation in light of Congress's emphasis on technological innovation.
      Commenters state that the requirement to consider technological innovation does not authorize 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. 
i. 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," and emphasized that "[t]he text gives the EPA broad discretion to weigh different factors in setting the standard." In Lignite Energy Council v. EPA, 198 F.3d 930 (D.C. Cir. 1999), the Court reiterated:
      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.	

j. Lack of requirement that standard be able to 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.	
Commenters contested this assertion, arguing that a 111(b) standard must be achievable by all new sources. We continue to take the same position we took in the proposed rulemaking 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 sequestration sites. As discussed below, sequestration sites are widely available, and a steam-generating plant with partial CCS that is sited near an area with sequestration sites available can serve demand in a large area that may not have sequestration sites available. In any event, the 1,400 lb CO2/MW standard that we promulgate in this rule can be achieved by coal-fired power plants through co-firing natural gas in lieu of installing partial-capture CCS, which moots the issue of the geographic availability of CCS. 
k. 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(a), 402(i), 1307 (b), and 1307(b) (adding section 48A(g) to the 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 ...."  
      IRC section 48A(g) contains a similar constraint concerning the use of technology of level of emission reduction from electric generating unit 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 section 402(i) and 421 (a), the EPA proposed that these provisions barred consideration where EPAct05 assistance facilities were the sole support of the BSER determination, but EPAct05 sources could support a BSER determination so long as there is additional evidence supporting the determination. In addition, the EPA viewed the prohibition as relating only to the technology or emissions reduction for which assistance was given. The EPA likewise interpreted IRC section 48A(g) 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. The EPA also proposed the interpretation that the phrase "with respect to which a credit is allowed under this section" refers 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.
      Some commenters supported the EPA's proposed interpretation. Others challenged a reading whereby EPAct05 facility information could comprise 99 percent of the supporting information for a BSER determination, but could be considered because the determination was not based "solely" on EPAct05 sources. They urged a reading that the EPA could consider information from projects funded under the EPAct05 only if, without that information, the EPA could justify its chosen standard as the BSER  -  in other words, a "but for" test. Some commenters argued that the provisions simply required the EPA to rely only upon non-EPAct05 facilities to support a determination that a technology or level of performance is adequately demonstrated.
      In this final rule, the EPA is adopting the interpretations of both 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. The EPA also notes that the extreme example provided in the comments (reading "solely" to allow EPAct05 sources to be the overwhelming basis for a determination that a technology or level of performance is adequately demonstrated) is not presented here, where the principal evidence that partial CCS is a demonstrated and feasible technology comes from sources which received no assistance of any type under EPAct05. This evidence satisfies the "but for" construction urged by these commenters.
      Certain commenters took the extreme position that these EPAct05 provisions bar consideration even of facilities' existence if the facility received EPAct05 assistance. The argument is that these facilities' experience cannot be considered as an example of first-of-a-kind so that later-built plants cannot be considered to learn at all from the EPAct05 facilities' experience. See Section V below. The EPA does not accept this argument. The EPAct05 provisions relate to whether a technology is demonstrated, and the level of performance achieved by use of technology. These provisions thus relate in some way to an EPAct05 source's performance and operation. Merely acknowledging the evident fact of the source's existence is none of these. Moreover, these same commenters referred to these same plants in their other comments as examples of high costs of CCS technology. If there is an absolute prohibition on considering information from EPAct05 facilities, then these plants' costs to date also cannot be considered. EPA also does not agree that these commenters could submit comments citing EPAct05 facilities' experience to support their contentions but that the EPA is barred from responding.
      In any case, as shown in Section V below, the EPA finds that partial 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.
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 boiler or IGCC 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 the fossil proportion of the fuel 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 subpart Da. First, we proposed to include all utility boilers and IGCC units 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 to include all utility boilers and IGCC facilities that are 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 applicability 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 facility 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 broader proposed 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 rather 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 electric sales criterion should be recast to be based on the permit conditions. 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) would create regulatory uncertainty and could lead to applicability confusion 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 practical since applicability would not be known prior to determining compliance and could change annually. 
      Therefore, this action finalizes applicability criteria based on design criteria and federally enforceable permit restrictions included in each individual permit. Based on permit restrictions, if any, of net electric sales, it will be clear from the time of construction if a unit is subject to this rule. To be consistent with the applicability in subpart Da (i.e., `constructed for the purpose of'), the applicability includes utility boilers and IGCC units unless the electric sales restriction has always been included in the operating permit (i.e., in the original and the current operating permit without any lapses). We have concluded that this approach is equivalent to, but clearer than, the existing language used in subpart Da. In addition, without the restriction to have always been subject to the electric sales restriction, existing units could add permit restrictions on allowable electric sales to avoid obligation under 111(d). As described in Section III, industrial combined heat and power and dedicated non-fossil fuel units also are not included in the scope of this action. 
      In this rule, we are finalizing the definition of a steam generating EGU as a utility boiler or IGCC unit that: (1) is capable of combusting more than 250 MMBtu/h heat input of fossil 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 GHG standards for certain EGUs. These include: (1) steam generating units and IGCC facilities that are currently 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) facilities 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) combined heat and power facilities technically capable of selling more electricity than the product of their design efficiency times their potential electric output, that are not subject to a federally enforceable permit limiting annual net electric sales to this amount (design efficiency times potential electric output) or 219,000 MWh (whichever is greater) or less. 
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). 
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 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." The EPA, through regulations, has determined that certain types of changes are exempt from consideration as a modification. 
      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) 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. 
      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
      The EPA has determined that the BSER for newly constructed steam generating units is partial implementation of carbon capture and storage (CCS) technology to the extent of removal efficiency that meets a final emission limitation of 1,400 lb CO2/MWh-gross. The final standard of performance is less stringent than the proposed emission limitation of 1,100 lb CO2/MWh-gross. This change, as will be discussed in greater detail later in this preamble, is in response to public comments and reflects a re-examination of the potential BSER technologies. For a newly constructed fossil fuel-fired utility boiler, post-combustion carbon capture can be implemented by treating a slip-stream of the combustion flue gas. For a newly constructed IGCC unit, a pre-combustion capture system can be used to remove CO2 from a partially shifted (or potentially un-shifted) syngas stream or, alternatively by co-firing with natural gas. 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 of this preamble.
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. As explained below, however, the final BSER determination and the scope of modifications to which the final standards apply differ in important respects from what the EPA proposed.
      The EPA proposed that the 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 large modifications to affected modified steam generating units that are consistent with the proposed BSER determination for modified steam generating units. The final standard for that subcategory of modified sources 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 modifications resulting in a potential hourly increase in CO2 emissions (mass per hour) of less than or equal to ten percent and is withdrawing the proposed standards for those sources.
      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 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

Source
                                 Sub-category
                                Final Standard*
                                       

                                 lb CO2/MWh-gr
New Sources
All
                                     1,400



Modified Sources
Sources where the modification results in an increase in potential hourly CO2 emissions (lb CO2/hr) of more than 10 percent
Best annual performance (lb CO2/MWh-gross) during the time period from 2002 to the time of the modification



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 the subcategory of modified steam generating sources that result in more significant 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 emissions mass per unit of useful energy output, specifically, in pounds per megawatt-hour (lb CO2/MWh-gr). The standard of performance would apply to affected sources upon the effective date of the final action. 
      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 useful energy output (on a gross basis) over the rolling 12-operating-month compliance period. 
      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 84-operating-month compliance period option that we proposed 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 both utility boilers and IGCC units. 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 technology 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. 
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-gross, issued in this action and reflecting certain key changes from the proposal, 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 greenhouse gas emissions and supports technological innovation.
B. Partial CCS as the BSER for Newly Constructed Steam Generating Units
In the January 2014 proposal, we proposed that partial CCS technology with a percentage capture that would result in an emission limitation of 1,100 lb CO2/MWh-gross is the BSER for new fossil fuel-fired steam generating units, that is, for both utility boilers and IGCC units. For a new utility boiler firing bituminous coal, the BSER at proposal would be capture and storage (that is, either storage on-site or transfer to a qualified storage facility) of approximately 40 percent of the CO2 from the source. In this final action, we affirm that partial CCS technology represents the best system of emission reduction for new steam generating units, but we have determined that the percentage of capture that qualifies as the BSER should be reduced to the amount that would result in an emission limitation of 1,400 lb CO2/MWh-gross. For a new utility boiler firing bituminous coal, the BSER would be capture and storage of approximately 20 percent of the CO2 from the source. The change from the proposed emission limitation to the final emission limitation reflects response to comments received on the proposed standards and is largely based on our assessment of comments received on the estimated costs to implement partial CCS. In the sections that follow, we explain the technical configurations that may be used to implement partial capture to meet the final standard, describe the operational flexibilities that partial capture 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 partial capture and storage in the amount that results in an emission limitation of 1,400 lb CO2/MWh-gross best meets those criteria, including, among others, that partial capture and storage is technically feasible, provides meaningful emission reductions, can be implemented at a reasonable cost, and is adequately demonstrated. We also discuss alternative (i.e., non-CCS) compliance options that new source project developers can also use to meet the final standard of performance. We also explain why the emission standard of 1,400 lb CO2/MWh-gross is achievable.
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-gr, which would have required a new steam generating unit burning bituminous coal to capture and store (including either storage on-site or transfer to a qualified storage facility) roughly 40 percent of its CO2 emissions and a new IGCC unit to capture and store roughly 25 percent of its CO2 emissions. The EPA arrived at those proposed levels by examining the available CCS implementation configurations and concluding that this level of partial CCS best balances the BSER criteria and results in an achievable emission level. The EPA did not propose to find "full CCS" (i.e., more than 90 percent capture and storage) to be the BSER because the expected costs to implement the technology are high and are projected to substantially exceed the projected costs of other dispatchable technologies that developers are considering (e.g., new nuclear and biomass). See generally 79 FR at 1477-78.
2. Basis for the Final Standards
      For this final action, the EPA reexamined the technology options available at proposal. Those are: highly efficient generation without CCS, partial CCS, and full (i.e., more than 90 percent) CCS. Consistent with our determination in the January 2014 proposal, we remain convinced that highly efficient generation does not represent the best system because it does not achieve emission reductions beyond the sector's business as usual, when options that do achieve more emission reductions are available. We also do not find that full CCS is the BSER because, at this time, the costs are predicted to be significantly more than that for implementation of partial CCS and significantly more than completing technologies such as nuclear-powered generation. 
      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 percentage capture and final standard of performance of 1,400 lb CO2/MWh-gross are less stringent than at proposal and reflect changes that were 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 supercritical utility boiler burning bituminous coal can meet this final emission limitation by capturing and storing (including on-site storage or transfer to a qualified facility) approximately 20 percent of the CO2 produced from the facility. Most new IGCC units will be able to meet the emission limitation using more limited CCS (i.e., less than 10 percent). This BSER is technically feasible, as shown by the fact that post-combustion CCS is demonstrated in full-scale operation within the electricity generating industry, and full-scale pre-combustion CCS has been demonstrated in several chemical industry plants with results that are reasonably transferable to the electricity generating sector. There are also numerous operating results from smaller-scale operations that are reasonably predictive of operation at full-scale. In addition, partial CCS will result in substantial emissions reductions at reasonable cost, is consistent with the other BSER criteria, is adequately demonstrated, and is consistent with emission standards that are achievable not only through partial CCS but also through alternative compliance approaches.
3. Consideration of Projects Receiving Funding Under the EPAct05
      As noted in Section III.K above, the EPA's determination of 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 assistance from the Department of Energy (DOE), as well as 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 standing alone is sufficient to support its BSER determination.
D. Post-Combustion CCS
     In this section on post-combustion CCS, we describe a variety of facts that support our conclusion that the technical feasibility is adequately demonstrated. First, we describe the technology of post-combustion capture, citing authoritative sources. We then describe EGUs that have previously utilized or demonstrated, or are currently utilizing, post-combustion carbon capture technology. Further, we identify commercial vendors that offer carbon capture technology and offer performance guarantees. In addition, we note that industry and technology developers have publically stated 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 many combustion processes are often at atmospheric pressure and are moved through the flue gas system by fans, and the concentration of CO2 is somewhat dilute. Most post-combustion capture system utilize liquid solvents that separate the CO2 from the flue gas. 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 are the most commonly used in post-combustion capture systems. In a chemisorption-based separation process, the CO2 is absorbed by the liquid solvent and then released by heating to form a high purity CO2 stream. This heating 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. Development of advanced solvents  -  those that are chemically stable, have high CO2 absorption capacities, and have low regeneration energy requirements  -  are an active area of research. Many post-combustion solvents will also selectively remove other acidic gases such as sulfur dioxide (SO2) and hydrochloric acid (HCl), which can result in degradation of the solvent. In those cases, the acidic gases will need to be scrubbed to very low levels prior to the flue gas entering the CO2 capture system.
      Additional information on post-combustion carbon capture can be found in a summary technical support document.
   2. 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 "better than expected."[,] 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 generation side is producing more power than estimated and the energy penalty (parasitic load) is much lower than expected. Water use at the facility is consistent with levels that were predicted. The total project costs  -  for the power plant and the carbon capture plant  -  was $1.467B (CAD). The CO2 from the capture system is more than 99.999 percent pure with only trace levels of N2 in the product stream. 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 will be used for enhanced oil recovery (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, CO2 injection for both EOR and geologic storage. The CCS system is fully integrated with the electricity production of the plant.
Some commenters noted that, at 110 MW, the Boundary Dam Unit #3 is a relatively small coal-fired utility boiler and thus does not indicate 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 could be used to treat a slipstream of a much larger supercritical utility boiler (approximately 500 to 600 MW) in order to meet the final standard of performance of 1,400 lb CO2/MWh-gross, which would only require partial CCS on the order of approximately 20 percent.
A "slipstream" 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 separate streams and treated separately in different control equipment before being recombined to exit from a common stack. A slipstream configuration is often used to treat a smaller portion of the bulk flue gas stream as a way of testing or demonstrating a control technology or measurement technology. For implementation of partial post-combustion 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 portion 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 slipstream gas  -  resulting in an overall capture of about 20 percent. 
In its study on the cost and performance of a range of carbon capture, the DOE/NETL determined that the slipstream approach was the most economical for carbon capture of less than 90 percent of the total CO2. The advantages of the slipstream 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.
The carbon capture system at Boundary Dam does not utilize the slipstream 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 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. The EPA is not aware 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. 
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 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. 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) are both circulating fluidized bed (CFB) coal-fired power plants with carbon capture equipment that is equipped with amine scrubbers developed by ABB/Lummus. The scrubbers were designed to process a slipstream 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 slipstream (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.
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. 
Each of these processes indicate a willingness of industry to utilize available post-combustion technology for capture of CO2 for commercial purposes. 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 Trona facility as compared to the solvents that are being used at Boundary Dam and WA Parish (Thompsons, TX).
3.	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 facts 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 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 for the reasons discussed below, that does not disqualify them from being considered. 
a. Petra Nova WA Parish Project. Petra Nova, a joint venture between NRG and JX Nippon Oil & Gas Exploration, is constructing a commercial-scale post-combustion carbon capture project at 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 slipstream of the 610 MW WA Parish facility. This project is an indication that developers are confident in the technical feasibility of post-combustion carbon capture.
      The project was originally envisioned as a 60 MW slipstream demonstration and received DOE CCPI funding (as provided in EPAct05) on that basis. The project was later expanded to the larger 240 MW slipstream because of the need to capture larger volumes of CO2 for EOR operations. No additional DOE or other federal funding was obtained for the expansion from a 60 MW slipstream to a 240 MW slipstream. 
      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 or sequester 1.6 million tons of captured CO2 each year. The project is expected to be operational in 2016. 
      In 2014 project materials, NRG recognized the importance of CCS technology by noting: 
      "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. 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. As an existing source, the WA Parish facility will not be subject to final standards of performance issued in this action. However, since it will be capturing roughly 35 percent of the CO2 produced by the facility, it should meet the final emission limitation of 1,400 lb CO2/MWh-gross.
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 slipstream configuration. However, the system is designed to capture roughly 35 percent of the CO2 from the WA Parish (90 percent of the CO2 from the 240 MW slipstream 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 slipstream from a 1,000 MW unit in order to meet the final standard of performance of 1,400 lb CO2/MWh-gross. 
      Again, the experience at the WA Parish will be directly transferable to post-combustion capture at a new utility boiler, even though WA Parish is an existing source. The experience will be directly transferrable to other types of post-combustion sources including those using different boiler types and those burning different coals. 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.  
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 slipstream 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. 
      AEP, with assistance from the DOE, had planned to expand the slipstream 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, and did not express doubts about the feasibility of the technology. 
      AEP also prepared a Front End Engineering & Design (FEED) Report, 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. See 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.
         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 for CO2 absorption and desorption that was jointly developed by MHI and Japanese utility Kansai Electric Power Co. The captured CO2 from the Plant Barry demonstration project was stored underground in a nearby deep saline geologic formation.
E. Pre-Combustion CCS
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  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 heat recovery steam generator and steam turbine). The gasification process also typically produces some amount of CO2 as a by-product along with other 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:
                              CO + H2O  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.
2. 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's Great Plains Synfuels Plant uses approximately 18,000 tons of North Dakota lignite in a coal gasification process which produces syngas (a mixture of carbon monoxide, carbon dioxide, and hydrogen) 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 used for home heating and electricity generation.
      Capture of CO2 from the facility began in 2000. The Synfuels Plant, using a pre-combustion RECTISOL(R) 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 that 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 of carbon monoxide (CO), hydrogen (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.
      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, it is only the manner in which the syngas is used that 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(R) process (or other similar physical gas removal systems) is not feasible for an IGCC EGU. In confirmation, according to product literature, RECTISOL(R), 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.
b. International projects. There are some international projects that are in various stages of development that indicate confidence by the developers in the technical feasibility of pre-combustion carbon capture. Summit Carbon Capture, LLC is developing the Caledonia Clean Energy Project, a proposed IGCC plant that would be built in Scotland, U.K. Captured CO2 from the plant will be transported via on-shore and sub-sea pipeline to a subsea saline formation in the North Sea for sequestration. The U.K. Department of Energy & Climate Change (DECC) recently announced funding to allow for feasibility studies on a proposed 570-megawatt, IGCC power plant that would include CCS.
      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 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. 
      Vattenfall and Nuon's pilot project in Bugennum, The Netherlands involves capture from a coal- and biomass-fired IGCC plants. It has operated since 2011. 
      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. 
      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. 
      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.
      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. 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 Selexol(TM) 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. 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 65 percent. The pre-combustion solvent, Selexol(TM) 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 Selexol(TM) 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)
      
      Thus, Mississippi Power believes that, because the Selexol(TM) 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, 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. The facility will utilize the Linde Rectisol(R) gas cleanup process to capture carbon dioxide  -  the same process that has been deployed for decades, including at the Dakota Gasification facility. 
Hydrogen Energy California, LLC (HECA), is proposing to build an IGCC facility similar to TCEP in western Kern County, California. The HECA IGCC plant will be fueled by coal and petroleum coke that will produce 300 MW of power and will capture CO2 for use in EOR operations. They expect to capture approximately 90 percent of the produced CO2. HECA also intends to employ the Rectisol(R) process for carbon capture.
Neither of these facilities has been constructed; so they do not provide direct evidence of technical feasibility. However, they both plan to employ the same carbon capture technology that is used at the Dakota Gasification facility and provide a clear indication that project developers have confidence in that technology.
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, 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 (upholding standards 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)"). 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."
      Linde and BASF offer performance guarantees for CCS 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 they note that Linde is offering turn-key capture plants while BASF is the world's leading technical supplier for gas treatment. According to their literature, the companies are making commercially available post-combustion capture technology for lignite and hard coal fired power plants, and are offering "proven and tested processes including guarantees" (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 CCS. For example, Fluor has developed patented CO2 recovery technologies to help its clients reduce GHG emissions. The Fluor product literature specifically points to Econamine FG Plus[SM] process which uses an amine solvent to capture and produce food grade CO2 from post-combustion sources. The literature further notes that Econamine FG Plus[SM] (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.
      Fluor has also published an article titled "Commercially Available CO2 Capture Technology" in which it describes the EFG+ technology. 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 greenhouse gas effect but to provide an economic source of CO2 for use in enhanced oil recovery and industrial purposes, such as in the beverage industry."
      Mitshubishi Heavy Industries (MHI) offers a CO2 capture system that uses a proprietary energy-efficient CO2 absorbent called KS-1(TM). Compared with the conventional monoethanolamine (MEA)-based absorbent, KS-1(TM) 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 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 greenhouse gas abatement regulations by removing CO2 from their exhaust streams, with the added benefit of simultaneously lowering SO2 and NO2 emissions.
      Other companies are at various stages of developing and demonstrating processes to remove CO2 from flue gas streams.
2. Academic and Other Literature 
Climate science and climate change mitigation options  -  include CCS - are the subject of great academic interest and a large body of academic literature on the subjects exits. In addition, other research organizations (e.g., U.S. national laboratories and others) have also published studies on these subjects. A compendium of relevant literature is provided in a Technical Support Document available in the rulemaking docket.   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 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 the fact the Selexol(TM) process has been used in industry for decades minimized technical risk of its use at the Kemper IGCC facility. For example:
The carbon capture process being utilized for the Kemper County IGCC is a commercial technology referred to as Selexol(TM). The Selexol(TM) 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.
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."

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."

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). 

As discussed above, in fact, vendors do offer performance guarantees. Moreover, 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.
G. Response to Key Comments
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 Court has explained that a standard of performance 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. (See 79 FR 1463; see also Section V.C above.) However, 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.
2. Must a technology 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 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.  In any event, as discussed above, Boundary Dam has provided data from the operation of the CCS equipment itself.
      In a related argument, other commenters stated that a system cannot be adequately demonstrated unless all of its component parts are operating together. 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 (1[st] Cir 2000); Native Village of Point Hope v Salazar 680 F 3d 1123, 1133 (9th Cir. 2012).
      The short of it is that the "EPA does have authority to hold the industry to a standard of improved design and 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 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. The EPA has done so here.  
      Most obviously, the final standard reflects experience of full-scale operation of both pre- and post-combustion carbon capture. 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. The DOE/NETL is explicit that its studies confirm the technical feasibility of CCS, stating, in relevant part, that the "studies ... establish estimates for the cost and performance of combustion and gasification based power plants ... with ... carbon dioxide capture and storage.  Several ranks of coal are being assessed in process configurations that are based on technology that could be constructed today such that the plant could be operational in the 2012 - 2015 timeframe."
 It is important to note that, while some commenters challenged 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 above.
Much has been written about the complexities of adding CCS systems to fossil fuel-fired power plants. Some commenters argued that the EPA minimized  -  or even ignored - those complexities in the discussion presented in the January 2014 proposal. On the contrary, the EPA has not minimized or ignored these complexities. 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." 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. 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 cost. 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. The EPA addresses technical feasibility of partial CCS in this final action. The Boundary Dam facility, in particular, demonstrates that the complexities of implementing CCS  -  even full CCS  -  can be overcome. Many of the challenges that are often noted are only issues for implementation of CCS retrofits for existing sources. 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 EPA's determination of that partial CCS is technically feasible and adequately demonstrated. However, the EPA mentioned in the January 2014 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 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, 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") and 341 n. 157.  
A. 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, EPA concludes that the costs associated with the final standard are reasonable.
      In reaching this determination, the EPA evaluated capital costs on a per-plant basis, responding to public comment that noted the particular significance of capital costs for fossil steam EGUs. As in the proposal, the EPA also considered how the standard would affect the levelized cost of electricity for 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 cost impacts on consumers. Accordingly, EPA concludes that the costs of the final standard are reasonable. 
1. Rationale at Proposal
At proposal, the EPA evaluated the costs of new fossil steam EGUs implementing full (90 percent) and partial CCS. The EPA compared the predicted levelized cost of electricity (LCOE) of those units against the LCOE of other new units using 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 full CCS was higher than those of these other technologies, and we did not propose to identify full CCS as BSER on this basis. Id. at 1477. The EPA determined that the proposed standard of performance of 1,100 lb CO2/MWh-gross, reflecting partial CCS, could be implemented at reasonable cost based on a comparison of the projected LCOE associated with achieving this standard with the alternative dispatchable technologies just mentioned. 
In addition, the EPA concluded that the costs of 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 enhanced oil recovery. 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 fossil steam generation 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 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. 
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. 
   1. Current Market Context
      The EIA projects that few new fossil steam 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. 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, US electricity demand growth has followed a downward sloping trend for decades with future growth expected to remain very low. Furthermore, the EPA projects that for any new fossil fuel-fired electricity generating capacity that is constructed through 2020, natural gas will be the overwhelming fuel of choice.
      Accordingly, construction of new uncontrolled fossil steam generating capacity is not anticipated in the near term, even in the absence of the standards of performance we are finalizing today, 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." Public announcements and IRPs also indicate that utilities are interested in a range of technologies that could provide or preserve fuel diversity within generating fleets. In particular, fuel diversity could provide important additional value by serving as a hedge against the possibility that future natural gas prices will far exceed projected levels. 
      In addition, the EPA recognizes that there may be interest in combined-purpose plants that would generate power as well as produce chemicals or carbon dioxide for use in enhanced oil recovery projects. These facilities would similarly provide additional value due to the revenue streams from saleable chemical products or carbon dioxide. 
      As demonstrated below, the agency carefully considered the reasonableness of costs in identifying a standard that allows a path forward for such projects while rejecting more stringent options that would impose excessive costs. 
   2. Consideration of Capital Costs
	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. Extensive comment from industry representatives and others noted that fossil-steam units are very capital-intensive projects and recommended that capital costs be considered 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 in line with prior regulations and 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. 
      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 electric generating units 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 above the $120M cost of the plant. See 1972 Supplemental Statement, 37 FR 5767, 5769 (March 21, 1972). The D.C. Circuit upheld 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 1979 NSPS for fossil steam electric generating units, 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 EPA's determination that the standard was reasonable. Id. at 410.
      The cost and investment impacts of the 1978 NSPS on electric utilities was subsequently evaluated in a 1982 Congressional Budget Office (CBO) retrospective study. 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. The study further noted that air pollution control requirements in general had led to an estimated a 37.5 to 45 percent increase in capital costs for coal-fired power plant installation between 1971 and 1980. 
      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." In assessing the capital cost impacts of the suite of 1970's 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." 
      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 similar 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 SCPC unit to meet the final emission limitation of 1,400 lb CO2/MWh-gross would be an increase of 17.3 percent for capital costs. Incremental capital costs of control for a new IGCC unit would be even less. See Table 7 below.  
Table 7. Comparison of capital costs for a new SCPC and a new SCPC meeting the final standard of performance.

                                     Total

                                   Overnight

                                 Capital Cost

                                    ($/kW)

                                       
SCPC - no CCS
                                     2,452

                                       
SCPC - partial CCS
                                     2,876
(1,400 lb CO2/MWh-gr)
                                       

                                       
Incremental cost increase 
                                     17.3%

                                       

   3. 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. 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-heavy fossil-steam units, the LCOE can serve as a useful complement because it takes into account all specified costs, over the whole lifetime of the project. 
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 that for comparable alternative 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. 
                                                  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. 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.
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. Therefore, isolating a comparison of technologies based on their costs is only appropriate when they can be assumed to provide the similar service by essentially providing the similar values of electricity generated. It should be noted that different types of generation do not provide identical services, but nevertheless may be similar enough to permit of comparison through use of the LCOE.
As we indicated in the proposal, we evaluated publicly available Integrated Resource Plans (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. 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. The options for 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. 
      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 easily ramped up or down as needed, e.g., coal-fired units, NGCC units, nuclear) with that of non-dispatchable technologies 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 other sources, as shown in Table 8 below. As discussed in further detail below, these estimates rely most heavily on DOE/NETL cost projections for fossil fuel generating technologies and on the updated DOE/EIA AEO2014 for non-fossil generation technologies.
Table 8. Predicted Cost and CO2 Emission Levels for a Range of Potential New Generation Technologies
 New Generation
                                   Emission
                                  LCOE (+30%)
 Technology
                                 lb CO2/MWh-g
                                     $/MWh
SCPC - no CCS
                                     1,700
                                   77 - 100
SCPC* - no CCS
                                     1,700
                                   89 - 116

                                       
                                       
SCPC + partial CCS 
                                     1,400
                                   93 - 121
SCPC + partial CCS 
                                     1,100
                                  110  -  143
                                       


IGCC - no CCS
                                     1,450
                                  94  -  122
IGCC + partial CCS
                                     1,400
                                   97 - 126
IGCC + partial CCS
                                     1,100
                                  109  -  142
                                       


NGCC
                                  < 1,000
                                  52  -  86**
                                       


Nuclear
                                       0
                                  96  -  125
Biomass
                                       -
                                  103  -  134
Geothermal
                                       0
                                   48  -  62
  * Includes the 3 percent CUA
  ** This range represents a natural gas price from $5/MMBtu to $10/MMBtu.
  
As shown in Table 8 above, we project that the LCOE for new fossil steam capacity meeting the final 1,400 lb CO2/MWh-gross 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 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 base load generation diversity  -  or at least non-NGCC alternatives -- to a power provider's portfolio; hence, they are viewed as comparable alternatives.
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, 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. 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  -  base load power and fuel diversity. 
We note further 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, 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 co-firing with natural gas.
   4. 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 "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-XX-YYY, June 2015) (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. Instead, EIA data shows that natural gas is likely to be the most widely-used fossil fuel for new construction of electric generating capacity through 2020. Of the coal-fired units moving forward at various advanced stages of construction and development - Southern Company's Kemper County Energy Facility, Summit Power's Texas Clean Energy Project (TCEP), and the Hydrogen Energy California Project (HECA)  -  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. 
      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. 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 [x] of the RIA.
      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 today 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. 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.  
      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 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 (as we did at proposal).  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." These facts support EPA's overall conclusion that the costs of the standard are reasonable.  
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 or IGCC unit 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.
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.
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.  
   c. 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-gross 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-gr 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.
      Most new IGCC units will be able to meet the final standard by capturing less than 10 percent of the CO2 and many IGCC designs have a sufficient compliance margin such that they would likely not need to use a water-gas-shift (WGS) reactor. As an alternative, most new IGCC facilities will be able to meet the final standard by co-firing less than ten percent natural gas.
      Natural gas co-firing has long been recognized as an option for coal-fired boilers to reduce emissions of criteria and hazardous air pollutants. The EPRI sponsored a study to assess gas co-firing in coal-fired boilers where they examined both technical and economic issues associated with natural gas co-firing. 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. 
      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 utilize natural gas.[,]
      A 2013 article entitled "Utility Options for Leveraging Natural Gas" noted that: 
      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. 
      
Table 9. Predicted Costs to Meet the Final Standard Using Natural Gas Co-firing.
 New Generation
                                   Emission
                                     LCOE*
                                    (+30%)
 Technology
                                 lb CO2/MWh-g
                                     $/MWh
                                     $/MWh
SCPC - no CCS
                                     1,700
                                      77
                                      100
SCPC + partial CCS 
                                     1,400
                                      93
                                      121
SCPC + NG co-fire
                                     1,400
                                      90
                                       -
                                       



IGCC - no CCS
                                     1,450
                                      94
                                      122
IGCC + partial CCS
                                     1,400
                                      97
                                      126
IGCC + NG co-fire
                                     1,400
                                      95
                                       -
                                       



NGCC
                                  < 1,000
                                   59  -  86
                                       -

* The LCOE values for non-natural gas generation (i.e., SCPC with and without CCS) include +30% for uncertainty. The NG technologies (i.e., co-firing and NGCC) are costs assuming a range of natural gas prices from $6.11/mmBtu to $10.00/mmBtu.
      
      The EPA thus again notes that the cost assumptions it is making here are highly conservative. That is, by costing partial CCS as BSER, the EPA is likely overestimating actual compliance costs since there exist other less expensive means of meeting the promulgated standard. 
   d. 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 projected that the next units could be constructed at a cost of at least 30 percent less than that at Unit #3. These savings primarily come from application of lessons learned from the Unit #3 design and construction. 
      To facilitate the transfer of the technology and to accelerate development of carbon capture technology, SaskPower has created the CCS Global Consortium. 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). 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.
      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.
   e. 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.
I. Key Comments Regarding EPA's Consideration of Costs
1. Use of LCOE as a Cost Metric
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. 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").
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 above, it addresses all costs equally and therefore provides a useful summary metric of all sources of costs per unit of production (i.e., megawatt-hours). Provided that those megawatt-hours are equally valuable, 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 accordingly as discussed above, the EPA has considered direct capital costs here as part of its assessment and found those costs to be reasonable. At the same time, the agency believes LCOE is a valuable complementary metric because there are other costs that are also considered when evaluating technology options to provide new generating capacity. According to EIA, the capital costs represent roughly 63 percent of the LCOE for a new coal-fired SCPC plant; roughly 66 percent of the LCOE for a new IGCC plant; roughly 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, for a variety of reasons, the power sector has moved toward increased use of natural gas. 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, the EPA recognizes the variety of factors that can be involved in selecting a generation source beyond capital costs, and in considering cost reasonableness we accordingly also considered metrics that encompassed other costs as well as the value of fuel and fleet diversity. 
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 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, both new nuclear power and fossil steam generation are similarly not 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. Because both fossil steam and nuclear generation serve a comparable role of offering a diverse source of base load power generation, EPA concludes that the comparison of their LCOE is a valid approach to evaluating cost reasonableness. 
Finally, the EPA noted that new nuclear addresses potential risks (including future costs to the source) associated with future carbon liabilities  -  the same risks coal with some degree of CCS would address.  See 79 FR at 1477.
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 AEO2013 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 AEO2014 for nuclear and other baseload 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. The studies evaluate numerous technology configurations utilizing different coal ranks and natural gas. 
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. The NETL studies were extensively peer reviewed. The EPA Science Advisory Board Work Group considering the adequacy of the peer review noted EPA staff's statement that "the NETL studies were all peer reviewed under DOE peer review protocols", further noted 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 (sic) by agency guidance."
The cost estimates were indicated by DOE/NETL to carry an accuracy of -15 percent to +30 percent, consistent with a AACE Class 4 cost estimate  -  i.e, a "feasibility study" level of design engineering. 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."
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), by the DOE's Energy Information Administration (EIA) in their 2014 Annual Energy Outlook (AEO2014), 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. 


Table 10. Selection of Levelized Cost of Electricity (LCOE) Projections 
                                       
                                 EPA Proposal
                                     EPRI
                                    AEO2014
                                   DOE/NETL
                                      CMU
                                       
                                   $2011/MWh
                                   $2011/MWh
                                   $2012/MWh
                                   $2011/MWh
                                   $2010/MWh
                                     SCPC
                                      92*
                                    62 -77
                                   87 - 114*
                                   91 - 118
                                      59
                                SCPC(full CCS)
                                      147
                                  102  -  137
                                       -
                                   147 - 191
                                       -
                              SCPC(partial CCS**)
                                      110
                                       -
                                       -
                                   110 - 126
                                      80
                                       
                                       
                                       
                                       
                                       
                                       
                                     IGCC
                                      97
                                   82  -  96
                                  106 - 132*
                                   101 - 131
                                       -
                                IGCC(full CCS)
                                      136
                                  105  -  136
                                   137 - 163
                                   142 - 185
                                       -
                              IGCC(partial CCS**)
                                      109
                                       -
                                       -
                                   112 - 146
                                       -
                                       
                                       
                                       
                                       
                                       
                                       
                                     NGCC
                                    59 - 86
                                   33  -  65
                                    59 - 86
                                    60 - 77
                                      63
                                       
                                       
                                       
                                       
                                       
                                       
                                    Nuclear
                                   103 - 114
                                   85  -  97
                                   93 - 102
                                       -
                                       -
                                  Geothermal
                                    80 - 99
                                   84 - 129
                                    46 - 50
                                       -
                                       -
                                    Biomass
                                   97 - 130
                                   90 - 155
                                   92 - 123
                                       -
                                      - 
   * These cost projections include a climate uncertainty adder (CUA); which is a 3-percentage point increase in the cost of capital
   ** Partial CCS is 1,100 lb/MWh for EPA costs; 1,000 lb/MWh for CMU cost
      
      
      The LCOE values from the EPRI, EIA, 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 + 30 percent uncertainty added as the higher estimate in the range. 
      The range presented for the EIA AEO2014 LCOE values is intended to represent regional variation for new generating sources (reflecting regional differences in construction labor costs, capital costs, and resource availability). Overall, as can be seen from the results in Table 10, the range of LCOE estimates from the different groups are in reasonable agreement.
      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 and includes the CUA in the cost of coal-fired utility boilers when evaluating competitiveness of that generating technology.
c. Industry information that corroborates NETL cost estimates. Information from vendors of CCS technology also supports the reliability of the cost estimates EPA is using here.  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 EPA is using for purposes of cost analysis in the rule.
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. 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.
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. 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. 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 in those predicted by NETL, EIA, EPRI and others. The company ultimately concluded that "in a world of uncertain gas prices, falling CO2 capture 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."
      In June 2012, Alstom Power released a report entitled "Cost assessment of fossil power plants equipped with CCS under typical scenarios".[,] 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 the Summit  -  are shown in Table 11 below. The EPA estimated costs are also included for comparison. The results show predicted costs for a new SCPC ranging from $53/MWh to $81/MWh and costs to implement full CCS ranging from $97/MWh to $147/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. There is very good agreement among the studies in the incremental cost to implement full CCS on the new SCPC units (ranging from 82 to 85 percent).
Table 11. Industry LCOE Estimates for Implementation of Post-Combustion CCS
 
                                                                         Summit
                                                                         Alstom
                                                                            EPA
 
                                                                          $/MWh
                                                                         $/MWh*
                                                                          $/MWh
SCPC
                                                                           64.5
                                                                           52.6
                                                                           81.0
SCPC + full CCS
                                                                          117.6
                                                                           97.4
                                                                          147.0
Full CCS incremental cost, %
                                                                          82.3%
                                                                          85.0%
                                                                          81.5%
SCPC + 50% CCS
                                                                           91.1
                                                                              -
                                                                              -
SCPC + 40% CCS
                                                                              -
                                                                              -
                                                                          110.0
SCPC + 20% CCS
                                                                              -
                                                                              -
                                                                           97.0
NGCC**
                                                                           47.7
                                                                           35.0
                                                                           59.0
* 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).
** Assumed natural gas prices = Summit ($4/mmBtu); Astom ($3.9/mmBtu); EPA ($6.11).

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." As explained above, no steam electric EGU would be cost competitive even without CCS  -  and that is substantiated in the projected costs present above in Table 11 where NGCC is consistently the most economic new generation option when compared 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 (and in this final rule), nor disavow its own estimates of CCS costs (which are even less) which it is publically disseminating in the marketplace.  See also 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. 
d. Use of cost information from EIA Annual Energy Outlook (AEO). For the January 2014 proposal the EPA chose to rely on the EIA AEO2013 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 AEO2013. Those costs were updated as part of the AEO2014 release. The changes are shown below in Table 12 below.

Table 12. Predicted Cost and Regional Variation (Range) for New Non-fossil Dispatchable Generating Technologies
 
                                    AEO2013
                                    AEO2013
                                    AEO2014
                                    AEO2014
                                       
                                    average
                                    range*
                                    average
                                    range*
Technology
                                   $2011/MWh
                                   $2011/MWh
                                   $2012/MWh
                                   $2012/MWh
                                       

                                       
                                       
                                       
Nuclear
                                      108
                                    104-115
                                      96
                                    93-102
Nuclear (w/subsidy)
                                       -
                                       -
                                      86
                                     83-92
Biomass
                                      111
                                    98-131
                                      103
                                    92-123
Geothermal
                                      90
                                    81-100
                                      48
                                     46-50
* Note that the "range" is intended to account for the significant regional variation in LCOE values based on local labor markets and the cost and availability of fuel or energy resources.

The estimated cost for all of these technologies decreased from AEO2013 to AEO2014. This was due to changes in the macroeconomic projections that resulted in lower financing costs in AEO2014 relative to the AEO2013. The EIA did not make any major updates to the initial cost inputs for most technologies, including nuclear.
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 AEO2014 presented LCOE costs as a single point estimate representing average nationwide costs and separately as a range to represent the regional variation in costs. That range reflecting regional variation is presented in Table 12. In order to compare the fossil fuel generation technologies from the NETL studies with the cost projections for non-fossil dispatchable technologies from EIA AEO2014, we assume that the EIA studies would carry a similar level of uncertainty (i.e., +30 percent) and we present the AEO2014 projected costs as the average nationwide LCOE plus an additional 30 percent to account for uncertainty.
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.
      The Boundary Dam Unit #3 facility utilizing post-combustion capture from Shell Cansolv is now operational. Petra Nova, a joint venture between NRG 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. 
      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 Selexol(TM) pre-combustion capture system in early 2016. 
      Other full-scale projects  -  such as the Summit Power Texas Clean Energy Project and the Hydrogen Energy California Project  -  have not commenced construction but remain viable projects. 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 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, the report "reflect[s] the cost of the next commercial offering for plants that include technologies that are not yet fully mature and/or which have not yet been serially deployed in a commercial context, e.g. IGCC plants and any plant with CO2 capture. These cost estimates for next commercial offerings do not include the unique cost premiums associated with first-of-a-kind (FOAK) plants that must demonstrate emerging technologies and resolve the cost and performance challenges associated with initial iterations."
     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.
     Research is underway 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.
To facilitate the transfer of the technology and to accelerate development of carbon capture technology, SaskPower has created the CCS Global Consortium. 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). 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. 
We also note certain features of the commercial plants already built that suggests that their costs are uniquely high, and otherwise not fairly comparable to the costs of plants meeting the NSPS using the BSER. Most obviously, all of these projects involve full rather than partial CCS.
      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 a provided a strong price signal for CO2. Today's action is an important component in developing that framework.
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, 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
      Commenters, however, argued that this conclusion  -  that without a CCS-based NSPS, no coal-fired generation will be built. They contented 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. There have been very few new coal-fired generating sources built 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 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.
5. Accuracy of Cost Estimates for Transportation and Geologic Sequestration
The EPA's estimates of costs include 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 also consistent with other published studies. 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 Greenhouse Gas Reporting Program subpart RR for geologic sequestration of CO2 in deep saline formations. 
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. 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. Some commenters suggested that the EPA underestimated the costs associated with transporting captured CO2 from an EGU to a sequestration site. 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.  
The EPA believes its estimates of transportation and sequestration costs are reasonable. First, the EPA in fact included 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 estimated transport, storage and monitoring (TSM) costs of $5-$15 per ton of CO2 for non-EOR applications. This estimate is reflected in the LCOE comparative costs.
      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. 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. For new sources, pipeline distance and costs can be factored into siting and, as discussed in section V.K, there is widespread availability of geologic formations for 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.K below further discussing the current availability of CO2 pipelines.
      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 Greenhouse Gas Reporting Program 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 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. 
      The EPA's cost estimates account for the requirements of the Underground Injection Control Class VI program, and Greenhouse Gas Reporting Program 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. 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.[,] 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. 
      The EPA's cost estimates for sequestration thus cover all aspects commenters claimed the EPA disregarded. The EPA also made reasonable assumptions regarding the assumed injection site: a deep saline formation with typical characteristics (e.g., depth and pressure). To that end, the EPA believes that the use of the costs and scenarios presented in these studies referenced are representative for the purposes of the cost analysis.
      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.L below, the construction permits issued by 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. Moreover, the company indicated it fully expected to be able to do so at full scale and explained how. For discussion of 40 CFR Part 98 subpart RR (the Greenhouse Gas Reporting Program requirements for geologic sequestration), including costs associated with compliance with those requirements, see section V.L below.
J. Achievable 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 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"). This is consistent with the Court's statements in Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427 (D.C. Cir. 1973) that it is necessary to "[k]eep[ ] in mind Congress' intent that new plants be controlled to the `maximum practicable degree.'"
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 500 MW coal-fired SCPC meeting the final standard of 1,400 lb CO2/MWh-gross will emit about 640,000 fewer metric tons of CO2 each year than that new unit would have emitted otherwise. That is equivalent to taking about 135,400 vehicles off the road each year and will result in over 25,000,000 fewer metric tons of CO2 in a 40-year operating life.
For comparison, see Table 13 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. 
Table 13. 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 plant
      636,300 
Coffeyville Fertilizer
      700,000 
Boundary Dam #3
    1,000,000 
Petra Nova/NRG WA Parish
    1,600,000 
Dakota Gasification
    3,000,000 
2013 CO2 supplied to U.S. EOR operations
   60,000,000 

K. Further Development and Deployment of CCS Technology
Researchers at Carnegie Mellon University (CMU), have studied that history and the technological response to environmental regulations. 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.
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 FGD units didn't 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 good 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 flue gas desulfurization (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.
L. Geologic and Geographic Considerations
In the following sections of the preamble, we discuss issues associated with the disposition of captured CO2: the "S" -sequestration  -  in CCS. We show that geologic sequestration (GS) capacity is available domestically in the form of geologic formations (e.g., deep saline formations) and EOR sites in most areas of the country. Where such GS capacity is unavailable, electricity demand in those areas can be served by coal-fired power plants built in neighboring areas with GS. For other of those areas, coal-fired power plants are either not being built due to state law prohibitions against building such units, or other available compliance alternatives exist allowing a new coal-fired power plant meeting the promulgated NSPS to be sited. 
      We further show that GS can be conducted safely, storing the sequestered CO2 without environmental release for geologic time periods. 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 Greenhouse Gas Reporting Program, 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 L of this preamble).
      Geologic sequestration (GS) (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). 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.
      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. For example, CO2 has been trapped for more than 65 million years in the Jackson Dome, located near Jackson, Mississippi. 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.
      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. As shown in the figure, there are 39 states for which onshore and offshore deep saline formation storage capacity has been identified. EOR operations are currently being conducted in 12 states. An additional 17 states have geology that is amenable to EOR operations. There are 10 states with operating CO2 pipelines and 23 states that are within 150 miles of an active EOR location. 
      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. 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. The availability of unmineable coal seams is shown in Figure 1 below.
      As discussed below in Sections K.1 and K.2 of this preamble, 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 against coal-fired power plants.

Figure 1: Geologic Sequestration in the Continental United States

 Figure 2  -  Electrical Transmission Lines Across the Continental United States 

1. Availability of Geologic Sequestration in Deep Saline Formations
      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. DOE estimates that areas of the United States 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. 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.
      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. The seven partnerships include more than 400 organizations spanning 43 states (and four Canadian provinces). 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.
      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. 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. No CO2 leakage has been reported from these sites, which further supports the availability of effective GS.
2. 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. 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 L below) that can be used for deployment of CCS across geographically diverse areas. 
      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 23 states are within 150 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, 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. According to data reported to the EPA's Greenhouse Gas Reporting Program (GHGRP), approximately 60 million metric tons of CO2 were supplied to EOR in the United States in 2013. Approximately 70 percent of this total CO2 supplied was produced from natural (geologic) CO2 sources and approximately 30 percent was captured from anthropogenic sources.
      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. 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. 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. 
      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. 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.
      * 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 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. 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.
      * 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 K.1 above). 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. 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. 
      As discussed in Section K.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 that sites are not available as a practical matter. 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. Other commenters noted significant geographic disparity in GS site availability, claiming absence of sites in southeastern areas of the country.
      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 K.3 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). In addition, there are alternative means of complying with the final standards of performance which 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.
3. 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. For example, these carbonate materials have been used in the construction industry and, more recently and innovatively, in cement production processes to replace Portland cement.
      For example, 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.
      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. 
      Alternative technologies that use captured CO2, such as the Skyonics project, are innovative advancements for CO2 utilization that are under development. However, consideration of how these emerging alternatives could be used to meet the performance standard involves understanding the ultimate fate of the captured CO2 and the degree to which the method permanently isolates the CO2 from the atmosphere. Unlike GS, currently there is not a monitoring and reporting mechanism to demonstrate that these alternative end uses of captured CO2 would result in permanent sequestration of the CO2. Therefore, they cannot be used to meet the performance standard at this time. As these alternative technologies are developed, the EPA is committed to working collaboratively with stakeholders to evaluate the efficacy of alternative sequestration technologies, address any regulatory hurdles, and develop appropriate monitoring and reporting protocols in the future.
4. Availability of Existing or Planned CO2 Pipelines
      CO2 has been transported via pipelines in the United States for nearly 40 years. 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. 
      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 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. 
      * 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. 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. 
      * Denbury completed the final section of the 325-mile Green Pipeline for transporting CO2 from Donaldsonville, Louisiana, to EOR oil fields in Texas. 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. A proposed project by NRG (Petra Nova) would capture CO2 from a power plant in Fort Bend County, Texas for transport to EOR sites in Jackson County, Texas through a proposed 82-mile CO2 pipeline. The project is anticipated to commence operation in 2016.
      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, 254 (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, which EPA has found to provide similar protective safeguards as the Department of Transportation regulations. See 79 FR 358-59 (Jan. 3, 2014). The EPA reiterates here its findings that existing controls over CO2 pipelines assure protective management, guard against releases, and assure that captured CO2 will be securely conveyed to a sequestration site.  
5. 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.
      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 electric generating units in the state. House Bill 25 prohibits the state Public Utility Commission from approving new electric generating units 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.
 6. Coal by wire
	In addition, as discussed in the proposal, electricity demand in states that may not have geological sequestration sites may be served by coal-fired electricity generation built in nearby areas with geological sequestration, which generation 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: "There are many examples where coal-fired power generated in one state is used to supply electricity in other states. For instance, 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. In another example, 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 sum, subsurface formations suitable for GS of CO2 captured from affected EGUs are geographically widespread throughout many parts of the United States, including via deep saline formations or EOR. Characteristics of geologic formations may vary based on geography, but the mechanisms by which CO2 is trapped underground are well understood and proven. Additionally, CO2 pipelines have been operating for over 40 years in the United States and new pipeline projects continue to be proposed and built. Some states already impose emission limits that can be met only through CCS, and in the few states that do not have geologic conditions suitable for GS, or may not be located in close proximity to these areas, demand could be served by coal-fired generation that is sited in areas with GS.
M. Final Requirements for Disposition of Captured CO2
      In 2010, the EPA finalized an effective and coherent regulatory framework to ensure that CO2 is safely sequestered -- that is, that CO2 can be injected and remain securely underground for geologic timeframes. 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 Greenhouse Gas Reporting Program (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 provide the monitoring mechanisms to identify and address potential leakage using SDWA and CAA authorities. 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. 
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 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. 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.
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. Notably:
      *       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.[,] 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. 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.
      *       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. 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.[,] 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. 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.
      *       Well construction must use materials that can withstand contact with CO2 over the operational and post-injection life of the project. 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.
      *       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.[,]
      *       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. 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. 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. 
      *       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 an indicator of potential leakage and USDW endangerment.
      *       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.
      *       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.
      *       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. 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.[,] 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. Following successful closure, the facility property deed must record that the underlying land is used for GS.
     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.[,][,][,][,][,] The EPA has also prepared and made available for public comment draft 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.[,][,][,]
      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. Following the operational period, Archer Daniels Midland plans a post-injection site care period of ten years. 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. 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. 
      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. 
      The permitting of these projects illustrates that permit applicants were able to address perceived challenges to issuance of Class VI permits. These permits demonstrate the EPA's view that these projects are capable of safely and securely sequestering large volumes of CO2 -- including from steam generating units -- for geologic timeframes since the EPA would not otherwise have issued the permits. 
b. Class II requirements. As explained in section K.2 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. 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. 
      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 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 Greenhouse Gas Reporting Program (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 40 CFR 60.46Da(h)(5) and 40 CFR 60.5555(d). 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. CO2 suppliers are required to report the annual quantity of CO2 transferred offsite and its end use, including GS. 
      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.
      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 40 CFR 60.46Da(h)(5) and 40 CFR 60.5555(d) to use the phrase "If your affected unit captures CO2" in place of the phrases "If your affected unit uses geologic sequestration" and "If your affected unit employs geologic sequestration", respectively. 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. 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.[,][,][,] 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. The subpart RR MRV plan includes five major components:
      * A delineation of monitoring areas based on the CO2 plume location. Monitoring may be phased in over time.
      * 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.
      * 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. 
      * 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. 
      * 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.
      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.
      Under this final rule, any well receiving CO2 captured from an affected source, be it a Class VI or Class II well, must report under subpart RR. As explained below in Section L.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.
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, as explained below, the practical effect of these complementary technical requirements 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 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 L.1, the UIC Class VI rule provides a framework to ensure the safety of underground injection of CO2 such that USDWs are not endangered. 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 L.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 for geologic timeframes (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. 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. 
      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. Once the anomalous operating conditions are verified, the cessation of injection, as required by UIC permits, will minimize any risk of release to air. 
      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, which 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 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..." 
      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 L.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 provides backup 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 to air.
      CO2 injected via Class II wells becomes sequestered by the trapping mechanisms described above in Section L.3.a. 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 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.
      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 J.1). The BSER determination and regulatory impact analysis for this rule relies on GS in deep saline formations. 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. 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. 
      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.
      Snøhvit 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. In 2011, the injection well was modified and injection was initiated in a second interval (Stø 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.
      As discussed above in Section K, 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 K.2). 
      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 tons per year. Storage integrity has been monitored by several US 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 ambient air.
      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 Snøhvit), 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.
5. 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).
      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 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" under section 111. 
      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, and 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. 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).
      The EPA addresses these comments in more detail in the Response to Comment Document.
6. 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: 
      * 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 a 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. 
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. 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.
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 is prohibitive to 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. Monitoring costs 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.
      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. 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. 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.
      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. 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. 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)). 
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. Other commenters noted the lack of long-term liability insurance, and noted uncertainties regarding long-term liability generally.
      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. 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. As noted earlier, both the Archer Daniels Midland 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.  
	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. Other commenters noted more generally that site characterization issues can be time-consuming and difficult, and quoted studies suggesting that it could take 5 years to obtain a Class VI permit. 
      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 K). 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. 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. 
N. Options That Were Considered 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.
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 pulverized coal (SCPC) or a supercritical CFB boiler, or a modern, well-performing IGCC unit.
      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-gr, a new SCPC unit using bituminous coal would emit nearly 1,700 lb CO2/MWh-gr, and a new IGCC unit would emit about 1,450 lb CO2/MWh-gr. Emissions from comparable sources utilizing sub-bituminous coal or lignite will have somewhat higher CO2 emissions.
      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, the majority of the most 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. Coal-fired power plants that have come on-line the most recently include AEP's John W. Turk, Jr. Power Plant, which is a 600 MW ultra-supercritical PC (USCPC) facility located in the southwest corner of Arkansas, and Duke Power's Edwardsport plant, which is a 618 MW "CCS ready" IGCC unit located in Knox County, Indiana. The majority of new coal-fired power plants that were brought on-line in 2010 or later have utilized supercritical boiler technology. And those 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. 
      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 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 [x.x], 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." 
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 caselaw, encouraging the development and implementation of advanced control technology must also be considered. 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 International Panel on Climate Change (IPCC) recently released its Fifth Assessment report, 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.
      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." 
      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-gross, 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 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 does not require 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 require the installation of advanced control equipment lead to increased use of that control equipment, and 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.
      
      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. As we will show later, the final standard that we are issuing in this action is less stringent than the proposed level and can be met at a lower cost than the proposed standard. 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 new coal-fired EGUs. In that scenario, a cost-reasonable standard is, in fact, 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 most IGCC units, the final standard of performance can be met simply 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-gross 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 (January 2014 proposal), 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 even greater than at proposal. The EPA thus is not selecting full capture CCS as BSER.
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 potential 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 potential hourly increase in CO2 emissions (mass per hour) of less than or equal to 10 percent ("small" modifications), is not issuing final standards for these sources in this action, and is withdrawing the proposed standards for these sources. 
   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 [x.x] (General Applicability) and section [x.x] (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 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." 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.
      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 potential hourly CO2 emissions (mass per hour) of more than 10 percent as compared to the source's potential to emit 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 potential hourly CO2 emissions (mass per hour) of 10 percent or less compared to the source's potential to emit during the previous 5 years, the EPA is not finalizing any standard or other requirements, and in a separate action today is withdrawing the June 2014 proposal with respect to these sources.
      As we discussed in the June 2014 proposal, the EPA has historically been notified of only a limited number of NSPS modifications 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 reconstruction or replacement of steam turbines and other equipment upgrades that result in substantial increases in a unit's potential 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 potential hourly CO2 emissions, as well as on the types of 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.
      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.
      To be clear, the EPA is not reaching a final decision that 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.
      In deferring issuance of standards of performance for those sources that conduct modifications resulting in a potential hourly increase in CO2 emissions of less than or equal to 10 percent, the EPA is exercising its discretion to propose and promulgate standards covering sources within a source category in a sequential manner, under appropriate circumstances, such as those present here, consistent with the case law that authorizes agencies to establish a regulatory framework in an incremental fashion, that is, a step at a time.[,]
      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 reconstruction 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 potential hourly CO2 emissions by well over 10 percent. 
      Therefore we are setting the threshold between "large" modifications and "small" modifications subcategory at 10 percent, a level commensurate with the magnitude of the emissions increases that could result from these types of projects, and we are issuing a final standard of performance for those sources that conduct modifications resulting in potential hourly CO2 emission increases that exceed that threshold. We are not issuing standards of performance for those sources that conduct modifications resulting in a potential hourly increase of CO2 emissions of less than or equal to 10 percent. 
      Therefore, in a separate action (published in a separate notice in the Federal Register today), the EPA is withdrawing the proposed standards for those sources that conduct modifications resulting in a potential 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. 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 part C 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 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 potential CO2 hourly emissions. Nevertheless, 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 potential hourly CO2 emissions associated with such modifications would generally be small and would therefore generally not subject such modifications to the standards of performance that the EPA is finalizing today for modified steam generating units with large increases in potential hourly CO2 emissions.
	We note that modified steam generating units that are not subject to the standard of performance finalized in this rule would be existing sources subject to section 111(d).
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 source'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 source'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 source'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". 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.
         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. 
         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. Technology Promotion 
      As noted previously, the case law makes clear that the EPA is to consider 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 EPA's decision that these technologies are not BSER. In contrast, 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 are finalizing 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-net for units with a heat input rating of greater than 2,000 MMBtu/h and 2,100 lb CO2/MWh-net 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-gross for large units and 1,800 to 2,200 lb CO2/MWh-gross 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-net 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-gross for sources with a heat input rating of greater than 2,000 MMBtu/h and 2,000 lb CO2/MWh-gross for sources with a heat input rating of 2,000 MMBtu/h or less. 
      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, Modified, and Reconstructed Stationary Combustion Turbines
      This section summarizes the final applicability requirements, BSER determinations, and emission standards for newly constructed, modified, and reconstructed stationary combustion turbines. We explain our rationale for these final decisions in Section IX of this preamble. 
A. Applicability Requirements
	We are finalizing emission standards for newly constructed, modified, and reconstructed stationary combustion turbines that (1) have a base load rating for fossil fuels greater than 250 MMBtu/h and (2) serve a generator capable of selling more than 25 MW of electricity to the grid. We also are finalizing applicability requirements that will exempt stationary combustion turbines that are dedicated peaking units, dedicated non-fossil units, or are physically incapable of burning natural gas (i.e., not connected to a natural gas pipeline), waste combustors and incinerators (units subject to subparts Eb or CCCC of this part), as well as the large majority of industrial combined heat and power units from the final emission standards. Specifically, the final emission standards do not apply to stationary combustion turbines subject to a federally enforceable permit condition limiting annual electric sales to the specific design efficiency of the combustion turbine multiplied by the unit's potential electric output or less or restricting annual fossil fuel use to 10 percent or less of a unit's heat input capacity. Finally, the final emission standards do not apply to combined heat and power units that are subject to a federally enforceable permit condition limiting net-electric sales to the unit's design efficiency multiplied by the unit's potential output or 219,000 MWh, whichever is greater.
B. Best System of Emission Reduction
	We are finalizing the same BSER as proposed. For newly constructed, modified, and reconstructed stationary combustion turbines. The BSER is the use of modern, efficient combined cycle technology. 
C. Final Emission Standards
      For all newly constructed, modified, and reconstructed natural gas-fired combustion turbines, we are finalizing an emission standard of 1,000 lb CO2/MWh-gross, calculated on a 12-operating month rolling average basis. We are also finalizing an optional emission standard of 1,080 lb CO2/MWh-net, calculated on a 12-operating month rolling average basis. 
IX. Rationale for Final Standards for Newly Constructed, Modified, and Reconstructed Stationary Combustion Turbines
	This section discusses three inter-related topics (1) applicability criteria, (2) BSER, and (3) achievability of the standards for combustion turbines. We summarize what was proposed, relevant comments received with our responses, and the rationale for the final determinations. The rationale includes a discussion on the role of simple cycle turbines in providing backup power in regions with large amounts of intermittent renewable generation. The achievability discussion explains how the applicability criteria taken together with our BSER determination ensure that the standards are achievable by affected units. 
      Applicability and subcategorization are closely tied to the required emission standards, and we are carefully considering them together. For example, some owners/operators may see an inherent value in not being subject to subpart TTTT, regardless of the requirements for that particular type of unit under subpart TTTT, and certain exemption criteria could lead to a perverse incentive to install new units or run units in a way that increases CO2 emissions above the baseline emission rate. Furthermore, the EPA recognizes that energy industry trends have evolved, and we are adjusting our proposed approach to reflect these changes. 
      For the proposed applicability to combustion turbines, the EPA used the 1/3 electric sales criteria, in part because it already exists in regulatory context (e.g., the coal-fired EGU NSPS) and would allow for consistency between regulations. Our understanding at proposal was that the 1/3 electric sales criterion would essentially exclude all simple cycle turbines and would serve to distinguish between peaking (i.e., low capital cost, flexible, but relatively inefficient simple cycle units) and intermediate and base load combustion turbines (i.e., higher capital cost, less flexible, but relatively efficient combined cycle units). Based on public comments however, our understanding of the potential future roles of combustion turbine EGUs has evolved. The growth of generation from intermittent renewable sources has created a perceived need for additional cycling generation that operates outside of the traditional roles of simple and combined cycle combustion turbines. In response, the market is developing new technologies to fill this need perceived by end users of combustion turbines. Some manufacturers have developed high efficiency simple cycle turbines. While these newer turbines have higher capital costs than older simple cycle turbine designs, they are significantly more efficient and have maintained similar flexibilities (e.g., ability to start and change load rapidly) as previous designs. In contrast, other manufacturers have developed fast start flexible combined cycle units specifically to fill this role. These newer combined cycle designs have lower design efficiencies than base load combined cycle designs, but are able to start up more quickly to respond to rapid changes in electricity demand. Therefore, there is no longer a clear distinction between the role of simple cycle and combined cycle turbines. 
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 an applicability determined strictly on design and permit restrictions and independent of actual operating characteristics. 
1. Proposed Applicability
      The proposed five applicability criteria for combustion turbines were that a 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 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 did not propose CO2 standards for two types of combustion turbines that are currently subject to criteria pollutant standards under subpart KKKK (the combustion turbine criteria pollutant NSPS). The first type was stationary combustion turbines that were constructed for the purpose of selling or 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. The second type of unit was non-natural gas-fired stationary combustion turbines (i.e., combustion turbines that actually combust 90 percent or less natural gas on a 3 year rolling average basis). Under the proposed approach, applicability with the GHG NSPS could change on an annual basis depending on actual electric sales and the composition of fuel burned. While the proposed applicability criteria did not explicitly exempt simple cycle combustion turbines, we concluded at proposal that it would as a practical matter exclude the vast majority of simple cycle turbines because, historically, simple cycle turbines have operated as peaking units and, on average, have sold less than five percent of their potential electric output on an annual basis.   
      We solicited comment on a range of issues related to the general applicability of the EGU GHG NSPS to combustion turbines. In conjunction with the proposed one-third sales criterion, we solicited comment on finalizing an electric sales criterion between 20 to 40 percent of the potential electric output or basing the electric sales criterion on the design efficiency of the combustion turbine (i.e., the sliding scale approach). Under the sliding scale approach, more efficient combustion turbines would be able to sell a greater portion of their potential electric output, relative to less efficient combustion turbines, prior to triggering the electric sales criterion. We also solicited comment on whether the 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 electric sales criterion for combustion turbines to eliminate any incentive to install multiple, exempt, small, and less efficient stationary combustion turbines. We also solicited comment on whether to provide an explicit exclusion for all simple cycle combustion turbines regardless of the amount of electricity sold. Finally, we solicited comment on how to implement the proposed actual electric sales and actual fuel use applicability criteria evaluated as 3-year rolling averages during the first three years of operation, and we requested comment on appropriate monitoring, recordkeeping, and requirements. We specifically solicited comment on whether these proposed requirements raise implementation issues because they are based on source operation after construction has occurred. 
      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. Specifically, we solicited comment on whether we should completely remove the electric sales (both the actual sales and "constructed for the purpose" criteria) and fuel use criteria components from the general applicability framework (that establishes the sets of sources that are subject to CAA section 111 standards). Instead the actual electric sales and fuel use thresholds would serve as subcategorization criteria for distinguishing classes of EGUs and subcategory-specific emissions standards. Under a broad applicability approach, the "constructed for the purpose of" would be completely eliminated and applicability for combustion turbines would be determined by the base load rating (i.e., greater than 250 MMBtu/h) and the capability to sell power to a utility distribution system (i.e., serving a generator capable of selling more than 25 MW to a utility distribution system). In contrast to the five proposed applicability criteria, under the broad applicability approach, affected units, including simple cycle peaking and oil-fired combustion turbines, would remain subject to the standard of performance regardless of their actual electric sales or fuel use. The broad applicability approach is consistent with historical NSPS applicability approaches based on design criteria with different emission standards for subcategories distinguished by operating characteristics. We solicited comment on all aspects of this "broad applicability approach," including the extent to which it would achieve the policy objectives of assuring that a simple cycle turbine and a combined cycle turbine are subject to the same standard if they sell more than the specified electric sales threshold to the grid. 
      We also requested comment on excluding electricity sold during system emergencies as counting toward net electric sales for determining sales in excess of the electric sales threshold. The rationale included that simple cycle combustion turbines intended only for peaking applications might be required to operate above the proposed electric sales threshold if a major power plant or transmission line is unexpectedly unavailable for an extended period of time. The EPA concluded that this flexibility is appropriate if the unit is called upon to run after all other available generating assets are already running at full load. The definition of "system emergency" presented in the proposal was "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 facility to operate to avert loss of load." 
2. Comments on Applicability
      We received comments specific to each one of the five 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. The comments and rationale for applicability to dedicated non-fossil units (i.e., units that combust less than 10 percent fossil fuel) and industrial CHP are discussed in Section III of this preamble. For combustion turbines, we received few specific comments on the 10 percent fossil fuel threshold and the 90 percent natural gas threshold. Many commenters supported the general size thresholds (i.e., have a base load heat input rating greater than 250 MMBtu/h and serving a generator with a capacity greater than 25 MW) because these thresholds are consistent with the thresholds used in states participating in the Regional Greenhouse Gas Initiative (RGGI) and under Title IV programs. Other commenters opposed this threshold 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 sources because unaffected units have a competitive advantage in energy markets because these exempt units would not be required to internalize the costs of compliance. The EPA received many comments on applicability of the proposed standards to simple cycle combustion turbines, the electric sales criteria (both the one-third sales relative to the potential electric output and the 219,000 MWh criteria), and the broad applicability approach.
      Commenters from the power sector generally supported a complete exemption of simple cycle turbines. The rationale for these commenters included that simple cycle turbines are uniquely capable of achieving the ramp rates necessary to respond to emergency conditions and hourly variations in output from intermittent renewables. Commenters noted that simple cycle combustion turbines serve different purpose than combined cycle power blocks and that economics will drive the use of combined cycle 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 an electric sales criterion between 40 to 60 percent. Some commenters supported the sliding scale approach and stated that incentives for manufacturers to develop and end users to purchase higher efficiencies combustion turbines could be directionally helpful towards mitigating concerns about a monolithic national constraint on simple cycle capacity factors. In contrast, others commented that fast response combined cycle units intended for peaking and intermediate load applications can achieve ramp rates comparable to simple cycle units. These commenters said that simple cycle turbines should be restricted to their historical role as peaking units and that the one-third electric sales criterion provides sufficient flexibility. Some commenters suggested that the one-third sales criterion could be reduced to 20 percent or lower without adverse impact on grid reliability. Commenters noted that a complete exclusion for simple cycle turbines creates an opportunity to evade the standard and could thereby increase GHG emissions by creating a regulatory incentive to install and operate less efficient unaffected units compared to more efficient affected units. According to these respondents, any applicability distinctions should be based on utilization and function rather than purpose or technology. 
      Commenters also noted that the 219,000 MWh electric sales criteria puts larger combustion turbines at a competitive disadvantage by distorting the market and could have the perverse impact of increasing GHG emissions. These commenters noted that the 219,000 MWh electric sales threshold permits combustion turbines smaller than about 80 MW to sell more than the proposed one-third electric sales threshold while larger, more efficient combustion turbines are restricted to selling one-third of their potential electric output to avoid applicability of the proposed CO2 standard. This creates a regulatory incentive to install multiple less efficient combustion turbines instead of fewer more efficient combustion turbines and could have the unintended consequence of increasing GHG emissions.
      Commenters in general supported that net electric sales applicability use a 3-year rolling average instead of a single year average. However, commenters noted that the inconsistency between the 3 calendar year applicability and 12-operating month compliance period results in compliance issues. For example, a facility could burn greater than 90 percent natural gas over a 3 year period, but could burn greater than 10 percent distillate oil during a 12-operatng month compliance period with the same 3 year period. Since the CO2 content of distillate oil is higher than natural gas, even if the facility is operating at maximum efficiency it would exceed the proposed emission standard. The inconsistency creates similar issues for 12-operating month periods with low electric sales, but the 3 year sales exceed the applicability threshold.
      In response to EPA's request for comments on whether the retrospective applicability requirements would create implementation issues, several permitting authorities opposed proposed applicability provisions that could change applicability determinations from year-to-year because this approach would result in compliance issues and in difficulties in determining proper pre-construction and operating permit conditions. These permitting authorities said that in order for a source to avoid applicability of the NSPS, the source must be subject to a federally enforceable permit limit 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: which is intended to provide clear and predictable standards of performance for new sources that would apply when they begin operations. 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 or not the GHG standard applies to a proposed new unit. Commenter said EGUs undergoing permitting should be allowed to request limits in operating permit conditions in order to remain below the proposed rule's applicability provisions, 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 stated a preference for the "proposed applicability approach" over the "broad applicability approach." These commenters did not think it was necessary to require combustion turbines with low electric sales or non-natural gas-fired combustion turbines to be subject to GHG 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) since these units would be subject "no emissions standards." In addition, some commenters stated that use of the "broad applicability" approach under CAA section 111(b) proceedings is not appropriate because the plain language of the CAA prohibits establishment of applicability requirements under CAA section 111 that rely on "no emissions standard" as suggested by the EPA. These commenters stated that "no emission standard" is not a "standard of performance" as defined in CAA section 111(a)(1) because a "standard of performance" is defined as a "requirement of continuous emission reduction." In contrast, many other commenters supported inclusion of new simple cycle units within the scope of the CAA 111(b) applicability criteria so that similar, existing simple cycle units would be subject to the CAA 111(d) standard (to preserve the discretion of state planners under section 111(d)). Numerous other commenters stated that all sources that sell electricity to the grid should be subject to the 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.
      Multiple commenters supported exclusion of electricity generated as a result of a grid emergency from counting towards net sales when determining applicability. One commenter stated that in addition to declared grid emergencies, there are other circumstances that warrant emergency exemption under the rule, including extreme market conditions, limitations on fuel supply, and reliability responses. Another commenter stated that the definition of "system emergency" should be defined as "any abnormal system condition that the Regional Transmission Organization, Independent System Operators, or Control Area Administrator determines requires immediate automatic or manual action to prevent a limit loss of transmission facilities or generators that could adversely affect the reliability of the power system and therefore calls for maximum generation resources to operate in the affected area, or for the specific affected facility to operate to avert loss of load." The commenter said this definition is appropriate because the benefits of operating these units to generate electrical power during emergency conditions outweigh any adverse impacts from short-term increases in CO2 emissions by units lower in the dispatch order.  
      Multiple commenters opposed the exclusion of grid emergencies when calculating a source's net electricity sales for rule applicability purposes because CAA section 111 emission standards must apply continuously, even during grid emergencies. The commenters stated that the EPA does not have the necessary authority under the CAA to suspend applicability of the standard during periods of "grid emergency". Some commenters stated that an exclusion is unnecessary, because the EPA possesses an effective mechanism to address the issue: The EPA Assistant Administrator for Enforcement is delegated the authority to advise a source that the government would not sue the source for taking certain actions during an emergency. Commenters said this enforcement discretion approach has provided prompt, flexible relief that is tailored to the needs of the particular emergency and the communities being served, yet is only utilized where the relief will address the particular emergency at hand. Commenters added this enforcement discretion approach is consistent with CAA's mandate that emission limits apply continuously and provide safeguards against abuse. One commenter stated that the emergencies that the EPA mentions happen rarely and typically last for short periods, and the proposed applicability threshold would allow a source to operate at its full rated capacity for up to 2,920 hours per year without triggering NSPS, and the potential occurrence of grid emergencies represents 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  -  can justify operating a peaking unit above a 10 percent capacity factor on a 3-year rolling average. 
3. Final Applicability
      For the final rule, we are retaining the applicability criteria that the unit must be capable of combusting more than 250 MMBtu/h heat input of fossil fuel, and must serve a generator capable of selling more than 25 MW to the grid. While some commenters suggested we should cover smaller EGUs as well, we did not propose to cover smaller units. Considering this, that smaller sources emit relatively few CO2 emissions compared to larger units, and that at this time we do not have information to identify an appropriate BSER for these units we are not finalizing any CO2 standards for smaller units. However, based on consideration of the comments received related to the other four proposed applicability criteria and practical implementation issues, we are revising how those criteria will be implemented. First, the proposed actual electric sales relative to the potential electric output and the actual percent natural gas usage criteria are being finalized as applicability criteria based on operating restriction included in a federally enforceable permit. Second, for non-CHP combustion turbines we are eliminating the proposed 219,000 MWh electric sales criterion. Next, the proposed 10 percent fossil fuel use applicability criteria is being finalized as an exemption for non-fossil fuel-fired units that are subject to a federally enforceable permit condition limiting the use of fossil fuel. Finally, similar to the proposed actual electric sales criteria, the proposed constructed for the purpose of selling one-third of your potential electric output applicability criteria is being finalized as an exemption for dedicated peaking units that are subject to a federally enforceable permit limiting annual electric sales. Section III described the rationale for why the EPA is not finalizing GHG standards for dedicated non-fossil fuel-fired or industrial CHP combustion turbines. The final applicability is generally consistent with the broad applicability approach we solicited comment on. 
      The EPA agrees with commenters that the NSPS applicability framework should be structured so that permitting authorities and the regulated community can determine what standards apply prior to a facility having commenced construction. Therefore, the EPA has concluded that the proposed retrospective applicability criteria for combustion turbines that included actual electric sales and the amount of natural gas combusted are not practical approaches, since applicability determinations verse these criteria could change from year to year (i.e., facilities could be moving in and out of applicability each year). Furthermore, from a practical implementation standpoint, existing permitting rules would generally require pre-construction permitting authorities to include enforceable conditions limiting operations such that unaffected units would not trigger either the proposed electric sales or fuel use thresholds if they were included as general applicability criteria. Such conditions are often called "avoidance" or "synthetic minor" conditions, and these conditions typically include ongoing monitoring, recordkeeping, and reporting requirements to ensure operations remain below a particular regulatory threshold. 
      The EPA evaluated several approaches for implementing the proposed retrospective applicability criteria through a pre-construction and operating permit program. For the proposed 90 percent natural gas fuel use criterion, the EPA has concluded that a comparable permit restriction would be to exempt all facilities not subject to an operating permit restriction requiring that natural gas contribute over 90 percent of the heat input. This is not a practical restriction since (1) 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) and not to limit lower emitting activities; (2) new combustion turbines could avoid applicability by simple not having a permit that requires the use of over 90 percent natural gas even if they intend to only burn natural gas; and (3) this approach is inconsistent with the objectives under CAA section 111(d) and would essentially provide a pathway for all combustion turbines to avoid applicability under state 111(d) plans. Similarly, finalizing an applicability requirement that exempts combustion turbines unless they have a permit restriction limiting non-natural gas to 10 percent or less of the heat input (i.e., limit the use of natural gas to less than 90 percent of the total heat input) is also problematic. Owners/operators of new combustion turbines could avoid applicability by simply being permitted to burn non-natural gas fuels for over 876 hours per year even if they actually intended to seldom, if ever, combust the alternate fuels. Many commenters expressed the need to maintain the ability to burn distillate oil, particularly during natural gas curtailments. Consequently, this approach would cause similar applicability issues for both 111(b) and 111(d). The EPA has concluded that the only way to distinguish a non-natural gas-fired combustion turbine and a natural gas-fired combustion turbine is the ability to burn any natural gas. Consistent with the intent of the rule (to establish GHG emission standards for natural gas-fired combustion turbines) we are not finalizing GHG standards for combustion turbines that are not capable of firing any natural gas. Combustion turbines without any connection to a natural gas pipeline would not be subject to any of the requirements of this rulemaking. 
      For the proposed one-third electric sales criterion, the EPA has concluded that a comparable permit restriction would be to require a combustion turbine to actually sell more electricity than the specified threshold. Similar to the fuel use requirement, this is impractical because new combustion turbines could avoid applicability by simply not having a permit restriction to actually sell more than one-third of its potential electric output. Even if a facility were subject to this restriction, a permit violation for a unit that does not operate enough to sell one-third of its potential electric output is nonsensical since system demand may not be sufficient to allow all permitted units to operate above the specified threshold. The EPA has concluded that a permit restriction similar to the proposed one-third electric sales criterion would restrict sales to less than one-third of the potential electric output. Combustion turbines not subject to a federally enforceable electric sales restriction would have to comply with the applicable standards. The EPA has concluded this approach is appropriate for identifying dedicated peaking units. To determine an appropriate annual electric sales threshold to subcategorize dedicated peaking units, the EPA reviewed operating data for existing simple cycle units from 2005 to 2014. The EPA has concluded that an appropriate annual electric sales threshold for dedicated peaking units should be high enough to include how the majority of simple cycle turbines have historically operated. We have concluded that based on the revised electric sales applicability criteria and practical implementation issues (i.e., operating permit restrictions are written on an annual basis) permit restrictions for NSPS applicability purpose will be annual limits, as opposed to the proposed 3 year actual net electric sales applicability criteria.
      As stated earlier, we have concluded it is appropriate to avoid perverse impacts resulting from the applicability of this rulemaking. If we set an electric sales applicability permit restriction threshold too low it could have the unintended impact of increasing GHG emissions. Utilities have an obligation to provide sufficient electricity to meet system demand regardless of specific emission standards that have been placed on individual units. By limiting certain units to less than one-third of their potential electric output, utilities and other developers could justify building multiple lower capital cost, but less efficient, simple cycle turbines combustion turbines subject to avoidance limits below the electric sales threshold compared to fewer higher capital cost more efficient simple cycle combustion turbines that could meet the same demand by operating just above the proposed threshold. In either case, system demand would be the same and a sufficient numbers of combustion turbines would be built to assure sufficient generation capacity was available, but the associated GHG emissions and the cost to ratepayers would be higher for the scenario with multiple turbines operating at lower loads than the fewer more efficient units. In contrast, setting an electric sales applicability threshold that is too high could leave new units with a substantial amount of potential CO2 emissions unregulated and would reduce the number of units included in 111(d) state plans. In addition, developers of new EGUs completely exempt from the 111(b) would also have a perceived benefit of not being subject to potential future revisions of 111(d) requirements. In balancing these competing factors, the EPA has concluded that a permit restriction tied to the design efficiency of the unit is appropriate (i.e, the sliding scale approach). Specifically, owners/operators of new units subject to a permit restriction limiting annual net electric sales to the design efficiency of the unit times the potential electric output (e.g., limiting annual hours of operation to the design efficiency times 8,760 hours) would not be subject to the final requirements of this rulemaking. For a more detailed discussion, see the BSER discussion. 
      The EPA has concluded concerns raised during the public comment period suggesting that the 219,000 MWh annual sales exemption would encourage the installation of multiple smaller, less efficient simple cycle combustion turbines instead of a single, more efficient and larger turbine are valid. The 219,000 MWh electric sales criterion allows simple cycle combustion turbines (e.g., less than 80 MW) to sell significantly more electricity relative to the potential electric output than larger turbines. Many commenters expressed that there is an inherent value in flexibility to operate simple cycle turbines at high capacity factors even if it is never intended to run at a high capacity factor. One of these factors is the ability to get capacity payments from the transmission authority. If we finalized the 219,000 MWh electric sales criterion for combustion turbines we would be providing a perverse incentive to install smaller, less efficient simple cycle turbines. We are therefore not finalizing the 219,000 MWh annual electric sales exemption for non-CHP combustion turbines. 
      We have concluded that the emergency conditions exemption provides flexibility to maintain system reliability and minimizes overall costs to the sector. Therefore, we are finalizing that electricity sold during hours of operation when the unit is called upon to operate due to a system emergency will not be counted as net electric sales. Electric sales from units that are not called upon to operate specifically due to the system emergency (e.g., already operating when the system emergency is declared) would be treated as normal net electric sales.
B. Identification of the Best System of Emission Reduction
      This section summarizes the proposed BSER for combustion turbines, provides a summary of comments received, and the final BSER determination. For combustion turbines, we proposed and are finalizing the use of combined cycle technology as the BSER for affected stationary combustion turbines. Combustion turbines would be required to meet an output based emission standard based on what we have concluded is an achievable standard based on review of emission rate information from existing natural gas-fired combined cycle units and permitted emission standards for recent natural gas-fired combined cycle units.
1. Proposed BSER
      At proposal, we considered three alternatives in evaluating the BSER for new natural gas-fired stationary combustion turbines (1) high efficiency simple cycle aeroderivative turbines (2) modern, efficient NGCC units, and (3) CCS. We rejected high-efficiency simple cycle aeroderivative turbines as the BSER because this standalone technology does not provide emission reductions and is more expensive compared to combined cycle technology. We rejected NGCC with CCS as the BSER because we concluded that at proposal we had insufficient information to make a determination regarding the technical feasibility of implementing CCS at combustion turbine units. In contrast, combined cycle units are the most common type of new fossil fuel-fired units being planned and built today for generating intermediate and base load power. The design is technically feasible and combined cycle units are currently the lowest-cost, most efficient option for new fossil fuel-fired power generation. After considering the technology options, the EPA proposed to find modern, efficient NGCC technology to be the BSER for stationary combustion turbines, and we based the proposed standards on the performance of recently constructed natural gas-fired combined cycle units. 
2. Comments
      Many commenters opposed the grouping of simple cycle units and combined cycle units in the same category and establishing the BSER for combustion turbines strictly based on the combined cycle mode of operation. Commenters pointed to the word "achievable" in CAA section 111(a)(1) and stated that applying an emission standard based on combined cycle technology to simple cycle units is legally indefensible because simple cycle units cannot achieve emission rates as low as combined cycle units. Commenters also stated that under CAA section 111(b)(2) the EPA may acknowledge these different functions by completing function-specific BSER determinations and by establishing separate standards for these functions. Many commenters stated that combined cycle technology should be the BSER for base-load and intermediate-load functions, while simple cycle should be the BSER for peak-load functions.
      Some commenters stated that the proposed BSER analysis for coal-fired units was inconsistent with the BSER analysis for natural gas-fired combustion turbines. They stated the EPA determined that use of CCS is feasible for coal-fired generation based on current CCS projects under development at coal-fired generating stations, but the agency did not come to the same conclusion for natural gas-fired combustion turbines when there is an NGCC project under development that will apply CCS to a slip stream of NGCC flue gas. Commenters further stated that it is irrelevant that the NGCC CCS project is a partial CCS project whereas the developmental projects for coal fired units are "full-scale." These commenters stated that the EPA cannot utilize projects under development as a basis for justifying CCS as BSER for coal fired units and then abandon this basis for NGCC units. In addition, some commenters disagreed with the EPA's decision to treat NGCC differently than coal-fired units on the basis that NGCC units start up and shut down more frequently than coal-fired units. The commenter said operating characteristics of NGCC units are not an impediment to using partial CCS, and suggested that NGCC operators could bypass the carbon capture system during startup and shutdown modes (which are typically shorter and less intensive efforts compared to startup or shutdown of a coal facility) and then employ the carbon capture system when operating normally. Many commenters stated that CO2 removal is just as technologically feasible and economically reasonable for an NGCC EGU as a coal-fired EGU. These commenters referred to literature suggesting that at 40 percent removal there would be no expected difference in the technical requirements for either type of EGU. Some commenters referred to a DOE/NETL study that suggests the cost of CCS for NGCC is more cost effective than for coal-fired EGUs. 
      Many commenters supported the EPA's determination that NGCC with CCS technology is not BSER for newly constructed, modified, or reconstructed combustion turbines. These commenters agreed that there are insufficient data on costs and site-specific constraints to conclude that CCS and EOR technologies are available and feasible at the numerous locations in the U.S. where combined cycle projects are currently planned based on projected natural gas prices. Commenters stated that the limited scope of the one CCS-on-NGCC project cited in the proposal did not reflect the costs of pipeline transport and geologic sequestration implicit in use of this technology as a nation-wide BSER technology because the slip stream of CO2 is used at a local facility that temporarily incorporates the CO2 into food products. Commenters also stated that CCS has not been adequately demonstrated or proven to be commercially viable for NGCC units. Other commenters stated that CO2 capture technologies do not match well with the operating flexibilities of NGCC and simple cycle units, and even if technical barriers could be overcome, application of CCS to gas-fired turbines would also be more costly (compared to applications of CCS to coal-fired units) on a dollars-per-ton-CO2-captured basis because of the higher flue gas volumes (per MW of generating capacity) and the lower CO2 concentrations from methane combustion in turbines compared to coal combustion in boilers.
      Some commenters stated that a CCS-based standard for NGCC units would negatively impact the environment and the nation's energy needs. They also stated that CAA section 111(a) requires the EPA to account not only for the cost of achieving emission reductions, but also for the impact of BSER on energy requirements and the environment. The commenters cited Costle, where the D.C. Circuit observed that, following its analysis of adequately demonstrated emissions technology, the EPA "must exercise its discretion to choose an achievable emission level which represents the best balance of economic, environmental, and energy considerations." The commenters also stated that requiring CCS on natural gas units would adversely affect the nation's energy needs and the environment because imposing partial CCS on natural gas-fired 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. Finally, the commenters stated that since NGCC units are projected to provide a significant share of new power generation, the EPA should recognize that requiring partial CCS on NGCC units would have proportionally higher impact on electricity prices compared to the projected number of new coal-fired generating projects. These commenters concluded that the EPA cannot determine that partial CCS is BSER for NGCC units without producing severe and unacceptable consequences for the availability of affordable electricity in the United States. In a related comment, another commenter said that CCS is technically feasible for gas turbine facilities, but agrees that requiring CCS for all new NGCC plants may hinder the construction of new, more efficient NGCC. Instead, the commenter suggested the EPA defer a decision on whether CCS is BSER for combustion turbine units until the subsequent NSPS revisions. The commenter expressed concerns that the EPA's rationale for rejecting CCS as BSER for NGCC, may be used by developers and permitting authorities as an excuse to reject CCS as Best Available Control Technology (BACT) in future New Source Review (NSR) permits.
      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 for reducing CO2 emissions with no negative environmental impacts and no negative economic impacts on rate payers. These commenters stated that advanced NGCC technologies are capable of achieving emission rates that are 8 percent lower than conventional NGCC facilities. Commenters said that the majority of existing sources that do not deploy these advanced technologies are currently able to meet the standard, and commenters said that the proposal failed to explain why these lower-emitting advanced technologies that are more than adequately demonstrated were not selected as the BSER.
3. Identification of BSER
      As stated in the proposal, combined cycle units have both lower GHG emissions and a lower cost of electricity than simple cycle turbine facilities when operated as intermediate and base load EGUs. Therefore, the use of a combined cycle technology would be BSER for higher capacity factor stationary combustion turbines. The EPA refined the LCOE costing approach used at proposal to compare the cost effectiveness of simple cycle combustion turbines compared to combined cycle combustion turbines by adding costs and efficiency impacts due to frequent cycling. Even accounting for these costs, combined cycle technology results in a lower cost of electricity, compared to a simple cycle unit, when electric sales exceed one-third of the potential electric output. Furthermore, we have concluded that high efficiency simple cycle turbine technology is a sub-component of the selected BSER. Recent combined cycle installations have included dampers that allow the associated combustion turbine to operate in either combined cycle mode or simple cycle mode. The selected BSER and emission standard is compatible with the construction of new, modified, and reconstructed bi-modal units with dampers that allow the new source to operate in either combined cycle mode or in simple cycle mode; therefore the use of combined cycle technology is BSER for periods of intermediate and base load operation. However, for dedicated peaking applications highly efficient simple cycle technology alone is considered the BSER. 
	The EPA has reviewed the comments on the use of CCS for combined cycle facilities and has concluded that even if CCS is demonstrated as a technical and reasonable cost option for combined cycle units on an individual basis, it would not qualify as BSER based on the nationwide economic impacts. Therefore, the EPA is not making a determination as to the technical availability or individual cost reasonableness of CCS for new combined cycle units. Nearly all new fossil fuel-fired EGUs being constructed today are using combined cycle technology for generating intermediate and base load power and requiring partial CCS on these units would result in unreasonable nationwide impacts. 
	The EPA has concluded that advanced combined cycle technology is simply incremental improvements to traditional combined cycle designs and not a unique technology and therefore cannot be the BSER. The emission rates achieved by these technologies were included within the data set of newer combined cycle designs used for establishing the standard. In addition, review of the operating data for combined cycle power blocks installed since 2000 indicates that the mode of operation in response to system demand (e.g., base load or intermediate load and capacity factor in general) impacts achieved efficiencies to a large enough extent that we cannot evaluate the impact of particular subcomponents used within the power block. So a conventional combined cycle power block located in a region of the country where system demand requires the power block to run continuously at base load can achieve higher efficiencies than an advanced combined cycle 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 combined cycle power blocks can achieve the section 111 standard in all regions of the country. 
4. Identification of Applicability Based on Permitted Electric Sales 
      At proposal, we assumed all combustion turbines operating above the proposed 1/3 electric sales criterion would be able to comply with a standard consistent with the performance of recently constructed combined cycle facilities. However, as described in the applicability section, our understanding of the future role of combustion turbine EGUs has evolved. At this time however, we do not have sufficient information to establish an appropriate output-based emission rate for combustion turbines operating with operations that span this entire category. Therefore, our applicability approach is to use a sliding scale trigger. With the sliding scale approach, the trigger for applicability for the combined cycle standard depends on the design efficiency of the unit. Affected units subject to federally enforceable permit restrictions limiting operating below the electric sales threshold would not be required to comply with the requirements included in subpart TTTT. This both encourages the installation of the most efficient technologies intended for limited operation by giving the most efficient units the flexibility to sell more electricity and minimizes emissions for higher capacity factor units by requiring them to comply with the requirements of subpart TTTT.  
      As discussed previously, the proposed percent actual electric sales relative to the potential electric output criterion is being finalized as a permit restriction applicability criteria. Based on the concerns raised in the comments about the impact of intermittent renewable generation (e.g., wind and solar) on the operation of simple cycle turbines, the EPA has done additional analysis. First, we evaluated the percent sales applicability criterion in greater detail to get a more accurate picture of how many simple cycles would have met the electric sales applicability criterion based on historical operation. We also examined the operation of simple turbines in regions with relatively large amounts of wind and solar generation. 
      In the proposal, the EPA estimated the number of simple cycle turbines that would have met the proposed applicability based on the number of simple cycle turbines that operated over 2,920 hours in any year. However, this was a simplification of the one-third actual electric sales criteria and overestimated the number of potentially impacted simple cycle turbines in two ways. First, the 2,920 hours simplification assumes operation at full load. However, the typical duty cycle (average capacity factor while operating) of simple cycle turbines is approximately 70 percent. Therefore, simple cycle turbines can operate in excess of 2,920 hours and still not be selling one-third of their potential electric output. Historically, only 10 of the 1,939 existing simple cycle turbines have individual years where sales exceeded one-third of their potential electric output. Second, the proposed one-third electric sales applicability criterion was on a 3-year rolling average basis. Using 3-year rolling average basis, the number of existing simple cycle turbines that historically sold enough electricity to meet the proposed one-third electric sales applicability is only two. 
	We used information reported to the Energy Information Administration (EIA) to determine the impact of renewable generation on the operation of simple cycle turbines. The EIA provides data on the total in-state electricity generation, including wind and solar, from 2008 through 2014. Interstate flow of electricity is available from 2008 through 2012. California, Texas, and the Southwest Power Pool (data approximated by EGUs in Nebraska, Kansas, and Oklahoma) all had increases for the percent of wind and solar electricity generated in-state and percent of total electric generation from wind and solar from 2008 through 2014. To determine the observed impact of the increased generation from intermittent renewable sources, the EPA reviewed data submitted for simple cycle turbines to the EPA's Clean Air Markets Division (CAMD) over the same time period.
	The percent 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 would expect to see a large change in the operation of simple cycle turbines in this region. However, the average percent electric sales compared to the potential electric output from simple cycle turbines only increased at an annual rate of 1.7 percent, and remained essentially unchanged at 3 percent of potential electric sales between 2008 and 2014. Overall, generation from simple cycle turbines increased slightly more at an annual rate of 2.5 percent, resulting from additional simple cycle capacity being in line with what was expected due to overall increased electricity demand. The lack of significant change in the operation of simple cycle turbines in this region could be explained by the relatively large amount of exported power. If most of the intermittent power was being exported, the intermittent nature of the power would primarily impact other transmission regions. An alternate explanation is that other generating assets are flexible enough to respond to the intermittent nature of wind generation and that simple cycle turbines are not necessary to backup wind and solar generating assets to the degree some commenters suggested. If this were the case, then new simple cycle turbine will primarily continue to fill their historical role as peaking units and flexible combined cycle units will provide the primary backup capacity for new wind and solar generating assets.
	The percent 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 the overall demand grew an average of 2 percent annually. However, similar to the Southwest Power Pool, the overall percent of electric sales relative to the potential electric output from simple cycle turbines has remained relatively unchanged. Average electric sales relative to potential electric output from simple cycle turbines increased at an annual rate of 0.9 percent. However, the overall generation from simple cycle combustion turbines increased at an annual rate of 6.6 percent, resulting from simple cycle capacity additions occurring at approximately four times what would be expected from growth in overall demand. The EPA has concluded that the most likely simple cycle turbines to support intermittent renewable generation are the most efficient simple cycle combustion turbines installed in the particular transmission region. 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 turbine in Texas sold more than 25 percent of its potential electric sales annually.  This growth in simple cycle turbine capacity could indicate that additional generation assets are necessary to provide firm capacity for intermittent generation sources such as wind and solar, but based on the data those simple cycle turbines are expected to continue operating as they have historically, and sell less than one-third of their potential electric output. 
	The percent 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 the other evaluated regions. As in Texas, considerable additional simple cycle capacity has been added in recent years. The average 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. Many of the new additions are intercooled simple cycle turbines that can be installed to back up wind and solar generation. The annual electric sales relative to the potential electric output for the intercooled turbines range 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.
      Based on historical amounts of intermittent generation, the proposed one-third actual electric sales threshold would appear to offer sufficient operational flexibility for new simple cycle turbines. Existing combined cycle, other generation assets, and demand response programs are currently proving adequate backup to renewable generation. In the future, however, existing combined cycle facilities will likely provide base load power and operate at higher capacity factors. They will therefore be less available to provide backup power for intermittent generation. In addition, the percent of power generated from 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 combined cycle technologies, reciprocating internal combustion engines, energy storage technologies, and demand response programs are promising technologies for providing backup power for renewable generation, none of them historically have been deployed in sufficient capacity to provide the potential necessary capacity 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 GHG benefits of these technologies compared to simple cycle turbines, the EPA has concluded at this time it is appropriate to finalize an NSPS that provides additional flexibility for new combustion turbines intended to run at lower capacity factors. Specifically, new combustion turbines can avoid the requirements of subpart TTTT by requesting a federally enforceable permit restriction to sell the design efficiency times the potential electric output electricity on an annual basis. 
      The EPA considered multiple options for extending flexibility for simple cycle turbines. Ultimately, we concluded that a trigger based on the design net efficiency at standard conditions is appropriate. The electric sales trigger for applicability of the combined cycle based standard would be based on the design net efficiency of the facility. The EPA has concluded this approach provides sufficient operational flexibility for new simple cycle combustion turbines, even with increased future use. In addition, even though the historical electric sales of simple cycle turbines is less than 5 percent, this net efficiency trigger approach has the impact of promoting the installation of the most efficient generating technologies since applicability and operational flexibility would be linked directly to the efficiency of the devices. The design net efficiencies for currently available potentially impacted aeroderivative simple cycle combustion turbines range from approximately 32 percent for smaller designs to 39 percent for the largest intercooled designs. The efficiencies of industrial frame units range from 30 percent for smaller designs to 36 percent for the largest units. 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 United States 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 higher heating value. For natural gas, the LHV is approximately 10 percent lower that the HHV. Therefore, the corresponding LHV efficiency ranges would be 35 to 44 percent for aeroderative designs and 33 to 40 percent for frame designs. Based on comments, we anticipate the aeroderative turbines will make up the majority of new combustion turbines intended for limited use (i.e., peaking) applications. Based on the sliding scale applicability approach, owners/operators of new simple cycle combustion turbines could elect to request a federally enforceable permit limiting annual sales to between 32 to 39 percent of the potential electric output to avoid complying with the standards in this rulemkaing. Based on historical operation of simple cycle turbines, 99.5 percent do not sell more than one-third of their potential electric output on an annual basis. Therefore, the majority of new simple cycle applications could take a permit restriction without impacting how they would operate or what combustion turbine they would select. In addition, 99.9 percent of simple cycle turbines operate less than 36 percent on an annual basis. Owners/operators of new simple cycle combustion turbines would still have multiple technology options available to them to accommodate this amount of operation. The two simple cycle turbines that exceeded the 36 percent threshold had annual sales of 39 and 45 percent and are located in Montana and New York respectively. As noted earlier, the most efficient simple cycle turbine is 39 percent efficient and would accommodate operation of the Montana facility. The only simple cycle turbine that exceeded the maximum electric threshold permit restriction, 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 and the incremental generation due to the emergency would not have been counted as net electric sales for applicability purposes. Regardless, as described earlier, for combustion turbines operating above this threshold it is cost effective and the BSER is the additional of heat recovery to the turbine exhaust. Since the definition of stationary combustion turbine includes both simple and combined cycle units, we are capping the maximum permit restriction to 40 percent of the potential electric output. Combined cycle unit design efficiencies often exceed 50 percent. Without this restriction many existing combined cycle units could request permit limitations to avoid applicability with the 111(d) requirements. 
C. Achievability of the Final Standards
      We concluded at proposal that, for a combustion turbine designed to sell greater than one-third of its potential electric output, adding heat recovery and converting to a combined cycle is both cost effective (i.e., results in a lower cost of electricity) and results in a lower emission rate. The proposed standards of performance for natural gas-fired stationary combustion turbines were in the form of a gross-output-based emission limit expressed in units of mass of CO2 per unit of gross energy output, specifically, in lb CO2/MWh-gross. The subcategories for which the EPA proposed separate standards of performance were (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 less than or equal to 850 MMBtu/h. The EPA solicited comment on a broad range of issues related to the final standard. For new, modified, and reconstructed units we proposed a limit of 1,000 lb CO2/MWh-gross for large units (base load heat input rating greater than 850 MMBtu/h) and 1,100 lb CO2/MWh-gross for small units (base load heat input rating of 850 MMBtu/h or less). We solicited comment on a range of 950  -  1,100 lb CO2/MWh for large stationary combustion turbines and an emission standard range of 1,000  -  1,200 lb CO2/MWh for small stationary combustion turbines. We also solicited comment on eliminating the size subcategory, increasing the size distinction between large and small stationary combustion turbines to 900 MMBtu/h to account for larger aeroderivative designs, to 1,000 MMBtu/h to account for future incremental increases in base load ratings, or on increasing the size distinction to between 1,300 to 1,800 MMBtu/h. In addition, we solicited comment on establishing a variable capacity factor threshold that would allow more efficient, lower emitting turbines to run and be permitted for longer periods of operation (e.g., a higher capacity factor for the most efficient turbines being progressively lowered for lower efficiency turbines). 
      With respect to the size subcategory, some commenters and others agreed with the 850 MMBtu/h break point between large and small units, some suggested increasing it to 1,500 MMBtu/h, and others suggested eliminating the size based subcategorization. Some commenters stated that the current 850 MMBtu/h size distinction is inappropriate for CO2 because it was originally determined based on NOX performance and not significant for CO2 emission rates. These commenters stated that the 850 MMBtu/h cut-point, when compared to the existing fleet, does not result in a logical cut-point with a clear demarcation of higher emitting versus lower emitting technology on either side of this value, but rather divides the units at an arbitrary size classification. These commenters suggested 1,500 MMBtu/h since there is a clear cut-point in the existing fleet of gas turbines between the heat input range of 1,300 MMBtu/h and 1,800 MMBtu/h, with more efficient and lower CO2 emitting technology above and below 1,500 MMBtu/h. 
      In contrast, other commenters said that differentiation of small and large gas turbines cannot be justified because many of the same technologies that reduce the emission rates of larger units could be incorporated into smaller units. Commenters also said that separate standards for small and large turbines undermine the incentive for technology innovation, a key purpose of the NSPS program, and that relaxing standards for smaller units will discourage investment in more efficient technologies. These commenters recommended that the limit for both large and small units be no higher than 1,000 lb CO2/MWh. Finally, some commenters suggested that the EPA should regulate multiple small units built together as a single large unit if the combined heat input capacity of all gas turbines at the facility exceeds 850 MMBtu/h. 
      Numerous commenters from the power sector, air permitting authorities, and environmental groups acknowledged that accelerating renewable portfolio standards in certain states coupled with NERC reliability requirements can affect the performance of combined cycle natural gas EGUs as they are increasingly cycled and operated at lower capacity factors to complement hourly variations in intermittent renewable generation (e.g., solar and wind). However, commenters had a wide range of opinions on the extent to which intermittent renewables should be used to justify increasing the national emissions standard above the emission rate that can be achieved by well-operated and maintained intermediate and base-loaded combined cycle plants. 
      Commenters from the power sector generally supported increasing the standard for each subcategory to 1,100 lb CO2/MWh-gross for large units and 1,200 lb CO2/MWh-gross for small units and finalizing standards for modified and reconstructed standards that are 10 percent higher than the final standards for newly constructed combustion turbines because combustion turbines constructed prior to 2000 were not included in the EPA's BSER analysis for new sources. Conversely, some commenters stated that the proposed standards for combustion turbines do not reflect the emission rates that are achievable by modern, efficient NGCC power blocks, and these commenters do not believe the proposed numerical standards meet the CAA section 111 requirements for BSER. Some commenters stated that the appropriate limitation, consistent with Congressional objectives under CAA section 111, is 800 lb CO2/MWh-gross based on the performance of the lowest emitters in the CAMD database. Some commenters stated that a limitation of 850 lb CO2/MWh-gross reflected BSER for high-capacity factor units because half of the combined cycle plants in the CAMD database are achieving this level of emissions. One commenter from the power sector who operates combined cycle power plants stated that the final standard for new large combustion turbines should be 925 lb CO2/MWh-gross. Several other commenters stated that a reasonable standard for new combustion turbines would be 950 lb CO2/MWh-gross, and several commenters stated that the final standard for new small combustion turbines should be 1000 lb CO2/MWh-gross. Numerous commenters stated that the final standard for new sources should not exceed 1,000 lb CO2/MWh-gross for either large or small combustion turbines. Other commenters stated that since 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. These commenters stated that since 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.
      Numerous commenters supported tiered subcategories for peaking, load-following/intermediate, and base load units. Commenters noted that the EPA's proposals excluded units that operate in peaking mode and argued there is no basis in law or policy to exempt units from regulation simply because they operate less frequently, and hence less efficiently. Commenters said the EPA should cover all sources that supply (or are designed to supply) any amount of electricity to the grid, and should distinguish subcategories based on actual operation. Several commenters supported tiered standards based on capacity factor. They proposed 825 lb CO2/MWh-gross for base load units (those operating over 4,000 hours annually), 875 lb CO2/MWh-gross for intermediate and load-following units (those operating between 1,200 and 4,000 hours annually), and 1,100 lb CO2/MWh-gross for peaking units (those operating less than 1,200 hours per year). One of the most common comments received was that peaking units should be either included in a subcategory or completely exempted due to the highly variable capacity factors and duty cycles imposed by system operators on these versatile generators. Numerous commenters pointed to recent BACT limits for CO2 that indicate tiered limits are appropriate for the different roles served by combustion turbines citing BACT limits from 1,328 to 1,450 lb CO2/MWh-gross for peaking units. One commenter supported tiered limits consistent with recent BACT determinations in the State of New York: a combined cycle limit of 925 lb CO2/MWh-gross and a simple cycle limit of 1,450 lb CO2/MWh-gross. An air quality regulator from a state with rapidly increasing renewable generation supported a limit of 825 lb CO2/MWh-gross for base load NGCC units; 1,000 lb CO2/MWh-gross for intermediately loaded, large NGCC units; 1,100 lb CO2/MWh-gross for intermediately loaded, small NGCC units; and this commenter recommended that the EPA set a numerical limit specifically for peaking units after completion of a peaker-specific BSER analysis. 
      Other commenters opposed the tiered approach. Commenters suggested that separate standards for different operating conditions would be complicated to implement and enforce, provide few benefits, and could have the unintended consequence of encouraging less efficient technologies and less efficient operation. Commenters added that annual capacity factors would likely vary significantly from year to year, and possibly from month to month as the 12 operating month average is recalculated every operating month. The commenters stated that this real-world variability and uncertainty significantly diminishes the value of creating tiered standards for peaking and load-following units because individuals responsible for long-range decisions related to reliability may react to a system of tiered standards by purchasing additional generating assets to ensure system demand can be satisfied while operating individual units below tier-specific thresholds.
      After further evaluation, the EPA has concluded against subcategorizing the combustion turbine standard based on size for several reasons. While some commenters suggested that the division between large and small should be increased to 1,500 MMBtu/h, other commenters said subcategorizing based on size would distort the market and provide a regulatory incentive to install less efficient, smaller combined cycle facilities, resulting in increased GHG emissions. The EPA reviewed data on the size of available combined cycle facilities (without duct burners) listed in Gas Turbine World. Combined cycle turbines are not currently offered in the following output sizes: between 600 to 800 MMBtu/h, 1,000 to 1,200 MMBtu/h, and 1,300 to 1,800 MMBtu/h based on the heat input to the combustion turbine engine. However, a review of heat input data by the EPA for combined cycle facilities submitted to the EPA Clean Air Markets Division show that multiple combined cycle facilities have been built in the past with heat input capacities with the capacities listed above. Therefore, the EPA has concluded that the regulated community uses various sizes of combined cycle facilities and that no clear cut point distinguishes small and large combined cycle facilities. Subcategorizing by size could unduly influence the selection of technology and development of future turbine offerings. Further, the average emissions rate of combined cycle facilities of less than 850 MMBtu/h (the proposed cut point) is lower than the average emissions rate of combined cycle facilities with heat input ratings of 850 MMBtu/h up to 1,500 MMBtu/h. Finally, the EPA has concluded that, while certain smaller combined cycle designs are less efficient than larger combined cycle designs, this is primarily related to design choices of the heat recovery steam generator, and is not an inherent limitation in the technical ability of small combined cycle technologies to have comparable efficiencies to large combined cycle facilities.
	Since the standards were proposed, the EPA has expanded the NGCC emissions rate analysis that supported the proposed emission standards to include emissions information for combined cycle facilities that commenced operation in 2011, 2012, and 2013 and updated the emissions data to include emissions through 2014. Based on analysis of these data and the comments submitted on the proposed standard, the EPA has concluded that an emission standard of 1,000 lb CO2/MWh-gross is achievable for all affected combustion turbines. Therefore, the EPA is finalizing an emission standard of 1,000 lb/MWh-gross for all combustion turbines without any size based subcategories. Emissions data from combined cycle facilities with heat input ratings of less than 850 MMBtu/h have demonstrated that this level is achievable for smaller combined facilities. The sixteen NGCC facilities evaluated using the Clean Air Markets data have heat input rates of less than or equal to 850 MMBtu/h and an average 12-month maximum CO2 emission rate of 952 lb/MWh-gross. Three of the facilities evaluated using the Clean Air Markets data had a maximum 12-operating month rolling average emissions rate equal to or greater than 1,000 lb CO2/MWh-gross. One of those facilities had a maximum 12-operating-month rolling average emissions rate equal to or greater than 1,100 lb CO2/MWh-gross. In addition, the five facilities that commenced construction between 2007 and 2012 all have maximum 12-month emission rates of less than 950 lb CO2/MWh-gross. For larger units, twenty-five of the 314 combined cycle facilities with heat input ratings greater than 850 MMBtu/h had maximum 12-month average emission rates greater than 1,000 lb CO2/MWh. The analysis inherently includes multiple years of data and did not filter out periods of startup, shutdown, operation at intermediate load, or cycling when determining the maximum 12-operating month emission rate. The final standard includes a sufficient compliance margin to account for any performance degredation in the operation of these facilities. 
      In addition, multiple technologies that can increase the performance of new combined cycle facilities are currently available. First, vendors continue to improve the single cycle efficiency of combustion turbines. The use of more efficient combustion turbine engines improves the overall efficiency of combined cycle facilities. In addition, existing smaller combined cycle facilities were likely designed using single or dual pressure heat recovery steam generators without a reheat cycle. New designs could incorporate three pressure steam generators with a reheat cycle to improve the overall efficiency of the combined cycle facility. Additional technologies to reduce emission rates for new combustion turbines include CHP and integrated non-emitting technologies.  
      The EPA reviewed the GHG limitations in recently issued construction permits for NGCC facilities. In total 31 major permits were identified with 39 discrete limits on GHG emissions. Eight of the limits were expressed as lbs/h or tons per year and were not included in the analysis. In addition, One CHP unit that generates electricity and supplies steam to a chemical plant was in the set with a limit of 1,362 lb CO2/MWh based only on the gross electrical portion of output and does not account for the useful thermal output. Therefore, it was also not included in this analysis. Two of the permits did not clearly specify if the output based standard was on a gross or net basis and were therefore also excluded. The remaining 28 permit standards were expressed on a lb CO2/MWh or a heat rate basis that could be converted to a lb CO2/MWh basis. Eight permit limits were based on net output ranging from 774-936 lb CO2/MWh-net. The lowest emission limit was for a hybrid power plant with a solar component of heat input that could contribute up to 50 MW. Twenty permit limits were based on gross output ranging from 833-1,100 lb CO2/MWh-gross. Of these 28 permit limits, only one unit had a heat input capacity less than 1,500 MMBtu/h (366 MMBtu/h); this unit also had the highest emission limit of 1,100 lb CO2/MWh. All permit limits were evaluated over an annual period. Most of these permits included an allowance for a design margin to reflect the possibility that the constructed facility will not be able to achieve the design heat rate; an allowance for efficiency losses due to combustion turbine degradation prior to maintenance overhauls; an allowance for the steam turbine system; and an allowance for the variability in operation of auxiliary plant equipment due to use over time. Typically, the sum of these allowances was in the range of 10 to 13 percent. Limits typically considered whether the unit would be base load or load-following. Some permits limited the amount of No. 2 fuel oil that could be used as backup fuel and adjusted emission limits to account for this use. Startup and shutdown emissions were typically included in the annual average compliance calculation. 
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 U.S. Court of Appeals for the District of Columbia 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, 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. 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 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. 
      In the 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."). 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.
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 as frequent as practicable while ensuring monitoring 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 sections 75.53(g) and (h). The electronic portion of the monitoring plan should be submitted to the EPA's Clean Air Markets Division (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 section 75.20 and section 6 of Part 75, Appendix A within the 180-day window of time allotted under section 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 section 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 backup monitoring systems, as provided in sections 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 section 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 section 75.4(b) allotted for initial certification of the monitoring systems expires (whichever date is earlier). For EGUs subject to the 1,400 lb CO2/MWh-gross) 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 section 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
      This final rule specifies that compliance with the 1,400 lb CO2/MWh-gr 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 section 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.
E. Notification, Recordkeeping, and Reporting Requirements
      This final rule requires an EGU owner or operator to comply with the applicable notification requirements in section 75.61, sections 60.7(a)(1) and (a)(3), and section 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 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 2 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 section 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 (12[th]) operating month of the initial 12-operating-month compliance period. For that initial report and any subsequent report in which the 12[th] 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 section 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. 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 Best Available Control Technology (BACT) requirement for greenhouse gases 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 and existing and 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 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 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 greenhouse gases 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 at 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 at 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 sections 60.46Da(j), 60.4315(b), and 60.5515 of the agency's regulations. The 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 subparts Da, KKKK, and TTTT of part 60.
     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 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 GHG 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 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 sections 51.166(b)(48)(v) and 52.21(b)(49)(v) of the EPA's regulations, but did not vacate sections 51.166(b)(48)(iv) or 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 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 sections 51.166(b)(48)(iv) and 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 SER 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 applicable, without regard to the particular subparts of the definition of "regulated NSR pollutant" that may cover GHGs. Upon promulgation of the SER rule, it will then provide a framework that states may use when updating their SIPs consistent with the Supreme Court decision. 
	While the GHG SER rulemaking 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 sections 60.46Da(j), 60.4315(b), and 60.5515.  
      The EPA has evaluated these provisions 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 sections 51.166(b)(48)(iv) and 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 the EPA proposed for sections 60.46Da(j), 60.4315(b), and 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 sections 51.166(b)(48) and 52.21(b)(49) of the EPA's regulations. However, the courts have now vacated sections 51.166(b)(48)(v) and 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 in 60.46Da(j), 60.4315(b), and 60.5515 will not incorporate the vacated parts of sections 51.166(b)(48) and 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 sections 60.46Da(j), 60.4315(b), and 60.5515 without 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 sections 60.46Da(j), 60.4315(b), and 60.5515 to other subparts of part 60. 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 section 51.166 at this time solely to address the implications of regulating GHGs under CAA section 111.  
      The EPA understands that many commenters expressed concerned that PSD SIPs would also have to be amended to address the implications of regulating GHGs under CAA section 111. However, the language in 60.46Da(j), 60.4315(b), and 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 at 31522.  
      Moreover, it is more likely that states would need to consider a SIP revision if the EPA were to revise section 51.166 in this rule. Revisions to 51.166 can trigger requirements for states to revise their PSD program provisions under section 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 consolidate its revisions to 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 to adopt the proposed part 60 provisions in this final rule 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 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 51 and 52 as discussed briefly in the preceding section. 
      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 as:
      an emissions limitation (including a visible emission standard) based on the maximum degree of reduction for each pollutant subject to regulation under the Clean Air Act which would be emitted from any proposed major stationary source or major modification which the Administrator, on a case-by-case basis, taking into account energy, environmental, and economic impacts and other costs, determines is achievable for such facility through application of production processes and available methods, systems, and techniques, including fuel cleaning, clean fuels, or treatment or innovative fuel combustion techniques for control of each such pollutant....

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, p. 20-21 (March 2011) ("GHG Permitting Guidance"). 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 is established by the EPA through an applicable NSPS (i.e. the BACT floor) does not bar a permitting agency from justifying a more stringent standard as BACT. 
      In the proposed rule, the EPA discussed how this rule may relate to determination of BACT for new and existing EGUs that require PSD permits. 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 both a new, greenfield EGU facility or an existing facility that wants to add a new EGU in order to add or replace capacity. While this latter scenario is considered a "new affected facility" under the NSPS, it may also be considered a "modification" of an existing stationary source under PSD. 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 modified or reconstructed sources as those terms are defined under part 60. It is important to recognize that 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 potential 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 the specified emission threshold in order to be subject to PSD requirements. This emission calculation considers the unit's past annual emission 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, this NSPS could establish a BACT floor for sources that are modifying an existing EGU and their emissions make them subject to PSD.
      In the preamble to the proposed rule, 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 EGUs or non-EGU sources. 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. This 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.
      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 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 a natural consequence of setting an NSPS under the terms of the CAA. 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. In addition, to 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 with setting a BSER of partial CCS in this NSPS. Although 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 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 greenhouse gases in January 2011 and more information about GHG control technology has been gained in this four-and-a-half year period. 
      Additionally, if a state was processing a permit application for a solid fuel-fired EGU and CCS was not proposed as BACT (or not even considered as a possible 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 approved state implementation plan, the state has primacy over their permitting actions and discretion to interpret their approved rules and 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. Furthermore, if the EPA does not adversely comment on a certain 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 -- it does not contain any final determination of BACT for any source. Furthermore, we disagree with the commenters' characterization of the content of the GHG Permitting Guidance. The guidance specifically states "[f]or the purposes of a BACT analysis for GHGs, 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 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 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. Nothing in the guidance is inconsistent with agency's present position that CCS is adequately demonstrated for the types of sources covered by this rule, 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 required "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 was 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 at 1489-90. The relevant issue for title V purposes was, in essence, whether promulgation of CAA section 111 requirements for GHGs 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 at 1489-90 (quoting 75 FR 31,583). 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 31,583). 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 at 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 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 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.
      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. 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 today 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.
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 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 at 1490.
	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. at 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 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 "the program will result in the collection, in the aggregate, from all sources [required to get an operating permit], of 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 at 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. at 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. See NSPS preamble at 1493, 1495. 
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, "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). 
      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 at 1494. 
      For part 71, we proposed a labor rate assumption of $52 per hour in 2011 dollars. Using that labor rate, we proposed to determine the GHG fee adjustment for each GHG permitting program activity to be a specific dollar amount for each activity ("set fees") that the source would pay for each activity performed. See 79 FR at 1495. The EPA proposed to revise 40 CFR 70.9(b)(2)(v) and 40 CFR 71.9(c)(8) to implement this option.
c. The GHG adjustment option 2. The second proposed GHG adjustment option (option 2) was to increase the dollar per ton ($/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. See NSPS proposal at 1494, 1495.
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. at 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 40 CFR 70.2 and 71.2), rather than solely CO2, which would be regulated under the section 111 standards and implemented through the EGU GHG NSPS. Id. at 1505, 1506, and 1511.
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. at 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.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 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).
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 EPA, but that they believed would be appropriate for their program.    
      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.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. 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.
	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 fee demonstration 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), 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. 
	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." 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.
	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 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. 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, 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.  
	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 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. 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.
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 prt 60, subparts Da, KKKK and TTTT. The final rule adds the clarification text only to subpart TTTT because the EPA is codifying all of the requirements for the affected EGUs in a new subpart TTTT and including all GHG emission standards for the affected sources (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. 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 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. 
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.
2. Cross-State Air Pollution Rule (CSAPR)
      The CSAPR requires states to take action to improve air quality by reducing SO2 and nitrogen oxide (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. The 316(b) 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.
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 simultaneously 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 (EO) 13563, "Improving Regulation and Regulatory Review," issued on January 18, 2011, states that "[i]n developing regulatory actions and identifying appropriate approaches, each agency shall attempt to promote... coordination, simplification, and harmonization. Each agency shall also seek to identify, as appropriate, means to achieve regulatory goals that are designed to promote innovation." Within the EPA, we are paying careful attention to the interrelatedness and potential impacts on the industry, reliability and cost that these various rulemakings can have. 
      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 fossil fuel-fired steam generating units that can be met by capturing and storing approximately 20 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.
      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.
XII. 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-XX-YYY, June 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. 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 the 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.
      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 today. 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 modified or reconstructed EGUs in the period of analysis. 
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 designated critical habitat. Section 7(a)(2) of the ESA requires federal agencies, in consultation with the U.S. Fish and Wildlife Service (FWS) and/or the National Marine Fisheries Service, 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. Indirect effects are those that are caused by the action, later in time, and are reasonably certain to occur. Id. To trigger a consultation requirement, there must thus be a causal connection between the federal action, the effect in question, and the listed species, and the effect must be reasonably certain to occur.
     The EPA has 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 species or designated critical habitat for purposes of ESA section 7(a)(2) consultation. 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). These reductions are projected to be minor. 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. With respect to the projected GHG emission reductions, the EPA does not believe that such 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 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.[329]  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. The EPA has also previously considered issues relating to GHG emissions in connection with the requirements of ESA section 7(a)(2). 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[330] 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 CO 2 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).
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 reconstructed or modified EGUs 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 reconstructed or modified EGUs 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 plant utilize partial CCS to meet the final standard of performance (i.e., approximately 20 percent capture), the increased water use will not be significant. The EPA is unaware of any solid waste impact resulting from this rule.
E. What are the compliance costs?
      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 modified or reconstructed EGUs 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.
      As previously stated, the EPA anticipates few units will trigger the 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?
      There are no direct monetized climate benefits in terms of CO2 emission reductions associated with these standards of performance. However, by clarifying that in the future, newly constructed coal-fired power plants will be required to meet a particular performance standard, this rule provides a path forward for new coal-fired generation and the deployment of CCS. It ensures that new EGUs, whether gas or coal-fired, will meet standards for CO2 control into the future.
      As also previously stated, the EPA anticipates few units will trigger the 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.  
XII. Statutory and Executive Order Reviews
Additional information about these Statutory and Executive Orders can be found at http://www2.epa.gov/laws-regulations/laws-and-executive-orders.
A. Executive Order 12866, Regulatory Planning and Review, and Executive Order 13563, Improving Regulation and Regulatory Review
	This final action is 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-XX-YYY, June 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 modified or reconstructed EGUs 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 XX. 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 2506.03). 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. 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 natural gas-fired 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 based on requirements in the NSPS General Provisions (40 CFR part 60, subpart A), which are mandatory for all owners/operators subject to CAA section 111 national emission standards, 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 17 affected newly constructed natural gas-fired stationary 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 natural gas-fired stationary combustion turbines). As previously stated, the EPA expects few modified or reconstructed EGUs in the period of analysis. Specifically, the EPA believes it unlikely that fossil fuel-fired electric utility steam generating units or natural gas-fired 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 sources 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, which are mandatory for all owners/operators subject to CAA section 111 national emission standards, 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 $2,665 and 32 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 $32,886 and 395 labor hours. There are no annualized capital costs or O&M costs associated with burden for newly constructed EGUs. Average burden hours per response are estimated to be 8 hours. The total number of respondents over the 3-year ICR period is estimated to be 37.
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. 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 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-XX-YYY, June 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 modified fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines 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-XX-YYY, June 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-XX-YYY, June 2015) for further discussion of sensitivities.)
      As previously stated, the EPA expects few modified or reconstructed fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines 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-XX-YYY, June 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 modified or reconstructed fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines 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 modified or reconstructed fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines 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 modified or reconstructed EGUs 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 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 greenhouse gas that contributes to climate change and is emitted in significant quantities by fossil fuel-fired power plants. The EPA believes that the CO2 emission reductions resulting from implementation of these final guidelines, as well as substantial ozone and PM2.5 emission reductions as a co-benefit, will further improve children's health. 
      The assessment literature cited in the EPA's 2009 Endangerment Finding concluded that certain populations and lifestages, including children, the elderly, and the poor, are most vulnerable to climate-related health effects. The assessment literature since 2009 strengthens these conclusions by providing more detailed findings regarding these groups' vulnerabilities and the projected impacts they may experience.
      These assessments describe how children's unique physiological and developmental factors contribute to making them particularly vulnerable to climate change. Impacts to children are expected from heat waves, air pollution, infectious and waterborne illnesses, and mental health effects resulting from extreme weather events. In addition, children are among those especially susceptible to most allergic diseases, as well as health effects associated with heat waves, storms, and floods. Additional health concerns may arise in low income households, especially those with children, if climate change reduces food availability and increases prices, leading to food insecurity within households.
       More detailed information on the impacts of climate change to human health and welfare is provided in Section II.A of this preamble. 
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. 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 modified or reconstructed fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines 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 
      This final action involves technical standards. The following voluntary consensus standards are used in the final rule: American Society for Testing and Materials (ASTM) Methods D388-12 (Standard Classification of Coals by Rank), D396-13c (Standard Specification for Fuel Oils), D975-14 (Standard Specification for Diesel Fuel Oils), D3699-13b (Standard Specification for Kerosene), D6751-12 (Standard Specification for Biodiesel Fuel Blend Stock (B100) for Middle Distillate Fuels), D7467-13 (Standard Specification for Diesel Fuel Oil, Biodiesel Blend (B6 to B20)), and American National Standards Institute (ANSI) Standard C12.20 (American National Standard for Electricity Meters - 0.2 and 0.5 Accuracy Classes). The rule also requires use of Appendices A, B, D, F and G to 40 CFR part 75; 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. These 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 F and G, above, where 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.
      Strong scientific evidence that the potential impacts of climate change raise environmental justice issues is found 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, summarized in the record for the Endangerment Finding. Their conclusions include 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 on established reservations that are restricted to reservation boundaries and therefore have limited relocation options. 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. 
 	Southwest native cultures are especially vulnerable to water quality and availability impacts. Native Alaskan communities are likely to experience 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. The new assessment literature provides more detailed findings regarding these populations' vulnerabilities and projected impacts they may experience. In addition, the most recent assessment literature provides new information on how some communities of color may be uniquely vulnerable to climate change health impacts in the United States. These studies 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, the studies also find that climate change poses particular threats to health, wellbeing, and ways of life of indigenous peoples in the United States.  
      As the scientific literature presented above and in the Endangerment Finding illustrates, low income communities and 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 natural gas-fired 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 modified or reconstructed fossil fuel-fired electric utility steam generating units or natural gas-fired stationary combustion turbines 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).
XIII. Statutory Authority
The statutory authority for this action is provided by sections 111, 301, 302, and 307(d)(1)(C) of the CAA as amended (42 U.S.C. 7411, 7601, 7602, 7607(d)(1)(C)). This action is also subject to section 307(d) of the CAA (42 U.S.C. 7607(d)).

List of Subjects
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:__________________.  

________________________
Gina McCarthy,
Administrator
For the reasons stated in the preamble, title 40, chapter I, part 60, 70, 71, and 98 of the Code of the Federal Regulations is amended as follows:
PART 60-- STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES
      1. The authority citation for part 60 continues to read as follows:
	Authority: 42 U.S.C. 7401, et seq.
      2. Part 60 is amended by adding subpart TTTT to read as follows:
Subpart TTTT Standards of Performance for Greenhouse Gas Emissions for Electric Utility Generating Units 
Sec.
Applicability

§ 60.5508	What is the purpose of this subpart?
§ 60.5509	Am I subject to this subpart?

Emission Standards

§ 60.5515	Which greenhouse gases 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 CO2 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?

Applicability
§ 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, 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.
§ 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 modification or reconstruction after June 18, 2014 that meets the relevant applicability conditions in paragraphs (a)(1) and (a)(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 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 (b)(9) 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 limiting net-electric sales to one-third or less of its potential electric output or 219,000 MWh or less on an annual basis.
      (2) Your EGU is capable of combusting 90% or more non-fossil fuel and subject to a federally enforceable permit limiting fossil fuel use to 10% or less of the annual capacity factor.
      (3) Your EGU is a combined heat and power unit that is subject to a federally enforceable permit limiting annual net-electric sales to the design efficiency times the potential electric output or 219,000 MWh (whichever is greater) or less.
(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 unit 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) Modified units that conduct modifications resulting in a potential hourly increase in CO2 emissions (mass per hour) of 10 percent or less.
      (8) Your EGU is a stationary combustion turbine that is subject to a federally enforceable permit limiting annual net-electric sales to the design efficiency times the potential electric output or less as net-electrical sales.
      (9) Your stationary combustion turbine is not capable of combusting natural gas (e.g., not connected to a natural gas pipeline).
Emission Standards
§ 60.5515 Which greenhouse gases are regulated by this subpart?
(a) The greenhouse gas regulated by this subpart is carbon dioxide (CO2).
(b) PSD and Title V Thresholds for Greenhouse Gases.
(1) For the purposes of § 51.166(b)(49)(ii) of this chapter, with respect to GHG emissions from affected EGUs, 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 § 51.166(b)(48) and in any SIP approved by the EPA that is interpreted to incorporate, or specifically incorporates, § 51.166(b)(48) of this chapter.
(2) For the purposes of § 52.21(b)(50)(ii) of this chapter, 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 § 52.21(b)(49) of this chapter.
(3) For the purposes of § 70.2 of this chapter, 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 §  70.2 of this chapter.
(4) For the purposes of § 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 § 71.2 of this chapter. 
§ 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 Table 2 of this subpart, consistent with paragraphs (b) and (c) of this section, as applicable. 
      (b) Except as specified in paragraph (c) of the 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, 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 may petition the Administrator in writing to comply with the alternate applicable net energy output standard. If the Administrator grants the petition, the source will beginning on the date the Administrator grants the petition have to 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 operators complying with the net output based standard must petition the Administrator to switch back to complying with the gross energy output based standard.
General Compliance Requirements
§ 60.5525 What are my general requirements for complying with this subpart?
      Compliance with the applicable CO2 emission standard of this subpart shall be determined on a 12-operating month rolling average basis. See Tables 1-2 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). 
      (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.
      (b) At all times you must operate and maintain each affected EGU, including associated equipment and monitoring equipment, 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 Table 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 §72.2 of this chapter) on or after the effective date of this rule, the first month of the initial compliance period shall be the first operating month (as defined in §60.5580) after the calendar month in which emissions reporting is required to begin under:
      (i) §63.5555(c)(3)(i), for units subject to the Acid Rain Program; or 
      (ii) §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 §72.2 of this chapter) prior to the effective date of this rule:
      (i) If the date on which emissions reporting is required to begin under §75.64(a) of this chapter has passed prior to the effective date of this rule, emissions reporting shall begin according to §63.5555(c)(3)(i) (for Acid Rain program units), or according to §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 §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 §75.64(a) of this chapter occurs on or after the effective date of this rule, then the first month of the initial compliance period shall be the first operating month (as defined in §60.5580) after the calendar month in which emissions reporting is required to begin under §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 §60.5580) after the calendar month in which emissions reporting is required to begin under §63.5555(c)(3)(iii).  
              Monitoring and Compliance Determination Procedures
§ 60.5535 How do I monitor and collect data to demonstrate compliance? 
      (a) You must prepare a monitoring plan to quantify the hourly CO2 mass emission rate (tons/hr), in accordance with the applicable provisions in § 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 §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 § 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 §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 § 75.11(b) of this chapter. 
(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 § 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 (a)(6)(i) through (iv) of this section.  Perform this calculation only for "valid operating hours", as defined in §60.5540(a)(1).
      (i) Begin with the hourly CO2 mass emission rate (tons/hr), 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 §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/hr values and EGU (or stack) operating times used to calculate CO2 mass emissions are required to be recorded under §75.57(e) of this chapter and must be reported electronically under §75.64(a)(6).  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. 
      (1) 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/hr).  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 §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 §72.2 of this chapter), to convert it to 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 §75.57(e) of this chapter and must be reported electronically under §75.64(a)(6)  You must use these data to calculate the hourly CO2 mass emissions.
      (d) Consistent with § 60.5520, 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. For a combined heat and power (CHP) EGU, as defined in §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.
      (e) Consistent with § 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 § 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 Table 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 § 72.2 of this chapter). If you attain compliance with the applicable emissions standard in § 60.5520 at the common stack, each affected EGU sharing the stack is in compliance.
(g) In accordance with § 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 § 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.
§60.5540 How do I demonstrate compliance with my CO2 emissions standard?
 	(a) In accordance with § 60.5520, to demonstrate compliance with the applicable CO2 emission standard in Table 1 or 2 of this subpart, for the initial and each subsequent 12-operating month rolling average compliance period, you must follow the procedures in paragraphs (a)(1) through(a)(7) of this section to calculate the CO2 mass emissions rate for your affected EGU(s) in units of the applicable emissions standard (kg/MWh). You must use the hourly CO2 mass emissions and generation load data from §60.5535 in the calculations.
(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 §60.5580) are obtained for all of the parameters used to determine the hourly CO2 mass emissions (kg); 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
(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
(iii) The total gross or net energy output (Pgross/net) 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 §60.5535 for all of the valid operating hours in the compliance period. 
(5) 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 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 § 60.5520) value reported under part 75 of this chapter to MWh, multiply by the corresponding EGU or stack operating time.
      Pgross/net = PeST+ PeCT + PeIE-(Pe)FWT +  PtPS + PtHR + PtIE 
      Where: a
      Pgross/net =	In accordance with § 60.5520, gross or net energy output of your affected EGU for each valid operating hour (as defined in 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.
      (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.
      T = 	Electric Transmission and Distribution Factor.
      T = 	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.
      T = 	1.0 for all other affected EGUs.
                  
      (ii) If applicable to your affected EGU, you must calculate (Pt)PS using the following equation:
      (Pt)PS = Qm x H3.6 x 109
      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, as applicable) in Joules per kilogram (J/kg) (or Btu/lb).
      3.6 x 10[9] = Conversion factor (J/MWh) (or 3.413 x 106 Btu/MWh).
            
(6) In accordance with § 60.5520, 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.
(7) 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) of this section. Round off the result two significant figures.
      (b) In accordance with § 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 subpart.  
      Notification, Reports, and Records
§ 60.5550 What notifications must I submit and when?
      (a) You must prepare and submit the notifications specified in § 60.7(a)(1) and (a)(3) and § 60.19, as applicable to your affected EGU(s) (see Table 3 of this Subpart).
      (b) You must prepare and submit notifications specified in § 75.61 of this chapter, as applicable to your affected EGUs. 
§ 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 § 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 § 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 §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 § 60.5520, the CO2 emissions standard (as identified in Table 1 or 2) with which your affected EGU must comply; and
      (vi) Consistent with § 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 § 60.5520, gross energy output or net energy output sold to an electric grid over the 4 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 §75.64(a), i.e., beginning with data recorded on and after the earlier of: 
(A) The date of provisional certification, as defined in §75.20(a)(3) of this chapter; or
(B) 180 days after the date on which the EGU commences commercial operation (as defined in §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 §75.64(a), if that date occurs on or after the effective date of this rule; or
(B)  The effective date of this rule, if the date on which reporting would ordinarily be required to begin under §75.64(a) has passed prior to the effective date of this rule.  
(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 electrical generation data on that date.  Otherwise, emissions data reporting shall begin on the date that the Client Tool is first able to receive and process net generation 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 §75.4(j) of this chapter, §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 §60.5540(a)(1)), and shall not be used in the compliance determinations under §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 §72.20 of this chapter; or
(2) The person appointed as the Alternate Designated Representative (ADR) under §72.22 of this chapter; or
(3) A person (or persons) authorized by the DR or ADR under §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 (optional) 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.
      (e) 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:
      (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.
§ 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 § 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 §75.53(g) and (h) of this chapter;
(ii) Operating parameter records under §75.57(b)(1) through (b)(4) of this chapter;
(iii) The records under §75.57(c)(2) of this chapter, for stack gas volumetric flow rate; 
(iv) The records under §75.57(c)(3) for continuous moisture monitoring systems;
(v) The records under §75.57(e)(1), except for paragraph (e)(1)(x), for CO2 concentration monitoring systems or O2 monitors used to calculate CO2 concentration;
(vi) The records under §75.58(c)(1), paragraphs (c)(1)(i), (c)(1)(ii), and (c)(1)(viii) through (c)(1)(xiv), for oil flow meters;
(vii) The records under §75.58(c)(4), paragraphs (c)(4)(i), (c)(4)(ii), (c)(4)(iv), (c)(4)(v), and (c)(4)(vii) through (c)(4)(xi), for gas flow meters;
(viii) The quality-assurance records under §75.59(a) of this chapter, paragraphs (a)(1) through (a)(12) and (a)(15), for CEMS;
(ix) The quality-assurance records under §75.59(a) of this chapter, paragraphs (b)(1) through (b)(4), for fuel flow meters; and
(x) Records of data acquisition and handling system (DAHS) verification under §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);
(2) Each compliance period, including, each 12-operating month compliance period.
      (d) Consistent with § 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).
§ 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 § 60.7. You may maintain the records off site and electronically for the remaining year(s) as required by this subpart.
                      Other Requirements and Information
§ 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 § 60.1 through 60.19, listed in Table 3 to this subpart, do not apply to your affected EGU.
§ 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 § 60.8(b).
§ 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, baseload rating includes the heat input from duct burners.
      Coal means all solid fuels classified as anthracite, bituminous, subbituminous, or lignite by the American Society of Testing and Materials in ASTM D388 (incorporated by reference, see § 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.
Coal refuse means waste products of coal mining, physical coal cleaning, and coal preparation operations (e.g. culm, gob, etc.) containing coal, matrix material, clay, and other organic and inorganic material. 
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 thermal output) on a higher heating value basis of the EGU at the base load rating and ISO conditions.
Distillate oil means fuel oils that comply with the specifications for fuel oil numbers 1 and 2, as defined by the American Society of Testing and Materials in ASTM D396 (incorporated by reference, see § 60.17); diesel fuel oil numbers 1 and 2, as defined by the American Society for Testing and Materials in ASTM D975 (incorporated by reference, see § 60.17); kerosene, as defined by the American Society of Testing and Materials in ASTM D3699 (incorporated by reference, see § 60.17); biodiesel as defined by the American Society of Testing and Materials in ASTM D6751 (incorporated by reference, see § 60.17); or biodiesel blends as defined by the American Society of Testing and Materials in ASTM D7467 (incorporated by reference, see § 60.17).
      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 electric utility 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-operaitng 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 a 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 unit or IGCC means a combined cycle stationary combustion turbine that is designed to burn fuels containing 50 percent (by heat input) or more solid-derived fuel not meeting the definition of natural gas. 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 (15o 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. In addition, natural gas contains 20.0 grains or less of total sulfur per 100 standard cubic feet. Finally, natural gas does not include the following gaseous fuels: landfill gas, digester gas, refinery gas, sour gas, blast furnace gas, coal-derived gas, producer gas, coke oven gas, or any gaseous fuel produced in a process which might result in highly variable sulfur content or heating value.
      Net-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 distribution system minus purchased power of the thermal host EGU 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 grid 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:
      (i) Except as provided under paragraph (ii) of this definition, the net electric or mechanical output  from the affected EGU plus 100 percent of the useful thermal output; or
      (ii) 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;
      Oil means crude oil or petroleum or a fuel derived from crude oil or petroleum, including distillate and residual oil, and gases derived from solid oil-derived fuels (not meeting the definition of natural gas). 
      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.
Standard ambient temperature and pressure (SATP) conditions means 298.15 Kelvin (25o C, 77 [o]F)) and 100.0 kilopascals (14.504 psi, 0.987 atm) pressure. The enthalpy of water at SATP conditions is 50 Btu/lb.
      Potential electric output means 33 percent or the design efficiency on a net output basis 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 310,000 MWh 12 month potential electric output capacity). 
      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. If a stationary combustion turbine burns any solid fuel directly it is considered a steam generating unit.
      Steam generating unit means any furnace, boiler, or other device used for combusting fuel and producing steam (nuclear steam generators are not included) plus any integrated equipment that provides electricity or useful thermal output to the affected EGU(s) or auxiliary equipment.
      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 §75.20 of this chapter and appendix A to part 75 of this chapter must be met before quality-assured data are reported under this subpart; for on-going quality assurance, the daily, quarterly, and semiannual/annual test requirements in sections 2.1, 2.2, and 2.3 of appendix B to part 75 of this chapter must be met and the data validation criteria in sections 2.1.5, 2.2.3, and 2.3.2 of appendix B to part 75 of this chapter apply.  For fuel flow meters, the initial certification requirements in section 2.1.5 of appendix D to part 75 of this chapter must be met before quality-assured data are reported under this subpart (except for qualifying commercial billing meters under section 2.1.4.2 of appendix D), and for on-going quality assurance, the provisions in section 2.1.6 of appendix D to part 75 of this chapter apply (except for qualifying commercial billing meters). 
Violation means a specified averaging period over which the CO2 emissions rate is higher than the applicable emissions standard located in Table 1 or Table 2 of 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 (net energy output-based standards are only applicable to affected EGUs subject to a federally enforceable permit limiting GHG emissions on a net energy output basis)
      Note: all numerical values have a minimum of 2 significant figures
Affected EGU
CO2 Emission Standard
Newly constructed steam generating unit or integrated gasification combined cycle (IGCC) EGU
640 kg CO2/MWh of gross energy output (1,400 lb CO2/MWh)
Reconstructed steam generating unit or IGCC EGU that has base load rating of 2,100 GJ/h (2,000 MMBtu/h) or less
910 kg of CO2 per MWh of gross energy output (2,000 lb CO2/MWh)
Reconstructed steam generating unit or IGCC EGU that has a base load rating greater than 2,100 GJ/h (2,000 MMBtu/h)
820 kg of CO2 per MWh of gross energy output (1,800 lb CO2/MWh) 
Modified steam generating or IGCC unit
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 or Modification after June 18, 2014
      Note: all numerical values have a minimum of 2 significant figures
Affected EGU
CO2 Emission Standard
Newly constructed, reconstructed, or modified stationary combustion turbine 
450 kg of CO2 per MWh of gross energy output (1,000 lb CO2/MWh); or
490 kilograms (kg) of CO2 per megawatt-hour (MWh) of net energy output (1,080 lb/MWh) 

Table 3 to Subpart TTTT of Part 60  -  Applicability of Subpart A General Provisions to Subpart TTTT
General Provisions citation
Subject of citation
Applies to subpart TTTT
Explanation
§ 60.1
Applicability
Yes

§ 60.2
Definitions
Yes
Additional terms defined in § 60.5580
§ 60.3
Units and Abbreviations
Yes

§ 60.4
Address
Yes
Does not apply to information reported electronically through ECMPS. Duplicate submittals are not required. 
§ 60.5
Determination of construction or modification
Yes

§ 60.6
Review of plans
Yes

§ 60.7
Notification and Recordkeeping
Yes
Only the requirements to submit the notifications in 60.7(a)(1) and (a)(3) and to keep records of malfunctions in §60.7(b), if applicable
§ 60.8
Performance tests
No

§ 60.9
Availability of Information
Yes

§ 60.10
State authority
Yes

§ 60.11
Compliance with standards and maintenance requirements
No

§ 60.12
Circumvention
Yes

§ 60.13
Monitoring requirements
No
All monitoring is done according to Part 75  
§ 60.14
Modification
No

§ 60.15
Reconstruction
No

§ 60.16
Priority list
No

§ 60.17
Incorporations by reference
Yes

§ 60.18
General control device requirements
No

§ 60.19
General notification and reporting requirements
Yes
Does not apply to  notifications under
§75.61 or to information reported through ECMPS.


PART 70 --  STATE OPERATING PERMIT PROGRAMS
      3. The authority citation for part 70 continues to read as follows:
Authority: 42 U.S.C. 7401 et seq.
      4. Section 70.2 is amended by revising the introductory text, removing "or" from the end of paragraph (2), adding "or" to the end of paragraph (3), and adding paragraph (4) to the definition of "Regulated pollutant (for presumptive fee calculation)." 
      The revision and additions read as follows: 
§ 70.2  Definitions.
*	*	*	*	*
      Regulated pollutant (for presumptive fee calculation), which is used only for purposes of § 70.9(b)(2), means any regulated air pollutant except the following: 
*	*	*	*	*
      (4) Greenhouse gases.
*	*	*	*	*
	5. Section 70.9 is amended by revising paragraph (b)(2)(i), and by adding paragraph (b)(2)(v) to read as follows:
§ 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. 

                                   Activity
Burden hours per activity
GHG completeness determination (for initial permit or updated application)

GHG evaluation for a modification or related permit action

GHG evaluation at permit renewal
                                                                               
                                                                             43
                                                                               
                                                                               
                                                                              7

                                                                             10

*	*	*	*	*
PART 71 --  FEDERAL OPERATING PERMIT PROGRAMS
      6. The authority citation for part 71 continues to read as follows:
Authority: 42 U.S.C. 7401 et seq.
      7. Section 71.2 is amended by removing "or" from the end of paragraph (2), adding "or" to the end of paragraph (3), and adding paragraph (4) to the definition of "Regulated pollutant (for fee calculation)."  
      The revisions and additions read as follows:
§ 71.2   Definitions.
*	*	*	*	*
      Regulated pollutant (for fee calculation), which is used only for purposes of § 71.9(c), means any "regulated air pollutant" except the following:
*	*	*	*	*
      (4) Greenhouse gases.
*	*	*	*	*	
      8. Section 71.9 is amended by: 
      a. Revising paragraphs (c)(1), (c)(2)(i), (c)(3), and (c)(4), and 
      b. Adding paragraph (c)(8). 
      The revisions and additions read as follows:
§ 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  
      (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 x32)+[(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 x32)+( D x24)+[(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 updated application)

GHG evaluation for a permit modification or related permit action 

GHG evaluation at permit renewal
                                                                               
                                                                         $2,236
                                                                               
                                                                               
                                                                           $364
                                                                               
                                                                           $520

*	*	*	*	*
PART 98 --  MANDATORY GREENHOUSE GAS REPORTING
       9. The authority citation for part 98 is revised to read as follows:
 Authority: 42 U.S.C. 7401-7671q.
Subpart PP -- Suppliers of Carbon Dioxide
       10. Section 98.426 is amended by adding paragraph (h) to read as follows:
§ 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.
       11. Section 98.427 is amended by adding paragraph (d) to read as follows:
§ 98.427 Records that must be retained.
*	*	*	*	*
	(d) Facilities subject to § 98.426(h) must retain records of CO2 in metric tons that is transferred to each subpart RR facility.

