39798 Federal Register / Vol. 89, No. 91 / Thursday, May 9, 2024 / Rules and Regulations 
ENVIRONMENTAL PROTECTION 
AGENCY 
40 CFR Part 60 
[EPA–HQ–OAR–2023–0072; FRL–8536–01– 
OAR] 
RIN 2060–AV09 
New Source Performance Standards 
for Greenhouse Gas Emissions From New, Modified, and Reconstructed Fossil Fuel-Fired Electric Generating Units; Emission Guidelines for Greenhouse Gas Emissions From Existing Fossil Fuel-Fired Electric Generating Units; and Repeal of the Affordable Clean Energy Rule 
AGENCY : Environmental Protection 
Agency (EPA). 
ACTION : Final rule. 
SUMMARY : The Environmental Protection 
Agency (EPA) is finalizing multiple actions under section 111 of the Clean Air Act (CAA) addressing greenhouse gas (GHG) emissions from fossil fuel- fired electric generating units (EGUs). First, the EPA is finalizing the repeal of the Affordable Clean Energy (ACE) Rule. Second, the EPA is finalizing emission guidelines for GHG emissions from existing fossil fuel-fired steam generating EGUs, which include both coal-fired and oil/gas-fired steam generating EGUs. Third, the EPA is finalizing revisions to the New Source Performance Standards (NSPS) for GHG emissions from new and reconstructed fossil fuel-fired stationary combustion turbine EGUs. Fourth, the EPA is finalizing revisions to the NSPS for GHG emissions from fossil fuel-fired steam generating units that undertake a large modification, based upon the 8-year review required by the CAA. The EPA is not finalizing emission guidelines for GHG emissions from existing fossil fuel- fired stationary combustion turbines at this time; instead, the EPA intends to take further action on the proposed emission guidelines at a later date. 
DATES : This final rule is effective on July 
8, 2024. The incorporation by reference of certain publications listed in the rules is approved by the Director of the Federal Register as of July 8, 2024. The incorporation by reference of certain other materials listed in the rule was approved by the Director of the Federal Register as of October 23, 2015. ADDRESSES : The EPA has established a 
docket for these actions under Docket ID 
No. EPA–HQ–OAR–2023–0072. All documents in the docket are listed on the https://www.regulations.gov 
website. Although listed, some 
information is not publicly available, e.g., Confidential Business Information 
(CBI) or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, is not placed on the internet and will be publicly available only in hard copy form. Publicly available docket materials are available electronically through https:// 
www.regulations.gov. 
FOR FURTHER INFORMATION CONTACT : Lisa 
Thompson (she/her), Sector Policies and Programs Division (D243–02), Office of Air Quality Planning and Standards, U.S. Environmental Protection Agency, 109 T.W. Alexander Drive, P.O. Box 12055, Research Triangle Park, North Carolina 27711; telephone number: (919) 541–5158; and email address: thompson.lisa@epa.gov. 
SUPPLEMENTARY INFORMATION : 
Preamble acronyms and 
abbreviations. Throughout this 
document the use of ‘‘we,’’ ‘‘us,’’ or ‘‘our’’ is intended to refer to the EPA. The EPA uses multiple acronyms and terms in this preamble. While this list may not be exhaustive, to ease the reading of this preamble and for reference purposes, the EPA defines the following terms and acronyms here: 
ACE Affordable Clean Energy rule 
BSER best system of emissions reduction Btu British thermal unit CAA Clean Air Act CBI Confidential Business Information CCS carbon capture and sequestration/ 
storage 
CCUS carbon capture, utilization, and 
sequestration/storage 
CO
2carbon dioxide 
DER distributed energy resources DOE Department of Energy EEA energy emergency alert EGU electric generating unit EIA Energy Information Administration EJ environmental justice E.O. Executive Order EPA Environmental Protection Agency FEED front-end engineering and design FGD flue gas desulfurization FR Federal Register GHG greenhouse gas GW gigawatt GWh gigawatt-hour HAP hazardous air pollutant HRSG heat recovery steam generator IIJA Infrastructure Investment and Jobs Act IRC Internal Revenue Code 
kg kilogram kWh kilowatt-hour LCOE levelized cost of electricity LNG liquefied natural gas MATS Mercury and Air Toxics Standards MMBtu/h million British thermal units per 
hour 
MMT CO
2e million metric tons of carbon 
dioxide equivalent 
MW megawatt MWh megawatt-hour NAAQS National Ambient Air Quality 
Standards 
NESHAP National Emission Standards for 
Hazardous Air Pollutants 
NGCC natural gas combined cycle NO
Xnitrogen oxides 
NSPS new source performance standards NSR New Source Review PM particulate matter PM
2.5fine particulate matter 
RIA regulatory impact analysis TSD technical support document U.S. United States 
Organization of this document. The 
information in this preamble is 
organized as follows: 
I. Executive Summary 
A. Climate Change and Fossil Fuel-Fired 
EGUs 
B. Recent Developments in Emissions 
Controls and the Electric Power Sector 
C. Summary of the Principal Provisions of 
These Regulatory Actions 
D. Grid Reliability Considerations 
E. Environmental Justice Considerations F. Energy Workers and Communities G. Key Changes From Proposal 
II. General Information 
A. Action Applicability B. Where To Get a Copy of This Document 
and Other Related Information 
III. Climate Change Impacts IV. Recent Developments in Emissions 
Controls and the Electric Power Sector 
A. Background B. GHG Emissions From Fossil Fuel-Fired 
EGUs 
C. Recent Developments in Emissions 
Control 
D. The Electric Power Sector: Trends and 
Current Structure 
E. The Legislative, Market, and State Law 
Context 
F. Future Projections of Power Sector 
Trends 
V. Statutory Background and Regulatory 
History for CAA Section 111 
A. Statutory Authority To Regulate GHGs 
From EGUs Under CAA Section 111 
B. History of EPA Regulation of 
Greenhouse Gases From Electricity 
Generating Units Under CAA Section 111 and Caselaw 
C. Detailed Discussion of CAA Section 111 
Requirements 
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174 FR 66496 (December 15, 2009). 
2The 5th National Climate Assessment (NCA5) 
states that the effects of human-caused climate 
change are already far-reaching and worsening across every region of the United States and that climate change affects all aspects of the energy system-supply, delivery, and demand-through the increased frequency, intensity, and duration of extreme events and through changing climate trends. 
3https://www.epa.gov/ghgemissions/sources- 
greenhouse-gas-emissions. VI. ACE Rule Repeal 
A. Summary of Selected Features of the 
ACE Rule 
B. Developments Undermining ACE Rule’s 
Projected Emission Reductions 
C. Developments Showing That Other 
Technologies Are the BSER for This 
Source Category 
D. Insufficiently Precise Degree of 
Emission Limitation Achievable From Application of the BSER 
E. Withdrawal of Proposed NSR Revisions 
VII. Regulatory Approach for Existing Fossil 
Fuel-Fired Steam Generating Units 
A. Overview B. Applicability Requirements and Fossil 
Fuel-Type Definitions for Subcategories of Steam Generating Units 
C. Rationale for the BSER for Coal-Fired 
Steam Generating Units 
D. Rationale for the BSER for Natural Gas- 
Fired and Oil-Fired Steam Generating 
Units 
E. Additional Comments Received on the 
Emission Guidelines for Existing Steam Generating Units and Responses 
F. Regulatory Requirement To Review 
Emission Guidelines for Coal-Fired Units 
VIII. Requirements for New and 
Reconstructed Stationary Combustion Turbine EGUs and Rationale for Requirements 
A. Overview B. Combustion Turbine Technology C. Overview of Regulation of Stationary 
Combustion Turbines for GHGs 
D. Eight-Year Review of NSPS E. Applicability Requirements and 
Subcategorization 
F. Determination of the Best System of 
Emission Reduction (BSER) for New and Reconstructed Stationary Combustion Turbines 
G. Standards of Performance H. Reconstructed Stationary Combustion 
Turbines 
I. Modified Stationary Combustion 
Turbines 
J. Startup, Shutdown, and Malfunction K. Testing and Monitoring Requirements L. Recordkeeping and Reporting 
Requirements 
M. Compliance Dates N. Compliance Date Extension 
IX. Requirements for New, Modified, and 
Reconstructed Fossil Fuel-Fired Steam Generating Units 
A. 2018 NSPS Proposal Withdrawal B. Additional Amendments C. Eight-Year Review of NSPS for Fossil 
Fuel-Fired Steam Generating Units 
D. Projects Under Development 
X. State Plans for Emission Guidelines for 
Existing Fossil Fuel-Fired EGUs 
A. Overview B. Requirement for State Plans To Maintain 
Stringency of the EPA’s BSER Determination 
C. Establishing Standards of Performance D. Compliance Flexibilities E. State Plan Components and Submission 
XI. Implications for Other CAA Programs 
A. New Source Review Program B. Title V Program 
XII. Summary of Cost, Environmental, and 
Economic Impacts A. Air Quality Impacts 
B. Compliance Cost Impacts C. Economic and Energy Impacts D. Benefits E. Net Benefits F. Environmental Justice Analytical 
Considerations and Stakeholder Outreach and Engagement 
G. Grid Reliability Considerations and 
Reliability-Related Mechanisms 
XIII. Statutory and Executive Order Reviews 
A. Executive Order 12866: Regulatory 
Planning and Review and Executive Order 14094: Modernizing Regulatory Review 
B. Paperwork Reduction Act (PRA) C. Regulatory Flexibility Act (RFA) D. Unfunded Mandates Reform Act of 1995 
(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 Populations and Low-Income Populations 
H. Executive Order 13211: Actions 
Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use 
I. National Technology Transfer and 
Advancement Act (NTTAA) and 1 CFR Part 51 
J. Executive Order 12898: Federal Actions 
To Address Environmental Justice in Minority Populations and Low-Income Populations and Executive Order 14096: 
Revitalizing Our Nation’s Commitment to Environmental Justice for All 
K. Congressional Review Act (CRA) 
XIV. Statutory Authority 
I. Executive Summary 
In 2009, the EPA concluded that GHG 
emissions endanger our nation’s public 
health and welfare.1Since that time, the 
evidence of the harms posed by GHG emissions has only grown, and Americans experience the destructive and worsening effects of climate change every day.
2Fossil fuel-fired EGUs are 
the nation’s largest stationary source of GHG emissions, representing 25 percent of the United States’ total GHG emissions in 2021.
3At the same time, a 
range of cost-effective technologies and approaches to reduce GHG emissions from these sources is available to the power sector—including carbon capture and sequestration/storage (CCS), co- firing with less GHG-intensive fuels, and more efficient generation. Congress 
has also acted to provide funding and other incentives to encourage the deployment of various technologies, including CCS, to achieve reductions in GHG emissions from the power sector. 
In this notice, the EPA is finalizing 
several actions under section 111 of the Clean Air Act (CAA) to reduce the significant quantity of GHG emissions from fossil fuel-fired EGUs by establishing emission guidelines and new source performance standards (NSPS) that are based on available and cost-effective technologies that directly reduce GHG emissions from these sources. Consistent with the statutory command of CAA section 111, the final NSPS and emission guidelines reflect the application of the best system of emission reduction (BSER) that, taking into account costs, energy requirements, and other statutory factors, is adequately demonstrated. 
Specifically, the EPA is first finalizing 
the repeal of the Affordable Clean Energy (ACE) Rule. Second, the EPA is finalizing emission guidelines for GHG emissions from existing fossil fuel-fired steam generating EGUs, which include both coal-fired and oil/gas-fired steam generating EGUs. Third, the EPA is finalizing revisions to the NSPS for GHG emissions from new and reconstructed fossil fuel-fired stationary combustion turbine EGUs. Fourth, the EPA is finalizing revisions to the NSPS for GHG emissions from fossil fuel-fired steam generating units that undertake a large modification, based upon the 8-year review required by the CAA. The EPA is not finalizing emission guidelines for GHG emissions from existing fossil fuel- fired combustion turbines at this time and plans to expeditiously issue an additional proposal that more comprehensively addresses GHG emissions from this portion of the fleet. The EPA acknowledges that the share of GHG emissions from existing fossil fuel- fired combustion turbines has been growing and is projected to continue to do so, particularly as emissions from other portions of the fleet decline, and that it is vital to regulate the GHG emissions from these sources consistent with CAA section 111. 
These final actions ensure that the 
new and existing fossil fuel-fired EGUs that are subject to these rules reduce 
their GHG emissions in a manner that is cost-effective and improves the emissions performance of the sources, consistent with the applicable CAA requirements and caselaw. These standards and emission guidelines will significantly decrease GHG emissions from fossil fuel-fired EGUs and the associated harms to human health and 
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4https://www.epa.gov/ghgemissions/sources- 
greenhouse-gas-emissions. 5U.S. Energy Information Administration (EIA). 
Electric Power Annual. 2010 and 2022. https://
www.eia.gov/electricity/annual/html/epa_ 03_01_
a.html. 
6https://www.congress.gov/bill/117th-congress/ 
house-bill/3684. 
7https://www.congress.gov/bill/117th-congress/ 
house-bill/4346. welfare. Further, the EPA has designed 
these standards and emission guidelines in a way that is compatible with the nation’s overall need for a reliable supply of affordable electricity. 
A. Climate Change and Fossil Fuel-Fired 
EGUs 
These final actions reduce the 
emissions of GHGs from new and existing fossil fuel-fired EGUs. The increasing concentrations of GHGs in the atmosphere are, and have been, warming the planet, resulting in serious and life-threatening environmental and 
human health impacts. The increased concentrations of GHGs in the atmosphere and the resulting warming have led to more frequent and more intense heat waves and extreme weather events, rising sea levels, and retreating snow and ice, all of which are occurring at a pace and scale that threaten human health and welfare. 
Fossil fuel-fired EGUs that are 
uncontrolled for GHGs are one of the biggest domestic sources of GHG emissions. At the same time, there are technologies available (including technologies that can be applied to fossil fuel-fired power plants) to significantly reduce emissions of GHGs from the power sector. Low- and zero- GHG electricity are also key enabling technologies to significantly reduce GHG emissions in almost every other sector of the economy. 
In 2021, the power sector was the 
largest stationary source of GHGs in the United States, emitting 25 percent of overall domestic emissions.
4In 2021, 
existing fossil fuel-fired steam generating units accounted for 65 percent of the GHG emissions from the sector, but only accounted for 23 percent of the total electricity generation. 
Because of its outsized contributions 
to overall emissions, reducing emissions from the power sector is essential to addressing the challenge of climate change—and sources in the power sector also have many available options for reducing their climate-destabilizing emissions. Particularly relevant to these actions are several key technologies (CCS and co-firing of lower-GHG fuels) that allow fossil fuel-fired steam generating EGUs and stationary combustion turbines to provide power while emitting significantly lower GHG emissions. Moreover, with the increased electrification of other GHG-emitting sectors of the economy, such as personal vehicles, heavy-duty trucks, and the heating and cooling of buildings, reducing GHG emissions from these 
affected sources can also help reduce power sector pollution that might otherwise result from the electrification of other sectors of the economy. 
B. Recent Developments in Emissions 
Controls and the Electric Power Sector 
Several recent developments 
concerning emissions controls are relevant for the EPA’s determination of the BSER for existing coal-fired steam generating EGUs and new natural gas- fired stationary combustion turbines. These include lower costs and continued improvements in CCS technology, alongside Federal tax incentives that allow companies to largely offset the cost of CCS. Well- established trends in the sector further inform where using such technologies is cost effective and feasible, and form part of the basis for the EPA’s determination of the BSER. 
In recent years, the cost of CCS has 
declined in part because of process improvements learned from earlier deployments and other advances in the technology. In addition, the Inflation Reduction Act (IRA), enacted in 2022, extended and significantly increased the tax credit for carbon dioxide (CO
2) 
sequestration under Internal Revenue Code (IRC) section 45Q. The provision of tax credits in the IRA, combined with the funding included in the Infrastructure Investment and Jobs Act (IIJA), enacted in 2021, incentivize and facilitate the deployment of CCS and other GHG emission control technologies. As explained later in this preamble, these developments support the EPA’s conclusion that CCS is the BSER for certain subcategories of new and existing EGUs because it is an adequately demonstrated and available control technology that significantly reduces emissions of dangerous pollution and because the costs of its 
installation and operation are reasonable. Some companies have already made plans to install CCS on their units independent of the EPA’s regulations. 
Well documented trends in the power 
sector also influence the EPA’s determination of the BSER. In particular, CCS entails significant capital expenditures and is only cost- reasonable for units that will operate enough to defray those capital costs. At the same time, many utilities and power generating companies have recently announced plans to accelerate changing the mix of their generating assets. The IIJA and IRA, state legislation, technology advancements, market forces, consumer demand, and the advanced age of much of the existing fossil fuel-fired generating fleet are collectively leading to, in most cases, decreased use of the fossil fuel-fired units that are the subjects of these final actions. From 2010 through 2022, fossil fuel-fired generation declined from approximately 72 percent of total net generation to approximately 60 percent, with generation from coal-fired sources dropping from 49 percent to 20 percent of net generation during this period.
5 
These trends are expected to continue and are relevant to determining where capital-intensive technologies, like CCS, may be feasibly and cost-reasonably deployed to reduce emissions. 
Congress has taken other recent 
actions to drive the reduction of GHG emissions from the power sector. As noted earlier, Congress enacted IRC section 45Q in section 115 of the Energy Improvement and Extension Act of 2008 to provide a tax credit for the sequestration of CO
2. Congress 
significantly amended IRC section 45Q in the Bipartisan Budget Act of 2018, and more recently in the IRA, to make this tax incentive more generous and effective in spurring long-term deployment of CCS. In addition, the IIJA provided more than $65 billion for infrastructure investments and upgrades for transmission capacity, pipelines, and low-carbon fuels.
6Further, the Creating 
Helpful Incentives to Produce Semiconductors and Science Act (CHIPS Act) authorized billions more in funding for development of low- and non-GHG emitting energy technologies that could provide additional low-cost options for power companies to reduce overall GHG emissions.
7As discussed 
in greater detail in section IV.E.1 of this preamble, the IRA, the IIJA, and CHIPS contain numerous other provisions encouraging companies to reduce their GHGs. 
C. Summary of the Principal Provisions 
of These Regulatory Actions 
These final actions include the repeal 
of the ACE Rule, BSER determinations and emission guidelines for existing fossil fuel-fired steam generating units, and BSER determinations and accompanying standards of performance for GHG emissions from new and reconstructed fossil fuel-fired stationary combustion turbines and modified fossil fuel-fired steam generating units. 
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8CAA section 111(a)(1). 9Presumptive standards of performance are 
discussed in detail in section X of the preamble. 
While states establish standards of performance for sources, the EPA provides presumptively approvable standards of performance based on the degree of emission limitation achievable through application of the BSER for each subcategory. The EPA is taking these actions 
consistent with its authority under CAA 
section 111. Under CAA section 111, once the EPA has identified a source category that contributes significantly to dangerous air pollution, it proceeds to regulate new sources and, for GHGs and certain other air pollutants, existing sources. The central requirement is that the EPA must determine the ‘‘best system of emission reduction . . . adequately demonstrated,’’ taking into account the cost of the reductions, non- air quality health and environmental impacts, and energy requirements.
8The 
EPA may determine that different sets of sources have different characteristics relevant for determining the BSER and may subcategorize sources accordingly. 
Once it identifies the BSER, the EPA 
must determine the ‘‘degree of emission limitation’’ achievable by application of the BSER. For new sources, the EPA establishes the standard of performance with which the sources must comply, which is a standard for emissions that reflects the degree of emission limitation. For existing sources, the EPA includes the information it has developed concerning the BSER and associated degree of emission limitation in emission guidelines and directs the states to adopt state plans that contain standards of performance that are consistent with the emission guidelines. 
Since the early 1970s, the EPA has 
promulgated regulations under CAA section 111 for more than 60 source categories, which has established a robust set of regulatory precedents that has informed the development of these final actions. During this period, the courts, primarily the U.S. Court of Appeals for the D.C. Circuit and the Supreme Court, have developed a body of caselaw interpreting CAA section 111. As the Supreme Court has recognized, the EPA has typically (and does so in these actions) determined the BSER to be ‘‘measures that improve the pollution performance of individual sources,’’ such as add-on controls and clean fuels. West Virginia v. EPA, 597 
U.S. 697, 734 (2022). For present purposes, several of a BSER’s key features include that it must reduce emissions, be based on ‘‘adequately demonstrated’’ technology, and have a reasonable cost of control. The case law interpreting section 111 has also recognized that the BSER can be forward-looking in nature and take into 
account anticipated improvements in control technologies. For example, the EPA may determine a control to be ‘‘adequately demonstrated’’ even if it is new and not yet in widespread commercial use, and, further, that the 
EPA may reasonably project the development of a control system at a future time and establish requirements that take effect at that time. Further, the most relevant costs under CAA section 111 are the costs to the regulated facility. The actions that the EPA is 
finalizing are consistent with the requirements of CAA section 111 and its regulatory history and caselaw, which is discussed in further detail in section V of this preamble. 
1. Repeal of ACE Rule 
The EPA is finalizing its proposed 
repeal of the existing ACE Rule 
emission guidelines. First, as a policy matter, the EPA concludes that the suite of heat rate improvements (HRI) that was identified in the ACE Rule as the BSER is not an appropriate BSER for existing coal-fired EGUs. Second, the ACE Rule rejected CCS and natural gas co-firing as the BSER for reasons that no longer apply. Third, the EPA concludes that the ACE Rule conflicted with CAA section 111 and the EPA’s implementing regulations because it did not provide sufficient specificity as to the BSER the EPA had identified or the ‘‘degree of emission limitation achievable though application of the [BSER].’’ 
Also, the EPA is withdrawing the 
proposed revisions to the New Source Review (NSR) regulations that were included the ACE Rule proposal (83 FR 44773–83; August 31, 2018). 
2. Emission Guidelines for Existing 
Fossil Fuel-Fired Steam Generating Units 
The EPA is finalizing CCS with 90 
percent capture as BSER for existing coal-fired steam generating units. These units have a presumptive standard
9of 
an 88.4 percent reduction in annual emission rate, with a compliance deadline of January 1, 2032. As explained in detail below, CCS is an adequately demonstrated technology that achieves significant emissions reduction and is cost-reasonable, taking into account the declining costs of the technology and a substantial tax credit available to sources. In recognition of the significant capital expenditures involved in deploying CCS technology and the fact that 45 percent of regulated units already have announced retirement dates, the EPA is finalizing a separate subcategory for existing coal- fired steam generating units that 
demonstrate that they plan to permanently cease operation before January 1, 2039. The BSER for this subcategory is co-firing with natural gas, at a level of 40 percent of the unit’s annual heat input. These units have a presumptive standard of 16 percent reduction in annual emission rate corresponding to this BSER, with a compliance deadline of January 1, 2030. 
The EPA is finalizing an applicability 
exemption for existing coal-fired steam EGUs demonstrating that they plan to permanently cease operation prior to January 1, 2032, based on the Agency’s determination that units retiring before this date generally do not have cost- reasonable options for improving their GHG emissions performance. Sources that demonstrate they will permanently cease operation before this applicability deadline will not be subject to these emission guidelines. Further, the EPA is not finalizing the proposed imminent- term or near-term subcategories. 
The EPA is finalizing the proposed 
structure of the subcategory definitions for natural gas- and oil-fired steam generating units. The EPA is also finalizing routine methods of operation and maintenance as the BSER for intermediate load and base load natural gas- and oil-fired steam generating units. Furthermore, the EPA is finalizing presumptive standards for natural gas- and oil-fired steam generating units that are slightly higher than at proposal: base load sources (those with annual capacity factors greater than 45 percent) have a presumptive standard of 1,400 lb CO
2/MWh-gross, and intermediate load 
sources (those with annual capacity factors greater than 8 percent and less than or equal to 45 percent) have a presumptive standard of 1,600 lb CO
2/ 
MWh-gross. For low load (those with 
annual capacity factors less than 8 percent), the EPA is finalizing a uniform fuels BSER and a presumptive input- based standard of 170 lb CO
2/MMBtu 
for oil-fired sources and a presumptive standard of 130 lb CO
2/MMBtu for 
natural gas-fired sources. 
3. Standards of Performance for New 
and Reconstructed Fossil Fuel-Fired Combustion Turbines 
The EPA is finalizing emission 
standards for three subcategories of combustion turbines—base load, intermediate load, and low load. The BSER for base load combustion turbines includes two components to be implemented initially in two phases. The first component of the BSER for base load combustion turbines is highly efficient generation (based on the emission rates that the best performing 
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10See 83 FR 65424, December 20, 2018. units are achieving) and the second 
component for base load combustion turbines is utilization of CCS with 90 percent capture. Recognizing the lead time that is necessary for new base load combustion turbines to plan for and install the second component of the BSER (i.e., 90 percent CCS), including 
the time that is needed to deploy the associated infrastructure (CO
2pipelines, 
storage sites, etc.), the EPA is finalizing a second phase compliance deadline of January 1, 2032, for this second component of the standard. 
The EPA has identified highly 
efficient simple cycle generation as the BSER for intermediate load combustion turbines. For low load combustion turbines, the EPA is finalizing its proposed determination that the BSER is the use of lower-emitting fuels. 
4. New, Modified, and Reconstructed 
Fossil Fuel-Fired Steam Generating Units 
The EPA is finalizing revisions of the 
standards of performance for coal-fired steam generating units that undertake a large modification (i.e., a modification 
that increases its hourly emission rate by more than 10 percent) to mirror the emission guidelines for existing coal- fired steam generators. This reflects the EPA’s determination that such modified sources are capable of meeting the same presumptive standards that the EPA is finalizing for existing steam EGUs. Further, this revised standard for modified coal-fired steam EGUs will avoid creating an unjustified disparity between emission control obligations for 
modified and existing coal-fired steam EGUs. 
The EPA did not propose, and we are 
not finalizing, any review or revision of the 2015 standard for large modifications of oil- or gas-fired steam generating units because we are not aware of any existing oil- or gas-fired steam generating EGUs that have undertaken such modifications or have plans to do so, and, unlike an existing coal-fired steam generating EGUs, existing oil- or gas-fired steam units have no incentive to undertake such a modification to avoid the requirements we are including in this final rule for existing oil- or gas-fired steam generating units. 
As discussed in the proposal 
preamble, the EPA is not revising the NSPS for newly constructed or reconstructed fossil fuel-fired steam electric generating units (EGU) at this time because the EPA anticipates that few, if any, such units will be constructed or reconstructed in the foreseeable future. However, the EPA has recently become aware that a new coal-fired power plant is under 
consideration in Alaska. Accordingly, the EPA is not, at this time, finalizing its proposal not to review the 2015 NSPS, and, instead, will continue to consider whether to review the 2015 NSPS. As developments warrant, the EPA will determine either to conduct a review, and propose revised standards of performance, or not conduct a review. 
Also, in this final action, the EPA is 
withdrawing the 2018 proposed amendments
10to the NSPS for GHG 
emissions from coal-fired EGUs. 
5. Severability 
This final action is composed of four 
independent rules: the repeal of the 
ACE rule; GHG emission guidelines for existing fossil fuel-fired steam generating units; NSPS for GHG emissions from new and reconstructed fossil fuel-fired combustion turbines; and revisions to the standards of performance for new, modified, and reconstructed fossil fuel-fired steam generating units. The EPA could have finalized each of these rules in separate Federal Register notices as separate final actions. The Agency decided to include these four independent rules in a single Federal Register notice for administrative ease because they all relate to climate pollution from the fossil fuel-fired electric generating units source category. Accordingly, despite grouping these rules into one single Federal Register notice, the EPA intends that each of these rules described in sections I.C.1 through I.C.4 is severable from the other. 
In addition, each rule is severable as 
a practical matter. For example, the EPA would repeal the ACE Rule separate and apart from finalizing new standards for 
these sources as explained herein. Moreover, the BSER and associated emission guidelines for existing fossil fuel-fired steam generating units are independent of and would have been the same regardless of whether the EPA finalized the other parts of this rule. In determining the BSER for existing fossil fuel-fired steam generating units, the EPA considered only the technologies available to reduce GHG emissions at those sources and did not take into consideration the technologies or standards of performance for new fossil fuel-fired combustion turbines. The same is true for the Agency’s evaluation and determination of the BSER and associated standards of performance for new fossil fuel-fired combustion turbines. The EPA identified the BSER and established the standards of performance by examining the controls that were available for these units. That analysis can stand alone and apart from the EPA’s separate analysis for existing fossil fuel-fired steam generating units. Though the record evidence (including, for example, modeling results) often addresses the availability, performance, and expected implementation of the technologies at both existing fossil fuel- fired steam generating units and new fossil fuel-fired combustion turbines in the same record documents, the evidence for each evaluation stands on its own, and is independently sufficient to support each of the final BSERs. 
In addition, within section I.C.1, the 
final action to repeal the ACE Rule is severable from the withdrawal of the NSR revisions that were proposed in parallel with the ACE Rule proposal. Within the group of actions for existing fossil fuel-fired steam generating units in section I.C.2, the requirements for each subcategory of existing sources are severable from the requirements for each other subcategory of existing sources. For example, if a court were to invalidate the BSER and associated emission standard for units in the medium-term subcategory, the BSER and associated emission standard for units in the long-term subcategory could function sensibly because the effectiveness of the BSER for each subcategory is not dependent on the effectiveness of the BSER for other subcategories. Within the group of actions for new and reconstructed fossil fuel-fired combustion turbines in section I.C.3, the following actions are severable: the requirements for each subcategory of new and reconstructed turbines are severable from the requirements for each other subcategory; and within the subcategory for base load turbines, the requirements for each of the two components are severable from the requirements for the other component. Each of these standards can function sensibly without the others. For example, the BSER for low load, intermediate load, and base load subcategories is based on the technologies the EPA determined met the statutory standards for those subcategories and are independent from each other. And in the base load subcategory units may practically be constructed using the most efficient technology without then installing CCS and likewise may install CCS on a turbine system that was not constructed with the most efficient technology. Within the group of actions for new, modified, and reconstructed fossil fuel- fired steam generating units in section I.C.4, the revisions of the standards of performance for coal-fired steam 
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11Joint Memorandum of Understanding on 
Interagency Communication and Consultation on 
Electric Reliability (March 9, 2023). https://www.epa.gov/power-sector/electric-reliability-mou. generators that undertake a large 
modification are severable from the withdrawal of the 2018 proposal to revise the NSPS for emissions of GHG from EGUs. Each of the actions in these final rules that the EPA has identified as severable is functionally independent— i.e., may operate in practice 
independently of the other actions. 
In addition, while the EPA is 
finalizing this rule at the same time as other final rules regulating different types of pollution from EGUs— specifically the Supplemental Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (FR 2024–09815, EPA–HQ–OW–2009–0819; FRL–8794– 02–OW); National Emission Standards for Hazardous Air Pollutants: Coal and Oil-Fired Electric Utility Steam Generating Units Review of the Residual Risk and Technology Review (FR 2024– 09148, EPA–HQ–OAR–2018–0794; FRL–6716.3–02–OAR); Hazardous and Solid Waste Management System: Disposal of Coal Combustion Residuals From Electric Utilities; Legacy CCR Surface Impoundments (FR 2024– 09157, EPA–HQ–OLEM–2020–0107; FRL–7814–04–OLEM)—and has considered the interactions between and cumulative effects of these rules, each rule is based on different statutory authority, a different record, and is completely independent of the other rules. 
D. Grid Reliability Considerations 
The EPA is finalizing multiple 
adjustments to the proposed rules that 
ensure the requirements in these final actions can be implemented without compromising the ability of power companies, grid operators, and state and Federal energy regulators to maintain resource adequacy and grid reliability. In response to the May 2023 proposed rule, the EPA received extensive comments from balancing authorities, independent system operators and regional transmission organizations, state regulators, power companies, and other stakeholders on the need for the final rule to accommodate resource adequacy and grid reliability needs. The EPA also engaged with the balancing authorities that submitted comments to the docket, the staff and Commissioners of the Federal Energy Regulatory Commission (FERC), the Department of Energy (DOE), the North American Electric Reliability Corporation (NERC), and other expert entities during the course of this rulemaking. Finally, at the invitation of FERC, the EPA participated in FERC’s Annual Reliability Technical Conference on November 9, 2023. These final actions respond to this 
input and feedback in multiple ways, including through changes to the universe of affected sources, longer compliance timeframes for CCS implementation, and other compliance flexibilities, as well as articulation of the appropriate use of RULOF to address reliability issues during state plan development and in subsequent state plan revisions. In addition to these adjustments, the EPA is finalizing several programmatic mechanisms specifically designed to address reliability concerns raised by commenters. For existing fossil fuel- fired EGUs, a short-term reliability emergency mechanism is available for states to provide more flexibility by using an alternative emission limitation during acute operational emergencies when the grid might be temporarily under heavy strain. A similar short-term reliability emergency mechanism is also available to new sources. In addition, the EPA is creating an option for states to provide for a compliance date extension for existing sources of up to 1 year under certain circumstances for sources that are installing control technologies to comply with their standards of performance. Lastly, states may also provide, by inclusion in their state plans, a reliability assurance mechanism of up to 1 year that under limited circumstances would allow existing units that had planned to cease operating by a certain date to temporarily remain available to support reliability. Any extensions exceeding 1 year must be addressed through a state plan revision. In order to utilize this reliability pathway, there must be an adequate demonstration of need and certification by a reliability authority, and approval by the appropriate EPA Regional Administrator. The EPA plans to seek the advice of FERC for extension requests exceeding 6 months. Similarly, for new fossil fuel-fired combustion turbines, the EPA is creating a mechanism whereby baseload units may request a 1-year extension of their CCS compliance deadline under certain circumstances. 
The EPA has evaluated the resource 
adequacy implications of these actions in the final technical support document (TSD), Resource Adequacy Analysis, 
and conducted capacity expansion modeling of the final rules in a manner that takes into account resource adequacy needs. The EPA finds that resource adequacy can be maintained with the final rules. The EPA modeled a scenario that complies with the final rules and that meets resource adequacy needs. The EPA also performed a variety of other sensitivity analyses looking at higher electricity demand (load growth) and impact of the EPA’s additional regulatory actions affecting the power sector. These sensitivity analyses indicate that, in the context of higher demand and other pending power sector rules, the industry has available pathways to comply with this rule that respect NERC reliability considerations and constraints. 
In addition, the EPA notes that 
significant planning and regulatory mechanisms exist to ensure that sufficient generation resources are available to maintain reliability. The EPA’s consideration of reliability in this rulemaking has also been informed by consultation with the DOE under the auspices of the March 9, 2023, memorandum of understanding (MOU)
11signed by the EPA 
Administrator and the Secretary of Energy, as well as by consultation with FERC expert staff. In these final actions, the EPA has included various flexibilities that allow power companies and grid operators to plan for achieving feasible and necessary reductions of GHGs from affected sources consistent with the EPA’s statutory charge while ensuring that the rule will not interfere with systems operators’ ability to ensure grid reliability. 
A thorough description of how 
adjustments in the final rules address reliability issues, the EPA’s outreach to balancing authorities, EPA’s supplemental notice, as well as the introduction of mechanisms to address short- and long-term reliability needs is presented in section XII.F of this preamble. 
E. Environmental Justice Considerations 
Consistent with Executive Order 
(E.O.) 14096, and the EPA’s 
commitment to upholding environmental justice (EJ) across its policies and programs, the EPA carefully considered the impacts of these actions on communities with environmental justice concerns. As part of the regulatory development process for these rulemakings, and consistent with directives set forth in multiple Executive Orders, the EPA conducted extensive outreach with interested parties including Tribal nations and communities with environmental justice concerns. These opportunities gave the EPA a chance to hear directly from the public, including from communities potentially impacted by these final 
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12Specifically, the EPA has relied on, and is 
incorporating as a basis for this rulemaking, 
analyses regarding possible adverse environmental effects from CCS, including those highlighted by commenters. Consideration of these effects is permissible under CAA section 111(a)(1). Although the EPA also conducted analyses of disproportionate impacts pursuant to E.O. 14096, see section XII.E, the EPA did not consider or rely on these analyses as a basis for these rules. 
1387 FR 8808, 8809 (February 16, 2022). 
14This framework includes, among other things, 
the EPA regulation of geologic sequestration wells under the Underground Injection Control (UIC) program of the Safe Drinking Water Act; required reporting and public disclosure of geologic sequestration activity, as well as implementation of rigorous monitoring, reporting, and verification of geologic sequestration under the EPA’s Greenhouse 
Gas Reporting Program (GHGRP); and safety regulations for CO
2pipelines administered by the 
Pipeline and Hazardous Materials and Safety Administration (PHMSA). actions. The EPA took this feedback into 
account in its development of these final actions.
12The EPA’s analysis of 
environmental justice in these final actions is briefly summarized here and discussed in further detail in sections XII.E and XIII.J of the preamble and section 6 of the regulatory impact analysis (RIA). 
Several environmental justice 
organizations and community representatives raised significant concerns about the potential health, environmental, and safety impacts of CCS. The EPA takes these concerns seriously, agrees that any impacts to historically disadvantaged and overburdened communities are important to consider, and has carefully considered these concerns as it finalized its determinations of the BSERs for these rules. The Agency acknowledges that while these final actions will result in large reductions of both GHGs and 
other emissions that will have significant positive benefits, there is the potential for localized increases in emissions, particularly if units installing CCS operate for more hours during the year and/or for more years than they would have otherwise. However, as discussed in section VII.C.1.a.iii(B), a robust regulatory framework exists to reduce the risks of localized emissions increases in a manner that is protective of public health, safety, and the environment. The Council on Environmental Quality’s (CEQ) February 2022 Carbon Capture, Utilization, and 
Sequestration Guidance and the EPA’s evaluation of BSER recognize that multiple Federal agencies have responsibility for regulating and permitting CCS projects, along with state and tribal governments. As the CEQ has noted, Federal agencies have ‘‘taken actions in the past decade to develop a robust carbon capture, utilization, and sequestration/storage (CCUS) regulatory framework to protect the environment and public health across multiple statutes.’’
13 14 Furthermore, the EPA plans to review and update as needed its guidance on NSR permitting, specifically with respect to BACT determinations for GHG emissions and consideration of co- pollutant increases from sources installing CCS. For the reasons explained in section VII.C, the EPA is finalizing the determination that CCS is the BSER for certain subcategories of new and existing EGUs based on its consideration of all of the statutory criteria for BSER, including emission reductions, cost, energy requirements, and non-air health and environmental considerations. At the same time, the EPA recognizes the critical importance of ensuring that the regulatory framework performs as intended to protect communities. 
These actions are focused on 
establishing NSPS and emission guidelines for GHGs that states will implement to significantly reduce GHGs and move us a step closer to avoiding the worst impacts of climate change, which is already having a disproportionate impact on communities with environmental justice concerns. The EPA analyzed several illustrative scenarios representing potential compliance outcomes and evaluated the potential impacts that these actions may have on emissions of GHG and other health-harming air pollutants from fossil fuel-fired EGUs, as well as how these changes in emissions might affect air quality and public health, particularly for communities with EJ concerns. 
The EPA’s national-level analysis of 
emission reduction and public health impacts, which is documented in section 6 of the RIA and summarized in greater detail in section XII.A and XII.D of this preamble, finds that these actions achieve nationwide reductions in EGU emissions of multiple health-harming air pollutants including nitrogen oxides (NO
X), sulfur dioxide (SO 2), and fine 
particulate matter (PM 2.5), resulting in 
public health benefits. The EPA also evaluated how the air quality impacts associated with these final actions are distributed, with particular focus on communities with EJ concerns. As discussed in the RIA, our analysis indicates that baseline ozone and PM
2.5 
concentration will decline substantially relative to today’s levels. Relative to these low baseline levels, ozone and PM
2.5concentrations will decrease 
further in virtually all areas of the country, although some areas of the country may experience slower or faster 
rates of decline in ozone and PM
2.5 
pollution over time due to the changes in generation and utilization resulting from these rules. Additionally, our comparison of future air quality conditions with and without these rules suggests that while these actions are anticipated to lead to modest but widespread reductions in ambient levels of PM
2.5and ozone for a large majority 
of the nation’s population, there is potential for some geographic areas and demographic groups to experience small increases in ozone concentrations relative to the baseline levels which are projected to be substantially lower than today’s levels. 
It is important to recognize that while 
these projections of emissions changes and resulting air quality changes under various illustrative compliance scenarios are based upon the best information available to the EPA at this time, with regard to existing sources, each state will ultimately be responsible for determining the future operation of fossil fuel-fired steam generating units located within its jurisdiction. The EPA expects that, in making these determinations, states will consider a number of factors and weigh input from the wide range of potentially affected stakeholders. The meaningful engagement requirements discussed in section X.E.1.b.i of this preamble will ensure that all interested stakeholders— including community members adversely impacted by pollution, energy workers affected by construction and/or other changes in operation at fossil-fuel- fired power plants, consumers and other interested parties—will have an opportunity to have their concerns heard as states make decisions balancing a multitude of factors including appropriate standards of performance, compliance strategies, and compliance flexibilities for existing EGUs, as well as public health and environmental considerations. The EPA believes that these provisions, together with the protections referenced above, can reduce the risks of localized 
emissions increases in a manner that is protective of public health, safety, and the environment. 
F. Energy Workers and Communities 
These final actions include 
requirements for meaningful 
engagement in development of state plans, including with energy workers and communities. These communities, including energy workers employed at affected EGUs, workers who may construct and install pollution control technology, workers employed by fuel extraction and delivery, organizations 
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15The EPA is not placing qualifications on the 
type of hydrogen a source may elect to co-fire at this 
time (see section VIII.F.6.a of this preamble for further discussion). The Agency continues to recognize that even though the combustion of hydrogen is zero-GHG emitting, its production can entail a range of GHG emissions, from low to high, depending on the production method. Thus, even though the EPA is not finalizing the low-GHG hydrogen co-firing as a BSER, as proposed, it maintains that the overall GHG profile of a particular method of hydrogen production should be a primary consideration for any source that decides to co-fire hydrogen to ensure that overall GHG reductions and important climate benefits are achieved. The EPA also notes the anticipated final rule from the U.S. Department of the Treasury pertaining to clean hydrogen production tax and energy credits, which in its proposed form contains certain eligibility parameters, as well as programs 
administered by the U.S. Department of Energy, such as the recent H2Hubs selections. representing these workers, and 
communities living near affected EGUs, are impacted by power sector trends on an ongoing basis and by these final actions, and the EPA expects that states will include these stakeholders as part of their constructive engagement under the requirements in this rule. 
The EPA consulted with the Federal 
Interagency Working Group on Coal and Power Plant Communities and Economic Revitalization (Energy Communities IWG) in development of these rules and the meaningful engagement requirements. The EPA notes that the Energy Communities IWG has provided resources to help energy communities access the expanded federal resources made available by the Bipartisan Infrastructure Law, CHIPS and Science Act, and Inflation Reduction Act, many of which are relevant to the development of state plans. 
G. Key Changes From Proposal 
The key changes from proposal in 
these final actions are: (1) the reduction 
in number of subcategories for existing coal-fired steam generating units, (2) the extension of the compliance date for existing coal-fired steam generating units to meet a standard of performance based on implementation of CCS, (3) the removal of low-GHG hydrogen co-firing as a BSER pathway, and (4) the addition of two reliability-related instruments. In addition, (5), the EPA is not finalizing proposed requirements for existing fossil fuel-fired stationary combustion turbines at this time. 
The reduction in number of 
subcategories for existing coal-fired steam generating units: The EPA proposed four subcategories for existing coal-fired steam generating units, which would have distinguished these units by operating horizon and by load level. These included subcategories for existing coal-fired EGUs planning to 
cease operations in the imminent-term (i.e., prior to January 1, 2032) and those 
planning to cease operations in the near- term (i.e., prior to January 1, 2035). 
While commenters were generally supportive of the proposed subcategorization approach, some requested that the cease-operation-by date for the imminent-term subcategory be extended and the utilization limit for the near-term subcategory be relaxed. The EPA is not finalizing the imminent- term and near-term subcategories of coal-fired steam generating units. Rather, the EPA is finalizing an applicability exemption for coal-fired steam generating units demonstrating that they plan to permanently cease operation before January 1, 2032. See section VII.B of this preamble for further discussion. 
The extension of the compliance date 
for existing coal-fired steam generating units to meet a standard of performance based on implementation of CCS. The EPA proposed a compliance date for implementation of CCS for long-term coal-fired steam generating units of January 1, 2030. The EPA received comments asserting that this deadline did not provide adequate lead time. In consideration of those comments, and the record as a whole, the EPA is finalizing a CCS compliance date of January 1, 2032 for these sources. 
The removal of low-GHG hydrogen co- 
firing as a BSER pathway and only use of low-GHG hydrogen as a compliance option: The EPA is not finalizing its 
proposed BSER pathway of low-GHG hydrogen co-firing for new and reconstructed base load and intermediate load combustion turbines in accordance with CAA section 111(a)(1). The EPA is also not finalizing its proposed requirement that only low- GHG hydrogen may be co-fired in a combustion turbine for the purpose of compliance with the standards of performance. These decisions are based on uncertainties identified for specific criteria used to evaluate low-GHG hydrogen co-firing as a potential BSER, and after further analysis in response to public comments, the EPA has determined that these uncertainties prevent the EPA from concluding that low-GHG hydrogen co-firing is a component of the ‘‘best’’ system of emission reduction at this time. Under CAA section 111, the EPA establishes standards of performance but does not mandate use of any particular technology to meet those standards. Therefore, certain sources may elect to co-fire hydrogen for compliance with the final standards of performance, even absent the technology being a BSER pathway.
15See section VIII.F.5 of this 
preamble for further discussion. The addition of two reliability-related 
instruments: Commenters expressed 
concerns that these rules, in 
combination with other factors, may affect the reliability of the bulk power system. In response to these comments the EPA engaged extensively with balancing authorities, power companies, reliability experts, and regulatory authorities responsible for reliability to inform its decisions in these final rules. As described later in this preamble, the EPA has made adjustments in these final rules that will support power companies, grid operators, and states in maintaining the reliability of the electric grid during the implementation of these final rules. In addition, the EPA has undertaken an analysis of the reliability and resource adequacy implications of these final rules that supports the Agency’s conclusion that these final rules can be implemented without adverse consequences for grid 
reliability. Further, the EPA is finalizing two reliability-related instruments as an additional layer of safeguards for reliability. These instruments include a reliability mechanism for short-term emergency issues, and a reliability assurance mechanism, or compliance flexibility, for units that have chosen compliance pathways with enforceable retirement dates, provided there is a documented and verified reliability concern. In addition, the EPA is finalizing compliance extensions for unanticipated delays with control technology implementation. Specifically, as described in greater detail in section XII.F of this preamble, the EPA is finalizing the following features and changes from the proposal that will provide even greater certainty that these final rules are sensitive to reliability-related issues and constructed in a manner that does not interfere with grid operators’ responsibility to deliver reliable power: 
(1) longer compliance timelines for 
existing coal-fired steam generating units; 
(2) a mechanism to extend 
compliance timelines by up to 1 year in the case of unforeseen circumstances, outside of an owner/operator’s control, that delay the ability to apply controls (e.g., supply chain challenges or 
permitting delays); 
(3) transparent unit-specific 
compliance information for EGUs that will allow grid operators to plan for system changes with greater certainty and precision; 
(4) a short-term reliability mechanism 
to allow affected EGUs to operate at 
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16See the EPA’s website, https://www.epa.gov/ 
tribal/tribes-approved-treatment-state-tas, for 
information on those tribes that have treatment as a state for specific environmental regulatory programs, administrative functions, and grant programs. baseline emission rates during 
documented reliability emergencies; and 
(5) a reliability assurance mechanism 
to allow states to delay cease operation dates by up to 1 year in cases where the planned cease operation date is forecast to disrupt system reliability. 
Not finalizing proposed requirements 
for existing fossil fuel-fired stationary combustion turbines at this time: The EPA proposed emission guidelines for large (i.e., greater than 300 MW), 
frequently operated (i.e., with an annual 
capacity factor of greater than 50 percent), existing fossil fuel-fired stationary combustion turbines. The EPA received a wide range of comments on the proposed guidelines. Multiple commenters suggested that the proposed provisions would largely result in shifting of generation away from the most efficient natural gas-fired turbines to less efficient natural gas-fired turbines. Commenters stated that, as emissions from coal-fired steam generating units decreased, existing natural gas-fired EGUs were poised to become the largest source of GHG emissions in the power sector. Commenters noted that these units play an important role in grid reliability, particularly as aging coal-fired EGUs retire. Commenters further noted that the existing fossil fuel-fired stationary combustion turbines that were not covered by the proposal (i.e., the smaller 
and less frequently operating units) are often less efficient, less well controlled for other pollutants such as NO
X, and 
are more likely to be located near population centers and communities with environmental justice concerns. 
The EPA agrees with commenters 
who observed that GHG emissions from existing natural gas-fired stationary combustion turbines are a growing portion of the emissions from the power sector. This is consistent with EPA modeling that shows that by 2030 these units will represent the largest portion of GHG emissions from the power sector. The EPA agrees that it is vital to promulgate emission guidelines to address GHG emissions from these sources, and that the EPA has a responsibility to do so under section 111(d) of the Clean Air Act. The EPA also agrees with commenters who noted that focusing only on the largest and 
most frequently operating units, without also addressing emissions from other units, as the May 2023 proposed rule provided, may not be the most effective way to address emissions from this sector. The EPA’s modeling shows that over time as the power sector comes closer to reaching the phase-out threshold of the clean electricity incentives in the Inflation Reduction Act (IRA) (i.e., a 75 percent reduction in 
emissions from the power sector from 2022 levels), the average capacity factor for existing natural gas-fired stationary combustion turbines decreases. Therefore, the EPA’s proposal to focus only on the largest units with the highest capacity factors may not be the most effective policy design for reducing GHG emissions from these sources. 
Recognizing the importance of 
reducing emissions from all fossil fuel- fired EGUs, the EPA is not finalizing the proposed emission guidelines for certain existing fossil fuel-fired stationary combustion turbines at this time. Instead, the EPA intends to issue a new, more comprehensive proposal to regulate GHGs from existing sources. The new proposal will focus on achieving greater emission reductions from existing stationary combustion turbines—which will soon be the largest stationary sources of GHG emissions— while taking into account other factors including the local non-GHG impacts of gas turbine generation and the need for reliable, affordable electricity. 
II. General Information A. Action Applicability 
The source category that is the subject 
of these actions is composed of fossil 
fuel-fired electric utility generating units. The North American Industry Classification System (NAICS) codes for the source category are 221112 and 921150. The list of categories and NAICS codes is not intended to be exhaustive, but rather provides a guide for readers regarding the entities that these final actions are likely to affect. 
Final amendments to 40 CFR part 60, 
subpart TTTT, are directly applicable to affected facilities that began construction after January 8, 2014, but before May 23, 2023, and affected facilities that began reconstruction or modification after June 18, 2014, but before May 23, 2023. The NSPS codified in 40 CFR part 60, subpart TTTTa, is directly applicable to affected facilities that begin construction, reconstruction, or modification on or after May 23, 2023. Federal, state, local, and tribal government entities that own and/or operate EGUs subject to 40 CFR part 60, subpart TTTT or TTTTa, are affected by these amendments and standards. 
The emission guidelines codified in 
40 CFR part 60, subpart UUUUb, are for states to follow in developing, submitting, and implementing state plans to establish performance standards to reduce emissions of GHGs from designated facilities that are existing sources. Section 111(a)(6) of the 
CAA defines an ‘‘existing source’’ as ‘‘any stationary source other than a new source.’’ Therefore, the emission guidelines would not apply to any EGUs that are new after January 8, 2014, or reconstructed after June 18, 2014, the applicability dates of 40 CFR part 60, subpart TTTT. Under the Tribal Authority Rule (TAR), eligible tribes may seek approval to implement a plan under CAA section 111(d) in a manner similar to a state. See 40 CFR part 49, subpart A. Tribes may, but are not required to, seek approval for treatment in a manner similar to a state for purposes of developing a tribal implementation plan (TIP) implementing the emission guidelines codified in 40 CFR part 60, subpart UUUUb. The TAR authorizes tribes to develop and implement their own air quality programs, or portions thereof, under the CAA. However, it does not require tribes to develop a CAA program. Tribes may implement programs that are most relevant to their air quality needs. If a tribe does not seek and obtain the authority from the EPA to establish a TIP, the EPA has the authority to establish a Federal CAA section 111(d) plan for designated facilities that are located in areas of Indian country.
16A Federal plan would 
apply to all designated facilities located in the areas of Indian country covered 
by the Federal plan unless and until the EPA approves a TIP applicable to those facilities. 
B. Where To Get a Copy of This 
Document and Other Related Information 
In addition to being available in the 
docket, an electronic copy of these final rulemakings is available on the internet at https://www.epa.gov/stationary- 
sources-air-pollution/greenhouse-gas- standards-and-guidelines-fossil-fuel- fired-power. Following signature by the EPA Administrator, the EPA will post a copy of these final rulemakings at this same website. Following publication in the Federal Register, the EPA will post 
the Federal Register version of the final 
rules and key technical documents at this same website. 
C. Judicial Review and Administrative 
Review 
Under CAA section 307(b)(1), judicial 
review of these final actions is available only by filing a petition for review in 
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17The CAA states in section 302(h) that ‘‘[a]ll 
language referring to effects on welfare includes, 
but is not limited to, effects on soils, water, crops, vegetation, manmade materials, animals, wildlife, weather, visibility, and climate, damage to and deterioration of property, and hazards to transportation, as well as effects on economic values and on personal comfort and well-being, whether caused by transformation, conversion, or combination with other air pollutants.’’ 42 U.S.C. 7602(h). 
18Finding That Greenhouse Gas Emissions From 
Aircraft Cause or Contribute to Air Pollution That May Reasonably Be Anticipated To Endanger Public Health and Welfare. 81 FR 54422, August 15, 2016 (‘‘2016 Endangerment Finding’’). the United States Court of Appeals for 
the District of Columbia Circuit by July 8, 2024. These final actions are ‘‘standard[s] of performance or requirement[s] under section 111,’’ and, in addition, are ‘‘nationally applicable regulations promulgated, or final action taken, by the Administrator under [the CAA],’’ CAA section 307(b)(1). Under CAA section 307(b)(2), the requirements established by this final rule may not be challenged separately in any civil or criminal proceedings brought by the EPA to enforce the 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 the EPA 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. Environmental Protection Agency, Room 3000, WJC West 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. 
Environmental Protection Agency, 1200 Pennsylvania Ave. NW, Washington, DC 20460. 
III. Climate Change Impacts 
Elevated concentrations of GHGs have 
been warming the planet, leading to 
changes in the Earth’s climate that are occurring at a pace and in a way that threatens human health, society, and the natural environment. While the EPA is not making any new scientific or factual findings with regard to the well- documented impact of GHG emissions on public health and welfare in support of these rules, the EPA is providing in this section a brief scientific background on climate change to offer additional context for these rulemakings and to help the public understand the environmental impacts of GHGs. 
Extensive information on climate 
change is available in the scientific assessments and the EPA documents that are briefly described in this section, as well as in the technical and scientific information supporting them. One of those documents is the EPA’s 2009 ‘‘Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the CAA’’ (74 FR 66496, December 15, 2009) (‘‘2009 Endangerment Finding’’). In the 2009 Endangerment Finding, the Administrator found under section 202(a) of the CAA that elevated atmospheric concentrations of six key well-mixed GHGs—CO
2, methane (CH 4), 
nitrous oxide (N 2O), HFCs, 
perfluorocarbons (PFCs), and sulfur hexafluoride (SF
6)—‘‘may reasonably be 
anticipated to endanger the public health and welfare of current and future generations’’ (74 FR 66523, December 15, 2009). The 2009 Endangerment Finding, together with the extensive scientific and technical evidence in the supporting record, documented that climate change caused by human emissions of GHGs threatens the public health of the U.S. population. It explained that by raising average temperatures, climate change increases the likelihood of heat waves, which are associated with increased deaths and illnesses (74 FR 66497, December 15, 2009). While climate change also increases the likelihood of reductions in cold-related mortality, evidence indicates that the increases in heat mortality will be larger than the decreases in cold mortality in the U.S. (74 FR 66525, December 15, 2009). The 2009 Endangerment Finding further explained that compared with a future without climate change, climate change is expected to increase tropospheric ozone pollution over broad areas of the U.S., including in the largest metropolitan areas with the worst tropospheric ozone problems, and thereby increase the risk of adverse effects on public health (74 FR 66525, December 15, 2009). Climate change is also expected to cause more intense hurricanes and more frequent and intense storms of other types 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 (74 FR 66525 December 15, 2009). Children, the elderly, and the poor are among the most vulnerable to these climate-related health effects (74 FR 66498, December 15, 2009). 
The 2009 Endangerment Finding also 
documented, together with the extensive scientific and technical evidence in the supporting record, that climate change touches nearly every 
aspect of public welfare
17in the U.S., 
including the following: changes in water supply and quality due to changes in drought and extreme rainfall events; increased risk of storm surge and flooding in coastal areas and land loss due to inundation; increases in peak electricity demand and risks to electricity infrastructure; and the potential for significant agricultural disruptions and crop failures (though offset to some extent by carbon fertilization). These impacts are also global and may exacerbate problems outside the U.S. that raise humanitarian, trade, and national security issues for the U.S. (74 FR 66530, December 15, 2009). 
In 2016, the Administrator issued a 
similar finding for GHG emissions from aircraft under section 231(a)(2)(A) of the CAA.
18In the 2016 Endangerment 
Finding, the Administrator found that the body of scientific evidence amassed in the record for the 2009 Endangerment Finding compellingly supported a similar endangerment finding under CAA section 231(a)(2)(A) and also found that the science assessments released between the 2009 and 2016 Findings ‘‘strengthen and further support the judgment that GHGs in the atmosphere may reasonably be anticipated to endanger the public health and welfare of current and future generations’’ (81 FR 54424, August 15, 2016). 
Since the 2016 Endangerment 
Finding, the climate has continued to change, with new observational records being set for several climate indicators 
such as global average surface temperatures, GHG concentrations, and sea level rise. Additionally, major scientific assessments continue to be released that further advance our understanding of the climate system and the impacts that GHGs have on public health and welfare for both current and future generations. These updated observations and projections document the rapid rate of current and future 
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19USGCRP, 2017: Climate Science Special 
Report: Fourth National Climate Assessment, 
Volume I [Wuebbles, D.J., D.W. Fahey, K.A. Hibbard, D.J. Dokken, B.C. Stewart, and T.K. Maycock (eds.)]. U.S. Global Change Research Program, Washington, DC, USA, 470 pp, doi: 10.7930/J0J964J6. 
20USGCRP, 2016: The Impacts of Climate Change 
on Human Health in the United States: A Scientific Assessment. Crimmins, A., J. Balbus, J.L. Gamble, C.B. Beard, J.E. Bell, D. Dodgen, R.J. Eisen, N. Fann, M.D. Hawkins, S.C. Herring, L. Jantarasami, D.M. Mills, S. Saha, M.C. 
21USGCRP, 2018: Impacts, Risks, and Adaptation 
in the United States: Fourth National Climate Assessment, Volume II [Reidmiller, D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K. Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research Program, Washington, DC, USA, 1515 pp. doi:10.7930/NCA4.2018. 
22IPCC, 2018: Global Warming of 1.5 °C. An IPCC 
Special Report on the impacts of global warming of 1.5°C above pre-industrial levels and related global 
greenhouse gas emission pathways, in the context of strengthening the global response to the threat of climate change, sustainable development, and efforts to eradicate poverty [Masson-Delmotte, V., P. Zhai, H.-O. Po ¨rtner, D. Roberts, J. Skea, P.R. Shukla, 
A. Pirani, W. Moufouma-Okia, C. Pe ´an, R. Pidcock, 
S. Connors, J.B.R. Matthews, Y. Chen, X. Zhou, M.I. Gomis, E. Lonnoy, T. Maycock, M. Tignor, and T. Waterfield (eds.)]. 
23IPCC, 2019: Climate Change and Land: an IPCC 
special report on climate change, desertification, land degradation, sustainable land management, food security, and greenhouse gas fluxes in terrestrial ecosystems [P.R. Shukla, J. Skea, E. Calvo Buendia, V. Masson-Delmotte, H.-O. Po ¨rtner, D.C. 
Roberts, P. Zhai, R. Slade, S. Connors, R. van Diemen, M. Ferrat, E. Haughey, S. Luz, S. Neogi, M. Pathak, J. Petzold, J. Portugal Pereira, P. Vyas, E. Huntley, K. Kissick, M. Belkacemi, J. Malley, (eds.)]. 
24IPCC, 2019: IPCC Special Report on the Ocean 
and Cryosphere in a Changing Climate [H.-O. Po¨rtner, D.C. Roberts, V. Masson-Delmotte, P. Zhai, 
M. Tignor, E. Poloczanska, K. Mintenbeck, A. Alegriı ´a, M. Nicolai, A. Okem, J. Petzold, B. Rama, 
N.M. Weyer (eds.)]. 
25National Academies of Sciences, Engineering, 
and Medicine. 2016. Attribution of Extreme Weather Events in the Context of Climate Change. Washington, DC: The National Academies Press. https://dio.org/10.17226/21852. 
26National Academies of Sciences, Engineering, 
and Medicine. 2017. Valuing Climate Damages: Updating Estimation of the Social Cost of Carbon Dioxide. Washington, DC: The National Academies Press. https://doi.org/10.17226/24651. 
27National Academies of Sciences, Engineering, 
and Medicine. 2019. Climate Change and Ecosystems. Washington, DC: The National Academies Press. https://doi.org/10.17226/25504. 
28Blunden, J. and T. Boyer, Eds., 2022: ‘‘State of 
the Climate in 2021.’’ Bull. Amer. Meteor. Soc., 103 (8), Si–S465, https://doi.org/10.1175/ 2022BAMSStateoftheClimate.1. 
29U.S. Environmental Protection Agency. 2021. 
Climate Change and Social Vulnerability in the United States: A Focus on Six Impacts. EPA 430– R–21–003. 
30Jay, A.K., A.R. Crimmins, C.W. Avery, T.A. 
Dahl, R.S. Dodder, B.D. Hamlington, A. Lustig, K. Marvel, P.A. Me ´ndez-Lazaro, M.S. Osler, A. 
Terando, E.S. Weeks, and A. Zycherman, 2023: Ch. 1. Overview: Understanding risks, impacts, and responses. In: Fifth National Climate Assessment. Crimmins, A.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, B.C. Stewart, and T.K. Maycock, Eds. U.S. Global Change Research Program, Washington, DC, USA. https://doi.org/10.7930/NCA5.2023.CH1 . 31IPCC, 2023: Summary for Policymakers. In: 
Climate Change 2023: Synthesis Report. 
Contribution of Working Groups I, II and III to the Sixth Assessment Report of the Intergovernmental Panel on Climate Change [Core Writing Team, H. Lee and J. Romero (eds.)]. 
32https://gml.noaa.gov/webdata/ccgg/trends/co2/ 
co2_ annmean_ mlo.txt. 
33IPCC, 2021: Summary for Policymakers. In: 
Climate Change 2021: The Physical Science Basis. Contribution of Working Group I to the Sixth Assessment Report of the Intergovernmental Panel on Climate Change [Masson-Delmotte, V., P. Zhai, A. Pirani, S.L. Connors, C. Pe ´an, S. Berger, N. Caud, 
Y. Chen, L. Goldfarb, M.I. Gomis, M. Huang, K. Leitzell, E. Lonnoy, J.B.R. Matthews, T.K. Maycock, T. Waterfield, O. Yelekc ¸i, R. Yu, and B. Zhou 
(eds.)]. Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA, pp. 3– 32, doi:10.1017/9781009157896.001. 
34NOAA National Centers for Environmental 
Information, State of the Climate 2021 retrieved on August 3, 2023, from https://www.ncei.noaa.gov/ 
bams-state-of-climate. 
35Blunden, J. and T. Boyer, Eds., 2022: ‘‘State of 
the Climate in 2021.’’ Bull. Amer. Meteor. Soc., 103 (8), Si–S465, https://doi.org/10.1175/ 2022BAMSStateoftheClimate1. 
36IPCC, 2021. 37IPCC, 2021. 
38USGCRP, 2018: Impacts, Risks, and Adaptation 
in the United States: Fourth National Climate Assessment, Volume II [Reidmiller, D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K. Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research Program, Washington, DC, USA, 1515 pp. doi:10.7930/NCA4.2018. 
39IPCC, 2018. 
40IPCC, 2021. 
41These are drought measures based on soil 
moisture. 
42IPCC, 2021. 
43Annual Mauna Loa CO 2concentration data 
from https://gml.noaa.gov/webdata/ccgg/trends/ 
co2/co2_ annmean_ mlo.txt, accessed September 9, 
2023. 
44IPCC, 2013. climate change both globally and in the 
U.S.19 20 21 22 23 24 25 26 27 28 29 30 31  The most recent information 
demonstrates that the climate is 
continuing to change in response to the human-induced buildup of GHGs in the atmosphere. These recent assessments show that atmospheric concentrations of GHGs have risen to a level that has no precedent in human history and that they continue to climb, primarily because of both historical and current anthropogenic emissions, and that these elevated concentrations endanger our health by affecting our food and water sources, the air we breathe, the weather we experience, and our interactions with the natural and built environments. For example, atmospheric concentrations of one of these GHGs, CO
2, measured at Mauna 
Loa in Hawaii and at other sites around the world reached 419 parts per million (ppm) in 2022 (nearly 50 percent higher than preindustrial levels)
32and have 
continued to rise at a rapid rate. Global average temperature has increased by about 1.1 °C (2.0 °F) in the 2011–2020 
decade relative to 1850–1900.
33The 
years 2015–2021 were the warmest 7 years in the 1880–2021 record, contributing to the warmest decade on record with a decadal temperature of 0.82 °C (1.48 °F) above the 20th 
century.
34 35 The Intergovernmental 
Panel on Climate Change (IPCC) determined (with medium confidence) that this past decade was warmer than any multi-century period in at least the past 100,000 years.
36Global average sea 
level has risen by about 8 inches (about 21 centimeters (cm)) from 1901 to 2018, with the rate from 2006 to 2018 (0.15 inches/year or 3.7 millimeters (mm)/ year) almost twice the rate over the 1971 to 2006 period, and three times the rate of the 1901 to 2018 period.
37The rate 
of sea level rise over the 20th century 
was higher than in any other century in at least the last 2,800 years.
38Higher 
CO 2concentrations have led to 
acidification of the surface ocean in recent decades to an extent unusual in the past 65 million years, with negative impacts on marine organisms that use calcium carbonate to build shells or skeletons.
39Arctic sea ice extent 
continues to decline in all months of the year; the most rapid reductions occur in September (very likely almost a 13 percent decrease per decade between 1979 and 2018) and are unprecedented in at least 1,000 years.
40Human- 
induced climate change has led to heatwaves and heavy precipitation becoming more frequent and more intense, along with increases in agricultural and ecological droughts
41 
in many regions.42 
The assessment literature 
demonstrates that modest additional amounts of warming may lead to a climate different from anything humans have ever experienced. The 2022 CO
2 
concentration of 419 ppm is already higher than at any time in the last 2 million years.
43If concentrations exceed 
450 ppm, they would likely be higher than any time in the past 23 million years:
44at the current rate of increase of 
more than 2 ppm per year, this would occur in about 15 years. While GHGs are not the only factor that controls climate, it is illustrative that 3 million years ago (the last time CO
2concentrations were 
above 400 ppm) Greenland was not yet completely covered by ice and still supported forests, while 23 million years ago (the last time concentrations were above 450 ppm) the West Antarctic ice sheet was not yet developed, indicating the possibility that high GHG concentrations could lead to a world that looks very different from today and from the conditions in which human civilization has developed. If the 
Greenland and Antarctic ice sheets were 
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45USGCRP, 2018. 
46IPCC, 2018. 47IPCC, 2018. 
48IPCC, 2021. 
49USGCRP, 2018. 
50NIFC (National Interagency Fire Center). 2021. 
Total wildland fires and acres (1983–2020). 
Accessed August 2021. https://www.nifc.gov/ fireInfo/fireInfo_ stats_ totalFires.html. 51USGCRP, 2018. 
52Jay, A.K., A.R. Crimmins, C.W. Avery, T.A. 
Dahl, R.S. Dodder, B.D. Hamlington, A. Lustig, K. 
Marvel, P.A. Me ´ndez-Lazaro, M.S. Osler, A. 
Terando, E.S. Weeks, and A. Zycherman, 2023: Ch. 
1. Overview: Understanding risks, impacts, and responses. In: Fifth National Climate Assessment. Crimmins, A.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, B.C. Stewart, and T.K. Maycock, Eds. U.S. Global Change Research Program, Washington, DC, USA. https://doi.org/10.7930/NCA5.2023.CH1 . 
53(1) Hartin, C., et al. (2023). Advancing the 
estimation of future climate impacts within the United States. Earth Syst. Dynam., 14, 1015–1037, https://doi.org/10.5194/esd-14-1015-2023 . (2) 
Supplementary Material for the Regulatory Impact Analysis for the Final Rulemaking, Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review, ‘‘Report on the Social Cost of Greenhouse 
Gases: Estimates Incorporating Recent Scientific Advances,’’ Docket ID No. EPA–HQ–OAR–2021– 0317, November 2023, (3) The Long-Term Strategy of the United States: Pathways to Net-Zero Greenhouse Gas Emissions by 2050. Published by the U.S. Department of State and the U.S. Executive Office of the President, Washington DC. November 2021, (4) Climate Risk Exposure: An Assessment of the Federal Government’s Financial Risks to Climate Change, White Paper, Office of Management and Budget, April 2022. 
54EPA (2021). Technical Documentation on the 
Framework for Evaluating Damages and Impacts (FrEDI). U.S. Environmental Protection Agency, EPA 430–R–21–004, https://www.epa.gov/cira/ fredi. Documentation has been subject to both a 
public review comment period and an independent 
Continued to melt substantially, sea levels would 
rise dramatically. 
The NCA4 found that it is very likely 
(greater than 90 percent likelihood) that by mid-century, the Arctic Ocean will be almost entirely free of sea ice by late summer for the first time in about 2 million years.
45Coral reefs will be at 
risk for almost complete (99 percent) losses with 1 °C (1.8 °F) of additional 
warming from today (2 °C or 3.6 °F since 
preindustrial). At this temperature, between 8 and 18 percent of animal, plant, and insect species could lose over half of the geographic area with suitable climate for their survival, and 7 to 10 percent of rangeland livestock would be projected to be lost.
46The IPCC 
similarly found that climate change has caused substantial damages and increasingly irreversible losses in terrestrial, freshwater, and coastal and open ocean marine ecosystems. 
Every additional increment of 
temperature comes with consequences. For example, the half degree of warming from 1.5 to 2 °C (0.9 °F of warming from 
2.7°F to 3.6 °F) above preindustrial 
temperatures is projected on a global scale to expose 420 million more people to frequent extreme heatwaves at least every five years, and 62 million more people to frequent exceptional heatwaves at least every five years (where heatwaves are defined based on a heat wave magnitude index which takes into account duration and intensity—using this index, the 2003 French heat wave that led to almost 15,000 deaths would be classified as an ‘‘extreme heatwave’’ and the 2010 Russian heatwave which led to thousands of deaths and extensive wildfires would be classified as ‘‘exceptional’’). It would increase the frequency of sea-ice-free Arctic summers from once in 100 years to once in a decade. It could lead to 4 inches of additional sea level rise by the end of the century, exposing an additional 10 million people to risks of inundation as well as increasing the probability of 
triggering instabilities in either the Greenland or Antarctic ice sheets. Between half a million and a million additional square miles of permafrost would thaw over several centuries. Risks to food security would increase from medium to high for several lower- income regions in the Sahel, southern Africa, the Mediterranean, central Europe, and the Amazon. In addition to food security issues, this temperature increase would have implications for human health in terms of increasing ozone concentrations, heatwaves, and vector-borne diseases (for example, 
expanding the range of the mosquitoes which carry dengue fever, chikungunya, yellow fever, and the Zika virus or the ticks which carry Lyme, babesiosis, or Rocky Mountain Spotted Fever).
47 
Moreover, every additional increment in warming leads to larger changes in extremes, including the potential for events unprecedented in the observational record. Every additional degree will intensify extreme precipitation events by about 7 percent. The peak winds of the most intense tropical cyclones (hurricanes) are projected to increase with warming. In addition to a higher intensity, the IPCC found that precipitation and frequency of rapid intensification of these storms has already increased, the movement speed has decreased, and elevated sea levels have increased coastal flooding, all of which make these tropical cyclones more damaging.
48 
The NCA4 also evaluated a number of 
impacts specific to the U.S. Severe drought and outbreaks of insects like the mountain pine beetle have killed hundreds of millions of trees in the western U.S. Wildfires have burned more than 3.7 million acres in 14 of the 17 years between 2000 and 2016, and Federal wildfire suppression costs were about a billion dollars annually.
49The 
National Interagency Fire Center has documented U.S. wildfires since 1983, and the 10 years with the largest acreage burned have all occurred since 2004.
50 
Wildfire smoke degrades air quality, increasing health risks, and more frequent and severe wildfires due to climate change would further diminish air quality, increase incidences of respiratory illness, impair visibility, and disrupt outdoor activities, sometimes thousands of miles from the location of the fire. Meanwhile, sea level rise has amplified coastal flooding and erosion impacts, requiring the installation of costly pump stations, flooding streets, and increasing storm surge damages. Tens of billions of dollars of U.S. real estate could be below sea level by 2050 under some scenarios. Increased frequency and duration of drought will reduce agricultural productivity in some regions, accelerate depletion of water supplies for irrigation, and expand the distribution and incidence of pests and diseases for crops and livestock. The NCA4 also recognized that climate change can increase risks to national security, both through direct impacts on military infrastructure and by affecting factors such as food and water availability that can exacerbate conflict outside U.S. borders. Droughts, floods, storm surges, wildfires, and other extreme events stress nations and people through loss of life, displacement of populations, and impacts on livelihoods.
51The NCA5 
further reinforces the science showing that climate change will have many impacts on the U.S., as described above in the preamble. Particularly relevant for these rules, the NCA5 states that climate change affects all aspects of the energy system-supply, delivery, and demand-through the increased frequency, intensity, and duration of extreme events and through changing climate trends.’’
52 
EPA modeling efforts can further 
illustrate how these impacts from climate change may be experienced across the U.S. EPA’s Framework for Evaluating Damages and Impacts (FrEDI)
53uses information from over 30 
peer-reviewed climate change impact studies to project the physical and economic impacts of climate change to the U.S. resulting from future temperature changes. These impacts are projected for specific regions within the U.S. and for more than 20 impact 
categories, which span a large number of sectors of the U.S. economy.
54Using 
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expert peer review, following EPA peer-review 
guidelines. 
55Compared to a world with no additional 
warming after the model baseline (1986–2005). 
56Ziska, L., A. Crimmins, A. Auclair, S. DeGrasse, 
J.F. Garofalo, A.S. Khan, I. Loladze, A.A. Pe ´rez de 
Leo´n, A. Showler, J. Thurston, and I. Walls, 2016: 
Ch. 7: Food Safety, Nutrition, and Distribution. The Impacts of Climate Change on Human Health in the United States: A Scientific Assessment. U.S. Global Change Research Program, Washington, DC, 189– 216. https://health2016.globalchange.gov/low/ 
ClimateHealth2016_ 07_Food_ small.pdf. 57WMO (World Meteorological Organization), 
Scientific Assessment of Ozone Depletion: 2018, Global Ozone Research and Monitoring Project— Report No. 58, 588 pp., Geneva, Switzerland, 2018. 58Generation and capacity are commonly 
reported statistics with key distinctions. Generation is the production of electricity and is a measure of an EGU’s actual output while capacity is a measure 
of the maximum potential production of an EGU 
under certain conditions. There are several methods to calculate an EGU’s capacity, which are suited for different applications of the statistic. Capacity is typically measured in megawatts (MW) for individual units or gigawatts (1 GW = 1,000 MW) for multiple EGUs. Generation is often measured in kilowatt-hours (1 kWh = 1,000 watt-hours), megawatt-hours (1 MWh = 1,000 kWh), gigawatt- hours (1 GWh = 1 million kWh), or terawatt-hours (1 TWh = 1 billion kWh). this framework, the EPA estimates that 
global emission projections, with no additional mitigation, will result in significant climate-related damages to the U.S.
55These damages to the U.S. 
would mainly be from increases in lives lost due to increases in temperatures, as well as impacts to human health from increases in climate-driven changes in air quality, dust and wildfire smoke exposure, and incidence of suicide. Additional major climate-related damages would occur to U.S. infrastructure such as roads and rail, as well as transportation impacts and coastal flooding from sea level rise, increases in property damage from tropical cyclones, and reductions in labor hours worked in outdoor settings and buildings without air conditioning. These impacts are also projected to vary from region to region with the Southeast, for example, projected to see some of the largest damages from sea level rise, the West Coast projected to experience damages from wildfire smoke more than other parts of the country, and the Northern Plains states projected to see a higher proportion of damages to rail and road infrastructure. While information on the distribution of climate impacts helps to better understand the ways in which climate change may impact the U.S., recent analyses are still only a partial assessment of climate impacts relevant to U.S. interests and in addition do not reflect increased damages that occur due to interactions between different sectors impacted by climate change or all the ways in which physical impacts of climate change occurring abroad have spillover effects in different regions of the U.S. 
Some GHGs also have impacts beyond 
those mediated through climate change. For example, elevated concentrations of 
CO
2stimulate plant growth (which can 
be positive in the case of beneficial species, but negative in terms of weeds and invasive species, and can also lead to a reduction in plant micronutrients
56) and cause ocean 
acidification. Nitrous oxide depletes the levels of protective stratospheric ozone.
57Methane reacts to form 
tropospheric ozone. 
Section XII.E of this preamble 
discusses the impacts of GHG emissions 
on individuals living in socially and economically vulnerable communities. While the EPA did not conduct modeling to specifically quantify changes in climate impacts resulting from these rules in terms of avoided temperature change or sea-level rise, the Agency did quantify climate benefits by monetizing the emission reductions through the application of the social cost of greenhouse gases (SC–GHGs), as described in section XII.D of this preamble. 
These scientific assessments, the EPA 
analyses, and documented observed changes in the climate of the planet and of the U.S. present clear support regarding the current and future dangers of climate change and the importance of GHG emissions mitigation. 
IV. Recent Developments in Emissions 
Controls and the Electric Power Sector 
In this section, we discuss 
background information about the electric power sector and controls available to limit GHG pollution from the fossil fuel-fired power plants regulated by these final rules, and then discuss several recent developments that are relevant for determining the BSER for these sources. After giving some general background, we first discuss CCS and explain that its costs have fallen significantly. Lower costs are central for the EPA’s determination that CCS is the BSER for certain existing coal-fired steam generating units and certain new natural gas-fired combustion turbines. Second, we discuss natural gas co-firing for coal- fired steam generating units and explain recent reductions in cost for this approach as well as its widespread availability and current and potential deployment within this subcategory. Third, we discuss highly efficient generation as a BSER technology for new and reconstructed simple cycle and combined cycle combustion turbine EGUs. The emission reductions achieved by highly efficient turbines are well demonstrated in the power sector, and along with operational and maintenance best practices, represent a cost-effective technology that reduces fuel consumption. Finally, we discuss key developments in the electric power sector that influence which units can feasibly and cost-effectively deploy 
these technologies. 
A. Background 1. Electric Power Sector 
Electricity in the U.S. is generated by 
a range of technologies, and different 
EGUs play different roles in providing reliable and affordable electricity. For example, certain EGUs generate base load power, which is the portion of electricity loads that are continually present and typically operate throughout all hours of the year. Intermediate EGUs often provide complementary generation to balance variable supply and demand resources. Low load ‘‘peaking units’’ provide capacity during hours of the highest daily, weekly, or seasonal net demand, 
and while these resources have low levels of utilization on an annual basis, they play important roles in providing generation to meet short-term demand and often must be available to quickly increase or decrease their output. Furthermore, many of these EGUs also play important roles ensuring the reliability of the electric grid, including facilitating the regulation of frequency and voltage, providing ‘‘black start’’ capability in the event the grid must be repowered after a widespread outage, and providing reserve generating capacity
58in the event of unexpected 
changes in the availability of other generators. 
In general, the EGUs with the lowest 
operating costs are dispatched first, and, as a result, an inefficient EGU with high fuel costs will typically only operate if other lower-cost plants are unavailable or are insufficient to meet demand. Units are also unavailable during both routine and unanticipated outages, which typically become more frequent as power plants age. These factors result in the mix of available generating capacity types (e.g., the share of 
capacity of each type of generating source) being substantially different than the mix of the share of total electricity produced by each type of generating source in a given season or year. 
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59The three network interconnections are the 
Western Interconnection, comprising the western 
parts of the U.S. and Canada, the Eastern Interconnection, comprising the eastern parts of the U.S. and Canada except parts of Eastern Canada in the Quebec Interconnection, and the Texas Interconnection, encompassing the portion of the Texas electricity system commonly known as the Electric Reliability Council of Texas (ERCOT). See map of all NERC interconnections at https://www.nerc.com/AboutNERC/keyplayers/PublishingImages/NERC%20Interconnections.pdf. 
60For example, PJM Interconnection, LLC, New 
York Independent System Operator (NYISO), Midwest Independent System Operator (MISO), California Independent System Operator (CAISO), etc. 
61For example, Los Angeles Department of Power 
and Water, Florida Power and Light, etc. 62Non-dispatchable renewable energy (electrical 
output cannot be used at any given time to meet fluctuating demand) is both variable and intermittent and is often referred to as intermittent renewable energy. The variability aspect results from predictable changes in electric generation (e.g., solar not generating electricity at night) that often occur on longer time periods. The intermittent aspect of renewable energy results from inconsistent generation due to unpredictable external factors outside the control of the owner/ operator (e.g., imperfect local weather forecasts) 
that often occur on shorter time periods. Since renewable energy fluctuates over multiple time periods, grid operators are required to adjust forecast and real time operating procedures. As more renewable energy is added to the electric grid and generation forecasts improve, the intermittency of renewable energy is reduced. 
63Edison Electric Institute (EEI). (November 18, 
2022). Clean Air Act Section 111 Standards and the 
Power Sector: Considerations and Options for 
Setting Standards and Providing Compliance Flexibility to Units and States. Public comments submitted to the EPA’s pre-proposal rulemaking, Document ID No. EPA–HQ–OAR–2022–0723–0024. Generated electricity must be 
transmitted over networks59of high 
voltage lines to substations where power 
is stepped down to a lower voltage for local distribution. Within each of these transmission networks, there are multiple areas where the operation of power plants is monitored and controlled by regional organizations to ensure that electricity generation and load are kept in balance. In some areas, the operation of the transmission system is under the control of a single regional operator;
60in others, individual 
utilities61coordinate the operations of 
their generation and transmission to balance the system across their respective service territories. 
2. Types of EGUs 
There are many types of EGUs 
including fossil fuel-fired power plants 
(i.e., those using coal, oil, and natural 
gas), nuclear power plants, renewable 
generating sources (such as wind and solar) and others. This rule focuses on the fossil fuel-fired portion of the generating fleet that is responsible for the vast majority of GHG emissions from the power sector. The definition of fossil fuel-fired electric utility steam generating units includes utility boilers as well as those that use gasification technology (i.e., integrated gasification 
combined cycle (IGCC) units). While coal is the most common fuel for fossil fuel-fired utility boilers, natural gas can also be used as a fuel in these EGUs and many existing coal- and oil-fired utility boilers have refueled as natural gas-fired utility boilers. An IGCC unit gasifies fuel—typically coal or petroleum coke— to form a synthetic gas (or syngas) composed of carbon monoxide (CO) and hydrogen (H
2), which can be combusted 
in a combined cycle system to generate power. The heat created by these technologies produces high-pressure steam that is released to rotate turbines, which, in turn, spin an electric generator. Stationary combustion turbine EGUs 
(most commonly natural gas-fired) use 
one of two configurations: combined cycle or simple cycle turbines. Combined cycle units have two generating components (i.e., two cycles) 
operating from a single source of heat. Combined cycle units first generate 
power from a combustion turbine (i.e., the combustion cycle) directly from the heat of burning natural gas or other fuel. The second cycle reuses the waste heat from the combustion turbine engine, which is routed to a heat recovery steam generator (HRSG) that generates steam, which is then used to produce additional power using a steam turbine (i.e., the steam cycle). Combining these 
generation cycles increases the overall efficiency of the system. Combined cycle units that fire mostly natural gas are commonly referred to as natural gas combined cycle (NGCC) units, and, with greater efficiency, are utilized at higher capacity factors to provide base load or intermediate load power. An EGU’s capacity factor indicates a power plant’s electricity output as a percentage of its total generation capacity. Simple cycle turbines only use a combustion turbine to produce electricity (i.e., there is no 
heat recovery or steam cycle). These less-efficient combustion turbines are generally utilized at non-base load capacity factors and contribute to reliable operations of the grid during periods of peak demand or provide flexibility to support increased generation from variable energy sources.
62 
Other generating sources produce 
electricity by harnessing kinetic energy from flowing water, wind, or tides, thermal energy from geothermal wells, or solar energy primarily through photovoltaic solar arrays. Spurred by a combination of declining costs, consumer preferences, and government policies, the capacity of these renewable technologies is growing, and when considered with existing nuclear energy, accounted for 40 percent of the overall net electricity supply in 2022. Many 
projections show this share growing over time. For example, the EPA’s Power Sector Platform 2023 using IPM (i.e., the EPA’s baseline projections of 
the power sector) projects zero-emitting sources reaching 76 percent of electricity generation by 2040. This shift is driven by multiple factors. These factors include changes in the relative economics of generating technologies, the efforts by states to reduce GHG emissions, utility and other corporate commitments, and customer preference. The shift is further promoted by provisions of Federal legislation, most notably the Clean Electricity Investment and Production tax credits included in IRC sections 48E and 45Y of the IRA, which do not begin to phase out until the later of 2032 or when power sector GHG emissions are 75 percent less than 2022 levels. (See section IV.F of this preamble and the accompanying RIA for additional discussion of projections for the power sector.) These projections are consistent with power company announcements. For example, as the Edison Electric Institute (EEI) stated in pre-proposal public comments submitted to the regulatory docket: ‘‘Fifty EEI members have announced forward-looking carbon reduction goals, two-thirds of which include a net-zero by 2050 or earlier equivalent goal, and members are routinely increasing the ambition or speed of their goals or altogether transforming them into net- zero goals ....  EEI’s member 
companies see a clear path to continued emissions reductions over the next decade using current technologies, including nuclear power, natural gas- based generation, energy demand efficiency, energy storage, and deployment of new renewable energy— especially wind and solar—as older coal-based and less-efficient natural gas- based generating units retire.’’
63The 
Energy Strategy Coalition similarly said in public comments that ‘‘[a]s major electrical utilities and power producers, our top priority is providing clean, affordable, and reliable energy to our customers’’ and are ‘‘seeking to advance’’ technologies ‘‘such as a carbon capture and storage, which can significantly reduce carbon dioxide 
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64Energy Strategy Coalition Comments on EPA’s 
proposed New Source Performance Standards for 
Greenhouse Gas Emissions From New, Modified, and Reconstructed Fossil Fuel-Fired Electric Generating Units; Emission Guidelines for Greenhouse Gas Emissions From Existing Fossil Fuel-Fired Electric Generating Units; and Repeal of the Affordable Clean Energy Rule, Document ID No. EPA–HQ–OAR–2023–0072–0672, August 14, 2023. 
65U.S. Environmental Protection Agency (EPA). 
Overview of greenhouse gas emissions. July 2021. https://www.epa.gov/ghgemissions/overview- greenhouse-gases#carbon-dioxide. 
66Natural gas is primarily CH 4, which has a 
higher hydrogen to carbon atomic ratio, relative to other fuels, and thus, produces the least CO
2per 
unit of heat released. In addition to a lower CO 2 
emission rate on a lb/MMBtu basis, natural gas is generally converted to electricity more efficiently than coal. According to EIA, the 2020 emissions rate for coal and natural gas were 2.23 lb CO
2/kWh 
and 0.91 lb CO 2/kWh, respectively. www.eia.gov/ 
tools/faqs/faq.php?id=74&t=11. 
67Values reflect the carbon content on a per unit 
of energy produced on a higher heating value (HHV) combustion basis and are not reflective of recovered useful energy from any particular technology. 
68Energy Information Administration (EIA). 
Carbon Dioxide Emissions Coefficients. https://www.eia.gov/environment/emissions/co2_ vol_
mass.php. 69U.S. Environmental Protection Agency (EPA). 
Inventory of U.S. Greenhouse Gas Emissions and 
Sinks: 1990–2021. https://www.epa.gov/ ghgemissions/inventory-us-greenhouse-gas- emissions-and-sinks-1990-2021. 
70Sinks are a physical unit or process that stores 
GHGs, such as forests or underground or deep-sea reservoirs of carbon dioxide. 
71U.S. Environmental Protection Agency (EPA). 
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990–2021. https://www.epa.gov/ ghgemissions/inventory-us-greenhouse-gas- emissions-and-sinks. 
72Petroleum and natural gas systems include: 
offshore and onshore petroleum and natural gas production; onshore petroleum and natural gas gathering and boosting; natural gas processing; natural gas transmission/compression; onshore 
natural gas transmission pipelines; natural gas local distribution companies; underground natural gas storage; liquified natural gas storage; liquified natural gas import/export equipment; and other petroleum and natural gas systems. 
73U.S. Environmental Protection Agency (EPA). 
Greenhouse Gas Reporting Program. Facility Level Information on Greenhouse Gases Tool (FLIGHT). https://ghgdata.epa.gov/ghgp/main.do# . 74U.S. Energy Information Administration (EIA). 
Preliminary Monthly Electric Generator Inventory, 
Form EIA–860M, November 2023. https://www.eia.gov/electricity/data/eia860m/. 
75U.S. Environmental Protection Agency (EPA). 
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990–2020. https://cfpub.epa.gov/ghgdata/ inventoryexplorer/#electricitygeneration/ entiresector/allgas/category/all. 
76U.S. Energy Information Administration (EIA). 
Monthly Energy Review, table 11.6. September 2022. https://www.eia.gov/totalenergy/data/ 
monthly/pdf/sec11.pdf. emissions from fossil fuel-fired 
EGUs.’’64 
B. GHG Emissions From Fossil Fuel- Fired EGUs 
The principal GHGs that accumulate 
in the Earth’s atmosphere above pre- industrial levels because of human activity are CO
2, CH 4, N2O, HFCs, PFCs, 
and SF 6. Of these, CO 2is the most 
abundant, accounting for 80 percent of all GHGs present in the atmosphere. This abundance of CO
2is largely due to 
the combustion of fossil fuels by the transportation, electricity, and industrial sectors.
65 
The amount of CO 2produced when a 
fossil fuel is burned in an EGU is a function of the carbon content of the fuel relative to the size and efficiency of the EGU. Different fuels emit different amounts of CO
2in relation to the energy 
they produce when combusted. The heat content, or the amount of energy produced when a fuel is burned, is mainly determined by the carbon and hydrogen content of the fuel. For example, in terms of pounds of CO
2 
emitted per million British thermal units of energy produced when combusted, natural gas is the lowest compared to other fossil fuels at 117 lb CO
2/MMBtu.66 67The average for coal is 
216 lb CO 2/MMBtu, but varies between 
206 to 229 lb CO 2/MMBtu by type (e.g., 
anthracite, lignite, subbituminous, and bituminous).
68The value for petroleum 
products such as diesel fuel and heating oil is 161 lb CO
2/MMBtu. 
The EPA prepares the official U.S. 
Inventory of Greenhouse Gas Emissions and Sinks69(the 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 presents total U.S. anthropogenic emissions and sinks
70of GHGs, 
including CO 2emissions since 1990. 
According to the latest inventory of all sectors, in 2021, total U.S. GHG emissions were 6,340 million metric tons of CO
2equivalent (MMT CO 2e).71 
The transportation sector (28.5 percent), which includes approximately 300 million vehicles, was the largest contributor to total U.S. GHG emissions with 1,804 MMT CO
2e followed by the 
power sector (25.0 percent) with 1,584 MMT CO
2e. In fact, GHG emissions from 
the power sector were higher than the GHG emissions from all other industrial sectors combined (1,487 MMT CO
2e). 
Specifically, the power sector’s emissions were far more than petroleum and natural gas systems
72at 301 MMT 
CO 2e; chemicals (71 MMT CO 2e); 
minerals (64 MMT CO 2e); coal mining 
(53 MMT CO 2e); and metals (48 MMT 
CO 2e). The agriculture (636 MMT CO 2e), 
commercial (439 MMT CO 2e), and 
residential (366 MMT CO 2e) sectors 
combined to emit 1,441 MMT CO 2e. 
Fossil fuel-fired EGUs are by far the 
largest stationary source emitters of GHGs in the nation. For example, according to the EPA’s Greenhouse Gas Reporting Program (GHGRP), of the top 100 large facilities that reported facility- level GHGs in 2022, 85 were fossil fuel- fired power plants while 10 were refineries and/or chemical plants, four were metals facilities, and one was a petroleum and natural gas systems facility.
73Of the 85 fossil fuel-fired 
power plants, 81 were primarily coal- fired, including the top 41 emitters of 
CO 2. In addition, of the 81 coal-fired 
plants, 43 have no retirement planned prior to 2039. The top 10 of these plants combined to emit more than 135 MMT of CO
2e, with the top emitter (James H. 
Miller power plant in Alabama) reporting approximately 22 MMT of CO
2e with each of its four EGUs 
emitting between 5 MMT and 6 MMT CO
2e that year. The combined capacity 
of these 10 plants is more than 23 gigawatts (GW), and all except for the Monroe (Michigan) plant operated at annual capacity factors of 50 percent or higher.
74For comparison, the largest 
GHG emitter in the U.S. that is not a fossil fuel-fired power plant is the ExxonMobil refinery and chemical plant in Baytown, Texas, which reported 12.6 MMT CO
2e (No. 6 overall in the nation) 
to the GHGRP in 2022. The largest metals facility in terms of GHG emissions was the U.S. Steel facility in Gary, Indiana, with 10.4 MMT CO
2e 
(No. 16 overall in the nation). 
Overall, CO 2emissions from the 
power sector have declined by 36 percent since 2005 (when the power sector reached annual emissions of 2,400 MMT CO
2, its historical peak to 
date).75The reduction in CO 2emissions 
can be attributed to the power sector’s ongoing trend away from carbon- intensive coal-fired generation and toward more natural gas-fired and renewable sources. In 2005, CO
2 
emissions from coal-fired EGUs alone measured 1,983 MMT.
76This total 
dropped to 1,351 MMT in 2015 and reached 974 MMT in 2019, the first time since 1978 that CO
2emissions from 
coal-fired EGUs were below 1,000 MMT. In 2020, emissions of CO
2from coal- 
fired EGUs measured 788 MMT as the result of pandemic-related closures and reduced utilization before rebounding in 2021 to 909 MMT. By contrast, CO
2 
emissions from natural gas-fired generation have almost doubled since 2005, increasing from 319 MMT to 613 MMT in 2021, and CO
2emissions from 
petroleum products (i.e., distillate fuel 
oil, petroleum coke, and residual fuel oil) declined from 98 MMT in 2005 to 18 MMT in 2021. 
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7780 FR 63662 (October 23, 2015). 78Bottoms, R.R. Process for Separating Acidic 
Gases (1930) United States patent application. 
United States Patent US1783901A; Allen, A.S. and Arthur, M. Method of Separating Carbon Dioxide from a Gas Mixture (1933) United States Patent Application. United States Patent US1934472A. 
79U.S. Department of Transportation, Pipeline 
and Hazardous Material Safety Administration, 
‘‘Hazardous Annual Liquid Data.’’ 2022. https://www.phmsa.dot.gov/data-and-statistics/pipeline/ gas-distribution-gas-gathering-gas-transmission- hazardous-liquids. 
80GHGRP US EPA. https://www.epa.gov/ 
ghgreporting/supply-underground-injection-and- geologic-sequestration-carbon-dioxide . 
81American Petroleum Institute (API). (2024). 
Carbon Capture and Storage: A Low-Carbon Solution to Economy-Wide Greenhouse Gas Emissions Reductions. https://www.api.org/news- policy-and-issues/carbon-capture-storage. 
82Major energy company presidents have made 
similar statements. For example, in 2021, Shell Oil Company president Gretchen H. Watkins testified to Congress that ‘‘Carbon capture and storage is a proven technology,’’ and in 2022, Joe Blommaert, the president of ExxonMobil Low Carbon Solutions, stated that ‘‘Carbon capture and storage is a readily available technology that can play a critical role in helping society reduce greenhouse gas emissions.’’ See https://www.congress.gov/117/meeting/house/ 
114185/witnesses/HHRG-117-GO00-Wstate- WatkinsG-20211028.pdf and https://
corporate.exxonmobil.com/news/news-releases/ 2022/0225_ exxonmobil-to-expand-carbon-capture- 
and-storage-at-labarge-wyoming-facility . 
83Woodall, B. (June 25, 2009). AEP sees carbon 
capture from coal ready by 2015. Reuters. https:// 
www.reuters.com/article/idUSTRE55O6TS/. 84Alstom Power. (June 14, 2011). Alstom Power 
study demonstrates carbon capture and storage 
(CCS) is efficient and cost competitive. https://www.alstom.com/press-releases-news/2011/6/press- releases-3-26. 
85Indiana Michigan Power. (July 14, 2011). AEP 
Places Carbon Capture Commercialization on Hold, Citing Uncertain Status of Climate Policy, Weak Economy. Press release. https://www.indianamichiganpower.com/company/news/ view?releaseID=1206. 
86U.S. Department of Energy (DOE). (2023). 
Pathways to Commercial Liftoff: Carbon Management. https://liftoff.energy.gov/wp-content/ 
uploads/2024/02/20230424-Liftoff-Carbon- Management-vPUB_ update4.pdf. When the EPA finalized the Clean 
Power Plan (CPP) in October 2015, the 
Agency projected that, as a result of the CPP, the power sector would reduce its annual CO
2emissions to 1,632 MMT by 
2030, or 32 percent below 2005 levels (2,400 MMT).
77Instead, even in the 
absence of Federal regulations for existing EGUs, annual CO
2emissions 
from sources covered by the CPP had fallen to 1,540 MMT by the end of 2021, a nearly 36 percent reduction below 2005 levels. The power sector achieved a deeper level of reductions than forecast under the CPP and approximately a decade ahead of time. By the end of 2015, several months after the CPP was finalized, those sources already had achieved CO
2emission 
levels of 1,900 MMT, or approximately 21 percent below 2005 levels. However, progress in emission reductions is not uniform across all states and is not guaranteed to continue, therefore Federal policies play an essential role. As discussed earlier in this section, the power sector remains a leading emitter of CO
2in the U.S., and, despite the 
emission reductions since 2005, current CO
2levels continue to endanger human 
health and welfare. Further, as sources in other sectors of the economy turn to electrification to decarbonize, future CO
2reductions from fossil fuel-fired 
EGUs have the potential to take on added significance and increased 
benefits. 
C. Recent Developments in Emissions 
Control 
This section of the preamble describes 
recent developments in GHG emissions control in general. Details of those controls in the context of BSER determination are provided in section VII.C.1.a for CCS on coal-fired steam generating units, section VII.C.2.a for natural gas co-firing on coal-fired steam generating units, section VIII.F.2.b for efficient generation on natural gas-fired combustion turbines, and section VIII.F.4.c.iv for CCS on natural gas-fired combustion turbines. Further details of the control technologies are available in the final TSDs, GHG Mitigation Measures for Steam Generating Units and GHG Mitigation Measures—CCS for 
Combustion Turbines, available in the docket for these actions. 
1. CCS 
One of the key GHG reduction 
technologies upon which the BSER 
determinations are founded in these final rules is CCS—a technology that can capture and permanently store CO
2 
from fossil fuel-fired EGUs. CCS has three major components: CO 2capture, 
transportation, and sequestration/ 
storage. Solvent-based CO 2capture was 
patented nearly 100 years ago in the 1930s
78and has been used in a variety 
of industrial applications for decades. Thousands of miles of CO
2pipelines 
have been constructed and securely operated in the U.S. for decades.
79And 
tens of millions of tons of CO 2have 
been permanently stored deep underground either for geologic sequestration or in association with enhanced oil recovery (EOR).
80The 
American Petroleum Institute (API) explains that ‘‘CCS is a proven technology’’ and that ‘‘[t]he methods that apply to [the] carbon sequestration process are not novel. The U.S. has more than 40 years of CO
2gas injection 
and storage experience. During the last 40 years the U.S. gas and oil industry’s (EOR) enhanced oil recovery operations) have injected more than 1 billion tonnes of CO
2.’’81 82 
In 2009, Mike Morris, then-CEO of 
American Electric Power (AEP), was interviewed by Reuters and the article noted that Morris’s ‘‘companies’ work in West Virginia on [CCS] gave [Morris] more insight than skeptics who doubt the technology.’’ In that interview, Morris explained, ‘‘I’m convinced it will be primetime ready by 2015 and deployable.’’
83In 2011, Alstom Power, 
the company that developed the 30 MW pilot project upon which Morris had based his conclusions, reiterated the 
claim that CCS would be commercially available in 2015. A press release from Alstom Power stated that, based on the results of Alstom’s ‘‘13 pilot and demonstration projects and validated by independent experts . . . we can now be confident that CCS works and is cost effective . . . and will be available at a commercial scale in 2015 and will allow [plants] to capture 90% of the emitted CO
2.’’ The press release went on to note 
that ‘‘the same conclusion applies for a 
gas plant using CCS.’’84 
In 2011, however, AEP determined 
that the economic and regulatory 
environment at the time did not support further development of the technology. After canceling a large-scale commercial project, Morris explained, ‘‘as a regulated utility, it is impossible to gain regulatory approval to cover our share of the costs for validating and deploying the technology without federal requirements to reduce greenhouse gas emissions already in place.’’
85 
Thirteen years later, the situation is 
fundamentally different. Since 2011, the technological advances from full-scale deployments (e.g., the Petra Nova and 
Boundary Dam projects discussed later in this preamble) combined with supportive policies in multiple states and the financial incentives included in the IRA, mean that CCS can be deployed at scale today. In addition to applications at fossil fuel-fired EGUs, installation of CCS is poised to dramatically increase across a range of industries in the coming years, including ethanol production, natural gas processing, and steam methane reformers.
86Many of the CCS projects 
across these industries, including capture systems, pipelines, and sequestration, are already in operation or are in advanced stages of deployment. There are currently at least 15 operating CCS projects in the U.S., and another 121 that are under 
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87Congressional Budget Office (CBO). (December 
13, 2023). Carbon Capture and Storage in the United 
States. https://www.cbo.gov/publication/59345 . 
88Global CCS Institute. (March 2021). Technology 
Readiness and Costs of CCS. https://www.globalccsinstitute.com/wp-content/uploads/ 2021/03/Technology-Readiness-and-Costs-for-CCS- 2021-1.pdf. 
89Willis, A. (May 12, 2021). Gov. Doug Burgum 
calls for North Dakota to be carbon neutral by 2030. The Dickinson Press. https://www.thedickinsonpress.com/business/gov-doug- burgum-calls-for-north-dakota-to-be-carbon- neutral-by-2030. 
90Tanaka, H. et al. Advanced KM CDR Process 
using New Solvent. 14th International Conference on Greenhouse Gas Control Technologies, GHGT– 14. https://www.cfaenm.org/wp-content/uploads/ 2019/03/GHGT14_ manuscript_ 20180913Clean- 
version.pdf. 
91Minot Daily News. (April 8, 2024). Hoeven: ND 
to lead country with carbon capture project at Coal Creek Station. https://minotdailynews.com/news/ local-news/2021/07/hoeven-nd-to-lead-country- with-carbon-capture-project-at-coal-creek-station/. 
92Rainbow Energy Center. (ND). Carbon Capture. 
https://rainbowenergycenter.com/what-we-do/ carbon-capture/. 
93PacifiCorp. (April 1, 2024). 2023 Integrated 
Resource Plan Update. https://www.pacificorp.com/ content/dam/pcorp/documents/en/pacificorp/ energy/integrated-resource-plan/2023_ IRP_
Update.pdf. 
94Rocky Mountain Power. (April 1, 2024). Rocky 
Mountain Power and 8 Rivers to collaborate on proposed Wyoming carbon capture project. Press release. https://www.rockymountainpower.net/ 
about/newsroom/news-releases/rmp-proposed- wyoming-carbon-capture-project.html. 95Competitive Power Ventures (CPV). Shay Clean 
Energy Center. https://www.cpv.com/our-projects/ cpv-shay-energy-center/. 
96The Associated Press (AP). (August 30, 2023). 
New owner restarts West Virginia coal-fired power plant and intends to convert it to hydrogen use. https://apnews.com/article/west-virginia-power- plant-coal-hydrogen-7b46798c8e3b093a8591f25f66340e8f. 
97omnigenglobal.com. 
98U.S. Energy Information Administration (EIA). 
(October 2023). Annual Coal Report 2022. https:// 
www.eia.gov/coal/annual/pdf/acr.pdf. 
99National Energy Technology Laboratory 
(NETL). Large Pilot Carbon Capture Project Supported by NETL Breaks Ground in Illinois. https://netl.doe.gov/node/12284. construction or in advanced stages of 
development.87 
Process improvements learned from 
earlier deployments of CCS, the availability of better solvents, and other advances have decreased the costs of CCS in recent years. As a result, the cost of CO
2capture, excluding any tax 
credits, from coal-fired power generation is projected to fall by 50 percent by 2025 compared to 2010.
88 
The IRA makes additional and significant reductions in the cost of implementing CCS by extending and increasing the tax credit for CO
2 
sequestration under IRC section 45Q. 
With this combination of polices, and 
the advances related to CO 2capture, 
multiple projects consistent with the emission reduction requirements of a 90 percent capture amine based BSER are in advanced stages of development. These projects use a wider range of technologies, and some of them are being developed as first-of-a-kind projects and offer significant advantages over the amine-based CCS technology that the EPA is finalizing as BSER. 
For instance, in North Dakota, 
Governor Doug Burgum announced a goal of becoming carbon neutral by 2030 while retaining the core position of its fossil fuel industries, and to do so by significant CCS implementation. Gov. Burgum explained, ‘‘This may seem like a moonshot goal, but it’s actually not. It’s actually completely doable, even with the technologies that we have today.’’
89Companies in the state are 
backing up this claim with projects in 
multiple industries in various stages of operation and development. In the power sector, two of the biggest projects under development are Project Tundra and Coal Creek. Project Tundra is a carbon capture project on Minnkota Power’s 705 MW Milton R Young Power Plant in Oliver County, North Dakota. Mitsubishi Heavy Industries will be providing an advanced version of its carbon capture equipment that builds upon the lessons learned from the Petra Nova project.
90Rainbow Energy is developing the project at the Coal Creek Station, located in McLean, North Dakota. Notably, Rainbow Energy purchased the 1,150 MW Coal Creek Station with a business model of installing CCS based on the IRC section 45Q tax credit of $50/ton that existed at the time (the IRA has since increased the amount to $85/ton).
91Rainbow 
Energy explains, ‘‘CCUS technology has been proven and is an economical option for a facility like Coal Creek Station. We see CCUS as the best way to manage emissions at our facility.’’
92 
While North Dakota has encouraged 
CCS on coal-fired power plants without specific mandates, Wyoming is taking a different approach. Senate Bill 42, enacted in 2024, requires utilities to generate a specified percentage of their electricity using coal-fired power plants with CCS. SB 42 updates HB 200, enacted in 2020, which required the CCS to be installed by 2030, which SB 42 extends to 2033. To comply with those requirements, PacificCorp has stated in its 2023 IRP that it intends to install CCS on two coal-fired units by 2028.
93Rocky Mountain Power has also 
announced that it will explore a new carbon capture technology at either its David Johnston plant or its Wyodak plant.
94Another CCS project is also 
under development at the Dry Fork Power Plant in Wyoming. Currently, a pilot project that will capture 150 tons of CO
2per day is under construction 
and is scheduled to be completed in late 2024. Work has also begun on a full- scale front end engineering design (FEED) study. 
Like North Dakota, West Virginia does 
not have a carbon capture mandate, but there are several carbon capture projects under development in the state. One is a new, 2,000 MW natural gas combined cycle plant being developed by Competitive Power Ventures that will capture 90–95 percent of the CO
2using 
GE turbine and carbon capture technology.95A second is an Omnis 
Fuel Technologies project to convert the coal-fired Pleasants Power Station to run on hydrogen.
96Omnis intends to 
use a pyrolysis-based process to convert coal into hydrogen and graphite. Because the graphite is a usable, solid form of carbon, no CO
2sequestration 
will be required. Therefore, unlike more traditional amine-based approaches, instead of the captured CO
2being a cost, 
the graphite product will provide a revenue stream.
97Omnis states that the 
Pleasants Power Project broke ground in August 2023 and will be online by 2025. 
It should be noted that Wyoming, 
West Virginia, and North Dakota represented the first-, second-, and seventh-largest coal producers, respectively, in the U.S. in 2022.
98 
In addition to the coal-based CCS 
projects mentioned above, multiple other projects are in advanced stages of development and/or have completed FEED studies. For instance, Linde/BASF is installing a 10 MW pilot project on the Dallman Power Plant in Illinois. Based on results from small scale pilot studies, techno economic analysis indicates that the Linde/BASF process can provide a significant reduction in capital costs compared to the NETL base case for a supercritical pulverized coal plant with carbon capture.’’
99Multiple 
other FEED studies are either completed or under development, putting those projects on a path to being able to be built and to commence operation well before January 1, 2032. 
In addition to the Competitive Power 
Partners project, there are multiple post- combustion CCS retrofit projects in various stages of development. In particular, NET Power is in advanced stages of development on a 300 MW project in west Texas using the Allam- Fetvedt cycle, which is being designed to achieve greater than 97 percent CO
2 
capture. In addition to working on this first project, NET Power has indicated that it has an additional project under development and is working with 
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100Net Power. (March 11, 2024). Q4 2023 
Business Update and Results. https://
d1io3yog0oux5.cloudfront.net/_cde4aad258e20f5aec49abd8654499f8/netpower/db/ 3583/33195/pdf/Q4_ 2023+Earnings+Presentation_
3.11.24.pdf. 
101U.S. Energy Information Administration (EIA). 
Form 923. https://www.eia.gov/electricity/data/ eia923/. 
102U.S. Environmental Protection Agency (EPA). 
‘‘Power Sector Emissions Data.’’ Washington, DC: Office of Atmospheric Protection, Clean Air Markets Division. https://campd.epa.gov . 103U.S. Energy Information Administration (EIA). 
(5 August 2020). Today in Energy. More than 100 coal-fired plants have been replaced or converted to natural gas since 2011. https://www.eia.gov/ todayinenergy/detail.php?id=44636. suppliers to support additional future 
projects.100 
In developing these final rules, the 
EPA reviewed the current state and cost of CCS technology for use with both steam generating units and stationary combustion turbines. This review is reflected in the respective BSER discussions later in this preamble and is further detailed in the accompanying RIA and final TSDs, GHG Mitigation Measures for Steam Generating Units and GHG Mitigation Measures—Carbon 
Capture and Storage for Combustion Turbines. These documents are 
included in the rulemaking docket. 
2. Natural Gas Co-Firing 
For a coal-fired steam generating unit, 
the substitution of natural gas for some 
of the coal so that the unit fires a combination of coal and natural gas is known as ‘‘natural gas co-firing.’’ Existing coal-fired steam generating 
units can be modified to co-fire natural gas in any desired proportion with coal. Generally, the modification of existing boilers to enable or increase natural gas firing involves the installation of new gas burners and related boiler modifications and may involve the construction of a natural gas supply pipeline if one does not already exist. In recent years, the cost of natural gas co- firing has declined because the expected difference between coal and gas prices has decreased and analysis supports lower capital costs for modifying existing boilers to co-fire with natural gas, as discussed in section VII.C.2.a of this preamble. 
It is common practice for steam 
generating units to have the capability to burn multiple fuels onsite, and of the 565 coal-fired steam generating units operating at the end of 2021, 249 of them reported use of natural gas as a primary fuel or for startup.
101Based on 
hourly reported CO 2emission rates from 
the start of 2015 through the end of 2020, 29 coal-fired steam generating units co-fired with natural gas at rates at or above 60 percent of capacity on an hourly basis.
102The capability of those 
units on an hourly basis is indicative of the extent of boiler burner modifications and sizing and capacity of natural gas pipelines to those units, and it implies that those units are technically capable of co-firing at least 60 percent natural gas on a heat input basis on average over the course of an extended period (e.g., a year). Additionally, many coal-fired steam generating EGUs have also opted to switch entirely to providing generation from the firing of natural gas. Since 2011, more than 80 coal-fired utility boilers have been converted to natural gas-fired utility boilers.
103 
In developing these final actions, the 
EPA reviewed in detail the current state of natural gas co-firing technology and costs. This review is reflected in the BSER discussions later in this preamble and is further detailed in the accompanying RIA and final TSD, GHG Mitigation Measures for Steam Generating Units. Both documents are included in the rulemaking docket. 
3. Efficient Generation 
Highly efficient generation is the 
BSER technology upon which the first 
phase standards of performance are based for certain new and reconstructed stationary combustion turbine EGUs. This technology is available for both simple cycle and combined cycle combustion turbines and has been demonstrated—along with best operating and maintenance practices— to reduce emissions. Generally, as the thermal efficiency of a combustion turbine increases, less fuel is burned per gross MWh of electricity produced and there is a corresponding decrease in CO
2 
and other air emissions. 
For simple cycle turbines, 
manufacturers continue to improve the efficiency by increasing firing temperature, increasing pressure ratios, using intercooling on the air compressor, and adopting other measures. Best operating practices for simple cycle turbines include proper maintenance of the combustion turbine flow path components and the use of inlet air cooling to reduce efficiency losses during periods of high ambient temperatures. For combined cycle turbines, a highly efficient combustion turbine engine is matched with a high- efficiency HRSG. High efficiency also includes, but is not limited to, the use of the most efficient steam turbine and minimizing energy losses using insulation and blowdown heat recovery. Best operating and maintenance practices include, but are not limited to, minimizing steam leaks, minimizing air infiltration, and cleaning and 
maintaining heat transfer surfaces. 
As discussed in section VIII.F.2.b of 
this preamble, efficient generation 
technologies have been in use at facilities in the power sector for decades and the levels of efficiency that the EPA is finalizing in this rule have been achieved by many recently constructed turbines. The efficiency improvements are incremental in nature and do not change how the combustion turbine is operated or maintained and present little incremental capital or compliance costs compared to other types of technologies that may be considered for new and reconstructed sources. In addition, more efficient designs have lower fuel costs, which offset at least a portion of the increase in capital costs. For additional discussion of this BSER technology, see the final TSD, Efficient 
Generation in Combustion Turbines in the docket for this rulemaking. 
Efficiency improvements are also 
available for fossil fuel-fired steam generating units, and as discussed further in section VII.D.4.a, the more efficiently an EGU operates the less fuel it consumes, thereby emitting lower amounts of CO
2and other air pollutants 
per MWh generated. Efficiency improvements for steam generating EGUs include a variety of technology upgrades and operating practices that may achieve CO
2emission rate 
reductions of 0.1 to 5 percent for 
individual EGUs. These reductions are small relative to the reductions that are achievable from natural gas co-firing and from CCS. Also, as efficiency increases, some facilities could increase their utilization and therefore increase their CO
2emissions (as well as 
emissions of other air pollutants). This 
phenomenon is known as the ‘‘rebound effect.’’ Because of this potential for perverse GHG emission outcomes resulting from deployment of efficiency measures at certain steam generating units, coupled with the relatively minor overall GHG emission reductions that would be expected, the EPA is not finalizing efficiency improvements as the BSER for any subcategory of existing coal-fired steam generating units. Specific details of efficiency measures are described in the final TSD, GHG Mitigation Measures for Steam Generating Units, and an updated 2023 Sargent and Lundy HRI report (Heat Rate Improvement Method Costs and Limitations Memo), available in the docket. 
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104U.S. Energy Information Administration (EIA). 
(7 February 2023). Today in Energy. Coal and 
natural gas plants will account for 98 percent of U.S. capacity retirements in 2023. https://www.eia.gov/todayinenergy/detail.php?id=55439. 105U.S. Energy Information Administration (EIA). 
Monthly Energy Review and Short-Term Energy 
Outlook, March 2016. https://www.eia.gov/ todayinenergy/detail.php?id=25392. 
106U.S. Energy Information Administration (EIA). 
Electric Power Monthly, March 2024. https://
www.eia.gov/electricity/monthly/current_ month/ 
march2024.pdf. 107U.S. Department of Energy (DOE). August 
2022. The Inflation Reduction Act Drives 
Significant Emissions Reductions and Positions 
America to Reach Our Climate Goals. https://www.energy.gov/sites/default/files/2022-08/ 8.18%20InflationReductionAct_ Factsheet_
Final.pdf. 
108U.S. Department of Energy (DOE). August 
2023. Investing in American Energy. Significant Impacts of the Inflation Reduction Act and Bipartisan Infrastructure Law on the U.S. Energy Economy and Emissions Reductions. https://www.energy.gov/sites/default/files/2023-08/ DOE%20OP%20Economy%20Wide%20Report_0.pdf. 
109U.S. Energy Information Administration (EIA). 
Annual Energy Review, table 8.2b Electricity net generation: electric power sector. https://www.eia.gov/totalenergy/data/annual/. D. The Electric Power Sector: Trends 
and Current Structure 
1. Overview 
The electric power sector is 
experiencing a prolonged period of 
transition and structural change. Since the generation of electricity from coal- fired power plants peaked nearly two decades ago, the power sector has changed at a rapid pace. Today, natural gas-fired power plants provide the largest share of net generation, coal-fired power plants provide a significantly smaller share than in the recent past, renewable energy provides a steadily increasing share, and as new technologies enter the marketplace, power producers continue to replace aging assets—especially coal-fired 
power plants—with more efficient and lower-cost alternatives. 
These developments have significant 
implications for the types of controls that the EPA determined to qualify as the BSER for different types of fossil fuel-fired EGUs. For example, power plant owners and operators retired an average annual coal-fired EGU capacity of 10 GW from 2015 to 2023, and coal- fired EGUs comprised 58 percent of all retired capacity in 2023.
104While use of 
CCS promises significant emissions reduction from fossil fuel-fired sources, it requires substantial up-front capital expenditure. Therefore, it is not a feasible or cost-reasonable emission reduction technology for units that intend to cease operation before they would be able to amortize its costs. Industry stakeholders requested that the EPA structure these rules to avoid imposing costly control obligations on coal-fired power plants that have announced plans to voluntarily cease operations, and the EPA has determined the BSER in accordance with its understanding of which coal-fired units will be able to feasibly and cost- effectively deploy the BSER technologies. In addition, the EPA recognizes that utilities and power plant operators are building new natural gas- fired combustion turbines with plans to operate them at varying levels of utilization, in coordination with other existing and expected new energy sources. These patterns of operation are important for the type of controls that the EPA is finalizing as the BSER for these turbines. 2. Broad Trends Within the Power 
Sector 
For more than a decade, the power 
sector has been experiencing substantial transition and structural change, both in terms of the mix of generating capacity and in the share of electricity generation supplied by different types of EGUs. These changes are the result of multiple factors, including normal replacements of older EGUs; technological improvements in electricity generation from both existing and new EGUs; changes in the prices and availability of different fuels; state and Federal policy; the preferences and purchasing behaviors of end-use electricity consumers; and substantial growth in electricity generation from renewable sources. 
One of the most important 
developments of this transition has been the evolving economics of the power sector. Specifically, as discussed in section IV.D.3.b of this preamble and in the final TSD, Power Sector Trends, the existing fleet of coal-fired EGUs continues to age and become more costly to maintain and operate. At the same time, natural gas prices have held relatively low due to increased supply, and renewable costs have fallen rapidly with technological improvement and growing scale. Natural gas surpassed coal in monthly net electricity generation for the first time in April 2015, and since that time natural gas has maintained its position as the primary fuel for base load electricity generation, for peaking applications, and for balancing renewable generation.
105In 
2023, generation from natural gas was more than 2.5 times as much as generation from coal.
106Additionally, 
there has been increased generation from investments in zero- and low-GHG emission energy technologies spurred by technological advancements, declining costs, state and Federal policies, and most recently, the IIJA and the IRA. For example, the IIJA provides investments and other policies to help commercialize, demonstrate, and deploy technologies such as small modular nuclear reactors, long-duration energy storage, regional clean hydrogen hubs, CCS and associated infrastructure, advanced geothermal systems, and advanced distributed energy resources (DER) as well as more traditional wind, solar, and battery energy storage resources. The IRA provides numerous tax and other incentives to directly spur deployment of clean energy technologies. Particularly relevant to these final actions, the incentives in the IRA,
107 108 which are discussed in detail 
later in this section of the preamble, support the expansion of technologies, such as CCS, that reduce GHG emissions from fossil-fired EGUs. 
The ongoing transition of the power 
sector is illustrated by a comparison of data between 2007 and 2022. In 2007, the year of peak coal generation, approximately 72 percent of the electricity provided to the U.S. grid was produced through the combustion of fossil fuels, primarily coal and natural gas, with coal accounting for the largest single share. By 2022, fossil fuel net generation was approximately 60 
percent, less than the share in 2007 despite electricity demand remaining relatively flat over this same period. Moreover, the share of generation supplied by coal-fired EGUs fell from 49 percent in 2007 to 19 percent in 2022 while the share supplied by natural gas- fired EGUs rose from 22 to 39 percent during the same period. In absolute terms, coal-fired generation declined by 59 percent while natural gas-fired generation increased by 88 percent. This reflects both the increase in natural gas capacity as well as an increase in the utilization of new and existing natural gas-fired EGUs. The combination of wind and solar generation also grew from 1 percent of the electric power sector mix in 2007 to 15 percent in 2022.
109 
Additional analysis of the utility 
power sector, including projections of future power sector behavior and the impacts of these final rules, is discussed in more detail in section XII of this preamble, in the accompanying RIA, and in the final TSD, Power Sector Trends. The latter two documents are 
available in the rulemaking docket. Consistent with analyses done by other energy modelers, the information 
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110U.S. Energy Information Administration (EIA). 
Short Term Energy Outlook, December 2023. 
111U.S. Energy Information Administration (EIA). 
(February 15, 2024). Today in Energy. Solar and 
Battery Storage to make up 81% of new U.S. Electric-generating capacity in 2024. https://www.eia.gov/todayinenergy/detail.php?id=61424. 
112U.S. Energy Information Administration (EIA). 
Today in Energy. Natural gas and renewables make up most of 2018 electric capacity additions. https:// 
www.eia.gov/todayinenergy/detail.php?id=36092. 
113U.S. Energy Information Administration (EIA). 
Today in Energy. Natural gas expected to surpass coal in mix of fuel used for U.S. power generation in 2016. March 2016. https://www.eia.gov/ todayinenergy/detail.php?id=25392. 114U.S. Energy Information Administration (EIA). 
Electric Generators Inventory, Form EIA–860M, Inventory of Operating Generators and Inventory of Retired Generators, March 2022. https://www.eia.gov/electricity/data/eia860m/. 
115U.S. Energy Information Administration (EIA). 
Today in Energy. More than 100 coal-fired plants have been replaced or converted to natural gas since 2011. August 2020. https://www.eia.gov/ todayinenergy/detail.php?id=44636. 
116This includes generating capacity at EGUs 
primarily operated to supply electricity to the grid and combined heat and power (CHP) facilities classified as Independent Power Producers and excludes generating capacity at commercial and industrial facilities that does not operate primarily as an EGU. Natural gas information reflects data for all generating units using natural gas as the primary fossil heat source unless otherwise stated. This includes combined cycle, simple cycle, steam, and miscellaneous (<1 percent). 
117U.S. Energy Information Administration (EIA). 
Electric Power Annuals 2010 (Tables 1.1.A and 1.1.B) and 2022 (Tables 4.2.A and 4.2.B). 118U.S. Environmental Protection Agency. 
National Electric Energy Data System (NEEDS) v7. December 2023. https://www.epa.gov/power-sector- modeling/national-electric-energy-data-system- needs. 
119U.S. Energy Information Administration (EIA). 
Electric Power Annual 2021, table 1.2. 
120U.S. Energy Information Administration (EIA). 
U.S. coal plant retirements linked to plants with higher operating costs. December 2019. https://www.eia.gov/todayinenergy/detail.php?id=42155. 
121eGRID 2020 (January 2022 release from EPA 
eGRID website). Represents data from generators that came online between 1950 and 2020 (inclusive); a 71-year period. Full eGRID data includes generators that came online as far back as 1915. 
122U.S. Energy Information Administration (EIA). 
Electric Generators Inventory, Form–860M, Inventory of Operating Generators and Inventory of Retired Generators. August 2022. https://www.eia.gov/electricity/data/eia860m/. provided in the RIA and TSD 
demonstrates that the sector trend of moving away from coal-fired generation is likely to continue, the share from natural gas-fired generation is projected to decline eventually, and the share of generation from non-emitting technologies is likely to continue increasing. For instance, according to the Energy Information Administration (EIA), the net change in solar capacity has been larger than the net change in capacity for any other source of electricity for every year since 2020. In 2024, EIA projects that the actual increase in generation from solar will exceed every other source of generating capacity. This is in part because of the large amounts of new solar coming online in 2024 but is also due to the large amount of energy storage coming online, which will help reduce renewable curtailments.
110EIA also 
projects that in 2024, the U.S. will see 
its largest year for installation of both solar and battery storage. Specifically, EIA projects that 36.4 GW of solar will be added, nearly doubling last year’s record of 18.4 GW. Similarly, EIA projects 14.3 GW of new energy storage. This would more than double last year’s record installation of 6.4 GW and nearly double the existing total capacity of 15.5 GW. This compares to only 2.5 GW of new natural gas turbine capacity.
111The 
only year since 2013 when renewable generation did not make up the majority of new generation capacity in the U.S. was 2018.
112 
3. Coal-Fired Generation: Historical Trends and Current Structure 
a. Historical Trends in Coal-Fired 
Generation 
Coal-fired steam generating units have 
historically been the nation’s foremost source of electricity, but coal-fired generation has declined steadily since its peak approximately 20 years ago.
113 
Construction of new coal-fired steam generating units was at its highest between 1967 and 1986, with approximately 188 GW (or 9.4 GW per year) of capacity added to the grid during that 20-year period.
114The peak 
annual capacity addition was 14 GW, 
which was added in 1980. These coal- fired steam generating units operated as base load units for decades. However, beginning in 2005, the U.S. power sector—and especially the coal-fired fleet—began experiencing a period of transition that continues today. Many of the older coal-fired steam generating units built in the 1960s, 1970s, and 1980s have retired or have experienced significant reductions in net generation due to cost pressures and other factors. Some of these coal-fired steam generating units repowered with combustion turbines and natural gas.
115 
With no new coal-fired steam generating units larger than 25 MW commencing construction in the past decade—and with the EPA unaware of any plans being approved to construct a new coal- fired EGU—much of the fleet that remains is aging, expensive to operate and maintain, and increasingly uncompetitive relative to other sources of generation in many parts of the country. 
Since 2007, the power sector’s total 
installed net summer capacity
116has 
increased by 167 GW (17 percent) while coal-fired steam generating unit capacity has declined by 123 GW.
117This 
reduction in coal-fired steam generating unit capacity was offset by a net increase in total installed wind capacity of 125 GW, net natural gas capacity of 110 GW, and a net increase in utility- scale solar capacity of 71 GW during the 
same period. Additionally, significant amounts (40 GW) of DER solar were also added. At least half of these changes were in the most recent 7 years of this period. From 2015 to 2022, coal capacity was reduced by 90 GW and this reduction in capacity was offset by a net increase of 69 GW of wind capacity, 63 GW of natural gas capacity, and 59 GW of utility-scale solar capacity. 
Additionally, a net summer capacity of 30 GW of DER solar were added from 
2015 to 2022. 
b. Current Structure of Coal-Fired 
Generation 
Although much of the fleet of coal- 
fired steam generating units has historically operated as base load, there can be notable differences in design and operation across various facilities. For example, coal-fired steam generating units smaller than 100 MW comprise 18 percent of the total number of coal-fired units, but only 2 percent of total coal- fired capacity.
118Moreover, average 
annual capacity factors for coal-fired 
steam generating units have declined from 74 to 50 percent since 2007.
119 
These declining capacity factors 
indicate that a larger share of units are operating in non-base load fashion largely because they are no longer cost- competitive in many hours of the year. 
Older power plants also tend to 
become uneconomic over time as they become more costly to maintain and operate,
120especially when competing 
for dispatch against newer and more efficient generating technologies that have lower operating costs. The average coal-fired power plant that retired between 2015 and 2022 was more than 50 years old, and 65 percent of the remaining fleet of coal-fired steam generating units will be 50 years old or more within a decade.
121To further 
illustrate this trend, the existing coal- fired steam generating units older than 40 years represent 71 percent (129 GW)
122of the total remaining capacity. 
In fact, more than half (100 GW) of the coal-fired steam generating units still operating have already announced retirement dates prior to 2039 or conversion to gas-fired units by the 
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123U.S. Environmental Protection Agency. 
National Electric Energy Data System (NEEDS) v6. 
October 2022. https://www.epa.gov/power-sector- modeling/national-electric-energy-data-system- needs. 
124U.S. Energy Information Administration (EIA). 
(October 2023). Annual Coal Report 2022. https:// 
www.eia.gov/coal/annual/pdf/acr.pdf. 
125U.S. Energy Information Administration (EIA). 
U.S. CO 2emissions from energy consumption by 
source and sector, 2022. https://www.eia.gov/ 
totalenergy/data/monthly/pdf/flow/CO2_ emissions_
2022.pdf. 
126U.S. Energy Information Administration (EIA). 
Electric Generators Inventory, Form EIA–860M, Inventory of Operating Generators and Inventory of Retired Generators, July 2022. https://www.eia.gov/ electricity/data/eia860m/. 127National Electric Energy Data System (NEEDS) 
v.6. 
128U.S. Energy Information Administration (EIA). 
Natural Gas Annual, September 2021. https://
www.eia.gov/energyexplained/natural-gas/ prices.php. 129https://www.congress.gov/bill/117th-congress/ 
house-bill/3684/text. 
130https://www.whitehouse.gov/wp-content/ 
uploads/2022/05/BUILDING-A-BETTER-AMERICA- V2.pdf. 
131https://www.congress.gov/bill/117th-congress/ 
house-bill/5376/text. same year.123As discussed later in this 
section, projections anticipate that this 
trend will continue. 
The reduction in coal-fired generation 
by electric utilities is also evident in data for annual U.S. coal production, which reflects reductions in international demand as well. In 2008, annual coal production peaked at nearly 1,172 million short tons (MMst) followed by sharp declines in 2015 and 2020.
124In 2015, less than 900 MMst 
were produced, and in 2020, the total dropped to 535 MMst, the lowest output since 1965. Following the pandemic, in 2022, annual coal production had increased to 594 MMst. For additional analysis of the coal-fired steam generation fleet, see the final TSD, Power Sector Trends included in the docket for this rulemaking. 
Notwithstanding these trends, in 
2022, coal-fired energy sources were still responsible for 50 percent of CO
2 
emissions from the electric power sector.
125 
4. Natural Gas-Fired Generation: Historical Trends and Current Structure 
a. Historical Trends in Natural Gas- 
Fired Generation 
There has been significant expansion 
of the natural gas-fired EGU fleet since 2000, coinciding with efficiency improvements of combustion turbine technologies, increased availability of natural gas, increased demand for flexible generation to support the expanding capacity of variable energy resources, and declining costs for all three elements. According to data from EIA, annual capacity additions for natural gas-fired EGUs peaked between 2000 and 2006, with more than 212 GW added to the grid during this period (about 35 GW per year). Of this total, approximately 147 GW (70 percent) were combined cycle capacity and 65 GW were simple cycle capacity.
126From 
2007 to 2022, more than 132 GW of capacity were constructed and approximately 77 percent of that total were combined cycle EGUs. This figure represents an average of almost 8.8 GW 
of new combustion turbine generation capacity per year. In 2022, the net summer capacity of combustion turbine EGUs totaled 419 GW, with 289 GW being combined cycle generation and 130 GW being simple cycle generation. 
This trend away from electricity 
generation using coal-fired EGUs to 
natural gas-fired turbine EGUs is also reflected in comparisons of annual capacity factors, sizes, and ages of affected EGUs. For example, the average annual capacity factors for natural gas- fired units increased from 28 to 38 percent between 2010 and 2022. And compared with the fleet of coal-fired steam generating units, the natural gas fleet is generally smaller and newer. While 67 percent of the coal-fired steam generating unit fleet capacity is over 500 MW per unit, 75 percent of the gas fleet is between 50 and 500 MW per unit. In terms of the age of the generating units, nearly 50 percent of the natural gas capacity has been in service less than 15 years.
127 
b. Current Structure of Natural Gas- Fired Generation 
In the lower 48 states, most 
combustion turbine EGUs burn natural gas, and some have the capability to fire distillate oil as backup for periods when natural gas is not available, such as when residential demand for natural gas is high during the winter. Areas of the country without access to natural gas often use distillate oil or some other locally available fuel. Combustion turbines have the capability to burn either gaseous or liquid fossil fuels, including but not limited to kerosene, naphtha, synthetic gas, biogases, liquified natural gas (LNG), and hydrogen. 
Over the past 20 years, advances in 
hydraulic fracturing (i.e., fracking) and 
horizontal drilling techniques have opened new regions of the U.S. to gas exploration. As the production of natural gas has increased, the annual average price has declined during the same period, leading to more natural gas-fired combustion turbines.
128 
Natural gas net generation increased 181 percent in the past two decades, from 601 thousand gigawatt-hours (GWh) in 2000 to 1,687 thousand GWh in 2022. For additional analysis of natural gas- fired generation, see the final TSD, Power Sector Trends included in the docket for this rulemaking. 
E. The Legislative, Market, and State 
Law Context 
1. Recent Legislation Impacting the 
Power Sector 
On November 15, 2021, President 
Biden signed the IIJA
129(also known as 
the Bipartisan Infrastructure Law), which allocated more than $65 billion in funding via grant programs, contracts, cooperative agreements, credit allocations, and other mechanisms to develop and upgrade infrastructure and expand access to clean energy technologies. Specific objectives of the legislation are to improve the nation’s electricity transmission capacity, pipeline infrastructure, and increase the availability of low-GHG fuels. Some of the IIJA programs
130that will impact 
the utility power sector include more than $20 billion to build and upgrade the nation’s electric grid, up to $6 billion in financial support for existing nuclear reactors that are at risk of closing, and more than $700 million for upgrades to the existing hydroelectric fleet. The IIJA established the Carbon Dioxide Transportation Infrastructure Finance and Innovation Program to provide flexible Federal loans and grants for building CO
2pipelines 
designed with excess capacity, enabling integrated carbon capture and geologic storage. The IIJA also allocated $21.5 billion to fund new programs to support the development, demonstration, and deployment of clean energy technologies, such as $8 billion for the development of regional clean hydrogen hubs and $7 billion for the development of carbon management technologies, including regional direct air capture hubs, carbon capture large-scale pilot projects for development of transformational technologies, and carbon capture commercial-scale demonstration projects to improve efficiency and effectiveness. Other clean energy technologies with IIJA and IRA funding include industrial demonstrations, geologic sequestration, grid-scale energy storage, and advanced nuclear reactors. 
The IRA, which President Biden 
signed on August 16, 2022,
131has the 
potential for even greater impacts on the electric power sector. Energy Security and Climate Change programs in the 
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13226 U.S.C. 45Q. Note, qualified facilities must 
meet prevailing wage and apprenticeship 
requirements to be eligible for the full value of the tax credit. 133Global CCS Institute. (2019). The LCFS and 
CCS Protocol: An Overview for Policymakers and Project Developers. Policy report. https://www.globalccsinstitute.com/wp-content/uploads/ 2019/05/LCFS-and-CCS-Protocol_ digital_ version- 
2.pdf. 
134EPA. (2024). Current Class VI Projects under 
Review at EPA. https://www.epa.gov/uic/current- class-vi-projects-under-review-epa. 135U.S. Department of the Treasury. (April 4, 
2023). Treasury Releases Guidance to Drive 
Investment to Coal Communities. Press release. https://home.treasury.gov/news/press-releases/ 
jy1383. 
136Fong, C., Posner, D., Varadarajan, U. (February 
16, 2024). The Energy Infrastructure Reinvestment Program: Federal financing for an equitable, clean economy. Case studies from Missouri and Iowa. Rocky Mountain Institute (RMI). https://rmi.org/ the-energy-infrastructure-reinvestment-program-federal-financing-for-an-equitable-clean-economy/. 
137U.S. Department of Agriculture (USDA). 
Empowering Rural America New ERA Program. https://www.rd.usda.gov/programs-services/ electric-programs/empowering-rural-america-new- era-program. 
138Rocky Mountain Institute (RMI). (October 4, 
2023). USDA $9.7B Rural Community Clean Energy Program Receives 150+ Letters of Interest. Press release. https://rmi.org/press-release/usda-9-7b- 
rural-community-clean-energy-program-receives- 150-letters-of-interest/. IRA covering grant funding and tax 
incentives provide significant investments in low and non GHG- emitting generation. For example, one of the conditions set by Congress for the expiration of the Clean Electricity Production Tax Credits of the IRA, found in section 13701, is a 75 percent reduction in GHG emissions from the power sector below 2022 levels. The IRA also contains the Low Emission Electricity Program (LEEP) with funding provided to the EPA with the objective to reduce GHG emissions from domestic electricity generation and use through promotion of incentives, tools to facilitate action, and use of CAA regulatory authority. In particular, CAA section 135, added by IRA section 60107, requires the EPA to conduct an assessment of the GHG emission reductions expected to occur from changes in domestic electricity generation and use through fiscal year 2031 and, further, provides the EPA $18 million ‘‘to ensure that reductions in [GHG] emissions are achieved through use of the existing authorities of [the Clean Air Act], incorporating the assessment. . . .’’ CAA section 135(a)(6). 
The IRA’s provisions also 
demonstrate an intent to support development and deployment of low- GHG emitting technologies in the power sector through a broad array of additional tax credits, loan guarantees, and public investment programs. Particularly relevant for these final actions, these provisions are aimed at reducing emissions of GHGs from new and existing generating assets, with tax credits for CCUS and clean hydrogen production, providing a pathway for the use of coal and natural gas as part of a low-GHG electricity grid. 
To assist states and utilities in their 
decarbonizing efforts, and most germane to these final actions, the IRA increased the tax credit incentives for capturing and storing CO
2, including from 
industrial sources, coal-fired steam generating units, and natural gas-fired stationary combustion turbines. The increase in credit values, found in section 13104 (which revises IRC section 45Q), is 70 percent, equaling $85/metric ton for CO
2captured and 
securely stored in geologic formations and $60/metric ton for CO
2captured 
and utilized or securely stored incidentally in conjunction with EOR.
132The CCUS incentives include 
12 years of credits that can be claimed at the higher credit value beginning in 
2023 for qualifying projects. These incentives will significantly cut costs and are expected to accelerate the adoption of CCS in the utility power and other industrial sectors. Specifically for the power sector, the IRA requires that a qualifying carbon capture facility have a CO
2capture design capacity of 
not less than 75 percent of the baseline 
CO 2production of the unit and that 
construction must begin before January 1, 2033. Tax credits under IRC section 45Q can be combined with some other tax credits, in some circumstances, and with state-level incentives, including California’s low carbon fuel standard, which is a market-based program with fuel-specific carbon intensity benchmarks.
133The magnitude of this 
incentive is driving investment and announcements, evidenced by the increased number of permit applications for geologic sequestration.
134 
The new provisions in section 13204 
(IRC section 45V) codify production tax credits for ‘clean hydrogen’ as defined in the provision. The value of the credits earned by a project is tiered (four different tiers) and depends on the estimated GHG emissions of the hydrogen production process as defined in the statute. The credits range from $3/kg H
2for less than 0.45 kilograms of 
CO 2-equivalent emitted per kilogram of 
low-GHG hydrogen produced (kg CO 2e/ 
kg H 2) down to $0.6/kg H 2for 2.5 to 4.0 
kg CO 2e/kg H 2(assuming wage and 
apprenticeship requirements are met). Projects with production related GHG emissions greater than 4.0 kg CO
2e/kg 
H2are not eligible. Future costs for 
clean hydrogen produced using renewable energy are anticipated to through 2030 due to these tax incentives and concurrent scaling up of manufacturing and deployment of clean hydrogen production facilities. 
Both IRC section 45Q and IRC section 
45V are eligible for additional provisions that increase the value and usability of the credits. Certain tax- exempt entities, such as electric co- operatives, may elect direct payment for the full 12- or 10-year lifetime of the credits to monetize the credits directly as cash refunds rather than through tax equity transactions. Tax-paying entities may elect to have direct payment of IRC section 45Q or 45V credits for 5 consecutive years. Tax-paying entities 
may also elect to transfer credits to unrelated taxpayers, enabling direct monetization of the credits again without relying on tax equity transactions. 
In addition to provisions such as 45Q 
that allow for the use of fossil- generating assets in a low-GHG future, the IRA also includes significant incentives to deploy clean energy generation. For instance, the IRA provides an additional 10 percent in production tax credit (PTC) and investment tax credit (ITC) bonuses for clean energy projects located in energy communities with historic employment and tax bases related to fossil fuels.
135 
The IRA’s Energy Infrastructure Reinvestment Program also provides $250 billion for the DOE to finance loan guarantees that can be used to reduce both the cost of retiring existing fossil assets and of replacement generation for those assets, including updating operating energy infrastructure with emissions control technologies.
136As a 
further example, the Empowering Rural America (New ERA) Program provides rural electric cooperatives with funds that can be used for a variety of purposes, including ‘‘funding for renewable and zero emissions energy systems that eliminate aging, obsolete or expensive infrastructure’’ or that allow rural cooperatives to ‘‘change [their] purchased-power mixes to support cleaner portfolios, manage stranded assets and boost [the] transition to clean energy.’’
137The $9.7 billion New ERA 
program represents the single largest investment in rural energy systems since the Rural Electrification Act of 1936.
138 
On September 12, 2023, the EPA 
released a report assessing the impact of the IRA on the power sector. Modeling results showed that economy-wide CO
2 
emissions are lower under the IRA. The 
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139U.S. Environmental Protection Agency (EPA). 
(September 2023). Electricity Sector Emissions 
Impacts of the Inflation Reduction Act. https://www.epa.gov/system/files/documents/2023-09/ Electricity_ Emissions_ Impacts_ Inflation_
Reduction_ Act_ Report_ EPA–FINAL.pdf. 
140West Virginia v. EPA, 597 U.S. at 734. 141See Comments of Edison Electric Institute to 
EPA’s Pre-Proposal Docket on Greenhouse Gas Regulations for Fossil Fuel-fired Power Plants, Document ID No. EPA–HQ–OAR–2022–0723–0024, November 18, 2022 (‘‘Fifty EEI members have announced forward-looking carbon reduction goals, two-third of which include a net-zero by 2050 or earlier equivalent goal, and members are routinely increasing the ambition or speed of their goals or altogether transforming them into net-zero goals.’’). 
142Energy Strategy Coalition Comments on EPA’s 
proposed New Source Performance Standards for Greenhouse Gas Emissions From New, Modified, and Reconstructed Fossil Fuel-Fired Electric Generating Units; Emission Guidelines for Greenhouse Gas Emissions From Existing Fossil Fuel-Fired Electric Generating Units; and Repeal of the Affordable Clean Energy Rule, Document ID No. EPA–HQ–OAR–2023–0072–0672, August 14, 2023. 
143Smart Electric Power Alliance Utility Carbon 
Tracker. https://sepapower.org/utility- 
transformation-challenge/utility-carbon-reduction- tracker/. 144Cao, L., Brindle., T., Schneer, K., and DeGolia, 
A. (December 2023). Turning Climate Commitments into Results: Evaluating Updated 2023 Projections vs. State Climate Targets. Environmental Defense Fund (EDF). https://www.edf.org/sites/default/files/ 2023–11/EDF-State-Emissions-Gap-December- 2023.pdf. 
145United Nations Framework Convention on 
Climate Change. What is the Paris Agreement? https://unfccc.int/process-and-meetings/the-paris- agreement. 
146U.S. Department of State and U.S. Executive 
Office of the President. November 2021. The Long- Term Strategy of the United States: Pathways to Net-Zero Greenhouse Gas Emissions by 2050. https://www.whitehouse.gov/wp-content/uploads/ 2021/10/us-long-term-strategy.pdf. 
147Cao, L., Brindle., T., Schneer, K., and DeGolia, 
A., December 2023. Turning Climate Commitments into Results: Evaluating Updated 2023 Projections vs. State Climate Targets. Environmental Defense Fund (EDF). https://www.edf.org/sites/default/files/ 2023-11/EDF-State-Emissions-Gap-December- 2023.pdf. 
148A full list of states currently participating in 
RGGI include Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Pennsylvania, Rhode Island, and Vermont. 
149Note that these figures do not include Virginia 
and Pennsylvania, which were not members of RGGI for the full duration of 2009–2023. Acadia Center: Regional Greenhouse Gas Initiative; Findings and Recommendations for the Third Program Review. https://acadiacenter.wpenginepowered.com/wp-content/uploads/2023/04/AC_RGGI_ 2023_ Layout_ R6.pdf. results from the EPA’s analysis of an 
array of multi-sector and electric sector modeling efforts show that a wide range of emissions reductions are possible. The IRA spurs CO
2emissions 
reductions from the electric power sector of 49 to 83 percent below 2005 levels in 2030. This finding reflects diversity in how the models represent the IRA, the assumptions the models use, and fundamental differences in model structures.
139 
In determining the CAA section 111 
emission limitations that are included in these final actions, the EPA did not consider many of the technologies that receive investment under recent Federal legislation. The EPA’s determination of the BSER focused on ‘‘measures that improve the pollution performance of individual sources,’’
140not generation 
technologies that entities could employ as alternatives to fossil fuel-fired EGUs. However, these overarching incentives and policies are important context for this rulemaking and influence where control technologies can be feasibly and cost-reasonably deployed, as well as how owners and operators of EGUs may respond to the requirements of these final actions. 
2. Commitments by Utilities To Reduce 
GHG Emissions 
Integrated resource plans (IRPs) are 
filed by public utilities and demonstrate how utilities plan to meet future forecasted energy demand while ensuring reliable and cost-effective service. In developing these rules, the EPA reviewed filed IRPs of companies that have publicly committed to 
reducing their GHGs. These IRPs demonstrate a range of strategies that public utilities are planning to adopt to reduce their GHGs, independent of these final actions. These strategies include retiring aging coal-fired steam generating EGUs and replacing them with a combination of renewable resources, energy storage, other non- emitting technologies, and natural gas- fired combustion turbines, and reducing GHGs from their natural gas-fired assets through a combination of CCS and reduced utilization. To affirm these findings, according to EIA, as of 2022 there are no new coal-fired EGUs in development. This section highlights recent actions and announced plans of many utilities across the industry to reduce GHGs from their fleets. Indeed, 50 power producers that are members of 
the Edison Electric Institute (EEI) have announced CO
2reduction goals, two- 
thirds of which include net-zero carbon emissions by 2050.
141The members of 
the Energy Strategies Coalition, a group of companies that operate and manage electricity generation facilities, as well as electricity and natural gas transmission and distribution systems, likewise are focused on investments to reduce carbon dioxide emissions from the electricity sector.
142This trend is 
not unique. Smaller utilities, rural electric cooperatives, and municipal entities are also contributing to these changes. 
Many electric utilities have publicly 
announced near- and long-term emission reduction commitments independent of these final actions. The Smart Electric Power Alliance demonstrates that the geographic footprint of commitments for 100 percent renewable, net-zero, or other carbon emission reductions by 2050 made by utilities, their parent companies, or in response to a state clean energy requirement, covers 
portions of 47 states and includes 80 percent of U.S. customer accounts.
143 
According to this same source, 341 utilities in 26 states have similar commitments by 2040. Additional detail about emission reduction commitments from major utilities is provided in section 2.2 of the RIA and in the final TSD, Power Sector Trends. 
3. State Actions To Reduce Power Sector GHG Emissions 
States across the country have taken 
the lead in efforts to reduce GHG emissions from the power sector. As of mid-2023, 25 states had made commitments to reduce economy-wide GHG emissions consistent with the goals of the Paris Agreement, including reducing GHG emissions by 50 to 52 percent by 2030.
144 145 146 These actions 
include legislation to decarbonize state power systems as well as commitments that require utilities to expand renewable and clean energy production through the adoption of renewable portfolio standards (RPS) and clean energy standards (CES). 
Several states have enacted binding 
economy-wide emission reduction targets that will require significant decarbonization from state power sectors, including California, Colorado, Maine, Maryland, Massachusetts, New Jersey, New York, Rhode Island, Vermont, and Washington.
147These 
commitments are statutory emission reduction targets accompanied by mandatory agency directives to develop comprehensive implementing regulations to achieve the necessary reductions. Some of these states, along with other neighboring states, also participate in the Regional Greenhouse Gas Initiative (RGGI), a carbon market limiting pollution from power plants throughout New England.
148The 
pollution limit combined with carbon price and allowance market has led member states to reduce power sector CO
2emissions by nearly 50 percent 
since the start of the program in 2009. This is 10 percent more than all non- RGGI states.
149 
Other states dependent on coal-fired 
power generation or coal production also have significant, albeit non- 
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150State of Wyoming. (Adopted March 24, 2020). 
House Bill 200 Reliable and dispatchable low- 
carbon energy standards. https://www.wyoleg.gov/ Legislation/2020/HB0200. 
151State of Wyoming. (Adopted March 15, 2024). 
Senate Bill 42 Low-carbon reliable energy standards-amendments. https://www.wyoleg.gov/ 
Legislation/2024/SF0042. 
152Berkeley Law. California Climate Policy 
Dashboard. https://www.law.berkeley.edu/research/ clee/research/climate/climate-policy-dashboard . 
153Berkeley Law. California Climate Policy 
Dashboard. https://www.law.berkeley.edu/research/ clee/research/climate/climate-policy-dashboard . 
154Basin Electric Power Cooperative. (May 2023). 
Press Release: Carbon Capture Technology Developers Break Ground at Wyoming Integrated Test Center Located at Basin Electric’s Dry Fork Station. https://www.basinelectric.com/News- 
Center/news-briefs/Carbon-capture-technology- developers-break-ground-at-Wyoming-Integrated- Test-Center-located-at-Basin-Electrics-Dry-Fork- Station. 
155State of Wyoming. (Adopted March 15, 2024). 
Senate Bill 42 Low-carbon reliable energy standards-amendments. https://www.wyoleg.gov/ 
Legislation/2024/SF0042. 
156Sabin Center for Climate Change Law. 2019. 
Legal Pathways to Deep Decarbonization. Interactive Tracker for State Action on Carbon Capture. https://cdrlaw.org/ccus-tracker/. 
157Sabin Center for Climate Change Law. 2019. 
Legal Pathways to Deep Decarbonization. Model Laws. Montana prohibition on acquiring coal plants without CCS. https://lpdd.org/resources/montana- prohibition-on-acquiring-coal-plants-without-ccs/ . 
158New York State. Climate Act: Progress to our 
Goals. https://climate.ny.gov/Our-Impact/Our- 
Progress. 
159Department of Ecology Washington State. 
Greenhouse Gases. https://ecology.wa.gov/Air- Climate/Climate-change/Tracking-greenhouse- gases. 
160State of Illinois General Assembly. Public Act 
102–0662: Climate and Equitable Jobs Act. 2021. https://www.ilga.gov/legislation/publicacts/102/ PDF/102-0662.pdf. 161General Assembly of North Carolina, House 
Bill 951 (2021). https://www.ncleg.gov/Sessions/ 
2021/Bills/House/PDF/H951v5.pdf. 
162These estimates are based on an analysis of the 
EPA’s NEEDS database, which contains information about EGUs across the country. The analysis includes a basic screen for units within the NEEDS database that are likely subject to the final 111(d) EGU rule, namely coal-steam units with capacity greater than 25 MW, and then removes units with an announced retirement dates prior to 2039, units with announced plans to convert from coal- to gas- 
fired units, and units likely to fall outside of the rule’s applicability via the cogeneration exemption. 
163DSIRE, Renewable Portfolio Standards and 
Clean Energy Standards (2023). https://ncsolarcen- prod.s3.amazonaws.com/wp-content/uploads/2023/ 12/RPS-CES-Dec2023-1.pdf; LBNL, U.S. State 
Renewables Portfolio & Clean Electricity Standards: 2023 Status Update. https://emp.lbl.gov/ publications/us-state-renewables-portfolio-clean. binding, commitments that signal broad 
public support for policy with emissions-based metrics and public affirmation that climate change is fundamentally linked to fossil-intensive energy sources. These states include Illinois, Michigan, Minnesota, New Mexico, North Carolina, Pennsylvania, and Virginia. States like Wyoming, the top coal producing state in the U.S., have promulgated sector-specific regulations requiring their public service commissions to implement low- carbon energy standards for public utilities.
150 151 Specific standards are 
further detailed in the sections that follow and in the final TSD, Power Sector Trends. 
Technologies like CCS provide a 
means to achieve significant emission reduction targets. For example, to achieve GHG emission reduction goals legislatively enacted in 2016, California Senate Bill 100, passed in 2018, requires the state to procure 60 percent of all electricity from renewable sources by 2030 and plan for 100 percent from carbon-free sources by 2045.
152 
Achieving California’s established goal of carbon-free electricity by 2045 requires emissions to be balanced by carbon sequestration, capture, or other technologies. Therefore, California Senate Bill 905, passed in 2022, requires 
the California Air Resources Board (CARB) to establish programs for permitting CCS projects while preventing the use of captured CO
2for 
EOR within the state.153As mentioned 
previously, as the top coal producing state, Wyoming has been exceptionally persistent on the implementation of CCS by incentivizing the national testing of CCS at Basin Electric’s coal-fired Dry Fork Station
154and by requiring the 
consideration of CCS as an alternative to coal plant retirement.
155At least five other states, including Montana and North Dakota, also have tax incentives and regulations for CCS.
156In the case 
of Montana, the acquisition of an equity interest or lease of coal-fired EGUs is prohibited unless it captures and stores at least 50 percent of its CO
2 
emissions.157These state policies have 
coincided with the planning and development of large CCS projects. 
Other states have broad 
decarbonization laws that will drive significant decrease in power sector GHG emissions. In New York, The Climate Leadership and Community Protection Act, passed in 2019, sets several climate targets. The most important goals include an 85 percent reduction in GHG emissions by 2050, 100 percent zero-emission electricity by 2040, and 70 percent renewable energy by 2030. Other targets include 9,000 MW of offshore wind by 2035, 3,000 MW of energy storage by 2030, and 6,000 MW of solar by 2025.
158 
Washington State’s Climate Commitment Act sets a target of reducing GHG emissions by 95 percent by 2050. The state is required to reduce emissions to 1990 levels by 2020, 45 percent below 1990 levels by 2030, 70 percent below 1990 levels by 2040, and 95 percent below 1990 levels by 2050. This also includes achieving net-zero emissions by 2050.
159Illinois’ Climate 
and Equitable Jobs Act, enacted in September 2021, requires all private coal-fired or oil-fired power plants to reach zero carbon emissions by 2030, municipal coal-fired plants to reach zero carbon emissions by 2045, and natural gas-fired plants to reach zero carbon emissions by 2045.
160In October 2021, 
North Carolina passed House Bill 951 that required the North Carolina Utilities Commission to ‘‘take all reasonable steps to achieve a seventy percent (70 percent) reduction in emissions of carbon dioxide (CO
2) emitted in the state from electric 
generating facilities owned or operated by electric public utilities from 2005 levels by the year 2030 and carbon neutrality by the year 2050.’’
161 
The ambition and scope of these state 
power sector polices will impact the electric generation fleet for decades. Seven states with 100-percent power sector decarbonization polices include a total of 20 coal-fired EGUs with slightly less than 10 GW total capacity and without announced retirement dates before 2039.
162Virginia, which has 
three coal-steam units with no announced retirement dates and one with a 2045 retirement date, enacted the Clean Economy Act in 2020 to impose a 100 percent RPS requirement by 2050. The combined capacity of all four of these units in Virginia totals nearly 1.5 GW. North Carolina, which has one coal-fired unit without an announced retirement date and one with a planned 2048 retirement, as previously mentioned, enacted a state law in 2021 requiring the state’s utilities commission to achieve carbon neutrality by 2050. The combined capacity of both units totals approximately 1.4 GW of capacity. Nebraska, where three public utility boards serving a large portion of the state have adopted net-zero electricity emission goals by 2040 or 2050, includes six coal-fired units with a combined capacity of 2.9 GW. The remaining eight units are in states with long-term decarbonization goals (Illinois, Louisiana, Maryland, and Wisconsin). All four of these states have set 100 percent clean energy goals by 2050. 
Twenty-nine states and the District of 
Columbia have enforceable RPS
163that 
require a percentage of electricity that utilities sell to come from eligible renewable sources like wind and solar rather than from fossil fuel-based sources like coal and natural gas. Furthermore, 20 states have adopted a CES that includes some form of clean 
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164This count is adapted from Lawrence Berkeley 
National Laboratory’s (LBNL) U.S. State Renewables 
Portfolio & Clean Electricity Standards: 2023 Status Update, which identifies 15 states with 100 percent 
CES. The LBNL count includes Virginia, which the EPA omits because it considers Virginia a 100 percent RPS. Further, the LBNL count excludes Louisiana, Michigan, New Jersey, and Wisconsin because their clean energy goals are set by executive order. The EPA instead includes Louisiana, New Jersey, and Wisconsin but characterizes them as goals rather than requirements. Michigan, which enacted a CES by statute after the LBNL report’s publication, is also included in the EPA count. Finally, the EPA count includes Maryland, whose December 2023 Climate Pollution Reduction Plan sets a goal of 100 percent clean energy by 2035, and Delaware, which enacted a statutory goal to reach net-zero GHG emissions by 2050. See LBNL, U.S. State Renewables Portfolio & Clean Electricity Standards: 2023 Status Update, https://emp.lbl.gov/ publications/us-state-renewables-portfolio-clean; Maryland’s Climate Pollution Reduction Plan, https://mde.maryland.gov/programs/air/ 
ClimateChange/Maryland%20Climate%20Reduction%20Plan/Maryland%27s%20Climate%20Pollution%20Reduction%20Plan%20-%20Final%20-%20Dec%2028%202023.pdf; and HB 99, An Act to Amend Titles 7 and 29 of the Delaware Code Relating to Climate Change, https://legis.delaware.gov/json/ BillDetail/GenerateHtmlDocumentEngrossment?engrossmentId=25785&docTypeId=6. 
165U.S. Environmental Protection Agency.Power 
Sector Platform 2023 using IPM. April 2024. https:// 
www.epa.gov/power-sector-modeling. 166Bistline, et al. (2023). ‘‘Emissions and Energy 
System Impacts of the Inflation Reduction Act of 2022.’’ https://www.science.org/stoken/author- 
tokens/ST-1277/full. 
167Bistline, et al. (2023). ‘‘Power Sector Impacts 
of the Inflation Reduction Act of 2022.’’https://iopscience.iop.org/article/10.1088/1748-9326/ ad0d3b. 
168Resource for the Future (2023). ‘‘Future 
Generation: Exploring the New Baseline for Electricity in the Presence of the Inflation Reduction Act.’’ https://www.rff.org/events/rff-live/ future-generation-exploring-the-new-baseline-for- electricity-in-the-presence-of-the-inflation- reduction-act/. 
169A wide variety of modeling teams have 
assessed baselines with IRA. The baseline estimated here is generally in line with these other estimates. Bistline, et al. (2023). ‘‘Power Sector Impacts of the 
Inflation Reduction Act of 2022.’’ https://iopscience.iop.org/article/10.1088/1748-9326/ ad0d3b. 
170U.S. Energy Information Administration (EIA), 
Preliminary Monthly Electric Generator Inventory, December 2023. https://www.eia.gov/electricity/ data/eia860m/ 
171U.S. Energy Information Administration (EIA), 
Electric Power Annual, table 3.1.A. November 2022. https://www.eia.gov/electricity/annual/ . 172International Energy Agency (IEA). Energy 
Policies of IEA Countries: United States 2019 Review. https://iea.blob.core.windows.net/assets/
7c65c270-ba15-466a-b50d-1c5cd19e359c/United_States_ 2019_ Review.pdf. 
173U.S. Energy Information Administration (EIA). 
(April 13, 2023). U.S. Electric Capacity Mix shifts from Fossil Fuels to Renewables in AEO2023. https://www.eia.gov/todayinenergy/ detail.php?id=56160. 
174Solomon, M., et al. (January 2023). Coal Cost 
Crossover 3.0: Local Renewables Plus Storage Create New Opportunities for Customer Savings and Community Reinvestment. Energy Innovation. https://energyinnovation.org/wp-content/uploads/ 2023/01/Coal-Cost-Crossover-3.0.pdf. 
175Barbose, G., et al. (September 2023). Tracking 
the Sun: Pricing and Design Trends for Distributed Photovoltaic Systems in the United States, 2023 Edition. Lawrence Berkeley National Laboratory. https://emp.lbl.gov/sites/default/files/5 _tracking_
the_sun_ 2023_ report.pdf. 
176U.S. Energy Information Administration (EIA). 
(August 2022). Electric Generators Inventory, Form– 860M, Inventory of Operating Generators and Inventory of Retired Generators. https://www.eia.gov/electricity/data/eia860m/. energy requirement or goal with a 100 
percent or net-zero target.164A CES 
shifts generating fleets away from fossil fuel resources by requiring a percentage of retail electricity to come from sources that are defined as clean. Unlike an RPS, which defines eligible generation in terms of the renewable attributes of its energy source, CES eligibility is based on the GHG emission attributes of the generation itself, typically with a zero or net-zero carbon emissions requirement. Additional discussion of state actions and legislation to reduce GHG emissions from the power sector is provided in the final TSD, Power Sector Trends. 
F. Future Projections of Power Sector 
Trends 
Projections for the U.S. power 
sector—based on the landscape of market forces in addition to the known actions of Congress, utilities, and states—have indicated that the ongoing transition will continue for specific fuel types and EGUs. The EPA’s Power Sector Platform 2023 using IPM reference case (i.e., the EPA’s 
projections of the power sector, which includes representation of the IRA absent further regulation), provides projections out to 2050 on future outcomes of the electric power sector. For more information on the details of this modeling, see the model documentation.
165 
Since the passage of the IRA in 
August 2022, the EPA has engaged with many external partners, including other governmental entities, academia, non- governmental organizations (NGOs), and industry, to understand the impacts that the IRA will have on power sector GHG emissions. In addition to engaging in several workgroups, the EPA has contributed to two separate journal articles that include multi-model comparisons of IRA impacts across several state-of-the-art models of the U.S. energy system and electricity sector
166 167 and participated in public 
events exploring modeling assumptions for the IRA.
168The EPA plans to 
continue collaborating with stakeholders, conducting external engagements, and using information gathered to refine modeling of the IRA. 
While much of the discussion below 
focuses on the EPA’s Power Sector Platform 2023 using IPM reference case, many other analyses show similar trends,
169and these trends are 
consistent with utility IRPs and public GHG reduction commitments, as well as state actions, both of which were described in the previous sections. 
1. Future Projections for Coal-Fired 
Generation 
As described in the EPA’s baseline 
modeling, coal-fired steam generating unit capacity is projected to fall from 181 GW in 2023
170to 52 GW in 2035, 
of which 11 GW includes retrofit CCS. Generation from coal-fired steam generating units is projected to also fall from 898 thousand GWh in 2021
171to 
236 thousand GWh by 2035. This change in generation reflects the anticipated continued decline in projected coal-fired steam generating 
unit capacity as well as a steady decline in annual operation of those EGUs that remain online, with capacity factors 
falling from approximately 48 percent in 2022 to 45 percent in 2035 at facilities that do not install CCS. By 2050, coal- fired steam generating unit capacity is projected to diminish further, with only 28 GW, or less than 16 percent of 2023 capacity (and approximately 9 percent of the 2010 capacity), still in operation across the continental U.S. 
These projections are driven by the 
eroding economic opportunities for coal-fired steam generating units to operate, the continued aging of the fleet of coal-fired steam generating units, and the continued availability and expansion of low-cost alternatives, like natural gas, renewable technologies, and 
energy storage. The projected retirements continue the trend of coal plant retirements in recent decades that is described in section IV.D.3. of this preamble (and further in the Power Sector Trends technical support document). The decline in coal generation capacity has generally resulted from a more competitive economic environment and increasing coal plant age. Most notably, declines in natural gas prices associated with the rise of hydraulic fracturing and horizontal drilling lowered the cost of natural gas-fired generation.
172Lower 
gas generation costs reduced coal plant capacity factors and revenues. Rapid declines in the costs of renewables and battery storage have put further price pressure on coal plants, given the zero marginal cost operation of solar and wind.
173 174 175 In addition, most 
operational coal plants today were built before 2000, and many are reaching or have surpassed their expected useful lives.
176Retiring coal plants tend to be 
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177Mills, A., et al. (November 2017). Power Plant 
Retirements: Trends and Possible Drivers. Lawrence 
Berkeley National Laboratory. https://live- etabiblio.pantheonsite.io/sites/default/files/lbnl_retirements_ data_ synthesis_ final.pdf. 
178National Association of Regulatory Utility 
Commissioners. (January 2020). Recent Changes to U.S. Coal Plant Operations and Current Compensation Practices. https://pubs.naruc.org/ pub/7B762FE1-A71B-E947-04FB-D2154DE77D45 . 179U.S. Energy Information Administration (EIA), 
Electric Power Annual, table 3.1.A. November 2022. https://www.eia.gov/electricity/annual/ . 
180U.S. Environmental Protection Agency, 
Inventory of U.S. Greenhouse Gas Emission Sources and Sinks. February 2023. https://www.epa.gov/ system/files/documents/2023-02/US-GHG- Inventory-2023-Main-Text.pdf. 181U.S. Energy Information Administration (EIA). 
Today in Energy. Solar and battery storage to make up 81 percent of new U.S. electric-generating capacity in 2024. February 2024. https://www.eia.gov/todayinenergy/detail.php?id=61424. old.177As plants age, their efficiency 
tends to decline and operations and 
maintenance costs increase. Older coal plant operational parameters are less aligned with current electric grid needs. Coal plants historically were used as base load power sources and can be slow (or expensive) to increase or decrease generation output throughout a typical day. That has put greater economic pressure on older coal plants, which are forced to either incur the costs of adjusting their generation or operate during less profitable hours when loads are lower or renewable generation is more plentiful.
178All of 
these factors have contributed to retirements over the past 15 years, and similar underlying factors are projected to continue the trend of coal retirements in the coming years. 
In 2020, there was a total of 1,439 
million metric tons of CO
2emissions 
from the power sector with coal-fired sources contributing to more than half of those emissions. In the EPA’s Power Sector Platform 2023 using IPM reference case, power sector related CO
2 
emission are projected to fall to 724 million metric tons by 2035, of which 23 percent is projected to come from coal-fired sources in 2035. 
2. Future Projections for Natural Gas- 
Fired Generation 
As described in the EPA’s Power 
Sector Platform 2023 using IPM reference case, natural gas-fired capacity is expected to continue to build out during the next decade with 34 GW of new capacity projected to come online by 2035 and 261 GW of new capacity by 2050. By 2035, the new natural gas capacity is comprised of 14 GW of simple cycle turbines and 20 GW of combined cycle turbines. By 2050, most of the incremental new capacity is projected to come just from simple cycle turbines. This also represents a higher rate of new simple cycle turbine builds compared to the reference periods (i.e., 2000–2006 and 2007–2021) discussed previously in this section. 
It should be noted that despite this 
increase in capacity, both overall generation and emissions from the natural gas-fired capacity are projected to decline. Generation from natural gas units is projected to fall from 1,579 thousand GWh in 2021
179to 1,344 
thousand GWh by 2035. Power sector 
related CO 2emissions from natural gas- 
fired EGUs were 615 million metric tons in 2021.
180By 2035, emission levels are 
projected to reach 521 million metric tons, 96 percent of which comes from NGCC sources. 
The decline in generation and 
emissions is driven by a projected decline in NGCC capacity factors. In model projections, NGCC units have a capacity factor early in the projection period of 59 percent, but by 2035, capacity factor projections fall to 48 percent as many of these units switch from base load operation to more intermediate load operation to support the integration of variable renewable energy resources. Natural gas-fired simple cycle turbine capacity factors also fall, although since they are used primarily as a peaking resource and 
their capacity factors are already below 10 percent annually, their impact on generation and emissions changes are less notable. 
Some of the reasons for this 
anticipated continued growth in natural gas-fired capacity, coupled with a decline in generation and emissions, include the anticipated growth in peak load, retirement of older fossil generators, and growth in renewable energy coupled with the greater flexibility offered by combustion turbines. Simple cycle turbines operate at lower efficiencies than NGCC units but offer fast startup times to meet peaking load demands. In addition, combustion turbines, along with energy storage technologies and demand response strategies, support the expansion of renewable electricity by meeting demand during peak periods and providing flexibility around the variability of renewable generation and electricity demand. In the longer term, as renewables and battery storage grow, they are anticipated to outcompete the need for some natural gas-fired generation and the overall utilization of natural gas-fired capacity is expected to decline. For additional discussion and analysis of projections of future coal- and natural gas-fired generation, see the final TSD, Power Sector Trends in the docket for this rulemaking. 
As explained in greater detail later in 
this preamble and in the accompanying RIA, future generation projections for natural gas-fired combustion turbines 
differ from those highlighted in recent historical trends. The largest source of new generation is from renewable energy, and projections show that total natural gas-fired combined cycle capacity is likely to decline after 2030 in response to increased generation from renewables, deployment of energy storage, and other technologies. Approximately 95 percent of capacity additions in 2024 are expected to be from non-emitting generation resources including solar, battery storage, wind, and nuclear.
181The IRA is likely to 
influence this trend, which is also expected to impact the operation of certain combustion turbines. For example, as the electric output from additional variable renewable generating sources fluctuates daily and seasonally, flexible low and intermediate load combustion turbines will be needed to support these variable sources and provide reliability to the grid. This requires the ability to start and stop quickly and change load more frequently. Today’s system includes 212 GW of intermediate and low load combustion turbines. These operational changes, alongside other tools like demand response, energy storage, and expanded transmission, will maintain reliability of the grid. 
V. Statutory Background and 
Regulatory History for CAA Section 111 
A. Statutory Authority To Regulate 
GHGs From EGUs Under CAA Section 111 
The EPA’s authority for and 
obligation to issue these final rules is 
CAA section 111, which establishes mechanisms for controlling emissions of air pollutants from new and existing stationary sources. CAA section 111(b)(1)(A) requires the EPA Administrator to promulgate a list of categories of stationary sources that the Administrator, in his or her judgment, finds ‘‘causes, or contributes significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare.’’ The EPA has the authority to define the scope of the source categories, determine the pollutants for which standards should be developed, and distinguish among classes, types, and sizes within categories in establishing the standards. 
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1. Regulation of Emissions From New 
Sources 
Once the EPA lists a source category, 
the EPA must, under CAA section 111(b)(1)(B), establish ‘‘standards of performance’’ for ‘‘new sources’’ in the source category. These standards are referred to as new source performance standards, or NSPS. The NSPS are national requirements that apply directly to the sources subject to them. 
Under CAA section 111(a)(1), a 
‘‘standard of performance’’ is defined, in the singular, as ‘‘a standard for emissions of air pollutants’’ that is determined in a specified manner, as noted in this section, below. 
Under CAA section 111(a)(2), a ‘‘new 
source’’ is defined, in the singular, 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.’’ Under CAA section 111(a)(3), a ‘‘stationary source’’ is defined as ‘‘any building, structure, facility, or installation which emits or may emit any air pollutant.’’ Under CAA section 111(a)(4), ‘‘modification’’ means 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. While this provision treats modified sources as new sources, EPA regulations also treat a source that undergoes ‘‘reconstruction’’ as a new source. Under the provisions in 40 CFR 60.15, ‘‘reconstruction’’ means the replacement of components of an existing facility such 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. Pursuant to CAA section 111(b)(1)(B), the standards of performance or revisions thereof shall become effective upon promulgation. 
In setting or revising a performance 
standard, CAA section 111(a)(1) provides that performance standards are to reflect ‘‘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 non-air quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated.’’ The term ‘‘standard of performance’’ in CAA 111(a)(1) makes 
clear that the EPA is to determine both the ‘‘best system of emission reduction . . . adequately demonstrated’’ (BSER) for the regulated sources in the source category and the ‘‘degree of emission limitation achievable through the application of the [BSER].’’ West Virginia v. EPA, 597 U.S. 697, 709 
(2022). To determine the BSER, the EPA first identifies the ‘‘system[s] of emission reduction’’ that are ‘‘adequately demonstrated,’’ and then determines the ‘‘best’’ of those systems, ‘‘taking into account’’ factors including ‘‘cost,’’ ‘‘nonair quality health and environmental impact,’’ and ‘‘energy requirements.’’ The EPA then derives from that system an ‘‘achievable’’ ‘‘degree of emission limitation.’’ The EPA must then, under CAA section 111(b)(1)(B), promulgate ‘‘standard[s] for emissions’’—the NSPS—that reflect that level of stringency. 
2. Regulation of Emissions From 
Existing Sources 
When the EPA establishes a standard 
for emissions of an air pollutant from new sources within a category, it must also, under CAA section 111(d), regulate emissions of that pollutant from existing sources within the same category, unless the pollutant is regulated under the National Ambient Air Quality Standards (NAAQS) program, under CAA sections 108–110, or the National Emission Standards for Hazardous Air Pollutants (NESHAP) program, under CAA section 112. See CAA section 111(d)(1)(A)(i) and (ii); West Virginia, 597 U.S. at 710. 
CAA section 111(d) establishes a 
framework of ‘‘cooperative federalism for the regulation of existing sources.’’ American Lung Ass’n, 985 F.3d at 931. CAA sections 111(d)(1)(A)–(B) require ‘‘[t]he Administrator . . . to prescribe regulations’’ that require ‘‘[e]ach state 
. . . to submit to [EPA] a plan . . . which establishes standards of performance for any existing stationary source for’’ the air pollutant at issue, and which ‘‘provides for the implementation and enforcement of such standards of performance.’’ CAA section 111(a)(6) defines an ‘‘existing source’’ as ‘‘any stationary source other than a new source.’’ 
To meet these requirements, the EPA 
promulgates ‘‘emission guidelines’’ that identify the BSER and the degree of emission limitation achievable through the application of the BSER. Each state must then establish standards of performance for its sources that reflect that level of stringency. However, the states need not compel regulated sources to adopt the particular components of the BSER itself. The 
EPA’s emission guidelines must also permit a state, ‘‘in applying a standard of performance to any particular source,’’ to ‘‘take into consideration, among other factors, the remaining useful life of the existing source to which such standard applies.’’ 42 U.S.C. 7411(d)(1). Once a state receives the EPA’s approval of its plan, the provisions in the plan become federally enforceable against the source, in the same manner as the provisions of an approved State Implementation Plan (SIP) under the Act. CAA section 111(d)(2)(B). If a state elects not to submit a plan or submits a plan that the EPA does not find ‘‘satisfactory,’’ the EPA must promulgate a plan that establishes Federal standards of performance for the state’s existing sources. CAA section 111(d)(2)(A). 
3. EPA Review of Requirements 
CAA section 111(b)(1)(B) requires the 
EPA to ‘‘at least every 8 years, review 
and, if appropriate, revise’’ new source performance standards. However, the Administrator need not review any such standard if the ‘‘Administrator determines that such review is not appropriate in light of readily available information on the efficacy’’ of the standard. Id. When conducting a review 
of an NSPS, the EPA has the discretion and authority to add emission limits for pollutants or emission sources not currently regulated for that source category. CAA section 111 does not by its terms require the EPA to review emission guidelines for existing sources, but the EPA retains the authority to do so. See 81 FR 59277 (August 29, 2016) (explaining legal authority to review 
emission guidelines for municipal solid waste landfills). 
B. History of EPA Regulation of 
Greenhouse Gases From Electricity Generating Units Under CAA Section 111 and Caselaw 
The EPA has listed more than 60 
stationary source categories under CAA section 111(b)(1)(A). See 40 CFR part 60, subparts Cb–OOOO. In 1971, the EPA listed fossil fuel-fired EGUs (which includes natural gas, petroleum, and coal) that use steam-generating boilers in a category under CAA section 111(b)(1)(A). See 36 FR 5931 (March 31, 1971) (listing ‘‘fossil fuel-fired steam generators of more than 250 million Btu per hour heat input’’). In 1977, the EPA listed fossil fuel-fired combustion turbines, which can be used in EGUs, in a category under CAA section 111(b)(1)(A). See 42 FR 53657 (October 3, 1977) (listing ‘‘stationary gas turbines’’). 
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182The EPA’s 2009 endangerment finding defines 
the air pollution which may endanger public health 
and welfare as the well-mixed aggregate group of the following gases: CO
2, methane (CH 4), nitrous 
oxide (N 2O), sulfur hexafluoride (SF 6), 
hydrofluorocarbons (HFCs), and perfluorocarbons (PFCs). 
183549 U.S. 497, 520 (2007). 
184131 S. Ct. 2527, 2537–38 (2011). Beginning in 2007, several decisions 
by the U.S. Supreme Court and the D.C. 
Circuit have made clear that under CAA section 111, the EPA has authority to regulate GHG emissions from listed source categories. The U.S. Supreme Court ruled in Massachusetts v. EPA 
that GHGs
182meet the definition of ‘‘air 
pollutant’’ in the CAA,183and 
subsequently premised its decision in 
AEP v. Connecticut184—that the CAA 
displaced any Federal common law right to compel reductions in CO
2 
emissions from fossil fuel-fired power plants—on its view that CAA section 111 applies to GHG emissions. The D.C. Circuit confirmed in American Lung Ass’n v. EPA, 985 F.3d 914, 977 (D.C. 
Cir. 2021), discussed in section V.B.5, that the EPA is authorized to promulgate requirements under CAA section 111 for GHG from the fossil fuel- fired EGU source category notwithstanding that the source category is regulated under CAA section 112. As discussed in section V.B.6, the U.S. Supreme Court did not accept certiorari on the question whether the EPA could regulate GHGs from fossil- fuel fired EGUs under CAA section 111(d) when other pollutants from fossil-fuel fired EGUs are regulated under CAA section 112 in West Virginia v. EPA, 597 U.S. 697 (2022), and so the 
D.C. Circuit’s holding on this issue remains good law. 
In 2015, the EPA promulgated two 
rules that addressed CO
2emissions from 
fossil fuel-fired EGUs. The first promulgated standards of performance for new fossil fuel-fired EGUs. ‘‘Standards of Performance for Greenhouse Gas Emissions From New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units; Final Rule,’’ (80 FR 64510; October 23, 2015) (2015 NSPS). The second promulgated emission guidelines for existing sources. ‘‘Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units; Final Rule,’’ (80 FR 64662; October 23, 2015) (Clean Power Plan, or CPP). 
1. 2015 NSPS 
In 2015, the EPA promulgated an 
NSPS to limit emissions of GHGs, 
manifested as CO
2, from newly 
constructed, modified, and reconstructed fossil fuel-fired electric 
utility steam generating units, i.e., utility boilers and IGCC EGUs, and newly constructed and reconstructed stationary combustion turbine EGUs. These final standards are codified in 40 CFR part 60, subpart TTTT. In promulgating the NSPS for newly constructed fossil fuel-fired steam generating units, the EPA determined the BSER to be a new, highly efficient, supercritical pulverized coal (SCPC) EGU that implements post-combustion partial CCS technology. The EPA concluded that CCS was adequately demonstrated (including being technically feasible) and widely available and could be implemented at reasonable cost. The EPA identified natural gas co-firing and IGCC technology (either with natural gas co- firing or implementing partial CCS) as alternative methods of compliance. 
The 2015 NSPS included standards of 
performance for steam generating units that undergo a ‘‘reconstruction’’ as well as units that implement ‘‘large modifications,’’ (i.e., modifications 
resulting in an increase in hourly CO
2 
emissions of more than 10 percent). The 2015 NSPS did not establish standards of performance for steam generating units that undertake ‘‘small modifications’’ (i.e., modifications 
resulting in an increase in hourly CO
2 
emissions of less than or equal to 10 percent), due to the limited information available to inform the analysis of a BSER and corresponding standard of performance. 
The 2015 NSPS also finalized 
standards of performance for newly constructed and reconstructed stationary combustion turbine EGUs. For newly constructed and reconstructed base load natural gas-fired stationary combustion turbines, the EPA finalized a standard based on efficient NGCC technology as the BSER. For newly constructed and reconstructed non-base load natural gas-fired stationary combustion turbines and for both base load and non-base load multi- fuel-fired stationary combustion turbines, the EPA finalized a heat input- based standard based on the use of lower-emitting fuels (referred to as clean fuels in the 2015 NSPS). The EPA did not promulgate final standards of 
performance for modified stationary combustion turbines due to lack of information. The 2015 NSPS remains in effect today. 
The EPA received six petitions for 
reconsideration of the 2015 NSPS. On May 6, 2016 (81 FR 27442), the EPA denied five of the petitions on the basis that they did not satisfy the statutory conditions for reconsideration under CAA section 307(d)(7)(B) and deferred 
action on one petition that raised the issue of the treatment of biomass. Apart from these petitions, the EPA proposed to revise the 2015 NSPS in 2018, as discussed in section V.B.2. 
Multiple parties also filed petitions 
for judicial review of the 2015 NSPS in the D.C. Circuit. These cases have been briefed and, on the EPA’s motion, are being held in abeyance pending EPA action concerning the 2018 proposal to revise the 2015 NSPS. 
In the 2015 NSPS, the EPA noted that 
it was authorized to regulate GHGs from the fossil fuel-fired EGU source categories because it had listed those source categories under CAA section 111(b)(1)(A). The EPA added that CAA section 111 did not require it to make a determination that GHGs from EGUs contribute significantly to dangerous air pollution (a pollutant-specific significant contribution finding), but in the alternative, the EPA did make that finding. It explained that ‘‘[greenhouse gas] air pollution may reasonably be anticipated to endanger public health or welfare,’’ 80 FR 64530 (October 23, 2015) and emphasized that power plants are ‘‘by far the largest emitters’’ of greenhouse gases among stationary sources in the U.S. Id. at 64522. In 
American Lung Ass’n v. EPA, 985 F.3d 
977 (D.C. Cir. 2021), the court held that even if the EPA were required to determine that CO
2from fossil fuel-fired 
EGUs contributes significantly to dangerous air pollution—and the court emphasized that it was not deciding that the EPA was required to make such a pollutant-specific determination—the determination in the alternative that the EPA made in the 2015 NSPS was not arbitrary and capricious and, accordingly, the EPA had a sufficient basis to regulate greenhouse gases from 
EGUs under CAA section 111(d) in the ACE Rule. This aspect of the decision remains good law. The EPA is not reopening and did not solicit comment on any of those determinations in the 2015 NSPS concerning its rational basis to regulate GHG emissions from EGUs or its alternative finding that GHG emissions from EGUs contribute significantly to dangerous air pollution. 
2. 2018 NSPS Proposal To Revise the 
2015 NSPS 
In 2018, the EPA proposed to revise 
the NSPS for new, modified, and reconstructed fossil fuel-fired steam generating units and IGCC units, in the Review of Standards of Performance for Greenhouse Gas Emissions From New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units; Proposed Rule (83 FR 65424; 
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185In the 2018 NSPS Proposal, the EPA solicited 
comment on whether it is required to make a 
determination that GHGs from a source category contribute significantly to dangerous air pollution as a predicate to promulgating a NSPS for GHG emissions from that source category for the first time. 83 FR 65432 (December 20, 2018). The EPA subsequently issued a final rule that provided that it would not regulate GHGs under CAA section 111 from a source category unless the GHGs from the category exceed 3 percent of total U.S. GHG emissions, on grounds that GHGs emitted in a lesser amount do not contribute significantly to dangerous air pollution. 86 FR 2652 (January 13, 2021). Shortly afterwards, the D.C. Circuit granted an unopposed motion by the EPA for voluntary vacatur and remand of the final rule. California v. EPA, No. 
21–1035, doc. 1893155 (D.C. Cir. April 5, 2021). 
186https://www.epa.gov/sites/default/files/2019- 
06/documents/utilities_ ria_final_ cpp_ repeal_ and_
ace_2019-06.pdf. December 20, 2018) (2018 NSPS 
Proposal). The EPA proposed to revise the NSPS for newly constructed units, based on a revised BSER of a highly efficient SCPC, without partial CCS. The EPA also proposed to revise the NSPS for modified and reconstructed units. As discussed in IX.A, in the present action, 
the EPA is withdrawing this proposed rule.
185 
3. Clean Power Plan 
With the promulgation of the 2015 
NSPS, the EPA also incurred a statutory obligation under CAA section 111(d) to issue emission guidelines for GHG emissions from existing fossil fuel-fired steam generating EGUs and stationary combustion turbine EGUs, which the EPA initially fulfilled with the promulgation of the CPP. See 80 FR 64662 (October 23, 2015). The EPA first determined that the BSER included three types of measures: (1) improving heat rate (i.e., the amount of fuel that 
must be burned to generate a unit of electricity) at coal-fired steam plants; (2) substituting increased generation from lower-emitting NGCC plants for generation from higher-emitting steam plants (which are primarily coal-fired); and (3) substituting increased generation from new renewable energy sources for generation from fossil fuel- fired steam plants and combustion turbines. See 80 FR 64667 (October 23, 2015). The latter two measures are known as ‘‘generation shifting’’ because they involve shifting electricity generation from higher-emitting sources to lower-emitting ones. See 80 FR 64728–29 (October 23, 2015). 
The EPA based this BSER 
determination on a technical record that evaluated generation shifting, including its cost-effectiveness, against the relevant statutory criteria for BSER and on a legal interpretation that the term ‘‘system’’ in CAA section 111(a)(1) is sufficiently broad to encompass shifting of generation from higher-emitting to lower-emitting sources. See 80 FR 64720 (October 23, 2015). The EPA then determined the ‘‘degree of emission 
limitation achievable through the application of the [BSER],’’ CAA section 111(a)(1), expressed as emission performance rates. See 80 FR 64667 (October 23, 2015). The EPA explained that a state would ‘‘have to ensure, through its plan, that the emission standards it establishes for its sources individually, in the aggregate, or in combination with other measures undertaken by the state, represent the equivalent of’’ those performance rates (80 FR 64667; October 23, 2015). Neither states nor sources were required to apply the specific measures identified in the BSER (80 FR 64667; October 23, 2015), and states could include trading or averaging programs in their state plans for compliance. See 80 FR 64840 (October 23, 2015). 
Numerous states and private parties 
petitioned for review of the CPP before the D.C. Circuit. On February 9, 2016, the U.S. Supreme Court stayed the rule pending review, West Virginia v. EPA, 
577 U.S. 1126 (2016). The D.C. Circuit held the litigation in abeyance, and ultimately dismissed it at the petitioners’ request. American Lung Ass’n, 985 F.3d at 937. 
4. The CPP Repeal and ACE Rule 
In 2019, the EPA repealed the CPP 
and replaced it with the ACE Rule. In contrast to its interpretation of CAA section 111 in the CPP, in the ACE Rule the EPA determined that the statutory ‘‘text and reasonable inferences from it’’ make ‘‘clear’’ that a ‘‘system’’ of emission reduction under CAA section 111(a)(1) ‘‘is limited to measures that can be applied to and at the level of the individual source,’’ (84 FR 32529; July 8, 2019); that is, the system must be limited to control measures that could be applied at and to each source to reduce emissions at each source. See 84 FR 32523–24 (July 8, 2019). Specifically, the ACE Rule argued that the requirements in CAA sections 111(d)(1), (a)(3), and (a)(6), that each state establish a standard of performance ‘‘for’’ ‘‘any existing source,’’ defined, in general, as any ‘‘building . . . [or] facility,’’ and the requirement in CAA section 111(a)(1) that the degree of 
emission limitation must be ‘‘achievable’’ through the ‘‘application’’ of the BSER, by their terms, impose this limitation. The EPA concluded that generation shifting is not such a control measure. See 84 FR 32546 (July 8, 2019). Based on its view that the CPP was a ‘‘major rule,’’ the EPA further determined that, absent ‘‘a clear statement from Congress,’’ the term ‘‘ ‘system of emission reduction’ ’’ should not be read to encompass ‘‘generation-shifting measures.’’ See 84 
FR 32529 (July 8, 2019). The EPA acknowledged, however, that ‘‘[m]arket- based forces ha[d] already led to significant generation shifting in the power sector,’’ (84 FR 32532; July 8, 2019), and that there was ‘‘likely to be no difference between a world where 
the CPP is implemented and one where it is not.’’ See 84 FR 32561 (July 8, 2019); the Regulatory Impact Analysis for the Repeal of the Clean Power Plan, and the Emission Guidelines for Greenhouse Gas Emissions from Existing Electric Utility Generating Units, 2–1 to 2–5.
186 
In addition, the EPA promulgated in 
the ACE Rule a new set of emission guidelines for existing coal-fired steam- generating EGUs. See 84 FR 32532 (July 8, 2019). In light of ‘‘the legal interpretation adopted in the repeal of the CPP,’’ (84 FR 32532; July 8, 2019)— which ‘‘limit[ed] ‘standards of performance’ to systems that can be applied at and to a stationary source,’’ (84 FR 32534; July 8, 2019)—the EPA found the BSER to be heat rate improvements alone. See 84 FR 32535 (July 8, 2019). The EPA listed various technologies that could improve heat rate (84 FR 32536; July 8, 2019), and identified the ‘‘degree of emission limitation achievable’’ by ‘‘providing ranges of expected [emission] reductions associated with each of the technologies.’’ See 84 FR 32537–38 (July 8, 2019). 
5. D.C. Circuit Decision in American 
Lung Association v. EPA Concerning the CPP Repeal and ACE Rule 
Numerous states and private parties 
petitioned for review of the CPP Repeal and ACE Rule. In 2021, the D.C. Circuit vacated the ACE Rule, including the CPP Repeal. American Lung Ass’n v. EPA, 985 F.3d 914 (D.C. Cir. 2021). The 
court held, among other things, that CAA section 111(d) does not limit the EPA, in determining the BSER, to measures applied at and to an individual source. The court noted that ‘‘the sole ground on which the EPA defends its abandonment of the [CPP] in favor of the ACE Rule is that the text of [CAA section 111] is clear and unambiguous in constraining the EPA to use only improvements at and to existing sources in its [BSER].’’ 985 F.3d at 944. The court found ‘‘nothing in the text, structure, history, or purpose of [CAA section 111] that compels the reading the EPA adopted.’’ 985 F.3d at 957. The court likewise rejected the 
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view that the CPP’s use of generation- 
shifting implicated a ‘‘major question’’ requiring unambiguous authorization by Congress. 985 F.3d at 958–68. 
The D.C. Circuit concluded that, 
because the EPA had relied on an ‘‘erroneous legal premise,’’ both the CPP Repeal Rule and the ACE Rule should be vacated. 985 F.3d at 995. The court did not decide, however, ‘‘whether the approach of the ACE Rule is a permissible reading of the statute as a matter of agency discretion,’’ 985 F.3d at 944, and instead ‘‘remanded to the EPA so that the Agency may ‘consider the question afresh,’ ’’ 985 F.3d at 995 (citations omitted). 
The court also rejected the arguments 
that the EPA cannot regulate CO
2 
emissions from coal-fired power plants under CAA section 111(d) at all because it had already regulated mercury emissions from coal-fired power plants under CAA section 112. 985 F.3d at 988. In addition, the court held that that the 2015 NSPS included a valid determination that greenhouse gases from the EGU source category contributed significantly to dangerous air pollution, which provided a sufficient basis for a CAA section 111(d) 
rule regulating greenhouse gases from existing fossil fuel-fired EGUs. Id. at 
977. 
Because the D.C. Circuit vacated the 
ACE Rule on the grounds noted above, it did not address the other challenges to the ACE Rule, including the arguments by Petitioners that the heat rate improvement BSER was inadequate because of the limited number of reductions it achieved and because the ACE Rule failed to include an appropriately specific degree of emission limitation. 
Upon a motion from the EPA, the D.C. 
Circuit agreed to stay its mandate with respect to vacatur of the CPP Repeal, American Lung Assn v. EPA, No. 19– 
1140, Order (February 22, 2021), so that the CPP remained repealed. Therefore, following the D.C. Circuit’s decision, no EPA rule under CAA section 111 to reduce GHGs from existing fossil fuel- fired EGUs remained in place. 
6. U.S. Supreme Court Decision in West 
Virginia v. EPA Concerning the CPP 
The Supreme Court granted petitions 
for certiorari from the D.C. Circuit’s American Lung Association decision, limited to the question of whether CAA section 111 authorized the EPA to determine that ‘‘generation shifting’’ was the best system of emission reduction for fossil-fuel fired EGUs. The Supreme Court did not grant certiorari on the question of whether the EPA was authorized to regulate GHG emissions from fossil-fuel fired power plants under CAA section 111, when fossil-fuel fired power plants are regulated for other pollutants under CAA section 112. In 2022, the U.S. Supreme Court reversed the D.C. Circuit’s vacatur of the ACE Rule’s embedded repeal of the CPP. West Virginia v. EPA, 597 U.S. 697 
(2022). The Supreme Court stated that CAA section 111 authorizes the EPA to determine the BSER and the degree of emission limitation that state plans must achieve. Id. at 2601–02. The 
Supreme Court concluded, however, that the CPP’s BSER of ‘‘generation- shifting’’ raised a ‘‘major question,’’ and was not clearly authorized by section 111. The Court characterized the generation-shifting BSER as ‘‘restructuring the Nation’s overall mix of electricity generation,’’ and stated that the EPA’s claim that CAA section 111 authorized it to promulgate generation shifting as the BSER was ‘‘not only unprecedented; it also effected a fundamental revision of the statute, changing it from one sort of scheme of regulation into an entirely different kind.’’ Id. at 2612 (internal 
quotation marks, brackets, and citation omitted). The Court explained that the EPA, in prior rules under CAA section 111, had set emissions limits based on ‘‘measures that would reduce pollution by causing the regulated source to operate more cleanly.’’ Id. at 2610. The 
Court noted with approval those ‘‘more traditional air pollution control measures,’’ and gave as examples ‘‘fuel- switching’’ and ‘‘add-on controls,’’ which, the Court observed, the EPA had considered in the CPP. Id. at 2611 
(internal quotations marks and citation omitted). In contrast, the Court continued, generation shifting was ‘‘unprecedented’’ because ‘‘[r]ather than focus on improving the performance of individual sources, it would improve the overall power system by lowering the carbon intensity of power generation. And it would do that by forcing a shift throughout the power grid from one type of energy source to another.’’ Id. at 2611–12 (internal 
quotation marks, emphasis, and citation omitted). 
The Court recognized that a rule 
based on traditional measures ‘‘may end up causing an incidental loss of coal’s market share,’’ but emphasized that the CPP was ‘‘obvious[ly] differen[t]’’ because, with its generation-shifting BSER, it ‘‘simply announc[ed] what the market share of coal, natural gas, wind, and solar must be, and then require[ed] plants to reduce operations or subsidize their competitors to get there.’’ Id. at 
2613 n.4. The Court also emphasized ‘‘the magnitude and consequence’’ of 
the CPP. Id. at 2616. It noted ‘‘the 
magnitude of this unprecedented power over American industry,’’ id. at 2612 
(internal quotation marks and citation omitted), and added that the EPA’s adoption of generation shifting ‘‘represent[ed] a transformative expansion in its regulatory authority.’’ Id. at 2610 (internal quotation marks 
and citation omitted). The Court also viewed the CPP as promulgating ‘‘a program that . . . Congress had considered and rejected multiple times.’’ Id. at 2614 (internal quotation 
marks and citation omitted). For these and related reasons, the Court viewed the CPP as raising a major question, and therefore, requiring ‘‘clear congressional authorization’’ as a basis. Id. (internal 
quotation marks and citation omitted). 
The Court declined to address the 
D.C. Circuit’s conclusion that the text of CAA section 111 did not limit the type of ‘‘system’’ the EPA could consider as the BSER to measures applied at and to an individual source. See id. at 2615. Nor did the Court address the scope of the states’ compliance flexibilities. 
7. D.C. Circuit Order Reinstating the 
ACE Rule 
On October 27, 2022, the D.C. Circuit 
responded to the U.S. Supreme Court’s reversal by recalling its mandate for the vacatur of the ACE Rule. American Lung Ass’n v. EPA, No. 19–1140, Order 
(October 27, 2022). Accordingly, at that time, the ACE Rule came back into effect. The court also revised its judgment to deny petitions for review challenging the CPP Repeal Rule, consistent with the judgment in West Virginia, so that the CPP remains 
repealed. The court took further action denying several of the petitions for review unaffected by the Supreme Court’s decision in West Virginia, which means that certain parts of its 2021 decision in American Lung Association remain in effect. These parts include the holding that the EPA’s prior regulation of mercury emissions from coal-fired electric power plants under CAA section 112 does not preclude the Agency from regulating CO
2from coal- 
fired electric power plants under CAA 
section 111, and the holding, discussed above, that the 2015 NSPS included a valid significant contribution determination and therefore provided a sufficient basis for a CAA section 111(d) rule regulating greenhouse gases from existing fossil fuel-fired EGUs. The court’s holding to invalidate amendments to the implementing regulations applicable to emission guidelines under CAA section 111(d) that extended the preexisting schedules 
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18740 CFR 60.22(b)(5), 60.22a(b)(5). Because the 
definition of subcategories depends on 
characteristics relevant to the BSER, and because those characteristics can differ as between new and existing sources, the EPA may establish different subcategories as between new and existing sources. for state and Federal actions and 
sources’ compliance, also remains in force. Based on the EPA’s stated intention to replace the ACE Rule, the court stayed further proceedings with respect to the ACE Rule, including the various challenges that its BSER was flawed because it did not achieve sufficient emission reductions and failed to specify an appropriately specific degree of emission limitation. 
C. Detailed Discussion of CAA Section 
111 Requirements 
This section discusses in more detail 
the key requirements of CAA section 111 for both new and existing sources that are relevant for these rulemakings. 
1. Approach to the Source Category and 
Subcategorizing 
CAA section 111 requires the EPA 
first to list stationary source categories that cause or contribute to air pollution which may reasonably be anticipated to endanger public health or welfare and then to regulate new sources within each such source category. CAA section 111(b)(2) grants the EPA discretion whether to ‘‘distinguish among classes, types, and sizes within categories of new sources for the purpose of establishing [new source] standards,’’ which we refer to as ‘‘subcategorizing.’’ Whether and how to subcategorize is a decision for which the EPA is entitled to a ‘‘high degree of deference’’ because it entails ‘‘scientific judgment.’’ Lignite Energy Council v. EPA, 198 F.3d 930, 
933 (D.C. Cir. 1999). 
Although CAA section 111(d)(1) does 
not explicitly address subcategorization, since its first regulations implementing the CAA, the EPA has interpreted it to authorize the Agency to exercise discretion as to whether and, if so, how to subcategorize, for the following reasons. CAA section 111(d)(1) grants the EPA authority to ‘‘prescribe regulations which shall establish a procedure . . . under which each State shall submit to the Administrator a plan [with standards of performance for existing sources.]’’ The EPA promulgates emission guidelines under this provision directing the states to regulate existing sources. The Supreme Court has recognized that, under CAA section 111(d), the ‘‘Agency, not the States, decides the amount of pollution reduction that must ultimately be achieved. It does so by again determining, as when setting the new source rules, ‘the best system of emission reduction . . . that has been adequately demonstrated for [existing covered] facilities.’ West Virginia, 597 U.S. at 710 (citations omitted). The EPA’s authority to determine the 
BSER includes the authority to create 
subcategories that tailor the BSER for differently situated sets of sources. Again, for new sources, CAA section 111(b)(2) confers authority for the EPA to ‘‘distinguish among classes, types, and sizes within categories.’’ Though CAA section 111(d) does not speak specifically to the creation of subcategories for a category of existing sources, the authority to identify the ‘‘best’’ system of emission reduction for existing sources includes the discretion to differentiate between differently situated sources in the category, and group those sources into subcategories in appropriate circumstances. The size, type, class, and other characteristics can make different emission controls more appropriate for different sources. A system of emission reduction that is ‘‘best’’ for some sources may not be ‘‘best’’ for others with different characteristics. For more than four decades, the EPA has interpreted CAA section 111(d) to confer authority on the Agency to create subcategories. The EPA’s implementing regulations under CAA section 111(d), promulgated in 1975, 40 FR 53340 (November 17, 1975), provide that the Administrator will specify different emission guidelines or compliance times or both ‘‘for different sizes, types, and classes of designated facilities when [based on] costs of control, physical limitations, geographical location, or [based on] similar factors.’’
187This regulation 
governs the EPA’s general authority to subcategorize under CAA section 111(d), and the EPA is not reopening that issue here. At the time of promulgation, the EPA explained that subcategorization allows the EPA to take into account ‘‘differences in sizes and types of facilities and similar considerations, including differences in control costs that may be involved for sources located in different parts of the country’’ so that the ‘‘EPA’s emission guidelines will in effect be tailored to what is reasonably achievable by particular classes of existing sources. . . .’’ Id. at 53343. The EPA’s 
authority to ‘‘distinguish among classes, types, and sizes within categories,’’ as provided under CAA section 111(b)(2), generally allows the Agency to place types of sources into subcategories. This is consistent with the commonly understood meaning of the term ‘‘type’’ in CAA section 111(b)(2): ‘‘a particular kind, class, or group,’’ or ‘‘qualities common to a number of individuals that distinguish them as an identifiable class.’’ See https://www.merriam- webster.com/dictionary/type. 
The EPA has developed subcategories 
in many rulemakings under CAA section 111 since the 1970s. These rulemakings have included subcategories on the basis of the size of the sources, see 40 CFR 60.40b(b)(1)–(2) (subcategorizing certain coal-fired steam generating units on the basis of heat input capacity); the types of fuel combusted, see Sierra Club, v. EPA, 657 
F.2d 298, 318–19 (D.C. Cir. 1981) (upholding a rulemaking that established different NSPS ‘‘for utility plants that burn coal of varying sulfur content’’), 2015 NSPS, 80 FR 64510, 64602 (table 15) (October 23, 2015) (subdividing new combustion turbines on the basis of type of fuel combusted); the types of equipment used to produce products, see 81 FR 35824 (June 3, 2016) (promulgating separate NSPS for many types of oil and gas sources, such as centrifugal compressors, pneumatic controllers, and well sites); types of manufacturing processes used to produce product, see 42 FR 12022 (March 1, 1977) (announcing availability of final guideline document for control of atmospheric fluoride emissions from existing phosphate fertilizer plants) and ‘‘Final Guideline Document: Control of Fluoride Emissions From Existing Phosphate Fertilizer Plants,’’ EPA–450/2–77–005 1–7 to 1–9, including table 1–2 (applying different control requirements for different manufacturing operations for phosphate fertilizer); levels of utilization of the sources, see 2015 NSPS, 80 FR 64510, 64602 (table 15) (October 23, 2015) (dividing new natural gas-fired combustion turbines into the subcategories of base load and non-base load); the activity level of the sources, see 81 FR 59276, 59278–79 (August 29, 2016) (dividing municipal solid waste landfills into the subcategories of active and closed landfills); and geographic location of the sources, see 71 FR 38482 (July 6, 2006) (SO
2NSPS for stationary combustion 
turbines subcategorizing turbines on the basis of whether they are located in, for example, a continental area, a non- continental area, the part of Alaska north of the Arctic Circle, and the rest of Alaska). Thus, the EPA has subcategorized many times in rulemaking under CAA sections 111(b) and 111(d) and based on a wide variety of physical, locational, and operational 
characteristics. 
Regardless of whether the EPA 
subcategorizes within a source category 
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188Portland Cement Ass’n v. Ruckelshaus, 486 
F.2d 375 (D.C. Cir. 1973); Essex Chemical Corp. v. 
Ruckelshaus, 486 F.2d 427 (D.C. Cir. 1973); Sierra 
Club v. Costle, 657 F.2d 298 (D.C. Cir. 1981); Lignite 
Energy Council v. EPA, 198 F.3d 930 (D.C. Cir. 
1999); Portland Cement Ass’n v. EPA, 665 F.3d 177 
(D.C. Cir. 2011); American Lung Ass’n v. EPA, 985 
F.3d 914 (D.C. Cir. 2021), rev’d in part, West Virginia v. EPA, 597 U.S. 697 (2022). See also 
Delaware v. EPA, No. 13–1093 (D.C. Cir. May 1, 
2015). 189See Sierra Club v. Costle, 657 F.2d 298, 326 
(D.C. Cir. 1981). 
190See Sierra Club v. Costle, 657 F.2d at 347. 
191See Lignite Energy Council, 198 F.3d at 933. 
192CAA section 111(a)(1), by its terms states that 
the factors enumerated in the parenthetical are part of the ‘‘adequately demonstrated’’ determination. In addition, the D.C. Circuit’s caselaw makes clear that the EPA may consider these same factors when it determines which adequately demonstrated system of emission reduction is the ‘‘best.’’ See Sierra Club v. Costle, 657 F.2d at 330 (recognizing that CAA 
section 111 gives the EPA authority ‘‘when determining the best technological system to weigh cost, energy, and environmental impacts’’). 
193See, e.g., Oil and Natural Gas Sector: New 
Source Performance Standards and National Emission Standards for Hazardous Air pollutants Reviews (77 FR 49494; August 16, 2012) (describing the three-step analysis in setting a standard of performance). 194As noted in section V.B.4 of this preamble, the 
ACE Rule adopted the interpretation that CAA 
section 111(a)(1), by its plain language, limits ‘‘system of emission reduction’’ to those control measures that could be applied at and to each source to reduce emissions at each source. 84 FR 32523–24 (July 8, 2019). The EPA has subsequently rejected that interpretation as too narrow. See 
Adoption and Submittal of State Plans for Designated Facilities: Implementing Regulations Under Clean Air Act Section 111(d), 88 FR 80535 (November 17, 2023). for purposes of determining the BSER 
and the degree of emission limitation achievable, a state retains certain flexibility in assigning standards of performance to its affected EGUs. The statutory framework for CAA section 111(d) emission guidelines, and the flexibilities available to states within that framework, are discussed below. 
2. Key Elements of Determining a 
Standard of Performance 
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. The current text of CAA section 111(a)(1) reads: ‘‘The term ‘standard of performance’ means a standard for emission 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 non-air quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated.’’ The D.C. Circuit has reviewed CAA section 111 rulemakings on numerous occasions since 1973,
188 
and has developed a body of caselaw that interprets the term ‘‘standard of performance,’’ as discussed throughout this preamble. 
The basis for standards of 
performance, whether promulgated by the EPA under CAA section 111(b) or established by the states under CAA section 111(d), is that the EPA determines the ‘‘degree of emission limitation’’ that is ‘‘achievable’’ by the sources by application of a ‘‘system of emission reduction’’ that the EPA determines is ‘‘adequately demonstrated,’’ ‘‘taking into account’’ the factors of ‘‘cost . . . and any nonair quality health and environmental impact and energy requirements,’’ and 
that the EPA determines to be the ‘‘best.’’ The D.C. Circuit has stated that in determining the ‘‘best’’ system, the EPA must also take into account ‘‘the amount of air pollution’’
189reduced 
and the role of ‘‘technological innovation.’’
190The D.C. Circuit has 
also stated that to determine the ‘‘best’’ system, the EPA may weigh the various factors identified in the statute and caselaw against each other, and has emphasized that the EPA has discretion in weighing the factors.
191 192  
The EPA’s overall approach to 
determining the BSER and degree of emission limitation achievable, which incorporates the various elements, is as follows: The EPA identifies ‘‘system[s] of emission reduction’’ that have been ‘‘adequately demonstrated’’ for a particular source category and determines the ‘‘best’’ of these systems after evaluating the amount of emission reductions, costs, any non-air health and environmental impacts, and energy requirements. As discussed below, for each of numerous subcategories, the EPA followed this approach to determine the BSER on the basis that the identified costs are reasonable and that the BSER is rational in light of the statutory factors, including the amount of emission reductions, that the EPA examined in its BSER analysis, consistent with governing precedent. 
After determining the BSER, the EPA 
determines an achievable emission limit based on application of the BSER.
193For 
a CAA section 111(b) rule, the EPA determines the standard of performance that reflects the achievable emission limit. For a CAA section 111(d) rule, the states have the obligation of establishing standards of performance for the affected sources that reflect the degree of emission limitation that the EPA has determined. As discussed below, the EPA is finalizing these determinations in association with each of the BSER determinations. 
The remainder of this subsection 
discusses each element in our general analytical approach. a. System of Emission Reduction 
The CAA does not define the phrase 
‘‘system of emission reduction.’’ In West 
Virginia v. EPA, the Supreme Court 
recognized that historically, the EPA had looked to ‘‘measures that improve the pollution performance of individual sources and followed a ‘‘technology- based approach’’ in identifying systems of emission reduction. In particular, the Court identified ‘‘the sort of ‘systems of emission reduction’ [the EPA] had always before selected,’’ which included ‘‘ ‘efficiency improvements, fuel- switching,’ and ‘add-on controls’.’’ 597 U.S. at 727 (quoting the Clean Power Plan).
194Section 111 itself recognizes 
that such systems may include off-site activities that may reduce a source’s pollution contribution, identifying ‘‘precombustion cleaning or treatment of fuels’’ as a ‘‘system’’ of ‘‘emission reduction.’’ 42 U.S.C. 7411(a)(7)(B). A ‘‘system of emission reduction’’ thus, at a minimum, includes measures that an individual source applies that improve the emissions performance of that source. Measures are fairly characterized as improving the pollution performance of a source where they reduce the individual source’s overall contribution to pollution. 
In West Virginia, the Supreme Court 
did not define the term ‘‘system of emissions reduction,’’ and so did not rule on whether ‘‘system of emission reduction’’ is limited to those measures that the EPA has historically relied upon. It did go on to apply the major questions doctrine to hold that the term ‘‘system’’ does not provide the requisite clear authorization to support the Clean Power Plan’s BSER, which the Court described as ‘‘carbon emissions caps based on a generation shifting approach.’’ Id. at 2614. While the Court 
did not define the outer bounds of the meaning of ‘‘system,’’ systems of emissions reduction like fuel switching, add-on controls, and efficiency improvements fall comfortably within the scope of prior practice as recognized by the Supreme Court. 
b. ‘‘Adequately Demonstrated’’ 
Under CAA section 111(a)(1), an 
essential, although not sufficient, 
condition for a ‘‘system of emission 
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195Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 
427, 433 (1973) (emphasis omitted). 
196See, e.g., Essex Chem. Corp. v. Ruckelshaus, 
486 F.2d 427 (D.C. Cir. 1973) (in which the D.C. 
Circuit upheld a CAA section 111 standard based on a system which had been extensively used in Europe but at the time of promulgation was only in use in the United States at one plant). 
197In introducing the respective bills which 
ultimately became the 1970 Clean Air Act upon Conference Committee review, both the House and Senate emphasized the urgency of the matter at hand, the intended power of the new legislation, and in particular its technology-forcing nature. The first page of the House report declared that ‘‘[t]he purpose of the legislation reported unanimously by [Committee was] to speed up, expand, and intensify the war against air pollution in the United States . . .’’ H.R. Rep. No. 17255 at 1 (1970). It was clear, stated the House report, that until that point ‘‘the strategies which [the United States had] pursued in the war against air pollution [had] been inadequate in several important respects, and the methods employed in implementing those strategies often [had] been slow and less effective than they might have been.’’ Id. The Senate report agreed, stating 
that their bill would ‘‘provide a much more intensive and comprehensive attack on air pollution,’’ 1 S. 4358 at 4 (1970), including, crucially, by increased federal involvement. See id. 
198The D.C. Circuit stated in Nat’l Asphalt 
Pavement Ass’n v. Train, 539 F.2d 775, 786 (D.C. 
Cir. 1976) ‘‘The standard of review of actions of the Administrator in setting standards of performance is an appropriately deferential one, and we are to affirm the action of the Administrator unless it is ‘‘arbitrary, capricious, an abuse of discretion, or otherwise not in accordance with law,’’ 5 U.S.C. 706(2)(A) (1970). Since this is one of those ‘‘highly technical areas, where our understanding of the import of the evidence is attenuated, our readiness to review evidentiary support for decisions must be correspondingly restrained.’’ Ethyl Corporation v. EPA, 96 S. Ct. 2663 (1976). ‘‘Our ‘expertise’ is not 
in setting standards for emission control, but in determining if the standards as set are the result of reasoned decision-making.’’ Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 434 (D.C. Cir. 1973)) 
(cleaned up).’’ 19942 U.S.C. 7409(b)(1). 
200744 F.3d 1334 (D.C. Cir. 2013). 
201Id. 
202While not relevant here, because CCS is 
already in existence, the text, case law, and legislative history make a compelling case that EPA is authorized to go farther than this, and may make a projection regarding the way in which a particular system will develop to allow for greater emissions reductions in the future. See 80 FR 64556–58 
(discussion of ‘‘adequately demonstrated’’ in 2015 NSPS). 
203Webster’s New World Dictionary: Second 
College Edition (David B. Guralnik, ed., 1972). reduction’’ to serve as the basis for an 
‘‘achievable’’ emission standard is that the Administrator must determine that the system is ‘‘adequately demonstrated.’’ The concepts of adequate demonstration and achievability are closely related: as the D.C. Circuit has stated, ‘‘[i]t is the system which must be adequately demonstrated and the standard which must be achievable,’’
195through 
application of the system. An achievable standard means a standard based on the EPA’s record-based finding that sufficient evidence exists to reasonably determine that the affected sources in the source category can adopt a specific system of emission reduction to achieve the specified degree of emission limitation. As discussed below, consistent with Congress’s use of the word ‘‘demonstrated,’’ the caselaw has approved the EPA’s ‘‘adequately demonstrated’’ determinations concerning systems utilized at test sources or other individual sources operating at commercial scale. The case law also authorizes the EPA to set an emissions standard at levels more stringent than has regularly been achieved, based on the understanding that sources will be able to adopt specific technological improvements to the system in question that will enable them to achieve the lower standard. Importantly, and contrary to some comments received on the proposed rule, CAA section 111(a)(1) does not require that a system of emission reduction exist in widespread commercial use in order to satisfy the ‘‘adequately demonstrated’’ requirement.
196Instead, CAA section 
111(a)(1) authorizes the EPA to establish standards which encourage the deployment of more effective systems of emission reduction that have been adequately demonstrated but that are not yet in widespread use. This aligns with Congress’s purpose in enacting the CAA, in particular its recognition that 
polluting sources were not widely adopting emission control technology on a voluntary basis and that Federal regulation was necessary to spur the development and deployment of those technologies.
197 i. Plain Text, Statutory Context, and 
Legislative History of the ‘‘Adequately 
Demonstrated’’ Provision in CAA Section 111(a)(1) 
Analysis of the plain text, statutory 
context, and legislative history of CAA section 111(a)(1) establishes two primary themes. First, Congress assigned the task of determining the appropriate BSER to the Administrator, based on a reasonable review of available evidence. Second, Congress authorized the EPA to set a standard, based on the evidence, that encourages broader adoption of an emissions- reducing technological approach that may not yet be in widespread use. 
The plain text of CAA section 
111(a)(1), and in particular the phrase ‘‘the Administrator determines’’ and the term ‘‘adequately,’’ confer discretion to the EPA in identifying the appropriate system. Rather than providing specific criteria for determining what constitutes appropriate evidence, Congress directed the Administrator to ‘‘determine[ ]’’ that the demonstration is ‘‘adequate[ ].’’ Courts have typically deferred to the EPA’s scientific and technological judgments in making such determinations.
198Further, use of the 
term ‘‘adequate’’ in provisions throughout the CAA highlights EPA flexibility and discretion in setting standards and in analyzing data that forms the basis for standard setting. 
In setting NAAQS under CAA section 
109, for example, the EPA is directed to determine, according to ‘‘the judgment 
of the Administrator,’’ an ‘‘adequate margin of safety.’’
199The D.C. Circuit 
has held that the use of the term ‘‘adequate’’ confers significant deference to the Administrator’s scientific and technological judgment. In Mississippi v. EPA,
200for example, the D.C. Circuit 
in 2013 upheld the EPA’s choice to set the NAAQS for ozone below 0.08 ppm, and noted that any disagreements with the EPA’s interpretations of the scientific evidence that underlay this decision ‘‘must come from those who are qualified to evaluate the science, not [the court].’’
201This Mississippi v. EPA 
precedent aligns with the general 
standard for judicial review of the EPA’s understanding of the evidence under CAA section 307(d)(9)(A) (‘‘arbitrary, capricious, an abuse of discretion, or otherwise not in accordance with law’’). 
The plain language of the phrase ‘‘has 
been adequately demonstrated,’’ in context, and in light of the legislative history, further strongly indicates that the system in question need not be in widespread use at the time the EPA’s rule is published. To the contrary, CAA section 111(a)(1) authorizes technology forcing, in the sense that the EPA is authorized to promote a system which is not yet in widespread use; provided the technology is in existence and the EPA has adequate evidence to extrapolate.
202 
Some commenters argued that use of 
the phrase ‘‘has been’’ in ‘‘has been adequately demonstrated’’ means that the system must be in widespread commercial use at the time of rule promulgation. We disagree. Considering the plain text, the use of the past tense, ‘‘has been adequately demonstrated’’ indicates a requirement that the technology currently be demonstrated. 
However, ‘‘demonstrated’’ in common usage at the time of enactment meant to ‘‘explain or make clear by using examples, experiments, etc.’’
203As a 
general matter, and as this definition indicates, the term ‘‘to demonstrate’’ suggests the need for a test or study— as in, for example, a ‘‘demonstration 
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204The statutory text at CAA section 119 
continues, ‘‘as determined by the Administrator, 
taking into account the cost of compliance, nonair quality health and environmental impact, and energy consideration.’’ 42 U.S.C. 7419(b)(3). 
205It should also be noted that the section 119 
language was added as part of the 1977 Clean Air Act amendments, while the section 111 language was established in 1970. Thus, Congress was aware of section 111’s more permissive language when it added the ‘‘reasonably available’’ language to section 119. 
20642 U.S.C. 7403(a)(1). 
207As the Supreme Court recently explained in 
Dubin v. United States, even words that might be 
indeterminate alone may be more easily interpreted in ‘‘company,’’ because per noscitur a sociis ‘‘a word is known by the company it keeps.’’ 599 U.S. 110, 244 (2023). 208H.R. Rep. No. 17255 at 921 (1970) (quoting 
CAA Sec. 112(a), as proposed). 
209S. Rept. 4358 at 91 (quoting CAA Sec. 
113(b)(2), as proposed). 
210S. Rep. 4358 at 15–16 (1970). The Senate 
Report went on to say that the EPA should ‘‘examine the degree of emission control that has been or can be achieved through the application of technology which is available or normally can be made available . . . at a cost and at a time which [the Agency] determines to be reasonable.’’ Id. Again, this language rebuts any suggestion that a BSER technology must be in widespread use at the time of rule enactment—Congress assumed only that the technology would be ‘‘available’’ or even that it ‘‘[could] be made available,’’ not that it would be already broadly used. 
211H.R. Rep. No. 17255 at 900. 212486 F.2d 427 (D.C. Cir. 1973). 
213Id. at 437. 
214Id. at 437. 
215Id. at 433–34 (D.C. Cir. 1973). See also Sierra 
Club v. Costle, 657 F.2d 298 (D.C. Cir. 1981), which 
supports the point that EPA may extrapolate from testing results, rather than relying on consistent performance, to identify an appropriate system and standard based on that system. In that case, EPA analyzed scrubber performance by considering performance during short-term testing periods. See id. at 377. 
216657 F.2d 298 (D.C. Cir. 1981). 
217Id. at 365, 370–73; 365. project’’ or ‘‘demonstration plant’’—that 
is, examples of technological feasibility. 
The statutory context is also useful in 
establishing that where Congress wanted to specify the availability of the control system, it did so. The only other use of the exact term ‘‘adequately demonstrated’’ occurs in CAA section 119, which establishes that, in order for the EPA to require a particular ‘‘means of emission limitation’’ for smelters, the Agency must establish that such means ‘‘has been adequately demonstrated to be reasonably available.... ’ ’
204The 
lack of the phrase ‘‘reasonably available’’ in CAA section 111(a)(1) is notable, and suggests that a system may be ‘‘adequately demonstrated’’ under CAA section 111 even if it is not ‘‘reasonably available’’ for every single source.
205 
The term ‘‘demonstration’’ also 
appears in CAA section 103 in an instructive context. CAA section 103, 
which establishes a ‘‘national research and development program for the prevention and control of air pollution’’ directs that as part of this program, the EPA shall ‘‘conduct, and promote the coordination and acceleration of, research, investigations, experiments, demonstrations, surveys, and studies relating to’’ the issue of air pollution.
206 
According to the canon of noscitur a sociis, associated words in a list bear on 
one another’s meaning.
207In CAA 
section 103, the word ‘‘demonstrations’’ appears alongside ‘‘research,’’ ‘‘investigations,’’ ‘‘experiments,’’ and ‘‘studies’’—all words suggesting the development of new and emerging technology. This supports interpreting CAA section 111(a)(1) to authorize the EPA to determine a system of emission reduction to be ‘‘adequately demonstrated’’ based on demonstration projects, testing, examples, or comparable evidence. 
Finally, the legislative history of the 
CAA in general, and section 111 in particular, strongly supports the point that BSER technology need not be in widespread use at the time of rule 
enactment. The final language of CAA section 111(a)(1), requiring that systems of emission reduction be ‘‘adequately demonstrated,’’ was the result of compromise in the Conference Committee between the House and Senate bill language. The House bill would have required that the EPA give ‘‘appropriate consideration to technological and economic feasibility’’ when establishing standards.
208The 
Senate bill would have required that standards ‘‘reflect the greatest degree of emission control which the Secretary determines to be achievable through application of the latest available control technology, processes, operating methods, or other alternatives.’’
209 
Although the exact language of neither the House nor Senate bill was adopted in the final bill, both reports made clear their intent that CAA section 111 would be significantly technology-forcing. In particular, the Senate Report referred to ‘‘available control technology’’—a phrase that, as just noted, the Senate bill included—but clarified that the technology need not ‘‘be in actual, routine use somewhere.’’
210The House 
Report explained that EPA regulations would ‘‘prevent and control such emissions to the fullest extent compatible with the available technology and economic feasibility as determined by [the EPA],’’ and ‘‘[i]n order to be considered ‘available’ the technology may not be one which constitutes a purely theoretical or experimental means of preventing or controlling air pollution.’’
211This last 
statement implies that the House Report anticipated that the EPA’s determination may be technology forcing. Nothing in the legislative history suggests that Congress intended 
that the technology already be in widespread commercial use. 
ii. Caselaw 
In a series of cases reviewing 
standards for new sources, the D.C. 
Circuit has held that an adequately demonstrated standard of performance 
may reflect the EPA’s reasonable projection of what that particular system may be expected to achieve going forward, extrapolating from available data from pilot projects or individual commercial-scale sources. A standard may be considered achievable even if the system upon which the standard is based has not regularly achieved the standard in testing. See, e.g., Essex Chem. Corp. v. Ruckelshaus
212 
(upholding a standard of 4.0 lbs per ton based on a system whose average control rate was 4.6 lbs per ton, and which had achieved 4.0 lbs per ton on only three occasions and ‘‘‘nearly equaled’ [the standard] on the average of nineteen different readings.’’)
213The 
Ruckelshaus court concluded that the 
EPA’s extrapolation from available data was ‘‘the result of the exercise of reasoned discretion by the Administrator’’ and therefore ‘‘[could not] be upset by [the] court.’’
214The 
court also emphasized that in order to be considered achievable, the standard set by the EPA need not be regularly or even specifically achieved at the time of rule promulgation. Instead, according to the court, ‘‘[a]n achievable standard is one which is within the realm of the adequately demonstrated system’s efficiency and which, while not at a level that is purely theoretical or experimental, need not necessarily be routinely achieved within the industry prior to its adoption.’’
215 
Case law also establishes that the EPA 
may set a standard more stringent than has regularly been achieved based on its identification of specific available technological improvements to the system. See Sierra Club v. Costle
216 
(upholding a 90 percent standard for SO
2emissions from coal-fired steam 
generators despite the fact that not all plants had previously achieved this standard, based on the EPA’s expectations for improved performance with specific technological fixes and the use of ‘‘coal washing’’ going forward).
217 
Further, the EPA may extrapolate based on testing at a particular kind of source to conclude that the technology at issue will also be effective at a different, 
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218198 F.3d 930 (D.C. Cir. 1999). 
219See id. at 933–34. 
220Id. at 934 (emphasis added). 
221486 F.2d 375 (D.C. Cir. 1973). See also Sierra 
Club v. Costle, 657 F.2d 298 (D.C. Cir. 1981), which 
supports the point that EPA may extrapolate from 
testing results, rather than relying on consistent performance, to identify an appropriate system and standard based on that system. In that case, EPA analyzed scrubber performance by considering performance during short-term testing periods. See id. at 377. 
222486 F.2d at 435–36. 223As discussed above, although the EPA is not 
relying on this point for purposes of these rules, it should be noted that the EPA may determine a system of emission reduction to be adequately demonstrated based on some amount of projection, even if some aspects of the system are still in development. Thus, the authorization for lead time accommodates the development of projected technology. 
224See Standards of Performance for New 
Residential Wood Heaters, New Residential Hydronic Heaters and Forced-Air Furnaces, 80 FR 13672, 13676 (March 16, 2015). 
225See Standards of Performance for New, 
Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review. 89 FR 16943 (March 8, 2024). 
226See id. at 16929. 
227See id. at 16937. 228See id. at 16886. 
22940 CFR 60.8. 
230For further discussion of lead time in the 
context of this rulemaking, see section VIII.F. 
231Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. 
Cir. 1981). See 79 FR 1430, 1464 (January 8, 2014); 
Lignite Energy Council, 198 F.3d at 933 (costs may not be ‘‘exorbitant’’); Portland Cement Ass’n v. EPA, 
513 F.2d 506, 508 (D.C. Cir. 1975) (costs may not be ‘‘greater than the industry could bear and survive’’). 
232These cost formulations are consistent with 
the legislative history of CAA section 111. The 1977 House Committee Report noted: 
In the [1970] Congress [sic: Congress’s] view, it 
was only right that the costs of applying best practicable control technology be considered by the owner of a large new source of pollution as a normal and proper expense of doing business. 
1977 House Committee Report at 184. Similarly, 
the 1970 Senate Committee Report stated: 
The implicit consideration of economic factors in 
determining whether technology is ‘‘available’’ should not affect the usefulness of this section. The overriding purpose of this section would be to related, source. See Lignite Energy 
Council v. EPA218(holding it 
permissible to base a standard for industrial boilers on application of SCR based on extrapolated information about the application of SCR on utility boilers).
219The Lignite court clarified 
that ‘‘where data are unavailable, EPA may not base its determination that a technology is adequately demonstrated or that a standard is achievable on mere speculation or conjecture,’’ but the ‘‘EPA may compensate for a shortage of 
data through the use of other qualitative methods, including the reasonable extrapolation of a technology’s performance in other industries.’’
220 
As a general matter, the case law is 
clear that at the time of Rule promulgation, the system which the EPA establishes as BSER need not be in widespread use. See, e.g., Ruckelshaus
221(upholding a standard 
based on a relatively new system which was in use at only one United States plant at the time of rule promulgation. Although the system was in use more extensively in Europe at the time of rule promulgation, the EPA based its analysis on test results from the lone U.S. plant only.)
222This makes good 
sense, because, as discussed above, CAA section 111(a)(1) authorizes a technology-forcing standard that encourages broader adoption of an emissions-reducing technological approach that is not yet broadly used. It follows that at the time of promulgation, not every source will be prepared to adopt the BSER at once. Instead, as discussed next, the EPA’s responsibility is to determine that the technology can be adopted in a reasonable period of time, and to base its requirements on this understanding. 
iii. Compliance Timeframe 
The preceding subsections have 
shown various circumstances under 
which the EPA may determine that a system of emission reduction is ‘‘adequately demonstrated.’’ In order to 
establish that a system is appropriate for the source category as a whole, the EPA must also demonstrate that the industry can deploy the technology at scale in the compliance timeframe. The D.C. Circuit has stated that the EPA may 
determine a ‘‘system of emission reduction’’ to be ‘‘adequately demonstrated’’ if the EPA reasonably projects that it may be more broadly deployed with adequate lead time. This view is well-grounded in the purposes of CAA section 111(a)(1), discussed above, which aim to control dangerous air pollution by allowing for standards which encourage more widespread adoption of a technology demonstrated at individual plants. 
As a practical matter, CAA section 
111’s allowance for lead time recognizes that existing pollution control systems may be complex and may require a predictable amount of time for sources across the source category to be able to design, acquire, install, test, and begin to operate them.
223Time may also be 
required to allow for the development of skilled labor, and materials like steel, concrete, and speciality parts. Accordingly, in setting 111 standards for both new and existing sources, the EPA has typically allowed for some amount of time before sources must demonstrate compliance with the 
standards. For instance, in the 2015 NSPS for residential wood heaters, the EPA established a ‘‘stepped compliance approach’’ which phased in requirements over 5 years to ‘‘allow manufacturers lead time to develop, test, field evaluate and certify current technologies’’ across their model lines.
224The EPA also allowed for a 
series of phase-ins of various requirements in the 2023 oil and gas NSPS.
225For example: the EPA 
finalized a compliance deadline for process controllers allowing for 1 year from the effective date of the final rule, to allow for delays in equipment availability;
226the EPA established a 1- 
year lead time period for pumps, also in response to possible equipment and labor shortages;
227and the EPA built in 
24 months between publication in the Federal Register and the commencement of a requirement to end 
routine flaring and route associated gas to a sales line.
228 
Finally, the EPA’s longstanding 
regulations for new source performance standards under CAA section 111 specifically authorize a minimum period for lead time. Pursuant to 40 CFR 60.11, compliance with CAA section 111 standards is generally determined in accordance with performance tests conducted under 40 CFR 60.8. Both of these regulatory provisions were adopted in 1971. Under 40 CFR 60.8, source performance is generally measured via performance tests, which must typically be carried out ‘‘within 60 days after achieving the maximum production rate at which the affected facility will be operated, but not later than 180 days after initial startup of such facility, or at such other times specified by this part, and at such other times as may be required by the Administrator under section 114 of the Act. . . .’’
229The fact that this 
provision has been in place for over 50 years indicates that the EPA has long recognized the need for lead time for at least one component of control development.
230 
c. Costs 
Under CAA section 111(a)(1), in 
determining whether a particular emission control is the ‘‘best system of emission reduction . . . adequately 
demonstrated,’’ the EPA is required to take into account ‘‘the cost of achieving [the emission] reduction.’’ Although the CAA does not describe how the EPA is to account for costs to affected sources, the D.C. Circuit has formulated the cost standard in various ways, including stating that the EPA may not adopt a standard the cost of which would be ‘‘excessive’’ or ‘‘unreasonable.’’
231 232  
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prevent new air pollution problems, and toward 
that end, maximum feasible control of new sources at the time of their construction is seen by the committee as the most effective and, in the long run, the least expensive approach. 
S. Comm. Rep. No. 91–1196 at 16. 
233Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. 
Cir. 1981). 
234Id. (EPA’s conclusion that the high cost of 
control was acceptable was ‘‘a judgment call with which we are not inclined to quarrel’’). 
2351977 House Committee Report at 184. 
236The costs for these standards were described 
in the rulemakings. See 36 FR 24876 (December 23, 1971), 37 FR 5769 (March 21, 1972). 237See 79 FR 1430, 1465 (January 8, 2014) (citing 
Sierra Club v. Costle, 657 F.2d at 351). 238Sierra Club v. Costle, 657 F.2d at 331 (citations 
omitted) (citing legislative history). 
239Sierra Club v. Costle, 657 F.2d at 327–28 
(quoting 44 FR 33583–84; June 11, 1979). The EPA has discretion in its 
consideration of cost under section 
111(a), both in determining the appropriate level of costs and in balancing costs with other BSER factors.
233To determine the BSER, the 
EPA must weigh the relevant factors, including the cost of controls and the amount of emission reductions, as well as other factors.
234 
The D.C. Circuit has repeatedly 
upheld the EPA’s consideration of cost in reviewing standards of performance. In several cases, the court upheld standards that entailed significant costs, consistent with Congress’s view that ‘‘the costs of applying best practicable control technology be considered by the owner of a large new source of pollution as a normal and proper expense of doing business.’’
235See Essex Chemical Corp. 
v. Ruckelshaus, 486 F.2d 427, 440 (D.C. 
Cir. 1973);236Portland Cement Ass’n 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 NSPS imposing controls on SO
2emissions from coal-fired power 
plants when the ‘‘cost of the new controls . . . is substantial. The EPA estimates that utilities will have to 
spend tens of billions of dollars by 1995 on pollution control under the new NSPS.’’). 
In its CAA section 111 rulemakings, 
the EPA has frequently used a cost- effectiveness metric, which determines the cost in dollars for each ton or other quantity of the regulated air pollutant removed through the system of emission reduction. See, e.g., 81 FR 35824 (June 
3, 2016) (NSPS for GHG and VOC emissions for the oil and natural gas source category); 71 FR 9866, 9870 (February 27, 2006) (NSPS for NO
X,SO 2, 
and PM emissions from fossil fuel-fired electric utility steam generating units); 61 FR 9905, 9910 (March 12, 1996) (NSPS and emission guidelines for nonmethane organic compounds and landfill gas from new and existing municipal solid waste landfills); 50 FR 40158 (October 1, 1985) (NSPS for SO
2 
emissions from sweetening and sulfur recovery units in natural gas processing plants). This metric allows the EPA to compare the amount a regulation would require sources to pay to reduce a particular pollutant across regulations and industries. In rules for the electric power sector, the EPA has also looked at a metric that determines the dollar increase in the cost of a MWh of electricity generated by the affected sources due to the emission controls, which shows the cost of controls relative to the output of electricity. See section VII.C.1.a.ii of this preamble, which discusses $/MWh costs of the Good Neighbor Plan for the 2015 Ozone NAAQS (88 FR 36654; June 5, 2023) and the Cross-State Air Pollution Rule (CSAPR) (76 FR 48208; August 8, 2011). This metric facilitates comparing costs across regulations and pollutants. In these final actions, as explained herein, the EPA looks at both of these metrics, in addition to other cost evaluations, to assess the cost reasonableness of the final requirements. The EPA’s consideration of cost reasonableness in this way meets the statutory requirement that the EPA take into account ‘‘the cost of achieving [the emission] reduction’’ under section 111(a)(1). 
d. Non-Air Quality Health and 
Environmental Impact and Energy Requirements 
Under CAA section 111(a)(1), the EPA 
is required to take into account ‘‘any nonair quality health and environmental impact and energy requirements’’ in determining the BSER. Non-air quality health and environmental impacts may include the impacts of the disposal of byproducts of the air pollution controls, or requirements of the air pollution control equipment for water. Portland Cement Ass’n v. Ruckelshaus, 465 F.2d 
375, 387–88 (D.C. Cir. 1973), cert. denied, 417 U.S. 921 (1974). Energy 
requirements may include the impact, if any, of the air pollution controls on the source’s own energy needs. 
e. Sector or Nationwide Component of 
Factors in Determining the BSER 
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.
237 
The D.C. Circuit based this interpretation—which it made in the 1981 Sierra Club v. Costle case 
regarding the NSPS for new power plants—on a review of the legislative history, stating, 
[T]he Reports from both Houses on the 
Senate and House bills illustrate very clearly 
that Congress itself was using a long-term lens with a broad focus on future costs, environmental and energy effects of different technological systems when it discussed section 111.
238 
The court has upheld EPA rules that 
the EPA ‘‘justified . . . in terms of the 
policies of the Act,’’ including balancing long-term national and regional impacts. For example, the court upheld a standard of performance for SO
2 
emissions from new coal-fired power plants on grounds that it— 
reflects a balance in environmental, 
economic, and energy consideration by being sufficiently stringent to bring about substantial reductions in SO
2emissions (3 
million tons in 1995) yet does so at 
reasonable costs without significant energy penalties....
239 
The EPA interprets this caselaw to 
authorize it to assess the impacts of the 
controls it is considering as the BSER, including their costs and implications for the energy system, on a sector-wide, regional, or national basis, as appropriate. For example, the EPA may assess whether controls it is considering would create risks to the reliability of the electricity system in a particular area or nationwide and, if they would, to reject those controls as the BSER. 
f. ‘‘Best’’ 
In determining which adequately 
demonstrated system of emission 
reduction is the ‘‘best,’’ the EPA has broad discretion. In AEP v. Connecticut, 
564 U.S. 410, 427 (2011), the Supreme Court explained that under CAA section 111, ‘‘[t]he appropriate amount of regulation in any particular greenhouse gas-producing sector cannot be prescribed in a vacuum: . . . informed assessment of competing interests is required. Along with the environmental benefit potentially achievable, our Nation’s energy needs and the possibility of economic disruption must weigh in the balance. The Clean Air Act entrusts such complex balancing to the EPA in the first instance, in combination with state regulators. Each ‘‘standard of performance’’ the EPA sets must ‘‘tak[e] into account the cost of achieving [emissions] reduction and any nonair quality health and environmental impact and energy requirements.’’ (paragraphing revised; citations omitted)). 
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240Sierra Club v. Costle, 657 F.2d at 319. 
241Sierra Club v. Costle, 657 F.2d at 321; see also 
New York v. Reilly, 969 F.2d at 1150 (because 
Congress did not assign the specific weight the 
Administrator should assign to the statutory elements, ‘‘the Administrator is free to exercise [her] discretion’’ in promulgating an NSPS). 
242Lignite Energy Council, 198 F.3d at 933 
(paragraphing revised for convenience). See New York v. Reilly, 969 F.2d 1147, 1150 (D.C. Cir. 1992) 
(‘‘Because Congress did not assign the specific weight the Administrator should accord each of these factors, the Administrator is free to exercise his discretion in this area.’’); see also NRDC v. EPA, 
25 F.3d 1063, 1071 (D.C. Cir. 1994) (The EPA did not err in its final balancing because ‘‘neither RCRA nor EPA’s regulations purports to assign any particular weight to the factors listed in subsection (a)(3). That being the case, the Administrator was free to emphasize or deemphasize particular factors, constrained only by the requirements of reasoned agency decisionmaking.’’). 
243See generally Standards of Performance for 
New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review—Supplemental Notice of Proposed Rulemaking, 87 FR 74765 (December 6, 2022) (proposing the BSER for reducing methane and VOC emissions from natural gas-driven controllers in the oil and natural gas sector on the basis of, among other things, impacts on emissions of criteria pollutants). In this preamble, for convenience, the EPA generally discusses the effects of controls on non-GHG air pollutants along with the effects of controls on non- air quality health and environmental impacts. 
244Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. 
1981) was governed by the 1977 CAAA version of the definition of ‘‘standard of performance,’’ which revised the phrase ‘‘best system of emission reduction’’ to read, ‘‘best technological system of continuous emission reduction.’’ As noted above, the 1990 CAAA deleted ‘‘technological’’ and ‘‘continuous’’ and thereby returned the phrase to how it read under the 1970 CAAA. The court’s interpretation of the 1977 CAAA phrase in Sierra Club v. Costle to require consideration of the 
amount of air emissions focused on the term ‘‘best,’’ and the terms ‘‘technological’’ and ‘‘continuous’’ were irrelevant to its analysis. It thus remains valid for the 1990 CAAA phrase ‘‘best system of emission reduction.’’ Likewise, 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,’’
240and emphasized that ‘‘[t]he 
text gives the EPA broad discretion to weigh different factors in setting the standard,’’ including the amount of emission reductions, the cost of the controls, and the non-air quality environmental impacts and energy requirements.
241And 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.
242 
Importantly, the courts recognize that 
the EPA must consider several factors and that determining what is ‘‘best’’ depends on how much weight to give the factors. In promulgating certain standards of performance, the EPA may give greater weight to particular factors than it does in promulgating other standards of performance. Thus, the determination of what is ‘‘best’’ is complex and necessarily requires an exercise of judgment. By analogy, the question of who is the ‘‘best’’ sprinter in the 100-meter dash primarily depends on only one criterion—speed—and therefore is relatively straightforward, whereas the question of who is the ‘‘best’’ baseball player depends on a 
more complex weighing of multiple criteria and therefore requires a greater exercise of judgment. 
The term ‘‘best’’ also authorizes the 
EPA to consider factors in addition to the ones enumerated in CAA section 111(a)(1), that further the purpose of the statute. In Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375 (D.C. Cir. 
1973), the D.C. Circuit held that under 
CAA section 111(a)(1) as it read prior to the enactment of the 1977 CAA Amendments that added a requirement that the EPA take account of non-air quality environmental impacts, the EPA must consider ‘‘counter-productive environmental effects’’ in Determining the BSER. Id. at 385. The court 
elaborated: ‘‘The standard of the ‘best system’ is comprehensive, and we cannot imagine that Congress intended that ‘best’ could apply to a system which did more damage to water than it prevented to air.’’ Id., n.42. In Sierra 
Club v. Costle, 657 F.2d at 326, 346–47, 
the court added that the EPA must consider the amount of emission reductions and technology advancement in determining BSER, as discussed in section V.C.2.g of this preamble. 
The court’s view that ‘‘best’’ includes 
additional factors that further the purpose of CAA section 111 is a reasonable interpretation of that term in its statutory context. The purpose of CAA section 111 is to reduce emissions of air pollutants that endanger public health or welfare. CAA section 111(b)(1)(A). The court reasonably surmised that the EPA’s determination of whether a system of emission reduction that reduced certain air pollutants is ‘‘best’’ should be informed by impacts that the system may have on other pollutants that affect public or welfare. Portland Cement Ass’n, 486 
F.2d at 385. The Supreme Court confirmed the D.C. Circuit’s approach in Michigan v. EPA, 576 U.S. 743 (2015), 
explaining that administrative agencies must engage in ‘‘reasoned decisionmaking’’ that, in the case of 
pollution control, cannot be based on technologies that ‘‘do even more damage to human health’’ than the emissions they eliminate. Id. at 751–52. After 
Portland Cement Ass’n, Congress revised CAA section 111(a)(1) to make explicit that in determining whether a system of emission reduction is the ‘‘best,’’ the EPA should account for non- air quality health and environmental impacts. By the same token, the EPA takes the position that in determining whether a system of emission reduction is the ‘‘best,’’ the EPA may account for the impacts of the system on air pollutants other than the ones that are the subject of the CAA section 111 regulation.
243We discuss immediately below other factors that the D.C. Circuit 
has held the EPA should account for in determining what system is the ‘‘best.’’ 
g. Amount of Emissions Reductions 
Consideration of 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’’ is implicit in the plain language of CAA section 111(a)(1)—the EPA must choose the best system of emission reduction. 
Indeed, consistent with this plain language and the purpose of CAA section 111, the EPA must consider the quantity of emissions at issue. 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’’).
244The fact that the 
purpose of a ‘‘system of emission reduction’’ is to reduce emissions, and that the term itself explicitly incorporates the concept of reducing emissions, supports the court’s view that in determining whether a ‘‘system of emission reduction’’ is the ‘‘best,’’ the EPA must consider the amount of emission reductions that the system would yield. Even if the EPA were not required to consider the amount of emission reductions, the EPA has the discretion to do so, on grounds that either the term ‘‘system of emission reduction’’ or the term ‘‘best’’ may reasonably be read to allow that discretion. 
h. Expanded Use and Development of 
Technology 
The D.C. Circuit has long held that 
Congress intended for CAA section 111 
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245Sierra Club v. Costle, 657 F.2d at 346 (‘‘Our 
interpretation of section 111(a) is that the mandated 
balancing of cost, energy, and non-air quality health and environmental factors embraces consideration of technological innovation as part of that balance. The statutory factors which EPA must weigh are broadly defined and include within their ambit subfactors such as technological innovation.’’). 
246See S. Rep. No. 91–1196 at 16 (1970) 
(‘‘Standards of performance should provide an incentive for industries to work toward constant improvement in techniques for preventing and controlling emissions from stationary sources’’); S. Rep. No. 95–127 at 17 (1977) (cited in Sierra Club v. Costle, 657 F.2d at 346 n.174) (‘‘The section 111 
Standards of Performance . . . sought to assure the use of available technology and to stimulate the development of new technology’’). 
247Portland Cement Ass’n v. Ruckelshaus, 486 
F.2d 375, 391 (D.C. Cir. 1973) (the best system of emission reduction must ‘‘look[ ] toward what may fairly be projected for the regulated future, rather than the state of the art at present’’). 
2481970 Senate Committee Report No. 91–1196 at 
15 (‘‘The maximum use of available means of preventing and controlling air pollution is essential to the elimination of new pollution problems’’). 
249Sierra Club v. Costle, 657 F.2d at 351 
(upholding a standard of performance designed to promote the use of an emerging technology). 250Sierra Club v. Costle, 657 F.2d 298, 364, n.276 
(D.C. Cir. 1981). 
251Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 
427, 433–34 (D.C. Cir. 1973), cert. denied, 416 U.S. 969 (1974). 
252Nat’l Lime Ass’n v. EPA, 627 F.2d 416, 433, 
n.46 (D.C. Cir. 1980). 
253Sierra Club v. Costle, 657 F.2d 298, 377 (D.C. 
Cir. 1981) (citing Nat’l Lime Ass’n v. EPA, 627 F.2d 
416 (D.C. Cir. 1980). In considering the representativeness of the source tested, the EPA may consider such variables as the ‘‘ ‘feedstock, operation, size and age’ of the source.’’ Nat’l Lime Ass’n v. EPA, 627 F.2d 416, 433 (D.C. Cir. 1980). 
Moreover, it may be sufficient to ‘‘generalize from a sample of one when one is the only available sample, or when that one is shown to be representative of the regulated industry along relevant parameters.’’ Nat’l Lime Ass’n v. EPA, 627 
F.2d 416, 434, n.52 (D.C. Cir. 1980). 
25440 CFR 60.21(e), 60.21a(e). to create incentives for new technology 
and therefore that the EPA is required to consider technological innovation as one of the factors in determining the ‘‘best system of emission reduction.’’ See Sierra Club v. Costle, 657 F.2d at 
346–47. The court has grounded its reading in the statutory text of CAA 111(a)(1), defining the term ‘‘standard of performance.’’
245In addition, the 
court’s interpretation finds support in the legislative history.
246The legislative 
history identifies three different ways that Congress designed CAA section 111 to authorize standards of performance that promote technological 
improvement: (1) The development of technology that may be treated as the ‘‘best system of emission reduction . . . adequately demonstrated;’’ under CAA section 111(a)(1);
247(2) the expanded 
use of the best demonstrated technology;
248and (3) the development 
of emerging technology.249Even 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 because technological innovation may be considered an element of the term ‘‘best,’’ particularly in light of Congress’s emphasis on technological innovation. 
i. Achievability of the Degree of 
Emission Limitation 
For new sources, CAA section 
111(b)(1)(B) and (a)(1) provides that the EPA must establish ‘‘standards of performance,’’ which are standards for emissions that reflect the degree of emission limitation that is ‘‘achievable’’ through the application of the BSER. A standard of performance is ‘‘achievable’’ 
if a technology can reasonably be projected to be available to an individual source at the time it is constructed that will allow it to meet the standard.
250Moreover, according to 
the court, ‘‘[a]n achievable standard is one which is within the realm of the adequately demonstrated system’s efficiency and which, while not at a level that is purely theoretical or experimental, need not necessarily be routinely achieved within the industry prior to its adoption.’’
251To be 
achievable, a standard ‘‘must be capable of being met under most adverse conditions which can reasonably be expected to recur and which are not or 
cannot be taken into account in determining the ‘costs’ of compliance.’’
252To show a standard is 
achievable, the EPA must ‘‘(1) identify variable conditions that might contribute to the amount of expected emissions, and (2) establish that the test data relied on by the agency are representative of potential industry- wide performance, given the range of variables that affect the achievability of the standard.’’
253 
Although the courts have established 
these standards for achievability in cases concerning CAA section 111(b) new source standards of performance, generally comparable standards for achievability should apply under CAA section 111(d), although the BSER may differ in some cases as between new and existing sources due to, for example, higher costs of retrofit. 40 FR 53340 (November 17, 1975). For existing sources, CAA section 111(d)(1) requires the EPA to establish requirements for state plans that, in turn, must include ‘‘standards of performance.’’ As the Supreme Court has recognized, this provision requires the EPA to promulgate emission guidelines that determine the BSER for a source category and then identify the degree of emission limitation achievable by application of the BSER. See West 
Virginia v. EPA, 597 U.S. at 710.
254 
The EPA has promulgated emission 
guidelines on the basis that the existing sources can achieve the degree of emission limitation described therein, even though under the RULOF provision of CAA section 111(d)(1), the state retains discretion to apply standards of performance to individual sources that are less stringent, which indicates that Congress recognized that the EPA may promulgate emission guidelines that are consistent with CAA section 111(d) even though certain individual sources may not be able to achieve the degree of emission limitation identified therein by applying the controls that the EPA determined to be the BSER. Note further that this requirement that the emission limitation be ‘‘achievable’’ based on the ‘‘best system of emission reduction . . . adequately demonstrated’’ indicates that the technology or other measures that the EPA identifies as the BSER must be technically feasible. 
3. EPA Promulgation of Emission 
Guidelines for States To Establish Standards of Performance 
CAA section 111(d)(1) directs the EPA 
to promulgate regulations establishing a 
procedure similar to that provided by CAA section 110 under which states submit state plans that establish ‘‘standards of performance’’ for emissions of certain air pollutants from sources which, if they were new sources, would be regulated under CAA section 111(b), and that provide for the implementation and enforcement of such standards of performance. The term ‘‘standard of performance’’ is defined under CAA section 111(a)(1), quoted above. Thus, CAA sections 111(a)(1) and (d)(1) collectively require the EPA to determine the degree of emission limitation achievable through application of the BSER to existing sources and to establish regulations under which states establish standards of performance reflecting that degree of emission limitation. The EPA addresses both responsibilities through its emission guidelines, as well as through its general implementing regulations for CAA section 111(d). Consistent with the statutory requirements, the general implementing regulations require that the EPA’s emission guidelines reflect— 
the degree of emission limitation achievable 
through the application of the best system of emission reduction which (taking into account the cost of such reduction and any non-air quality health and environmental 
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25540 CFR 60.21a(e). 
25640 CFR 60.21a(b), 60.24a(b). 
257As the Supreme Court explained in West 
Virginia v. EPA, ‘‘Although the States set the actual 
rules governing existing power plants, EPA itself 
still retains the primary regulatory role in Section 111(d).’’ 597 U.S. at 710. The Court elaborated that ‘‘[t]he Agency, not the States, decides the amount of pollution reduction that must ultimately be achieved. It does so by again determining, as when setting the new source rules, ‘the best system of emission reduction . . . that has been adequately demonstrated for [existing covered] facilities.’ 40 CFR 60.22(b)(5) (2021); see also 80 FR 64664, and n.1. The States then submit plans containing the emissions restrictions that they intend to adopt and enforce in order not to exceed the permissible level of pollution established by EPA. See §§ 60.23, 60.24; 42 U.S.C. 7411(d)(1).’’ Id. 
25840 CFR 60.24a(i). 
259See generally 40 CFR 60.23a–60.28a. impact and energy requirements) the 
Administrator has determined has been adequately demonstrated from designated facilities.
255 
Following the EPA’s promulgation of 
emission guidelines, each state must establish standards of performance for its existing sources, which the EPA’s regulations call ‘‘designated facilities.’’
256Such standards of 
performance must reflect the degree of emission limitation achievable through application of the best system of emission reduction as determined by the EPA, which the Agency may express as a presumptive standard of performance in the applicable emission guidelines. 
While the standards of performance 
that states establish in their plans must 
generally be no less stringent than the degree of emission limitation determined by the EPA,
257CAA section 
111(d)(1) also requires that the EPA’s regulations ‘‘permit the State in applying a standard of performance to any particular source . . . to take into consideration, among other factors, the remaining useful life of the existing source to which such standard applies.’’ Consistent with this statutory direction, the EPA’s general implementing regulations for CAA section 111(d) provide a framework for states’ consideration of remaining useful life and other factors (referred to as ‘‘RULOF’’) when applying a standard of performance to a particular source. In November 2023, the EPA finalized clarifications to its regulations governing states’ consideration of RULOF to apply less stringent standards of performance to particular existing sources. As amended, these regulations provide that states may apply a standard of performance to a particular designated facility that is less stringent than, or has a longer compliance schedule than, otherwise required by the applicable emission guideline taking into consideration that facility’s remaining useful life and other factors. To apply a less stringent standard of 
performance or longer compliance schedule, the state must demonstrate with respect to each facility (or class of such facilities), that the facility cannot reasonably achieve the degree of emission limitation determined by the EPA based on unreasonable cost of control resulting from plant age, location, or basic process design; physical impossibility or technical infeasibility of installing necessary control equipment; or other circumstances specific to the facility. In doing so, the state must demonstrate that there are fundamental differences between the information specific to a facility (or class of such facilities) and the information the EPA considered in determining the degree of emission limitation achievable through application of the BSER or the compliance schedule that make achieving such degree of emission reduction or meeting such compliance schedule unreasonable for that facility. 
In addition, under CAA section 116, 
states may establish standard of performances that are more stringent than the presumptive standards of performance contained in the EPA’s 
emission guidelines.
258The state must 
include the standards of performance in their state plans and submit the plans to the EPA for review according to the procedures established in the Agency’s general implementing regulations for CAA section 111(d).
259Under CAA 
section 111(d)(2)(A), the EPA approves state plans that are determined to be ‘‘satisfactory.’’ CAA section 111(d)(2)(A) also gives the Agency ‘‘the same authority’’ as under CAA section 110(c) to promulgate a Federal plan in cases where a state fails to submit a satisfactory state plan. 
VI. ACE Rule Repeal 
The EPA is finalizing repeal of the 
ACE Rule. The EPA proposed to repeal 
the ACE Rule and did not receive significant comments objecting to the proposal. The EPA is finalizing the proposal largely as proposed. A general summary of the ACE Rule, including its regulatory and judicial history, is included in section V.B.4 of this preamble. The EPA repeals the ACE Rule on three grounds that each independently justify the rule’s repeal. 
First, as a policy matter, the EPA 
concludes that the suite of heat rate improvements (HRI) the ACE Rule selected as the BSER is not an appropriate BSER for existing coal-fired EGUs. In the EPA’s technical judgment, the suite of HRI set forth in the ACE 
Rule provide negligible CO
2reductions 
at best and, in many cases, may increase CO
2emissions because of the ‘‘rebound 
effect,’’ as explained in section VII.D.4.a.iii of this preamble. These concerns, along with the EPA’s experience in implementing the ACE Rule, cast doubt that the ACE Rule would achieve emission reductions and increase the likelihood that the ACE Rule could make CO
2pollution worse. 
As a result, the EPA has determined it is appropriate to repeal the rule, and to reevaluate whether other technologies constitute the BSER. 
Second, even assuming the ACE 
Rule’s rejection of CCS and natural gas co-firing was supported at the time, the ACE Rule’s rationale for rejecting CCS and natural gas co-firing as the BSER no longer applies because of new factual developments. Since the ACE Rule was promulgated, changes in the power industry, developments in the costs of controls, and new federal subsidies have made other controls more broadly available and less expensive. Considering these developments, the EPA has determined that co-firing with natural gas and CCS are the BSER for certain subcategories of sources as described in section VII.C of this preamble, and that the HRI technologies adopted by the ACE Rule are not the BSER. Thus, repeal of the ACE Rule is proper on this ground as well. 
Third, the EPA concludes that the 
ACE Rule conflicted with CAA section 111 and the EPA’s implementing regulations because it did not specifically identify the BSER or the ‘‘degree of emission limitation achievable though application of the [BSER].’’ Instead, the ACE Rule described only a broad range of values as the ‘‘degree of emission limitation 
achievable.’’ In doing so, the rule did not provide the states with adequate guidance on the degree of emission limitation that must be reflected in the standards of performance so that a state plan would be approvable by the EPA. The ACE Rule is repealed for this reason also. 
A. Summary of Selected Features of the 
ACE Rule 
The ACE Rule determined that the 
BSER for coal-fired EGUs was a ‘‘list of ‘candidate technologies,’ ’’ consisting of seven types of the ‘‘most impactful HRI technologies, equipment upgrades, and best operating and maintenance practices,’’ (84 FR 32536; July 8, 2019), including, among others, ‘‘Boiler Feed Pumps’’ and ‘‘Redesign/Replace Economizer.’’ Id. at 32537 (table 1). The 
rule provided a range of improvements 
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260ACE Rule RIA 3–11, table 3–3. 
261The rebound effect becomes evident by 
comparing the results of the ACE Rule IPM runs for 
the 2018 reference case, EPA, IPM State-Level Emissions: EPAv6 November 2018 Reference Case, Document ID No. EPA–HQ–OAR–2017–0355– 26720, and for the ‘‘Illustrative ACE Scenario. IPM State-Level Emissions: Illustrative ACE Scenario, Document ID No. EPA–HQ–OAR–2017–0355– 
26724. 262ACE Rule RIA 3–11, table 3–3. 
263Sargent and Lundy. Heat Rate Improvement 
Method Costs and Limitations Memo. Available in 
Docket ID No. EPA–HQ–OAR–2023–0072. 
264See EPA, IPM State-Level Emissions: EPAv6 
November 2018 Reference Case, Document ID No. EPA–HQ–OAR–2017–0355–26720 (providing ACE reference case); IPM State-Level Emissions: Illustrative ACE Scenario, Document ID No. EPA– HQ–OAR–2017–0355–26724 (providing illustrative scenario). in heat rate that each of the seven 
‘‘candidate technologies’’ could achieve if applied to coal-fired EGUs of different capacities. For six of the technologies, the expected level of improvement in heat rate ranged from 0.1–0.4 percent to 1.0–2.9 percent, and for the seventh technology, ‘‘Improved Operating and Maintenance (O&M) Practices,’’ the range was ‘‘0 to >2%.’’ Id. The ACE Rule 
explained that states must review each of their designated facilities, on either a source-by-source or group-of-sources basis, and ‘‘evaluate the applicability of each of the candidate technologies.’’ Id. at 32550. States were to use the list of HRI technologies ‘‘as guidance but will be expected to conduct unit-specific evaluations of HRI potential, technical feasibility, and applicability for each of the BSER candidate technologies.’’ Id. at 
32538. 
The ACE Rule emphasized that states 
had ‘‘inherent flexibility’’ in evaluating candidate technologies with ‘‘a wide range of potential outcomes.’’ Id. at 
32542. The ACE Rule provided that states could conclude that it was not appropriate to apply some technologies. Id. at 32550. Moreover, if a state decided 
to apply a particular technology to a particular source, the state could determine the level of heat rate improvement from the technology could be anywhere within the range that the EPA had identified for that technology, or even outside that range. Id. at 32551. 
The ACE Rule stated that after the state evaluated the technologies and calculated the amount of HRI in this way, it should determine the standard of performance 0that the source could achieve, Id. at 32550, and then adjust 
that standard further based on the application of source-specific factors such as remaining useful life. Id. at 
32551. 
The ACE Rule then identified the 
process by which states had to take these actions. States must ‘‘evaluat[e] each’’ of the seven candidate technologies and provide a summary, which ‘‘include[s] an evaluation of the . . . degree of emission limitation achievable through application of the technologies.’’ Id. at 32580. Then, the 
state must provide a variety of information about each power plant, including, the plant’s ‘‘annual generation,’’ ‘‘CO
2emissions,’’ ‘‘[f]uel 
use, fuel price, and carbon content,’’ ‘‘operation and maintenance costs,’’ ‘‘[h]eat rates,’’ ‘‘[e]lectric generating capacity,’’ and the ‘‘timeline for implementation,’’ among other information. Id. at 32581. The EPA 
explained that the purpose of this data 
was to allow the Agency to ‘‘adequately and appropriately review the plan to determine whether it is satisfactory.’’ Id. 
at 32558. 
The ACE Rule projected a very low 
level of overall emission reduction if states generally applied the set of candidate technologies to their sources. The rule was projected to achieve a less- than-1-percent reduction in power- sector CO
2emissions by 2030.260 
Further, the EPA also projected that it would increase CO
2emissions from 
power plants in 15 states and the District of Columbia because of the ‘‘rebound effect’’ as coal-fired sources implemented HRI measures and became more efficient. This phenomenon is explained in more detail in section VII.D.4.a.iii of this document.
261 
The ACE Rule considered several 
other control measures as the BSER, including co-firing with natural gas and CCS, but rejected them. The ACE Rule rejected co-firing with natural gas primarily on grounds that it was too costly in general. 84 FR 32545 (July 8, 2019). The rule also concluded that generating electricity by co-firing natural gas in a utility boiler would be an inefficient use of the gas when compared to combusting it in a combustion turbine. Id. The ACE Rule 
rejected CCS on grounds that it was too costly. Id. at 32548. The rule identified 
the high capital and operating costs of CCS and noted the fact that the IRC section 45Q tax credit, as it then applied, would provide only limited benefit to sources. Id. at 32548–49. 
B. Developments Undermining ACE Rule’s Projected Emission Reductions 
The EPA’s first basis for repealing the 
ACE Rule is that it is unlikely that—if implemented—the rule would reduce emissions, and implementation could increase CO
2emissions instead. Thus, 
the EPA concludes that as a matter of policy it is appropriate to repeal the rule and evaluate anew whether other technologies qualify as the BSER. 
Two factors, taken together, 
undermine the ACE Rule’s projected emission reductions and create the risk that implementation of the ACE Rule could increase—rather than reduce— CO
2emissions from coal-fired EGUs. 
First, HRI technologies achieve only limited GHG emission reductions. The ACE Rule projected that if states generally applied the set of candidate technologies to their sources, the rule would achieve a less-than-1-percent reduction in power-sector CO
2 
emissions by 2030.262The EPA now 
doubts that even these minimal reductions would be achieved. The ACE Rule’s projected benefits were premised in part on a 2009 technical report by Sargent & Lundy that evaluated the effects of HRI technologies. In 2023, Sargent & Lundy issued an updated report which details that the HRI selected as the BSER in the ACE Rule would bring fewer emissions reductions than estimated in 2009. The 2023 report concludes that, with few exceptions, HRI technologies are less effective at reducing CO
2emissions than assumed 
in 2009. Further reinforcing the conclusion that HRIs would bring few reductions, the 2023 report also concluded that most sources had already optimized application of HRIs, and so there are fewer opportunities to reduce emissions than previously anticipated.
263 
Second, for a subset of sources, HRI 
are likely to cause a ‘‘rebound effect’’ leading to an increase in GHG emissions for those sources. The rebound effect is explained in detail in section VII.D.4.a.iii of this preamble. The ACE Rule’s analysis projected that the rule would increase CO
2emissions from 
power plants in 15 states and the District of Columbia. The EPA’s modeling projections assumed that, consistent with the rule, some sources would impose a small degree of efficiency improvements. The modeling showed that, as a consequence of these improvements, the rule would increase absolute emissions at some coal-fired sources as these sources became more efficient and displaced lower emitting sources like natural gas-fired EGUs.
264 
Even though the ACE Rule was 
projected to increase emissions in many states, these states were nevertheless obligated under the rule to assemble detailed state plans that evaluated available technologies and the performance of each existing coal-fired power plant, as described in section IX.A of this preamble. For example, the state was required to analyze the plant’s ‘‘annual generation,’’ ‘‘CO
2emissions,’’ 
‘‘[f]uel use, fuel price, and carbon content,’’ ‘‘operation and maintenance 
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265West Virginia CAA § 111(d) Partial Plan for 
Greenhouse Gas Emissions from Existing Electric 
Utility Generating Units (EGUs), https://dep.wv.gov/ daq/publicnoticeandcomment/Documents/ Proposed%20WV%20ACE%20State%20Partial%20Plan.pdf. costs,’’ ‘‘[h]eat rates,’’ ‘‘[e]lectric 
generating capacity,’’ and the ‘‘timeline for implementation,’’ among other information. 84 FR 32581 (July 8, 2019). The risk of an increase in emissions raises doubts that the HRI for coal-fired sources satisfies the statutory criteria to constitute the BSER for this category of sources. The core element of the BSER analysis is whether the emission reduction technology selected reduces emissions. See Essex Chem. Corp. v. 
Ruckelshaus, 486 F.2d 427, 441 (D.C. 
Cir. 1973) (noting ‘‘counter productive environmental effects’’ raises questions as to whether the BSER selected was in fact the ‘‘best’’). Moreover, this evaluation and the imposition of standards of performance was mandated even though the state plan would lead to an increase rather than decrease CO
2 
emissions. Imposing such an obligation on states under these circumstances was arbitrary. 
The EPA’s experience in 
implementing the ACE Rule reinforces these concerns. After the ACE Rule was promulgated, one state drafted a state plan that set forth a standard of performance that allowed the affected source to increase its emission rate. The draft partial plan would have applied to one source, the Longview Power, LLC facility, and would have established a standard of performance, based on the state’s consideration of the ‘‘candidate technologies,’’ that was higher (i.e., less 
stringent) than the source’s historical emission rate. Thus, the draft plan would not have achieved any emission reductions from the source, and instead 
would have allowed the source to increase its emissions, if it had been 
finalized.
265 
Because there is doubt that the 
minimal reductions projected by the ACE Rule would be achieved, and because the rebound effect could lead to an increase in emissions for many sources in many states, the EPA concludes that it is appropriate to repeal the ACE Rule and reevaluate the BSER for this category of sources. 
C. Developments Showing That Other 
Technologies Are the BSER for This Source Category 
Since the promulgation of the ACE 
Rule in 2019, the factual underpinnings of the rule have changed in several ways and lead the EPA to determine that HRI are not the BSER for coal-fired power plants. This reevaluation is consistent with FCC v. Fox Television Stations, 
Inc., 556 U.S. 502 (2009). There, the 
Supreme Court explained that an agency 
issuing a new policy ‘‘need not demonstrate to a court’s satisfaction that the reasons for the new policy are better than the reasons for the old one.’’ Instead, ‘‘it suffices that the new policy is permissible under the statute, that there are good reasons for it, and that the agency believes it to be better, which 
the conscious change of course adequately indicates.’’ Id. at 514–16 
(emphasis in original; citation omitted). 
Along with changes in the anticipated 
reductions from HRI, it makes sense for the EPA to reexamine the BSER because the costs of two control measures, co- firing with natural gas and CCS, have fallen for sources with longer-term operating horizons. As noted, the ACE Rule rejected natural gas co-firing as the BSER on grounds that it was too costly and would lead to inefficient use of natural gas. But as discussed in section VII.C.2.b of this preamble, the costs of natural gas co-firing are presently reasonable, and the EPA concludes that the costs of co-firing 40 percent by volume natural gas are cost-effective for existing coal-fired EGUs that intend to operate after January 1, 2032, and cease operation before January 1, 2039. In addition, changed circumstances— including that natural gas is available in greater amounts, that many coal-fired EGUs have begun co-firing with natural gas or converted wholly to natural-gas, and that there are fewer coal-fired EGUs in operation—mitigate the concerns the ACE Rule identified about inefficient use of natural gas. 
Similarly, the ACE Rule rejected CCS 
as the BSER on grounds that it was too costly. But the costs of CCS have substantially declined, as discussed in section VII.C.1.a.ii of the preamble, partly because of developments in the technology that have lowered capital costs, and partly because the IRA extended and increased the IRS section 45Q tax credit so that it defrays a higher portion of the costs of CCS. Accordingly, for coal-fired EGUs that will continue to operate past 2039, the EPA concludes that the costs of CCS are reasonable, as described in section VII.C.1.a.ii of the preamble. 
The emission reductions from these 
two technologies are substantial. For 
long-term coal-fired steam generating units, the BSER of 90 percent capture CCS results in substantial CO
2 
emissions reductions amounting to emission rates that are 88.4 percent lower on a lb/MWh-gross basis and 87.1 percent lower on a lb/MWh-net basis compared to units without capture, as described in section VII.C.2.b.iv of this preamble. For medium term units, the 
BSER of 40 percent natural gas co-firing achieves CO
2stack emissions reductions 
of 16 percent, as described in section VII.C.2.b.iv of this preamble. Given the availability of more effective, cost- reasonable technology, the EPA concludes that HRIs are not the BSER for all coal-fired EGUs. 
The EPA is thus finalizing a new 
policy for coal-fired power plants. This rule applies to those sources that intend to operate past January 1, 2032. For sources that intend to cease operations after January 1, 2032, but before January 1, 2039, the EPA concludes that the BSER is co-firing 40 percent by volume natural gas. The EPA concludes this control measure is appropriate because it achieves substantial reductions at reasonable cost. In addition, the EPA believes that because a large supply of natural gas is available, devoting part of this supply for fuel for a coal-fired steam generating unit in place of a percentage of the coal burned at the unit is an appropriate use of natural gas and will not adversely impact the energy system, as described in section VII.C.2.b.iii(B) of this preamble. For sources that intend to operate past January 1, 2039, the EPA concludes that the BSER is CCS with 90 percent capture of CO
2. The EPA believes that 
this control measure is appropriate because it achieves substantial reductions at reasonable cost, as described in section VII.C.1 of this preamble. 
The EPA is not concluding that HRI 
is the BSER for any coal-fired EGUs. As discussed in section VII.D.4.a, the EPA does not consider HRIs an appropriate BSER for coal-fired EGUs because these technologies would achieve few, if any, emissions reductions and may increase emissions due to the rebound effect. 
Most importantly, changed circumstances show that co-firing natural gas and CCS are available at reasonable cost, and will achieve more GHG emissions reductions. Accordingly, the EPA believes that HRI do not qualify as the BSER for any coal- fired EGUs, and that other approaches meet the statutory standard. On this basis, the EPA repeals the ACE Rule. 
D. Insufficiently Precise Degree of 
Emission Limitation Achievable From Application of the BSER 
The third independent reason why 
the EPA is repealing the ACE Rule is that the rule did not identify with sufficient specificity the BSER or the degree of emission limitation achievable through the application of the BSER. Thus, states lacked adequate guidance on the BSER they should consider and 
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level of emission reduction that the 
standards of performance must achieve. The ACE Rule determined the BSER to be a suite of HRI ‘‘candidate technologies,’’ but did not identify with specificity the degree of emission limitation states should apply in developing standards of performance for their sources. As a result, the ACE Rule conflicted with CAA section 111 and the implementing regulations, and thus failed to provide states adequate guidance so that they could ensure that their state plans were satisfactory and approvable by the EPA. 
CAA section 111 and the EPA’s 
longstanding implementing regulations establish a clear process for the EPA and states to regulate emissions of certain air pollutants from existing sources. ‘‘The statute directs the EPA to (1) ‘determine[ ],’ taking into account various factors, the ‘best system of emission reduction which . . . has been adequately demonstrated,’ (2) ascertain the ‘degree of emission limitation achievable through the application’ of that system, and (3) impose an emissions limit on new stationary sources that ‘reflects’ that amount.’’ West Virginia v. EPA, 597 U.S. at 709 
(quoting 42 U.S.C. 7411(d)). Further, ‘‘[a]lthough the States set the actual rules governing existing power plants, EPA itself still retains the primary regulatory role in Section 111(d) . . . [and] decides the amount of pollution reduction that must ultimately be achieved.’’ Id. at 2602. 
Once the EPA makes these 
determinations, the state must establish ‘‘standards of performance’’ for its sources that are based on the degree of emission limitation that the EPA determines in the emission guidelines. CAA section 111(a)(1) makes this clear through its definition of ‘‘standard of performance’’ as ‘‘a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the [BSER].’’ After the EPA determines the BSER, 40 CFR 60.22(b)(5), and the degree of emission limitation achievable from application of the BSER, ‘‘the States then submit plans containing the emissions restrictions that they intend to adopt and enforce in order not to exceed the 
permissible level of pollution established by EPA.’’ 597 U.S. at 710 (citing 40 CFR 60.23, 60.24; 42 U.S.C. 7411(d)(1)). 
The EPA then reviews the plan and 
approves it if the standards of performance are ‘‘satisfactory,’’ under CAA section 111(d)(2)(A). The EPA’s longstanding implementing regulations make clear that the EPA’s basis for determining whether the plan is 
‘‘satisfactory’’ includes that the plan must contain ‘‘emission standards . . . no less stringent than the corresponding emission guideline(s).’’ 40 CFR 60.24(c), 40 CFR 60.24a(c). In addition, under CAA section 111(d)(1), in ‘‘applying a standard of performance to any particular source’’ a state may consider, ‘‘among other factors, the remaining useful life of the existing source to which such standard applies.’’ This is also known as the RULOF provision and is discussed in section X.C.2 of this preamble. 
In the ACE Rule, the EPA recognized 
that the CAA required it to determine the BSER and identify the degree of emission limitation achievable through application of the BSER. 84 FR 32537 (July 8, 2019). But the rule did not make those determinations. Rather, the ACE Rule described the BSER as a list of ‘‘candidate technologies.’’ And the rule described the degree of emission limitation achievable by application of the BSER as ranges of reductions from the HRI technologies. The rule thus shifted the responsibility for determining the BSER and degree of emission limitation achievable from the EPA to the states. Accordingly, the ACE Rule did not meet the CAA section 111 requirement that the EPA determine the BSER or the degree of emission limitation from application of the BSER. 
As described above, the ACE Rule 
identified the HRI in the form of a list of seven ‘‘candidate technologies,’’ accompanied by a wide range of percentage improvements to heat rate that these technologies could provide. Indeed, for one of them, improved ‘‘O&M’’ practices (that is, operation and management practices), the range was ‘‘0 to >2%,’’ which is effectively unbounded. 84 FR 32537 (table 1) (July 8, 2019). The ACE Rule was clear that this list was simply the starting point for a state to calculate the standards of performance for its sources. That is, the seven sets of technologies were ‘‘candidate[s]’’ that the state could apply to determine the standard of performance for a source, and if the state did choose to apply one or more of them, the state could do so in a manner that yielded any percentage of heat rate improvement within the range that the EPA identified, or even outside that range. Thus, as a practical matter, the ACE Rule did not determine the BSER or any degree of emission limitation from application of the BSER, and so states had no guidance on how to craft approvable state plans. In this way, the ACE Rule did not adhere to the 
applicable statutory obligations. See 84 FR 32537–38 (July 8, 2019). The only constraints that the ACE 
Rule imposed on the states were 
procedural ones, and those did not give the EPA any benchmark to determine whether a plan could be approved or give the states any certainty on whether their plan would be approved. As noted above, when a state submitted its plan, it needed to show that it evaluated each candidate technology for each source or group of sources, explain how it determined the degree of emission limitation achievable, and include data about the sources. But because the ACE Rule did not identify a BSER or include a degree of emission limitation that the standards must reflect, the states lacked specific guidance on how to craft adequate standards of performance, and the EPA had no benchmark against which to evaluate whether a state’s submission was ‘‘satisfactory’’ under CAA section 111(d)(2)(A). Thus, the EPA’s review of state plans would be essentially a standardless exercise, notwithstanding the Agency’s longstanding view that it was ‘‘essential’’ that ‘‘EPA review . . . [state] plans for their substantive adequacy.’’ 40 FR 53342–43 (November 17, 1975). In 1975, the EPA explained that it was not appropriate to limit its review based ‘‘solely on procedural criteria’’ because otherwise ‘‘states could set extremely lenient standards . . . so long as EPA’s procedural requirements were met.’’ Id. at 53343. 
Finally, the ACE Rule’s approach to 
determining the BSER and degree of emission limitation departed from prior emission guidelines under CAA section 111(d), in which the EPA included a numeric degree of emission limitation. See, e.g., 42 FR 55796, 55797 (October 
18, 1977) (limiting emission rate of acid mist from sulfuric acid plants to 0.25 grams per kilogram of acid); 44 FR 29829 (May 22, 1979) (limiting concentrations of total reduced sulfur from most of the subcategories of kraft pulp mills, such as digester systems and lime kilns, to 5, 20, or 25 ppm over 12- hour averages); 61 FR 9919 (March 12, 1996) (limiting concentration of non- methane organic compounds from solid waste landfills to 20 parts per million by volume or a 98 percent reduction). The ACE Rule did not grapple with this change in position as required by FCC v. Fox Television Stations, Inc., 556 U.S. 
502 (2009), or explain why it was appropriate to provide a boundless degree of emission limitation achievable in this context. 
The EPA is finalizing the repeal the 
ACE Rule on this ground as well. The ACE Rule’s failure to determine the 
BSER and the associated degree of emission limitation achievable from 
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266Typically, the EPA assumes that the capital 
costs can be amortized over a period of 15 years. 
As discussed in section VII.C.1.a.ii of this preamble, in the case of CCS, the IRC section 45Q tax credit, which defrays a significant portion of the costs of CCS, is available for the first 12 years of operation. Accordingly, EPA generally assumed a 12-year amortization period in determining CCS costs. application of the BSER deviated from 
CAA section 111 and the implementing regulations. Without these determinations, the ACE Rule lacked any benchmark that would guide the states in developing their state plans, and by which the EPA could determine whether those state plans were satisfactory. 
For each of these three, independent 
reasons, repeal of the ACE Rule is proper. 
E. Withdrawal of Proposed NSR 
Revisions 
In addition to repealing the ACE Rule, 
the Agency is withdrawing the proposed revisions to the NSR applicability provisions that were included the ACE Rule proposal (83 FR 44756, 44773–83; August 31, 2018). These proposed revisions would have included an hourly emissions rate test to determine NSR applicability for a modified EGU, with the expressed purpose of alleviating permitting burdens for sources undertaking HRI projects pursuant to the ACE Rule emission guidelines. The ACE Rule final action did not include the NSR revisions, and the EPA indicated in that preamble that it intended to take final action on the NSR proposal in a separate action at a later date. However, the EPA did not take a final action on the NSR revisions, and the EPA has decided to no longer pursue them and to withdraw the proposed revisions. 
Withdrawal of the proposal to 
establish an hourly emissions test for NSR applicability for EGUs is appropriate because of the repeal of the ACE rule and the EPA’s conclusion that HRI is not the BSER for coal-fired EGUs. The EPA’s basis for proposing the NSR revisions was to ease permitting burdens for state agencies and sources that may result from implementing the ACE Rule. There was concern that, for sources that modified their EGU to 
improve the heat rate, if a source were to be dispatched more frequently because of improved efficiency (the ‘‘rebound effect’’), the source could experience an increase in absolute emissions for one or more pollutants and potentially trigger major NSR requirements. The hourly emissions rate test was proposed to relieve such sources that were undertaking HRI projects to comply with their state plans from the burdens of NSR permitting, particularly in cases in which a source has an increase in annual emissions of a pollutant. However, given that this final rule BSER is not based on HRIs for coal-fired EGUs, the NSR revisions proposed as part of the ACE Rule would no longer serve the purpose that the EPA expressed in that proposal 
preamble. 
Furthermore, in the event that any 
sources are increasing their absolute emissions after modifying an EGU, applicability of the NSR program is beneficial as a backstop that provides review of those situations to determine if additional controls or other emission limitations are necessary on a case-by- case basis to protect air quality. In addition, given that considerable time has passed since these EGU-specific NSR applicability revisions were proposed in 2018, should the EPA decide to pursue them at a later time, it is prudent for the Agency to propose them again at that time, accompanied with the EPA’s updated context and justification to support re-proposing the NSR revisions, rather than relying on the proposal from 2018. Therefore, the EPA is withdrawing these proposed NSR revisions. 
VII. Regulatory Approach for Existing 
Fossil Fuel-Fired Steam Generating Units 
Existing fossil fuel-fired steam 
generation units are the largest stationary source of CO
2emissions, 
emitting 909 MMT CO 2e in 2021. Recent 
developments in control technologies offer opportunities to reduce CO
2 
emissions from these sources. The EPA’s regulatory approach for these units is to require emissions reduction 
consistent with these technologies, where their use is cost-reasonable. 
A. Overview 
In this section of the preamble, the 
EPA identifies the BSER and degree of 
emission limitation achievable for the regulation of GHG emissions from existing fossil fuel-fired steam generating units. As detailed in section V of this preamble, to meet the requirements of CAA section 111(d), the EPA promulgates ‘‘emission guidelines’’ that identify the BSER and the degree of emission limitation achievable through the application of the BSER, and states then establish standards of performance for affected sources that reflect that level of stringency. To determine the BSER for a source category, the EPA identifies systems of emission reduction (e.g., control technologies) that have been adequately demonstrated and evaluates the potential emissions reduction, costs, any non-air health and environmental impacts, and energy requirements. As described in section V.C.1 of this preamble, the EPA has broad authority to create subcategories under CAA section 111(d). Therefore, where the sources in a category differ from each other by some characteristic that is relevant for the suitability of the 
emission controls, the EPA may create separate subcategories and make separate BSER determinations for those subcategories. 
The EPA considered the 
characteristics of fossil fuel-fired steam generating units that may impact the suitability of different control measures. First, the EPA observed that the type and amounts of fossil fuels—coal, oil, and natural gas—fired in the steam generating unit affect the performance 
and emissions reductions achievable by different control technologies, in part due to the differences in the carbon content of those fuels. The EPA recognized that many sources fire multiple types of fossil fuel. Therefore, the EPA is finalizing subcategories of coal-fired, oil-fired, and natural gas- fired steam generating units. The EPA is basing these subcategories, in part, on the amount of fuel combusted by the steam generating unit. 
The EPA then considered the BSER 
that may be suitable for each of those subcategories of fuel type. For coal-fired steam generating units, of the available control technologies, the EPA is determining that CCS with 90 percent capture of CO
2meets the requirements 
for BSER, including being adequately demonstrated and achieving significant emission reductions at reasonable cost for units operating in the long-term, as detailed in section VII.C.1.a of this preamble. Application of this BSER results in a degree of emission limitation equivalent to an 88.4 percent reduction in emission rate (lb CO
2/ 
MWh-gross). The compliance date for these sources is January 1, 2032. 
Typically, the EPA assumes that 
sources subject to controls operate in the long-term.
266See, for example, the 
2015 NSPS (80 FR 64509; October 23, 2015) or the 2011 CSAPR (76 FR 48208; August 8, 2011). Under that assumption, fleet average costs for CCS are comparable to the cost metrics the EPA has previously considered to be reasonable. However, the EPA observes that about half of the capacity (87 GW out of 181 GW) of existing coal-fired steam generating units have announced plans to permanently cease operation prior to 2039, as detailed in section IV.D.3.b of this preamble, affecting the period available for those sources to amortize the capital costs of CCS. 
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Accordingly, the EPA evaluated the 
costs of CCS for different amortization periods. For an amortization period of more than 7 years—such that sources operate after January 1, 2039— annualized fleet average costs are comparable to or less than the metrics of costs for controls that the EPA has previously found to be reasonable. However, the group of sources ceasing operation prior to January 1, 2039, have less time available to amortize the capital costs of CCS, resulting in higher annualized costs. 
Because the costs of CCS depend on 
the available amortization period, the EPA is creating a subcategory for sources demonstrating that they plan to permanently cease operation prior to January 1, 2039. Instead, for this subcategory of sources, the EPA is determining that natural gas co-firing at 40 percent of annual heat input meets the requirements of BSER. Application 
of the natural gas co-firing BSER results in a degree of emission limitation equivalent to a 16 percent reduction in emission rate (lb CO
2/MWh-gross). Co- 
firing at 40 percent entails significantly less control equipment and infrastructure than CCS, and as a result, the EPA has determined that affected sources are able to implement it more quickly than CCS, by January 1, 2030. Importantly, co-firing at 40 percent also entails significantly less capital cost than CCS, and as a result, the costs of co-firing are comparable to or less than the metrics for cost reasonableness with an amortization period that is 
significantly shorter than the period for CCS. The EPA has determined that the costs of co-firing meet the metrics for cost reasonableness for the majority of the capacity that permanently cease operation more than 2 years after the 
January 1, 2030, implementation date, or after January 1, 2032 (and up to December 31, 2038), and that therefore have an amortization period of more than 2 years (and up to 9 years). 
The EPA is also determining that 
sources demonstrating that they plan to permanently cease operation before January 1, 2032, are not subject to the 40 percent co-firing requirement. This is because their amortization period would be so short—2 years or less—that the costs of co-firing would, in general, be less comparable to the cost metrics for reasonableness for that group of sources. Accordingly, the EPA is defining the medium-term subcategory to include those sources demonstrating that they plan to permanently cease operating after December 31, 2031, and before January 1, 2039. 
Considering the limited emission 
reductions available in light of the cost reasonableness of controls with short amortization periods, the EPA is finalizing an applicability exemption for coal-fired steam generating units demonstrating that they plan to permanently cease operation before January 1, 2032. 
For natural gas- and oil-fired steam 
generating units, the EPA is finalizing subcategories based on capacity factor. 
Because natural gas- and oil-fired steam generating units with similar annual 
capacity factors perform similarly to one another, the EPA is finalizing a BSER of routine methods of operation and maintenance and a degree of emission limitation of no increase in emission rate for intermediate and base load subcategories. For low load natural gas- and oil-fired steam generating units, the EPA is finalizing a BSER of uniform fuels and respective degrees of emission limitation defined on a heat input basis (130 lb CO
2/MMBtu and 170 lb CO 2/ 
MMBtu). Furthermore, the EPA is finalizing presumptive standards for natural gas- and oil-fired steam generating units as follows: base load sources (those with annual capacity factors greater than 45 percent) have a presumptive standard of 1,400 lb CO
2/ 
MWh-gross, intermediate load sources (those with annual capacity factors greater than 8 percent and or less than or equal to 45 percent) have a presumptive standard of 1,600 lb CO
2/ 
MWh-gross. For low load oil-fired sources, the EPA is finalizing a presumptive standard of 170 lb CO
2/ 
MMBtu, while for low load natural gas- fired sources the EPA is finalizing a presumptive standard of 130 lb CO
2/ 
MMBtu. A compliance date of January 1, 2030, applies for all natural gas- and oil-fired steam generating units. 
The final subcategories and BSER are 
summarized in table 1 of this document. 
TABLE 1—S UMMARY OF FINAL BSER, S UBCATEGORIES , ANDDEGREES OF EMISSION LIMITATION FOR AFFECTED EGU S 
Affected 
EGUs Subcategory definition BSER Degree of 
emission 
limitation Presumptively 
approvable 
standard of 
performance * 
Long-term existing coal-fired 
steam generating units.Coal-fired steam generating units 
that are not medium-term units.CCS with 90 percent cap-
ture of CO 2.88.4 percent reduction in 
emission rate (lb CO 2/ 
MWh-gross).88.4 percent reduction in annual 
emission rate (lb CO 2/MWh- 
gross) from the unit-specific 
baseline. 
Medium-term existing coal- 
fired steam generating units.Coal-fired steam generating units 
that have demonstrated that they plan to permanently cease oper-ations after December 31, 2031, and before January 1, 2039.Natural gas co-firing at 40 
percent of the heat input to the unit.A 16 percent reduction in 
emission rate (lb CO
2/ 
MWh-gross).A 16 percent reduction in an-
nual emission rate (lb CO 2/ 
MWh-gross) from the unit- specific baseline. 
Base load existing oil-fired 
steam generating units.Oil-fired steam generating units with 
an annual capacity factor greater than or equal to 45 percent.Routine methods of oper-
ation and maintenance.No increase in emission rate 
(lb CO
2/MWh-gross).An annual emission rate limit of 
1,400 lb CO 2/MWh-gross. 
Intermediate load existing oil- 
fired steam generating units.Oil-fired steam generating units with 
an annual capacity factor greater than or equal to 8 percent and less than 45 percent.Routine methods of oper-
ation and maintenance.No increase in emission rate 
(lb CO
2/MWh-gross).An annual emission rate limit of 
1,600 lb CO 2/MWh-gross. 
Low load existing oil-fired 
steam generating units.Oil-fired steam generating units with 
an annual capacity factor less than 8 percent.lower-emitting fuels .............. 170 lb CO
2/MMBtu .............. 170 lb CO 2/MMBtu. 
Base load existing natural 
gas-fired steam generating units.Natural gas-fired steam generating 
units with an annual capacity fac-tor greater than or equal to 45 percent.Routine methods of oper-
ation and maintenance.No increase in emission rate 
(lb CO
2/MWh-gross).An annual emission rate limit of 
1,400 lb CO 2/MWh-gross. 
Intermediate load existing nat-
ural gas-fired steam gener-ating units.Natural gas-fired steam generating 
units with an annual capacity fac-tor greater than or equal to 8 per-cent and less than 45 percent.Routine methods of oper-
ation and maintenance.No increase in emission rate 
(lb CO
2/MWh-gross).An annual emission rate limit of 
1,600 lb CO 2/MWh-gross. 
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267The term ‘‘designated facility’’ means ‘‘any 
existing facility . . . which emits a designated 
pollutant and which would be subject to a standard of performance for that pollutant if the existing facility were an affected facility.’’ See 40 CFR 60.21a(b). 
268Under CAA section 111, the determination of 
whether a source is a new source or an existing source (and thus potentially a designated facility) is based on the date that the EPA proposes to 
establish standards of performance for new sources. 
269The EPA recognizes, however, that the word 
‘‘facility’’ is often understood colloquially to refer to a single power plant, which may have one or more EGUs co-located within the plant’s boundaries. TABLE 1—S UMMARY OF FINAL BSER, S UBCATEGORIES , ANDDEGREES OF EMISSION LIMITATION FOR AFFECTED EGU S— 
Continued 
Affected 
EGUs Subcategory definition BSER Degree of 
emission 
limitation Presumptively 
approvable 
standard of 
performance * 
Low load existing natural gas- 
fired steam generating units.Oil-fired steam generating units with 
an annual capacity factor less 
than 8 percent.lower-emitting fuels .............. 130 lb CO 2/MMBtu .............. 130 lb CO 2/MMBtu. 
* Presumptive standards of performance are discussed in detail in section X of the preamble. While states establish standards of performance for sources, the EPA 
provides presumptively approvable standards of performance based on the degree of emission limitation achievable through application of the BSER for each sub-
category. Inclusion in this table is for completeness. 
B. Applicability Requirements and 
Fossil Fuel-Type Definitions for Subcategories of Steam Generating Units 
In this section of the preamble, the 
EPA describes the rationale for the final applicability requirements for existing fossil fuel-fired steam generating units. The EPA also describes the rationale for the fuel type definitions and associated subcategories. 
1. Applicability Requirements 
For the emission guidelines, the EPA 
is finalizing that a designated facility
267 
is any fossil fuel-fired electric utility 
steam generating unit (i.e., utility boiler 
or IGCC unit) that: (1) was in operation or had commenced construction on or before January 8, 2014;
268(2) serves a 
generator capable of selling greater than 25 MW to a utility power distribution system; and (3) has a base load rating greater than 260 GJ/h (250 million British thermal units per hour (MMBtu/ h)) heat input of fossil fuel (either alone or in combination with any other fuel). Consistent with the implementing regulations, the term ‘‘designated facility’’ is used throughout this preamble to refer to the sources affected by these emission guidelines.
269For the 
emission guidelines, consistent with prior CAA section 111 rulemakings concerning EGUs, the term ‘‘designated facility’’ refers to a single EGU that is affected by these emission guidelines. The rationale for the final applicability requirements is the same as that for 40 CFR part 60, subpart TTTT (80 FR 64543–44; October 23, 2015). The EPA includes that discussion by reference here. 
Section 111(a)(6) of the CAA defines 
an ‘‘existing source’’ as ‘‘any stationary source other than a new source.’’ Therefore, the emission guidelines do not apply to any steam generating units that are new after January 8, 2014, or reconstructed after June 18, 2014, the applicability dates of 40 CFR part 60, subpart TTTT. Moreover, because the EPA is now finalizing revised standards of performance for coal-fired steam generating units that undertake a modification, a modified coal-fired steam generating unit would be considered ‘‘new,’’ and therefore not subject to these emission guidelines, if the modification occurs after the date 
the proposal was published in the Federal Register (May 23, 2023). Any coal-fired steam generating unit that has modified prior to that date would be considered an existing source that is subject to these emission guidelines. 
In addition, the EPA is finalizing in 
the applicability requirements of the emission guidelines many of the same exemptions as discussed for 40 CFR part 60, subpart TTTT, in section VIII.E.1 of this preamble. EGUs that may be excluded from the requirement to establish standards under a state plan are: (1) units that are subject to 40 CFR part 60, subpart TTTT, as a result of commencing a qualifying modification or reconstruction; (2) steam generating units subject to a federally enforceable permit limiting net-electric sales to one- third or less of their potential electric output or 219,000 MWh or less on an annual basis and annual net-electric sales have never exceeded one-third or less of their potential electric output or 219,000 MWh; (3) non-fossil fuel units (i.e., units that are capable of deriving at 
least 50 percent of heat input from non- fossil fuel at the base load rating) that are subject to a federally enforceable permit limiting fossil fuel use to 10 percent or less of the annual capacity factor; (4) combined heat and power (CHP) units that are subject to a federally enforceable permit limiting annual net-electric sales to no more than either 219,000 MWh or the product of 
the design efficiency and the potential electric output, whichever is greater; (5) units that serve a generator along with other affected EGU(s), where the effective generation capacity 
(determined based on a prorated output of the base load rating of EGU) is 25 MW or less; (6) municipal waste combustor units subject to 40 CFR part 60, subpart Eb; (7) commercial or industrial solid waste incineration units that are subject to 40 CFR part 60, subpart CCCC; (8) EGUs that derive greater than 50 percent of the heat input from an industrial process that does not produce any electrical or mechanical output or useful thermal output that is used outside the affected EGU; or (9) coal-fired steam generating units that have elected to permanently cease operation prior to January 1, 2032. 
The exemptions listed above at (4), 
(5), (6), and (7) are among the current exemptions at 40 CFR 60.5509(b), as discussed in section VIII.E.1 of this preamble. The exemptions listed above at (2), (3), and (8) are exemptions the EPA is finalizing revisions for 40 CFR part 60, subpart TTTT, and the rationale for the exemptions is in section VIII.E.1 of this preamble. For consistency with the applicability requirements in 40 CFR part 60, subpart TTTT, and 40 CFR part 60, subpart TTTTa, the Agency is finalizing these same exemptions for the applicability of the emission guidelines. 
2. Coal-Fired Units Permanently Ceasing 
Operation Before January 1, 2032 
The EPA is not addressing existing 
coal-fired steam generating units demonstrating that they plan to permanently cease operating before January 1, 2032, in these emission guidelines. Sources ceasing operation before that date have far less emission reduction potential than sources that will be operating longer, because there are unlikely to be appreciable, cost- reasonable emission reductions available on average for the group of sources operating in that timeframe. This is because controls that entail capital expenditures are unlikely to be 
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270As described in detail in section X.C.2 of this 
preamble, the EPA recognizes that particular 
affected EGUs may have characteristics that make it unreasonable to achieve the degree of emission limitation corresponding to 40 percent co-firing with natural gas. For example, a state may be able to demonstrate a fundamental difference between the costs the EPA considered in these emission guidelines and the costs to an affected EGU that plans to cease operation in late 2032. If such costs make it unreasonable for a particular unit to meet the degree of emission limitation corresponding to 40 percent co-firing with natural gas, the state may apply a less stringent standard of performance to that unit. Consistent with the requirements for calculating a less stringent standard of performance at 40 CFR 60.24a(f), under these emission guidelines states would consider whether it is reasonable for units that cannot cost-reasonably co- fire natural gas at 40 percent to co-fire at levels lower than 40 percent. It is thus appropriate that coal-fired EGUs that can reasonably co-fire any amount of natural gas be subject to these emission 
guidelines. 
271For the reasons described at length in section 
VI.B, the EPA does not believe that heat rate improvement measures or HRI are appropriate for sources retiring before January 1, 2032 because HRI applied to coal-fired sources achieve few emission reductions, and can lead to the ‘‘rebound effect’’ where CO
2emissions from the source increase 
rather than decrease as a consequence of imposing the technologies. 
272The EPA notes that this applicability 
exemption does not conflict with states’ ability to consider the remaining useful lives of ‘‘particular’’ sources that are subject to these emission guidelines. 42 U.S.C. 7411(d)(1). As the EPA’s implementing regulations specify, the provision for states’ consideration of RULOF is intended address the specific conditions of particular sources, 
whereas the EPA is responsible for determining generally how to regulate a source category under an emission guideline. Moreover, RULOF applies only to when a state is applying a standard of performance to an affected source—and the state would not apply a standard of performance to exempted sources. of reasonable cost for these sources due 
to the relatively short period over which they could amortize the capital costs of controls. 
In particular, in developing the 
emission guidelines, the EPA evaluated two systems of emission reduction that achieve substantial emission reductions for coal-fired steam generating units: CCS with 90 percent capture; and natural gas co-firing at 40 percent of heat input. For CCS, the EPA has determined that controls can be installed and fully operational by the compliance date of January 1, 2032, as detailed in section VII.C.1.a.i(E) of this preamble. CCS would therefore, in most cases, be unavailable to coal-fired steam generating units planning to cease operation prior to that date. Furthermore, the EPA evaluated the costs of CCS for different amortization periods. For an amortization period of more than 7 years—such that sources operate after January 1, 2039— annualized fleet average costs are comparable to or less than the costs of controls the EPA has previously determined to be reasonable ($18.50/ MWh of generation and $98/ton of CO
2 
reduced), as detailed in section VII.C.1.a.ii of this preamble. However, the costs for shorter amortization periods are higher. For sources ceasing operation by January 1, 2032, it would be unlikely that the annualized costs of CCS would be reasonable even were CCS installed at an earlier date (e.g., by 
January 1, 2030) due to the shorter amortization period available. 
Because the costs of CCS would be 
higher for shorter amortization periods, the EPA is finalizing a separate subcategory for sources demonstrating that they plan to permanently cease operating by January 1, 2039, with a BSER of 40 percent natural gas co-firing, as detailed in section VII.C.2.b.ii of this preamble. For natural gas co-firing, the EPA is finalizing a compliance date of January 1, 2030, as detailed in section VII.C.2.b.i(C) of this preamble. Therefore, the EPA assumes sources subject to a natural gas co-firing BSER can amortize costs for a period of up to 9 years. The EPA has determined that the costs of natural gas co-firing at 40 percent meet the metrics for cost reasonableness for the majority of the 
capacity that operate more than 2 years after the January 1, 2030, implementation date, i.e., that operate 
after January 1, 2032 (and up to December 31, 2038), and that therefore have an amortization period of more than 2 years (and up to 9 years). 
However, for sources ceasing 
operation prior to January 1, 2032, the EPA believes that establishing a best system of emission reduction 
corresponding to a substantial level of natural gas co-firing would broadly entail costs of control that are above those that the EPA is generally considering reasonable. Sources permanently ceasing operation before January 1, 2032 would have less than 2 years to amortize the capital costs, as detailed in section VII.C.2.a of this preamble. Compared to the metrics for cost reasonableness that EPA has previously deemed reasonable ($18.50/ MWh of generation and $98/ton of CO
2 
reduced), very few sources can co-fire 40 percent natural gas at costs comparable to these metrics with an amortization period of only one year; only 1 percent of units have costs that are below both $18.50/MWh of generation and $98/ton of CO
2reduced. 
The number of sources that can co-fire lower amounts of natural gas at costs comparable to these metrics is likewise limited—only approximately 34 percent of units can co-fire with 20 percent natural gas at costs lower than both cost metrics. Furthermore, the period that these sources would operate with co- firing for would be short, so that the emission reductions from that group of sources would be limited. 
By contrast, assuming a two-year 
amortization period, many more units can co-fire with meaningful amounts of natural gas at a cost that is consistent with the metrics EPA has previously used: 18 percent of units can co-fire with 40 percent natural gas at costs less than $98/ton and $18.50/MWh, and 50 percent of units can co-fire with 20 percent natural gas at costs lower than both metrics. Because a substantial number of sources can implement 40- 
percent co-firing with natural gas with an amortization period of two years or longer with reasonable costs, and even more can co-fire with lesser amounts with reasonable costs with amortization periods longer than two years,
270the EPA determined that a technology-based 
BSER was available for coal-fired units operating past January 1, 2032. 
Sources that retire before that date, 
however, are differently situated as described above. In light of the small number of sources that are planning to retire before January 1, 2032 that could cost-effectively co-fire with natural gas, coupled with the small amount of emissions reductions that can be achieved from co-firing in such a short time span, the EPA is choosing not to establish a BSER for these sources.
271 
Because, at this time, the EPA has 
determined that CCS and natural gas co- firing are not available at reasonable cost for sources ceasing operation before January 1, 2032, the EPA is not finalizing a BSER for such sources. Not finalizing a BSER for these sources is consistent with the Agency’s discretion to take incremental steps to address CO
2 
from sources in the category, and to direct the EPA’s limited resources at regulation of those sources that can achieve the most emission reductions. The EPA is therefore providing that existing coal-fired steam generating EGUs that have elected to cease operating before January 1, 2032, are not regulated by these emission guidelines. This exemption applies to a source until the earlier of December 31, 2031, or the date it demonstrates in the state plan that it plans to cease operation. If a source continues to operate past this date, it is no longer exempt from these emission guidelines. See section X.E.1 of this preamble for discussion of how state plans should address sources subject to exemption (9).
272 
3. Sources Outside of the Contiguous U.S. 
The EPA proposed the same emission 
guidelines for fossil fuel-fired steam 
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273Duke Edwardsport DOE FEED Study Fact 
Sheet. https://www.energy.gov/sites/default/files/ 
2024-01/OCED_ CCFEEDs_ AwardeeFactSheet_
Duke_ 1.5.2024.pdf. 
274For additional details on pre-combustion CO 2 
capture, please see the final TSD, GHG Mitigation 
Measures for Steam Generating Units. generating units in non-continental 
areas (i.e., Hawaii, the U.S. Virgin 
Islands, Guam, American Samoa, the Commonwealth of Puerto Rico, and the Northern Mariana Islands) and non- contiguous areas (non-continental areas and Alaska) as the EPA proposed for comparable units in the contiguous 48 states. The EPA notes that the modeling that supports the final emission guidelines focus on sources in the contiguous U.S. Further, the EPA notes that few, if any, coal-fired steam generating units operate outside of the contiguous 48 states and meet the applicability criteria. Finally, the EPA notes that the proposed BSER and degree of emissions limitation for non- continental oil-fired steam generating units would have achieved few emission reductions. Therefore, the EPA is not finalizing emission guidelines for existing steam generating units in states and territories (including Alaska, Hawaii, Guam, Puerto Rico, and the U.S. Virgin Islands) that are outside of the contiguous U.S. at this time. 
4. IGCC Units 
The EPA notes that existing IGCC 
units were included in the proposed 
applicability requirements and that, in section VII.B of this preamble, the EPA is finalizing inclusion of those units in the subcategory of coal-fired steam generating units. IGCC units gasify coal or solid fossil fuel (e.g., pet coke) to 
produce syngas (a mixture of carbon monoxide and hydrogen), and either burn the syngas directly in a combined cycle unit or use a catalyst for water-gas shift (WGS) to produce a pre- combustion gas stream with a higher concentration of CO
2and hydrogen, 
which can be burned in a hydrogen turbine combined cycle unit. As described in section VII.C of this preamble, the final BSER for coal-fired steam generating units includes co- firing natural gas and CCS. The few IGCC units that now operate in the U.S. either burn natural gas exclusively—and as such operate as natural gas combined cycle units—or in amounts near to the 40 percent level of the natural gas co- firing BSER. Additionally, IGCC units may be suitable for pre-combustion CO
2 
capture. Because the CO 2concentration 
in the pre-combustion gas, after WGS, is high relative to coal-combustion flue gas, pre-combustion CO
2capture for 
IGCC units can be performed using either an amine-based (or other solvent- based) capture process or a physical 
absorption capture process. Alternatively, post-combustion CO
2 
capture can be applied to the source. The one existing IGCC unit that still uses coal was recently awarded funding from DOE for a front-end engineering 
design (FEED) study for CCS targeting a capture efficiency of more than 95 percent.
273For these reasons, the EPA is 
not distinguishing IGCC units from other coal-fired steam generating EGUs, so that the BSER of co-firing for medium-term coal-fired units and CCS for long-term coal-fired units apply to IGCC units.
274 
5. Fossil Fuel-Type Definitions for Subcategories of Steam Generating Units 
In this action, the EPA is finalizing 
definitions for subcategories of existing fossil fuel-fired steam generating units based on the type and amount of fossil fuel used in the unit. The EPA is finalizing separate subcategories based on fuel type because the carbon content of the fuel combusted affects the output emission rate (i.e., lb CO
2/MWh). Fuels 
with a higher carbon content produce a greater amount of CO
2emissions per 
unit of fuel combusted (on a heat input 
basis, MMBtu) and per unit of electricity generated (i.e., MWh). 
The EPA proposed fossil fuel type 
subcategory definitions based on the definitions in 40 CFR part 63, subpart UUUUU, and the fossil fuel definitions in 40 CFR part 60, subpart TTTT. Those proposed definitions were determined by the relative heat input contribution of the different fuels combusted in a unit during the 3 years prior to the proposed compliance date of January 1, 2030. Further, to be considered an oil- fired or natural gas-fired unit for purposes of this emission guideline, a source would no longer retain the capability to fire coal after December 31, 2029. 
The EPA proposed a 3-year lookback 
period, so that the proposed fuel-type subcategorization would have been based, in part, on the fuel type fired between January 1, 2027, and January 1, 2030. However, the intent of the proposed fuel type subcategorization was to base the fuel type definition on the state of the source on January 1, 2030. Therefore, the EPA is finalizing the following fuel type subcategory definitions: 
•A coal-fired steam generating unit 
is an electric utility steam generating unit or IGCC unit that meets the definition of ‘‘fossil fuel-fired’’ and that burns coal for more than 10.0 percent of the average annual heat input during any continuous 3-calendar-year period after December 31, 2029, or for more than 15.0 percent of the annual heat input during any one calendar year after December 31, 2029, or that retains the capability to fire coal after December 31, 2029. 
•An oil-fired steam generating unit is 
an electric utility steam generating unit meeting the definition of ‘‘fossil fuel- fired’’ that is not a coal-fired steam generating unit, that no longer retains the capability to fire coal after December 31, 2029, and that burns oil for more than 10.0 percent of the average annual heat input during any continuous 3- calendar-year period after December 31, 2029, or for more than 15.0 percent of the annual heat input during any one calendar year after December 31, 2029. 
•A natural gas-fired steam 
generating unit is an electric utility steam generating unit meeting the definition of ‘‘fossil fuel-fired,’’ that is not a coal-fired or oil-fired steam generating unit, that no longer retains the capability to fire coal after December 31, 2029, and that burns natural gas for more than 10.0 percent of the average annual heat input during any continuous 3-calendar-year period after December 31, 2029, or for more than 15.0 percent of the annual heat input during any one calendar year after December 31, 2029. 
The EPA received some comments on 
the fuel type definitions. Those comments and responses are as follows. 
Comment: Some industry 
stakeholders suggested changes to the proposed definitions for fossil fuel type. Specifically, some commenters requested that the reference to the initial compliance date be removed and that the fuel type determination should instead be rolling and continually update after the initial compliance date. Those commenters suggested this would, for example, allow sources in the coal-fired subcategory that begin natural gas co-firing in 2030 to convert to the natural-gas fired subcategory prior to the proposed date of January 1, 2040, instead of ceasing operation. 
Other industry commenters suggested 
that to be a natural gas-fired steam generating unit, a source could either meet the heat input requirements during the 3 years prior to the compliance date or (emphasis added) no longer retain the 
capability to fire coal after December 31, 2029. Those commenters noted that, as proposed, a source that had planned to convert to 100 percent natural gas-firing would essentially have to do so prior to January 1, 2027, to meet the proposed heat input-based definition, in addition to removing the capability to fire coal by the compliance date. 
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Response: Although full natural gas 
conversions are not a measure that the 
EPA considered as a potential BSER, the emission guidelines do not prohibit such conversions should a state elect to require or accommodate them. As noted above, the EPA recognizes that many steam EGUs that formerly utilized coal as a primary fuel have fully or partially converted to natural gas, and that additional steam EGUs may elect to do so during the implementation period for these emission guidelines. However, these emission guidelines place reasonable constraints on the timing of such a conversion in situations where a source seeks to be regulated as a natural gas-fired steam EGU rather than as a coal-fired steam EGU. The EPA believes that such constraints are necessary in order to avoid creating a perverse incentive for EGUs to defer conversions in a way that could undermine the emission reduction purpose of the rule. Therefore, the EPA disagrees with those commenters that suggest the EPA should, in general, allow EGUs to be regulated as natural gas-fired steam EGUs when they undertake such conversions past January 1, 2030. 
However, the EPA acknowledges that 
the proposed subcategorization would have essentially required a unit to convert to natural gas by January 1, 2027 in order to be regulated as a natural gas- fired steam EGU. The EPA is finalizing fuel type subcategorization based on the state of the source on the compliance date of January 1, 2030, and during any period thereafter, as detailed in section VII.B of this preamble. Should a source not be able to fully convert to natural gas by this date, it would be treated as a coal-fired steam generating EGU; however, the state may be able to use the RULOF provisions, as discussed in 
section X.C.2 of this preamble, to particularize a standard of performance for the unit. Note that if a state relies on operating conditions within the control of the source as the basis of providing a less stringent standard of performance or longer compliance schedule, it must include those operating conditions as an enforceable requirement in the state plan. 40 CFR 60.24a(g). 
C. Rationale for the BSER for Coal-Fired 
Steam Generating Units 
This section of the preamble describes 
the rationale for the final BSERs for existing coal-fired steam generating units based on the criteria described in section V.C of this preamble. 
At proposal, the EPA evaluated two 
primary control technologies as potentially representing the BSER for existing coal-fired steam generating units: CCS and natural gas co-firing. For sources operating in the long-term, the 
EPA proposed CCS with 90 percent capture as BSER. For sources operating in the medium-term (i.e., those 
demonstrating that they plan to permanently cease operation by January 1, 2040), the EPA proposed 40 percent natural gas co-firing as BSER. For imminent-term and near-term sources ceasing operation earlier, the EPA proposed BSERs of routine methods of operation and maintenance. 
The EPA is finalizing CCS with 90 
percent capture as BSER for coal-fired steam generating units because CCS can achieve a substantial amount of emission reductions and satisfies the other BSER criteria. CCS has been adequately demonstrated and results in by far the largest emissions reductions of the available control technologies. As noted below, the EPA has also determined that the compliance date for CCS is January 1, 2032. CCS, however, entails significant up-front capital expenditures that are amortized over a period of years. The EPA evaluated the cost for different amortization periods, and the EPA has concluded that CCS is cost-reasonable for units that operate past January 1, 2039. As noted in section IV.D.3.b of this preamble, about half (87 GW out of 181 GW) of all coal- fired capacity currently in existence has announced plans to permanently cease operations by January 1, 2039, and additional sources are likely to do so because they will be older than the age at which sources generally have permanently ceased operations since 2000. The EPA has determined that the remaining sources that may operate after January 1, 2039, can, on average, install CCS at a cost that is consistent with the EPA’s metrics for cost reasonableness, accounting for an amortization period for the capital costs of more than 7 years, as detailed in section VII.C.1.a.ii of this preamble. If a particular source has costs of CCS that are fundamentally different from those amounts, the state may consider it to be a candidate for a different control requirement under the RULOF provision, as detailed in section X.C.2 of this preamble. For the group of sources that permanently cease operation before January 1, 2039, the EPA has concluded that CCS would in general be of higher cost, and therefore is finalizing a subcategory for these units, termed medium-term units, and finalizing 40 percent natural gas co- firing on a heat input basis as the BSER. 
These final subcategories and BSERs 
are largely consistent with the proposal, which included a long-term subcategory for sources that did not plan to 
permanently cease operations by January 1, 2040, with 90 percent capture CCS as the BSER; and a medium-term 
subcategory for sources that permanently cease operations by that date and were not in any of the other proposed subcategories, discussed next, with 40 percent co-firing as the BSER. For both subcategories, the compliance date was January 1, 2030. The EPA also proposed an imminent-term subcategory, for sources that planned to permanently cease operations by January 1, 2032; and a near-term subcategory, for sources that planned to permanently case operations by January 1, 2035, and that limited their annual capacity utilization to 20 percent. The EPA proposed a BSER of routine methods of operation and maintenance for these two subcategories. 
The EPA is not finalizing these 
imminent-term and near-term subcategories. In addition, after considering the comments, the EPA acknowledges that some additional time from what was proposed may be beneficial for the planning and installation of CCS. Therefore, the EPA is finalizing a January 1, 2032, compliance date for long-term existing coal-fired steam generating units. As noted above, the EPA’s analysis of the costs of CCS also indicates that CCS is cost-reasonable with a minimum amortization period of seven years; as a result, the final emission guidelines would apply a CCS-based standard only to those units that plan to operate for at least seven years after the compliance deadline (i.e., units that plan to remain 
in operation after January 1, 2039). For medium-term sources subject to a natural gas co-firing BSER, the EPA is finalizing a January 1, 2030, compliance date because the EPA has concluded that this provides a reasonable amount of time to begin co-firing, a technology that entails substantially less up-front infrastructure and, relatedly, capital expenditure than CCS. 
1. Long-Term Coal-Fired Steam 
Generating Units 
The EPA is finalizing CCS with 90 
percent capture of CO
2at the stack as 
BSER for long-term coal-fired steam generating units. Coal-fired steam generating units are the largest 
stationary source of CO
2in the United 
States. Coal-fired steam generating units have higher emission rates than other generating technologies, about twice the emission rate of a natural gas combined cycle unit. Typically, even newer, more efficient coal-fired steam generating units emit over 1,800 lb CO
2/MWh- 
gross, while many existing coal-fired steam generating units have emission rates of 2,200 lb CO
2/MWh-gross or 
higher. As noted in section IV.B of this 
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275U.S. Environmental Protection Agency (EPA). 
Inventory of U.S. Greenhouse Gas Emissions and 
Sinks: 1990–2021. U.S. Greenhouse Gas Emissions by Inventory Sector, 2021. https://cfpub.epa.gov/ ghgdata/inventoryexplorer/index.html#iallsectors/ allsectors/allgas/inventsect/current. 276Other technologies may be used to capture 
CO 2, as described in the final TSDs, GHG Mitigation 
Measures for Steam Generating Units and the GHG Mitigation Measures—Carbon Capture and Storage for Combustion Turbines, available in the rulemaking docket. 27780 FR 64549 (October 23, 2015). 
278Bottoms, R.R. Process for Separating Acidic 
Gases (1930) United States patent application. United States Patent US1783901A; Allen, A.S. and Arthur, M. Method of Separating Carbon Dioxide from a Gas Mixture (1933) United States Patent Application. United States Patent US1934472A. preamble, coal-fired sources emitted 909 
MMT CO 2e in 2021, 59 percent of the 
GHG emissions from the power sector and 14 percent of the total U.S. GHG emissions—contributing more to U.S. GHG emissions than any other sector, aside from transportation road sources.
275Furthermore, considering 
the sources in the long-term subcategory will operate longer than sources with shorter operating horizons, long-term coal-fired units have the potential to emit more total CO
2. 
CCS is a control technology that can 
be applied at the stack of a steam generating unit, achieves substantial reductions in emissions and can capture and permanently sequester more than 90 percent of CO
2emitted by coal-fired 
steam generating units. The technology is adequately demonstrated, given that it has been operated at scale and is widely applicable to these sources, and there are vast sequestration opportunities across the continental U.S. Additionally, the costs for CCS are reasonable, in light of recent technology cost declines and policies including the tax credit under IRC section 45Q. Moreover, the non-air quality health and environmental impacts of CCS can be mitigated and the energy requirements of CCS are not unreasonably adverse. The EPA’s weighing of these factors together provides the basis for finalizing CCS as BSER for these sources. In addition, this BSER determination aligns with the caselaw, discussed in section V.C.2.h of the preamble, stating that CAA section 111 encourages continued advancement in pollution control technology. 
At proposal, the EPA also evaluated 
natural gas co-firing at 40 percent of heat input as a potential BSER for long- term coal-fired steam generating units. While the unit level emission rate reductions of 16 percent achieved by 40 percent natural gas co-firing are appreciable, those reductions are substantially less than CCS with 90 percent capture of CO
2. Therefore, 
because CCS achieves more reductions at the unit level and is cost-reasonable, the EPA is not finalizing natural gas co- firing as the BSER for these units. Further, the EPA is not finalizing partial-CCS at lower capture rates (e.g., 30 percent) because it achieves substantially fewer unit-level reductions at greater cost, and because CCS at 90 percent is achievable. Notably, the IRC 
section 45Q tax credit may not be available to defray the costs of partial 
CCS and the emission reductions would be limited. And the EPA is not finalizing HRI as the BSER for these units because of the limited reductions and potential rebound effect. 
a. Rationale for CCS as the BSER for 
Long-Term Coal-Fired Steam Generating Units 
In this section of the preamble, the 
EPA explains the rationale for CCS as the BSER for existing long-term coal- fired steam generating units. This section discusses the aspects of CCS that are relevant for existing coal-fired steam generating units and, in particular, long- term units. As noted in section VIII.F.4.c.iv of this preamble, much of this discussion is also relevant for the EPA’s determination that CCS is the BSER for new base load combustion turbines. 
In general, CCS has three major 
components: CO
2capture, 
transportation, and sequestration/ storage. Detailed descriptions of these components are provided in section VII.C.1.a.i of this preamble. As an overview, post-combustion capture processes remove CO
2from the exhaust 
gas of a combustion system, such as a utility boiler or combustion turbine. This technology is referred to as ‘‘post- combustion capture’’ because CO
2is a 
product of the combustion of the primary fuel and the capture takes place after the combustion of that fuel. The exhaust gases from most combustion processes are at atmospheric pressure, contain somewhat dilute concentrations of CO
2,and are moved through the flue 
gas duct system by fans. To separate the CO
2contained in the flue gas, most 
current post-combustion capture 
systems utilize liquid solvents— commonly amine-based solvents—in CO
2scrubber systems using chemical 
absorption (or chemisorption).276In a 
chemisorption-based separation process, the flue gas is processed through the CO
2scrubber and the CO 2is absorbed 
by the liquid solvent. The CO 2-rich 
solvent is then regenerated by heating the solvent to release the captured CO
2. 
The high purity CO 2is then 
compressed and transported, generally through pipelines, to a site for geologic sequestration (i.e., the long-term 
containment of CO
2in subsurface 
geologic formations). Pipelines are subject to Federal safety regulations administered by PHMSA. Furthermore, sequestration sites are widely available across the nation, and the EPA has developed a comprehensive regulatory structure to oversee geologic sequestration projects and assure their safety and effectiveness.
277 
i. Adequately Demonstrated 
In this section of the preamble, the 
EPA explains the rationale for finalizing its determination that 90 percent capture applied to long-term coal-fired steam generating units is adequately demonstrated. In this section, the EPA first describes how simultaneous operation of all components of CCS functioning in concert with one another has been demonstrated, including a commercial scale application on a coal- fired steam generating unit. The demonstration of the individual components of CO
2capture, transport, 
and sequestration further support that CCS is adequately demonstrated. The EPA describes how demonstrations of CO
2capture support that 90 percent 
capture rates are adequately demonstrated. The EPA further describes how transport and geologic sequestration are adequately demonstrated, including the feasibility of transport infrastructure and the broad availability of geologic sequestration reservoirs in the U.S. 
(A) Simultaneous Demonstration of CO
2 
Capture, Transport, and Sequestration 
The EPA proposed that CCS was 
adequately demonstrated for 
applications on combustion turbines and existing coal-fired steam generating units. 
On reviewing the available 
information, all components of CCS— CO
2capture, CO 2transport, and CO 2 
sequestration—have been demonstrated concurrently, with each component operating simultaneously and in concert with the other components. 
(1) Industrial Applications of CCS 
Solvent-based CO
2capture was 
patented nearly 100 years ago in the 
1930s278and has been used in a variety 
of industrial applications for decades. For example, since 1978, an amine- based system has been used to capture approximately 270,000 metric tons of CO
2per year from the flue gas of the 
bituminous coal-fired steam generating units at the 63 MW Argus Cogeneration Plant at Searles Valley Minerals (Trona, 
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279Dooley, J.J., et al. (2009). ‘‘An Assessment of 
the Commercial Availability of Carbon Dioxide 
Capture and Storage Technologies as of June 2009.’’ U.S. DOE, Pacific Northwest National Laboratory, under Contract DE–AC05–76RL01830. 
280U.S. Department of Transportation, Pipeline 
and Hazardous Material Safety Administration, ‘‘Hazardous Annual Liquid Data.’’ 2022. https://www.phmsa.dot.gov/data-and-statistics/pipeline/ gas-distribution-gas-gathering-gas-transmission- hazardous-liquids. 
281GHGRP US EPA. https://www.epa.gov/ 
ghgreporting/supply-underground-injection-and- geologic-sequestration-carbon-dioxide. 
282Carbon Capture and Storage in the United 
States. CBO. December 13, 2023. https://www.cbo.gov/publication/59345. 
283Id. 
284https://netl.doe.gov/research/Coal/energy- 
systems/gasification/gasifipedia/great-plains. 
285https://co2re.co/FacilityData. 286Quest Carbon Capture and Storage Project 
Annual Summary Report, Alberta Department of Energy: 2021. https://open.alberta.ca/publications/ quest-carbon-capture-and-storage-project-annual- report-2021. 
287Aquistore Project. https://ptrc.ca/media/ 
whats-new/aquistore-co2-storage-project-reached- +500000-tonnes-stored. California).279Furthermore, thousands 
of miles of CO 2pipelines have been 
constructed and securely operated in 
the U.S. for decades.280And tens of 
millions of tons of CO 2have been 
permanently stored deep underground either for geologic sequestration or in association with EOR.
281There are 
currently at least 15 operating CCS projects in the U.S., and another 121 that are under construction or in advanced stages of development.
282 
This broad application of CCS demonstrates that the components of CCS have been successfully operated simultaneously. The Shute Creek Facility has a capture capacity of 7 million metric tons per year and has been in operation since 1986.
283The 
facility uses a solvent-based process to remove CO
2from natural gas, and the 
captured CO 2is stored in association 
with EOR. Another example of CCS in industrial applications is the Great Plains Synfuels Plant has a capture capacity of 3 million metric tons per year and has been in operation since 2000.
284 285 The Great Plains Synfuels 
Plant (Beulah, North Dakota) uses a 
solvent-based process to remove CO 2 
from lignite-derived syngas, the CO 2is 
transported by the Souris Valley pipeline, and stored underground in association with EOR in the Weyburn and Midale Oil Units in Saskatchewan, Canada. Over 39 million metric tons of CO
2has been captured since 2000. 
(2) Various CO 2capture methods are 
used in industrial applications and are tailored to the flue gas conditions of a particular industry (see the TSD GHG Mitigation Measures for Steam Generating Units for details). Of those capture technologies, amine solvent- based capture has been demonstrated for removal of CO
2from the post- 
combustion flue gas of fossil fuel-fired EGUs. The Quest CO
2capture facility in 
Alberta, Canada, uses amine-based CO 2 
capture retrofitted to three existing steam methane reformers at the Scotford 
Upgrader facility (operated by Shell Canada Energy) to capture and sequester approximately 80 percent of the CO
2in 
the produced syngas.286Amine-solvents 
are also applied for post-combustion capture from fossil fuel fired EGUs. The Quest facility has been operating since 2015 and captures approximately 1 million metric tons of CO
2per year. 
Applications of CCS at Coal-Fired Steam Generating Units 
For electricity generation 
applications, this includes operation of CCS at Boundary Dam Unit 3 in Saskatchewan, Canada. CCS at Boundary Dam Unit 3 includes capture of the CO
2from the flue-gas of the fossil 
fuel-fired EGU, compression of the CO 2 
onsite and transport via pipeline offsite, 
and storage of the captured CO 2 
underground. Storage of the CO 2 
captured at Boundary Dam primarily occurs via EOR. Moreover, CO
2captured 
from Boundary Dam Unit 3 is also stored in a deep saline aquifer at the Aquistore Deep Saline CO
2Storage 
Project, which has permanently stored over 550,000 tons of CO
2to date.287 
Other demonstrations of CCS include the 240 MWe Petra Nova CCS project at the subbituminous coal-fired W.A. Parish plant in Texas, which, because it was EPAct05-assisted, we cite as useful in section VII.C.1.a.i(B)(2) of this preamble, but not essential, corroboration. See section VII.C.1.a.i(H)(1) for a detailed description of how the EPA considers information from EPAct05-assisted projects. 
Commenters stated that that all 
constituent components of CCS—carbon capture, transportation, and sequestration—have not been adequately demonstrated in integrated, simultaneous operation. We disagree with this comment. The record described in the preceding shows that all components have been demonstrated simultaneously. Even if the record only included demonstration of the individual components of CCS, the EPA would still determine that CCS is adequately demonstrated as it would be reasonable on a technical basis that the individual components are capable of functioning together—they have been engineered and designed to do so, and the record for the demonstration of the individual components is based on 
decades of direct data and experience. 
(B) CO
2Capture Technology at Coal- 
Fired Steam Generating Units 
The EPA is finalizing the 
determination that the CO 2capture 
component of CCS has been adequately 
demonstrated at a capture efficiency of 90 percent, is technically feasible, and is achievable over long periods (e.g., a 
year) for the reasons summarized here and detailed in the following subsections of this preamble. This determination is based, in part, on the demonstration of the technology at existing coal-fired steam generating units, including the commercial-scale installation at Boundary Dam Unit 3. The application of CCS at Boundary Dam follows decades of development of CO
2capture for coal-fired steam 
generating units, as well as numerous smaller-scale demonstrations that have successfully implemented this technology. Review of the available information has also identified specific, currently available, minor technological improvements that can be applied today to better the performance of new capture plant retrofits, and which can assure that the capture plants achieve 90 percent capture. The EPA’s determination that 90 percent capture of CO
2is adequately demonstrated is 
further corroborated by EPAct05- assisted projects, including the Petra Nova project. 
Moreover, several CCS retrofit 
projects on coal-fired steam generating units are in progress that apply the lessons from the prior projects and use solvents that achieve higher capture rates. Technology providers that supply those solvents and the associated process technologies have made statements concluding that the technology is commercially proven and available today and have further stated 
that those solvents achieve capture rates of 95 percent or greater. Technology providers have decades of experience and have done the work to responsibly scale up the technology over that time across a range of flue gas compositions. Taking all of those factors into consideration, and accounting for the operation and flue gas conditions of the affected sources, solvent-based capture will consistently achieve capture rates of 90 percent or greater for the fleet of long-term coal-fired steam generating units. 
Various technologies may be used to 
capture CO
2, the details of which are 
described generally in section IV.C.1 of this preamble and in more detail in the final TSD, GHG Mitigation Measures for Steam Generating Units, which is 
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288Technologies to capture CO 2are also 
discussed in the final TSD, GHG Mitigation 
Measures—Carbon Capture and Storage for Combustion Turbines. 
289For pre-combustion capture (as is applicable 
to an IGCC unit), syngas produced by gasification passes through a water-gas shift catalyst to produce a gas stream with a higher concentration of hydrogen and CO
2. The higher CO 2concentration 
relative to conventional combustion flue gas reduces the demands (power, heating, and cooling) of the subsequent CO
2capture process (e.g., solid 
sorbent-based or solvent-based capture); the treated hydrogen can then be combusted in the unit. 290Giannaris, S., et al. Proceedings of the 15th 
International Conference on Greenhouse Gas Control Technologies (March 15–18, 2021). SaskPower’s Boundary Dam Unit 3 Carbon Capture Facility—The Journey to Achieving Reliability. https://papers.ssrn.com/sol3/papers.cfm?abstract _
id=3820191. 
291SaskPower Annual Report (2015–16). https:// 
www.saskpower.com/about-us/Our-Company/∼/ 
link.aspx?_ id=29E795C8C20D48398EAB
5E3273C256AD&_ z=z. 293Aquistore. https://ptrc.ca/aquistore. 
294Id. available in the rulemaking docket.288 
For post-combustion capture, these 
technologies include solvent-based methods (e.g., amines, chilled 
ammonia), solid sorbent-based methods, membrane filtration, pressure-swing adsorption, and cryogenic methods.
289 
Lastly, oxy-combustion uses a purified oxygen stream from an air separation unit (often diluted with recycled CO
2to 
control the flame temperature) to combust the fuel and produce a higher concentration of CO
2in the flue gas, as 
opposed to combustion with oxygen in air which contains 80 percent nitrogen. The CO
2can then be separated by the 
aforementioned CO 2capture methods. 
Of the available capture technologies, 
solvent-based processes have been the most widely demonstrated at commercial scale for post-combustion capture and are applicable to use with either combustion turbines or steam generating units. 
The EPA’s identification of CCS with 
90 percent capture as the BSER is premised, in part, on an amine solvent- based CO
2system. Amine solvents used 
for carbon capture are typically proprietary, although non-proprietary solvents (e.g., monoethanolamine, MEA) 
may be used. Carbon capture occurs by reactive absorption of the CO
2from the 
flue gas into the amine solution in an absorption column. The amine reacts with the CO
2but will also react with 
impurities in the flue gas, including SO
2. PM will also affect the capture 
system. Adequate removal of SO 2and 
PM prior to the CO 2capture system is 
therefore necessary. After pretreatment of the flue gas with conventional SO
2 
and PM controls, the flue gas goes through a quencher to cool the flue gas and remove further impurities before the CO
2absorption column. After 
absorption, the CO 2-rich amine solution 
passes to the solvent regeneration column, while the treated gas passes through a water and/or acid wash column to limit emission of amines or other byproducts. In the solvent regeneration column, the solution is heated (using steam) to release the absorbed CO
2. The released CO 2is then 
compressed and transported offsite, usually by pipeline. The amine solution from the regenerating column is then cooled, a portion of the lean solvent is treated in a solvent reclaiming process to mitigate degradation of the solvent, and the lean solvent streams are recombined and sent back to the absorption column. 
(1) Capture Demonstrations at Coal- 
Fired Steam Generating Units 
(a) SaskPower’s Boundary Dam Unit 3 
SaskPower’s Boundary Dam Unit 3, a 
110 MW lignite-fired unit in 
Saskatchewan, Canada, was designed to achieve CO
2capture rates of 90 percent 
using an amine-based post-combustion capture system retrofitted to the existing steam generating unit. The capture plant, which began operation in 2014, is the first full-scale CO
2capture system 
retrofit on an existing coal-fired power plant. It uses the amine-based Shell CANSOLV
®process, which includes an 
amine-based SO 2scrubbing process and 
a separate amine-based CO 2capture 
process, with integrated heat and power from the steam generating unit.
290 
After undergoing maintenance and 
design improvements in September and October of 2015 to address technical and mechanical challenges faced in its first year of operation, Boundary Dam Unit 3 completed a 72-hour test of its design capture rate (3,240 metric tons/ day), and captured 9,695 metric tons of CO
2or 99.7 percent of the design 
capacity (approximately 89.7 percent capture) with a peak rate of 3,341 metric tons/day.
291However, the capture plant 
has not consistently operated at this total capture efficiency. In general, the capture plant ran less than 100 percent of the flue gas through the capture equipment and the coal-fired steam generating unit also operates when the capture plant is offline for maintenance. As a result, although the capture plant has consistently achieved 90 percent capture rates of the CO
2in the processed 
slipstream, the amount of CO 2captured 
was less than 90 percent of the total amount of CO
2in the flue gas of the 
steam generating unit. Some of the reasons for this operation were due to the economic incentives and regulatory requirements of the project, while other reasons were due to technical challenges. The EPA has reviewed the record of CO
2capture at Boundary Dam 
Unit 3. While Boundary Dam is in Canada and therefore not subject to this action, these technical challenges have been sufficiently overcome or are actively mitigated so that Boundary Dam has more recently been capable of achieving capture rates of 83 percent when the capture plant is online.
292 
Furthermore, the improvements already employed and identified at Boundary Dam can be readily applied during the initial construction of a new CO
2 
capture plant today. 
The CO 2captured at Boundary Dam is 
mostly used for EOR and CO 2is also 
stored geologically in a deep saline reservoir at the Aquistore site.
293The 
amount of flue gas captured is based in part on economic reasons (i.e., to meet 
related contract requirements). The incentives for CO
2capture at Boundary 
Dam beyond revenue from EOR have been limited to date, and there have been limited regulatory requirements for CO
2capture at the facility. As a result, 
a portion (about 25 percent on average) of the flue gas bypasses the capture plant and is emitted untreated. However, because of increasing requirements to capture CO
2in Canada, 
Boundary Dam Unit 3 has more recently pursued further process optimization. 
Total capture efficiencies at the plant 
have also been affected by technical issues, particularly with the SO
2 
removal system that is upstream of the CO
2capture system. Operation of the 
SO 2removal system affects downstream 
CO 2capture and the amount of flue gas 
that can be processed. Specifically, fly ash (PM) in the flue gas at Boundary Dam Unit 3 contributed to fouling of SO
2system components, particularly in 
the SO 2reboiler and the demisters of the 
SO 2absorber column. Buildup of scale 
in the SO 2reboiler limited heat transfer 
and regeneration of the SO 2scrubbing 
amine, and high pressure drop affected the flowrate of the SO
2lean-solvent 
back to the SO 2absorber. Likewise, 
fouling of the demisters in the SO 2 
absorber column caused high pressure drop and restricted the flow of flue gas through the system, limiting the amount of flue gas that could be processed by the downstream CO
2capture system. To 
address these technical issues, additional wash systems were added, including ‘‘demister wash systems, a pre-scrubber flue gas inlet curtain spray wash system, flue gas cooler throat sprays, and a booster fan wash system.’’
294 
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295S&P Global Market Intelligence (January 6, 
2022). Only still-operating carbon capture project 
battled technical issues in 2021. https://www.spglobal.com/marketintelligence/en/news- insights/latest-news-headlines/only-still-operating- carbon-capture-project-battled-technical-issues-in- 2021-68302671. 
296SaskPower (October 18, 2022). BD3 Status 
Update: Q3 2023. https://www.saskpower.com/ 
about-us/Our-Company/Blog/2023/BD3-Status- Update-Q3-2023. 297Jacobs, B., et al. Proceedings of the 16th 
International Conference on Greenhouse Gas Control Technologies (October 2022). Reducing the CO
2Emission Intensity of Boundary Dam Unit 3 
Through Optimization of Operating Parameters of the Power Plant and Carbon Capture Facilities. https://papers.ssrn.com/sol3/papers.cfm?abstract _
id=4286430. 
298Pradoo, P., et al. Proceedings of the 16th 
International Conference on Greenhouse Gas Control Technologies (October 2022). Improving the Operating Availability of the Boundary Dam Unit 3 Carbon Capture Facility. https://papers.ssrn.com/ sol3/papers.cfm?abstract_ id=4286503. 
299International CCS Knowledge Centre. The 
Shand CCS Feasibility Study Public Report. https:// 
ccsknowledge.com/pub/Publications/Shand_ CCS_
Feasibility_ Study_ Public_ Report_ Nov2018_ (2021- 
05-12).pdf. 
30080 FR 64548–54 (October 23, 2015). 301Dooley, J.J., et al. (2009). ‘‘An Assessment of 
the Commercial Availability of Carbon Dioxide Capture and Storage Technologies as of June 2009.’’ U.S. DOE, Pacific Northwest National Laboratory, under Contract DE–AC05–76RL01830. 
302Dooley, J.J., et al. (2009). ‘‘An Assessment of 
the Commercial Availability of Carbon Dioxide Capture and Storage Technologies as of June 2009.’’ U.S. DOE, Pacific Northwest National Laboratory, under Contract DE–AC05–76RL01830. 
303Shady Point Plant (River Valley) was sold to 
Oklahoma Gas and Electric in 2019. https://www.oklahoman.com/story/business/columns/ 2019/05/23/oklahoma-gas-and-electric-acquires- aes-shady-point-after-federal-approval/ 60454346007/. 
304In the 2015 NSPS, the EPA provided a legal 
interpretation of the constraints on how the EPA could rely on EPAct05-assisted projects in determining whether technology is adequately demonstrated for the purposes of CAA section 111. Under that legal interpretation, ‘‘these provisions [in the EPAct05] . . . preclude the EPA from relying solely on the experience of facilities that received [EPAct05] assistance, but [do] not . . . preclude the EPA from relying on the experience of such facilities in conjunction with other information.’’ As part of the rulemaking action here, the EPA incorporates the legal interpretation and discussion of these EPAct05 provisions with respect the appropriateness of considering facilities that received EPAct05 assistance in determining whether CCS is adequately demonstrated, as found in the 2015 NSPS, 80 FR 64509, 64541–43 (October 23, 2015), and the supporting response to comments, EPA–HQ–OAR–2013–0495–11861 at pgs.113–134. Such issues will definitively not 
occur in a different type of SO 2removal 
system (e.g., wet lime scrubber flue gas 
desulfurization, wet-FGD). SO 2 
scrubbers have been successfully 
operated for decades across a large number of U.S. coal-fired sources. Of the coal-fired sources with planned operation after 2039, 60 percent have wet FGD and 23 percent have a dry FGD. In section VII.C.1.a.ii of this preamble, the EPA accounts for the cost of adding a wet-FGD for those sources that do not have an FGD. 
To further mitigate fouling due to fly 
ash, the PM controls (electrostatic precipitators) at Boundary Dam Unit 3 were upgraded in 2015/2016 by adding switch integrated rectifiers. Of the coal- fired sources with planned operation after 2039, 31 percent have baghouses and 67 percent have electrostatic precipitators. Sources with baghouses have greater or more consistent degrees of emission control, and wet FGD also provides additional PM control. 
Fouling at Boundary Dam Unit 3 also 
affected the heat exchangers in both the SO
2removal system and the CO 2 
capture system. Additional redundancies and isolations to those key components were added in 2017 to allow for online maintenance. Damage to the capture plant’s CO
2compressor 
resulted in an unplanned outage in 2021, and the issue was corrected.
295 
The facility reported 98.3 percent capture system availability in the third quarter of 2023.
296 
Regular maintenance further mitigates 
fouling in the SO 2and CO 2absorbers, 
and other challenges (e.g., foaming, 
biological fouling) typical of gas-liquid absorbers can be mitigated by standard procedures. According to the 2022 paper co-authored by the International CCS Knowledge Centre and SaskPower, ‘‘[a] number of initiatives are ongoing or planned with the goal of eliminating flue gas bypass as follows: Since 2016, online cleaning of demisters has been effective at controlling demister pressure; Chemical cleans and replacement of fouled packing in the absorber towers to reduce pressure losses; Optimization of antifoam injection and other aspects of amine health, to minimize foaming potential; [and] Optimization of Liquid-to-Gas (L/ G) ratio in the absorber and other 
process parameters,’’ as well as other optimization procedures.
297While 
foaming is mitigated by an antifoam injection regimen, the EPA further notes that the extent of foaming that could occur may be specific to the chemistry of the solvent and the source’s flue gas conditions—foaming was not reported for MHI’s KS–1 solvent when treating bituminous coal post-combustion flue gas at Petra Nova. Lastly, while biological fouling in the CO
2absorber 
wash water and the SO 2absorber caustic 
polisher has been observed, ‘‘the current mitigation plan is to perform chemical shocking to remove this particular buildup.’’
298 
Based on the experiences of Boundary 
Dam Unit 3, key improvements can be implemented in future CCS deployments during initial design and construction. Improvements to PM and SO
2controls can be made prior to 
operation of the CO 2capture system. 
Where fly ash is present in the flue gas, wash systems can be installed to limit associated fouling. Additional redundancies and isolations of key heat- exchangers can be made to allow for in- line cleaning during operation. Redundancy of key equipment (e.g., utilizing two CO
2compressor trains 
instead of one) will further improve operational availability. A feasibility study for the Shand power plant, which is also operated by SaskPower, includes many such design improvements, at an overall cost that was less than the cost for Boundary Dam.
299 
(b) Other Coal-Fired Demonstrations 
Several other projects have 
successfully demonstrated the capture component of CCS at electricity generating plants and other industrial facilities, some of which were previously noted in the discussion in the 2015 NSPS.
300Since 1978, an 
amine-based system has been used to capture approximately 270,000 metric tons of CO
2per year from the flue gas 
of the bituminous coal-fired steam 
generating units at the 63 MW Argus Cogeneration Plant (Trona, 
California).
301Amine-based carbon 
capture has further been demonstrated at AES’s Warrior Run (Cumberland, Maryland) and Shady Point (Panama, Oklahoma) coal-fired power plants, with the captured CO
2being sold for use in 
the food processing industry.302At the 
180 MW bituminous coal-fired Warrior Run plant, approximately 10 percent of the plant’s CO
2emissions (about 
110,000 metric tons of CO 2per year) has 
been captured since 2000 and sold to the food and beverage industry. AES’s 320 MW Shady Point plant fires subbituminous and bituminous coal, and captured CO
2from an approximate 
5 percent slipstream (about 66,000 metric tons of CO
2per year) from 2001 
through around 2019.303These 
facilities, which have operated for multiple years, clearly show the technical feasibility of post-combustion carbon capture. 
(2) EPAct05-Assisted CO
2Capture 
Projects at Coal-Fired Steam Generating 
Units304 
(a) Petra Nova 
Petra Nova is a 240 MW-equivalent 
capture facility that is the first at-scale application of carbon capture at a coal- fired power plant in the U.S. The system is located at the subbituminous coal- 
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305JX Nippon Oil & Gas Exploration Corporation. 
Restart of the large-scale Petra Nova Carbon 
Capture Facility in the U.S. (September 2023). https://www.nex.jx-group.co.jp/english/ newsrelease/upload_ files/20230913EN.pdf. 
306W.A. Parish Post-Combustion CO 2Capture 
and Sequestration Demonstration Project, Final Scientific/Technical Report (March 2020). https://www.osti.gov/servlets/purl/1608572. 
307Id. 308Id. 309U.S. Department of Energy (DOE). National 
Energy Technology Laboratory (NETL). https://www.netl.doe.gov/node/1741. 
31080 FR 64552 (October 23, 2015). 
311Project Tundra—Progress, Minnkota Power 
Cooperative, 2023. https://www.projecttundrand.com. 
312See Document ID No. EPA–HQ–OAR–2023– 
0072–0632. 
313Id. fired W.A. Parish Generating Station in 
Thompsons, Texas, and began operation in 2017, successfully capturing and sequestering CO
2for several years. The 
system was put into reserve shutdown (i.e., idled) in May 2020, citing the poor 
economics of utilizing captured CO
2for 
EOR at that time. On September 13, 2023, JX Nippon announced that the carbon capture facility at Petra Nova had been restarted.
305A final report 
from the National Energy Technology Laboratory (NETL) details the success of the project and what was learned from this first-of-a-kind demonstration at scale.
306The project used Mitsubishi 
Heavy Industry’s proprietary KM–CDR Process
®, a process that is similar to an 
amine-based solvent process but that uses a proprietary solvent. During its operation, the project successfully captured 92.4 percent of the CO
2from 
the slip stream of flue gas processed with 99.08 percent of the captured CO
2 
sequestered by EOR. 
The amount of flue gas treated at Petra 
Nova was consistent with a 240 MW size coal-fired steam EGU. The properties of the flue gas—composition, temperature, pressure, density, flowrate, etc.—are the same as would occur for a similarly sized coal-firing unit. Therefore, Petra Nova corroborates that the capture equipment—including the CO
2absorption column, solvent 
regeneration column, balance of plant equipment, and the solvent itself—work at commercial scale and can achieve capture rates of 90 percent. 
The Petra Nova project did experience 
periodic outages that were unrelated to the CO
2capture facility and do not 
implicate the basis for the EPA’s BSER determination.
307These include outages 
at either the coal-fired steam generating unit (W.A. Parish Unit 8) or the auxiliary combined cycle facility, extreme weather events (Hurricane Harvey), and the operation of the EOR site and downstream oil recovery and processing. Outages at the coal-fired steam generating unit itself do not compromise the reliability of the CO
2 
capture plant or the plant’s ability to achieve a standard of performance based on CCS, as there would be no CO
2to 
capture. Outages at the auxiliary combined cycle facility are also not relevant to the EPA’s BSER determination, because the final BSER is 
not premised on the CO
2capture plant 
using an auxiliary combined cycle plant for steam and power. Rather, the final BSER assumes the steam and power come directly from the associated steam generating unit. Extreme weather events can affect the operation of any facility. Furthermore, the BSER is not premised on EOR, and it is not dependent on downstream oil recovery or processing. Outages attributable to the CO
2capture 
facility were 41 days in 2017, 34 days in 2018, and 29 days in 2019—outages decreased year-on-year and were on average less than 10 percent of the year. Planned and unplanned outages are normal for industrial processes, including steam generating units. 
Petra Nova experienced some 
technical challenges that were addressed during its first 3 years of operation.
308One of these issues was 
leaks from heat exchangers due to the properties of the gasket materials— replacement of the gaskets addressed the issue. Another issue was vibration of the flue gas blower due to build-up of slurry and solids carryover. W.A. Parish Unit 8 uses a wet limestone FGD scrubber to remove SO
2, and the flue gas 
connection to the capture plant is located at the bottom of the duct running from the wet-FGD to the original stack. A diversion wall and collection drains were installed to mitigate solids and slurry carryover. Regular maintenance is required to clean affected components and reduce the amount of slurry carryover to the quencher. Solids and slurry carryover also resulted in calcium scale buildup on the flue gas blower. Although calcium concentrations were observed to increase in the solvent, impacts of calcium on the quencher and capture plant chemistry were not observed. Some scaling may have been occurring in the cooling section of the quencher and would have been addressed during a planned outage in 2020. Another issue encountered was scaling related to the CO
2compressor intercoolers, 
compressor dehydration system, and an associated heat exchanger. The issue was determined to be due to a material incompatibility of the CO
2compressor 
intercooler, and the components were replaced during a 2018 planned outage. To mitigate the scaling prior to the replacement of those components, the compressor drain was also rerouted to the reclaimer and a backup filtering system was also installed and used, both of which proved to be effective. Some decrease in performance was also observed in heat exchangers. The presence of cooling tower fill (a solid 
medium used to increase surface area in cooling towers) in the cooling water system exchangers may have impacted performance. It is also possible that there could have been some fouling in heat exchangers. Fill was planned to be removed and fouling checked for during regular maintenance. Petra Nova did not observe fouling of the CO
2absorber 
packing or high pressure drops across the CO
2absorber bed, and Petra Nova 
also did not report any foaming of the solvent. Even with the challenges that were faced, Petra Nova was never restricted in reaching its maximum capture rate of 5,200 tons of CO
2per 
day, a scale that was substantially greater than Boundary Dam Unit 3 (approximately 3,600 tons of CO
2per 
day). 
(b) Plant Barry 
Plant Barry, a bituminous coal-fired 
steam generating unit in Mobile, 
Alabama, began using the KM–CDR Process
®in 2011 for a fully integrated 
25 MWe CCS project with a capture rate of 90 percent.
309The CCS project at 
Plant Barry captured approximately 165,000 tons of CO
2annually, which 
was then transported via pipeline and sequestered underground in geologic formations.
310 
(c) Project Tundra 
Project Tundra is a carbon capture 
project in North Dakota at the Milton R. Young Station lignite coal-fired power plant. Project Tundra will capture up to 4 million metric tons of CO
2per year for 
permanent geologic storage. One planned storage site is collocated with the power plant and is already fully permitted, while permitting for a second nearby storage site is in progress.
311An 
air permit for the capture facility has also been issued by North Dakota Department of Environmental Quality. The project is designed to capture CO
2 
at a rate of about 95 percent of the treated flue gas.
312The capture plant 
will treat the flue gas from the 455 MW Unit 2 and additional flue gas from the 250 MW Unit 1, and will treat an equivalent capacity of 530 MW.
313The 
project began a final FEED study in February 2023 with planned completion 
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314‘‘An Overview of Minnkota’s Carbon Capture 
Initiative—Project Tundra,’’ 2023 LEC Annual 
Meeting, October 5, 2023. 
315Project Tundra—Progress, Minnkota Power 
Cooperative, 2023. https://www.projecttundrand.com. 
316Laum, Jason. Subtask 2.4—Overcoming 
Barriers to the Implementation of Postcombustion Carbon Capture. https://www.osti.gov/biblio/ 1580659. 
317DOE–EA–2197 Draft Environmental 
Assessment, August 17, 2023. https://www.energy.gov/nepa/listings/doeea-2197- documents-available-download. 
318Carbon Capture Demonstration Projects 
Selections for Award Negotiations. https://www.energy.gov/oced/carbon-capture- demonstration-projects-selections-award- negotiations. 
319DOE. https://www.energy.gov/oced/carbon- 
capture-demonstration-projects-program-front-end- engineering-design-feed-studies. 
320DE–FOA–0002962. https://oced- 
exchange.energy.gov/ FileContent.aspx?FileID=86c47d5d-835c-4343-86e8- 2ba27d9dc119. 321Id. 
322Diamond Vault Carbon Capture FEED Study. 
https://netl.doe.gov/sites/default/files/netl-file/ 23CM_ PSCC31_ Bordelon.pdf. 
323Note that while the FEED study is EPAct05- 
assisted, the capture plant is not. 
324Project Diamond Vault Overview. https://
www.cleco.com/docs/default-source/diamond- vault/project_ diamond_ vault_ overview.pdf. 
325Id. 326Bottoms, R.R. Process for Separating Acidic 
Gases (1930) United States patent application. United States Patent US1783901A; Allen, A.S. and Arthur, M. Method of Separating Carbon Dioxide from a Gas Mixture (1933) United States Patent Application. United States Patent US1934472A. 
327Shell Global—Carbon Capture and Storage. 
https://www.shell.com/energy-and-innovation/ carbon-capture-and-storage.html. 
328Shell Global—CANSOLV®CO 2Capture 
System. https://www.shell.com/business-customers/ 
catalysts-technologies/licensed-technologies/ emissions-standards/tail-gas-treatment-unit/ cansolv-co2.html. in April 2024,314and, prior to selection 
by DOE for funding award negotiation, 
the project was scheduled to begin construction in 2024.
315The project will 
use MHI’s KS–21 solvent and the Advanced KM–CDR process. The MHI solvent KS–1 and an advanced MHI solvent (likely KS–21) were previously tested on the lignite post-combustion flue gas from the Milton R. Young Station.
316To provide additional 
conditioning of the flue gas, the project is utilizing a wet electrostatic precipitator (WESP). A draft Environmental Assessment summarizing the project and potential environmental impacts was released by DOE.
317Finally, Project Tundra was 
selected for award negotiation for funding from DOE.
318 
That this project has funding through 
the Bipartisan Infrastructure Law, and that this funding is facilitated through DOE’s Office of Clean Energy Demonstration’s (OCED) Carbon Capture Demonstration Projects Program, does not detract from the adequate demonstration of CCS. Rather, the goal of that program is, ‘‘to accelerate the 
implementation of integrated carbon capture and storage technologies and catalyze significant follow-on investments from the private sector to mitigate carbon emissions sources in industries across America.’’
319For the 
commercial scale projects, the stated requirement of the funding opportunity announcement (FOA) is not that projects demonstrate CCS in general, but that they ‘‘demonstrate significant improvements in the efficiency, effectiveness, cost, operational and environmental performance of existing carbon capture technologies.’’
320This 
implies that the basic technology already exists and is already demonstrated. The FOA further notes that the technologies used by the projects receiving funding should be proven such that, ‘‘the technologies funded can be readily replicated and deployed into commercial practice.’’
321 
The EPA also notes that this and other on-going projects were announced well in advance of the FOA. Considering these factors, Project Tundra and other similarly funded projects are supportive of the determination that CCS is adequately demonstrated. 
(d) Project Diamond Vault 
Project Diamond Vault will capture 
up to 95 percent of CO
2emissions from 
the 600 MW Madison Unit 3 at Brame 
Energy Center in Lena, Louisiana. Madison Unit 3 fires approximately 70 percent petroleum coke and 30 percent bituminous (Illinois Basin) coal in a circulating fluidized bed. The FEED study for the project is targeted for completion on September 9, 2024.
322 323  
Construction is planned to begin by the end of 2025 with commercial operation starting in 2028.
324From the utility: 
‘‘Government Inflation Reduction Act (IRA) funding through 45Q tax credits makes the project financially viable. With these government tax credits, the company does not expect a rate increase as a result of this project.’’
325 
(e) Other Projects 
Other projects have completed or are 
in the process of completing feasibility work or FEED studies, or are taking other steps towards installing CCS on coal-fired steam generating units. These projects are summarized in the final TSD, GHG Mitigation Measures for 
Steam Generating Units, available in the docket. In general, these projects target capture rates of 90 percent or above and provide evidence that sources are actively pursuing the installation of CCS. 
(3) CO
2Capture Technology Vendor 
Statements 
CO 2capture technology providers 
have issued statements supportive of the 
application of systems and solvents for CO
2capture at fossil fuel-fired EGUs. 
These statements speak to the decades of experience that technology providers have and as noted below, vendors attest, and offer guarantees that 90 percent 
capture rates are achievable. Generally, while there are many CO
2capture 
methods available, solvent-based CO 2 
capture from post-combustion flue gas is particularly applicable to fossil fuel- fired EGUs. Solvent-based CO
2capture 
systems are commercially available from technology providers including Shell, Mitsubishi Heavy Industries (MHI), Linde/BASF, Fluor and ION Clean Energy. 
Technology providers have made 
statements asserting extensive experience in CO
2capture and the 
commercial availability of CO 2capture 
technologies. Solvent-based CO 2capture 
was first patented in the 1930s.326Since 
then, commercial solvent-based capture systems have been developed that are focused on applications to post- 
combustion flue gas. Several technology providers have over 30 years of experience applying solvent-based CO
2 
capture to the post-combustion flue gas of fossil fuel-fired EGUs. In general, technology providers describe the technologies for CO
2capture from post- 
combustion flue gas as ‘‘proven’’ or ‘‘commercially available’’ or ‘‘commercially proven’’ or ‘‘available now’’ and describe their experience with CO
2capture from post-combustion 
flue gas as ‘‘extensive.’’ CO 2capture 
rates of 90 percent or higher from post- combustion flue gas have been proven by CO
2capture technology providers 
using several commercially available solvents. Many of the available solvent technologies have over 50,000 hours of operation, equivalent to over 5 years of operation. 
Shell has decades of experience in 
CO
2capture systems. Shell notes that 
‘‘[c]apturing and safely storing carbon is an option that’s available now.’’
327 
Shell has developed the CANSOLV® 
CO 2capture system for CO 2capture 
from post-combustion flue gas, a regenerable amine that the company claims has multiple advantages including ‘‘low parasitic energy consumption, fast kinetics and extremely low volatility.’’
328Shell 
further notes, ‘‘Moreover, the technology has been designed for 
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329Shell Catalysts & Technologies—Shell 
CANSOLV®CO 2Capture System. https://
catalysts.shell.com/en/Cansolv-co2-fact-sheet. 
330Id. 
331Id. 
332Mitsubishi Heavy Industries—CO 2Capture 
Technology—CO 2Capture Process. https:// 
www.mhi.com/products/engineering/co2plants_
process.html. 
333Id. 
334Note: Petra Nova is an EPAct05-assisted 
project. W.A. Parish Post-Combustion CO 2Capture 
and Sequestration Demonstration Project, Final Scientific/Technical Report (March 2020). https://www.osti.gov/servlets/purl/1608572. 
335Id. 
336Mitsubishi Heavy Industries, ‘‘Mitsubishi 
Heavy Industries Engineering Successfully Completes Testing of New KS–21
TMSolvent for CO 2 
Capture,’’ https://www.mhi.com/news/211019.html . 337Id. 
338Linde Engineering—Post Combustion Capture. 
https://www.linde-engineering.com/en/process- 
plants/co2-plants/carbon-capture/post-combustion- capture/index.html. 
339Linde and BASF—Carbon capture storage and 
utilisation. https://www.linde-engineering.com/en/ 
images/Carbon-capture-storage-utilisation-Linde- BASF_ tcm19-462558.pdf. 
340Id. 
341Operating availability is the percent of time 
that the CO 2capture equipment is available relative 
to its planned operation. 
342Fluor—Comprehensive Solutions for Carbon 
Capture. https://www.fluor.com/client-markets/ 
energy/production/carbon-capture. 
343Fluor—Econamine FG PlusSM. https://
www.fluor.com/sitecollectiondocuments/qr/ 
econamine-fg-plus-brochure.pdf. 344ION Clean Energy—Company. https://
www.ioncleanenergy.com/company. 
345https://www.aep.com/news/releases/read/ 
1206/AEP-Places-Carbon-Capture- Commercialization-On-Hold-Citing-Uncertain- Status-Of-Climate-Policy-Weak-Economy. 
346Enchant Energy. What is Carbon Capture and 
Sequestration (CCS)? https://enchantenergy.com/ carbon-capture-technology/. 
347Rainbow Energy Center. Carbon Capture. 
https://rainbowenergycenter.com/what-we-do/ carbon-capture/. reliability through its highly flexible 
turn-up and turndown capacity.’’329 
The company has stated that ‘‘Over 90% of the CO
2in exhaust gases can be 
effectively and economically removed through the implementation of Shell’s carbon capture technology.’’
330Shell 
also notes, ‘‘Systems can be guaranteed for bulk CO
2removal of over 90%.’’331 
MHI in collaboration with Kansai 
Electric Power Co., Inc. began developing a solvent-based capture process (the KM CDR Process
TM) using 
the KS–1TMsolvent in 1990.332MHI 
describes the extensive experience of commercial application of the solvent, ‘‘KS–1
TM—a solvent whose high 
reliability has been confirmed by a track record of deliveries to 15 commercial plants worldwide.’’
333Notable 
applications of KS–1TMand the KM– 
CDR ProcessTMinclude applications at 
Plant Barry and Petra Nova. Previously, MHI has achieved capture rates of greater than 90 percent over long periods and at full scale at the Petra Nova project where the KS–1
TMsolvent 
was used.334MHI has further improved 
on the original process and solvent by making available the Advanced KM CDR Process
TMusing the KS–21TM 
solvent. From MHI, ‘‘Commercialization of KS–21
TMsolvent was completed 
following demonstration testing in 2021 at the Technology Centre Mongstad in Norway, one of the world’s largest carbon capture demonstration facilities.’’
335MHI has achieved CO 2 
capture rates of 95 to 98 percent using both the KS–1
TMand KS–21TMsolvent 
at the Technology Centre Mongstad (TCM).
336Higher capture rates under 
modified conditions were also measured, ‘‘In addition, in testing conducted under modified operating conditions, the KS–21
TMsolvent 
delivered an industry-leading carbon capture rate was 99.8% and demonstrated the successful recovery of CO
2from flue gas of lower concentration than the CO 2contained in 
the atmosphere.’’337 
Linde engineering in partnership with 
BASF has made available BASF’s 
OASE®blue amine solvent technology 
for post-combustion CO 2capture. Linde 
notes their experience: ‘‘We have longstanding experience in the design and construction of chemical wash processes, providing the necessary amine-based solvent systems and the CO
2compression, drying and 
purification system.’’338Linde also 
notes that ‘‘[t]he BASF OASE®process 
is used successfully in more than 400 plants worldwide to scrub natural, synthesis and other industrial gases.’’
339 
The OASE®blue technology has been 
successfully piloted at RWE Power, Niederaussem, Germany (from 2009 through 2017; 55,000 operating hours) and the National Center for Carbon Capture in Wilsonville, Alabama (January 2015 through January 2016; 3,200 operating hours). Based on the demonstrated performance, Linde concludes that ‘‘PCC plants combining Linde’s engineering skills and BASF’s OASE
®blue solvent technology are now 
commercially available for a wide range of applications.’’
340Linde and BASF 
have demonstrated capture rates over 90 percent and operating availability
341 
rates of more than 97 percent during 55,000 hours of operation. 
Fluor provides a solvent technology 
(Econamine FG Plus) and EPC services for CO
2capture. Fluor describes their 
technology as ‘‘proven,’’ noting that, ‘‘Proven technology. Fluor Econamine FG Plus technology is a propriety carbon capture solution with more than 30 licensed plants and more than 30 years of operation.’’
342Fluor further 
notes, ‘‘The technology builds on Fluor’s more than 400 CO
2removal 
units in natural gas and synthesis gas processing.’’
343Fluor further states, 
‘‘Fluor is a global leader in CO 2capture 
[. . .] with long-term commercial operating experience in CO
2recovery 
from flue gas.’’ On the status of Econamine FG Plus, Fluor notes that the ‘‘[the] Technology [is] commercially proven on natural gas, coal, and fuel oil flue gases,’’ and further note that ‘‘[o]perating experience includes using steam reformers, gas turbines, gas engines, and coal/natural gas boilers.’’ 
ION Clean Energy is a company 
focused on post-combustion carbon capture founded in 2008. ION’s ICE–21 solvent has been used at NCCC and TCM Norway.
344ION has achieved 
capture rates of 98 percent using the ICE–31 solvent. 
(4) CCS User Statements on CCS 
A number of the companies who have 
either completed large scale pilot 
projects or who are currently developing full scale projects have also indicated that CCS technology is currently a viable technology for large coal-fired power plants. In 2011, announcing a decision not to move forward with the first full scale commercial CCS installation of a carbon capture system on a coal plant, AEP did not cite any technology concerns, but rather indicated that ‘‘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.’’
345Enchant 
Energy, a company developing CCS for coal-fired power plants explained that its FEED study for the San Juan Generating Station, ‘‘shows that the technical and business case for adding carbon capture to existing coal-fired power plants is strong.’’
346Rainbow 
Energy, who is developing a carbon 
capture project at the Coal Creek Power Station in North Dakota explains, ‘‘CCUS technology has been proven and is an economical option for a facility like Coal Creek Station. We see CCUS as the best option to manage CO
2 
emissions at our facility.’’347 
(5) State CCS Requirements 
Several states encourage or even 
require sources to install CCS. These state requirements further indicate that CCS is well-established and effective. These state laws include the Illinois 2021 Climate and Equitable Jobs Act, which requires privately owned coal- 
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348State of Illinois General Assembly. Public Act 
102–0662: Climate and Equitable Jobs Act. 2021. 
https://www.ilga.gov/legislation/publicacts/102/ PDF/102-0662.pdf. 
349State of Illinois General Assembly. Public Act 
095–1027: Clean Coal Portfolio Standard Law. https://www.ilga.gov/legislation/publicacts/95/PDF/ 095-1027.pdf. 
350State of Michigan Legislature. Public Act 235 
of 2023. Clean and Renewable Energy and Energy Waste Reduction Act. https://legislature.mi.gov/ documents/2023-2024/publicact/pdf/2023-PA- 0235.pdf. 
351California Air Resources Board, 2022 Scoping 
Plan for Achieving Carbon Neutrality. https://ww2.arb.ca.gov/sites/default/files/2023-04/2022- sp.pdf. 
352State of California Legislature. Assembly Bill 
1279 (2022). The California Climate Crisis Act. https://leginfo.legislature.ca.gov/faces/ billTextClient.xhtml?bill_ id=202120220AB1279. 
353Louisiana Climate Initiatives Task Force. 
Louisiana Climate Action Plan (February 1, 2022). https://gov.louisiana.gov/assets/docs/CCI-Task- force/CAP/ClimateActionPlanFinal.pdf. 354Pennsylvania Dept. of Environmental 
Protection. Pennsylvania Climate Action Plan (2021). https://www.dep.pa.gov/Citizens/climate/ 
Pages/PA-Climate-Action-Plan.aspx. 
355https://www.governor.nd.gov/news/updated- 
waudio-burgum-addresses-williston-basin- petroleum-conference-issues-carbon-neutral. 
356https://westgov.org/initiatives/overview/ 
decarbonizing-the-west. 
357State of Wyoming Legislature. SF0042. Low- 
carbon Reliable Energy Standards-amendments. https://www.wyoleg.gov/Legislation/2024/SF0042. 
358Here, ‘‘turndown’’ is the ability of a facility to 
turn down some process value, such as flowrate, throughput or capacity. Typically, this is expressed as a ratio relative to operation at its maximum instantaneous capability. Because processes are designed to operate within specific ranges, turndown is typically limited by some lower threshold. 
359Here, ‘‘duty cycle’’ is the ratio of the gross 
amount of electricity generated relative to the amount that could be potentially generated if the unit operated at its nameplate capacity during every hour of operation. Duty cycle is thereby an indication of the amount of cycling or load following a unit experiences (higher duty cycles indicate less cycling, i.e., more time at nameplate 
capacity when operating). Duty cycle is different from capacity factor, as the latter also quantifies the amount that the unit spends offline. 360U.S. Environmental Protection Agency (EPA). 
‘‘Power Sector Emissions Data.’’ Washington, DC: Office of Atmospheric Protection, Clean Air Markets Division. Available from EPA’s Air Markets Program Data website: https://campd.epa.gov. 
361Jacobs, B., et al. Proceedings of the 16th 
International Conference on Greenhouse Gas Control Technologies (March 15–18, 2021). Reducing the CO
2Emission Intensity of Boundary 
Dam Unit 3 Through Optimization of Operating Parameters of the Power Plant and Carbon Capture Facilities. https://papers.ssrn.com/sol3/ papers.cfm?abstract_ id=4286430. 
362W.A. Parish Post-Combustion CO 2Capture 
and Sequestration Demonstration Project, Final Scientific/Technical Report (March 2020). https://www.osti.gov/servlets/purl/1608572. 
363International CCS Knowledge Centre. The 
Shand CCS Feasibility Study Public Report. https:// 
ccsknowledge.com/pub/Publications/Shand_ CCS_
Feasibility_ Study_ Public_ Report_ Nov2018_ (2021- 
05-12).pdf. 
364Here, a ‘‘train’’ in this context is a series of 
connected sequential process equipment. For carbon capture, a process train can include the quencher, absorber, stripper, and compressor. Rather than doubling the size of a single train of process equipment, a source could use two equivalent sized trains. 
365Jacobs, B., et al. Proceedings of the 16th 
International Conference on Greenhouse Gas Control Technologies (March 15–18, 2021). Reducing the CO
2Emission Intensity of Boundary 
Dam Unit 3 Through Optimization of Operating Parameters of the Power Plant and Carbon Capture Facilities. https://papers.ssrn.com/sol3/ papers.cfm?abstract_ id=4286430. 
366International CCS Knowledge Centre. The 
Shand CCS Feasibility Study Public Report. https:// 
ccsknowledge.com/pub/Publications/Shand_ CCS_
Feasibility_ Study_ Public_ Report_ Nov2018_ (2021- 
05-12).pdf. fired units to reduce emissions to zero 
by 2030 and requires publicly owned coal-fired units to reduce emissions to zero by 2045.
348Illinois has also 
imposed CCS-based CO 2emission 
standards on new coal-fired power plants since 2009 when the state adopted its Clean Coal Portfolio Standard law.
349The statute required an 
initial capture rate of 50 percent when enacted but steadily increased the capture rate requirement to 90 percent in 2017, where it remains. 
Michigan in 2023 established a 100 
percent clean energy requirement by 2040 with a nearer term 80 percent clean energy by 2035 requirement.
350 
The statute encourages the application of CCS by defining ‘‘clean energy’’ to include generation resources that achieve 90 percent carbon capture. 
California identifies carbon capture 
and sequestration as a necessary tool to reduce GHG emissions within its 2022 scoping plan update
351and, that same 
year, enacted a statutory requirement through Assembly Bill 1279
352 
requiring the state to plan and implement policies that enable carbon capture and storage technologies. 
Several states in different parts of the 
country have adopted strategic and planning frameworks that also encourage CCS. Louisiana, which in 2020 set an economy-wide net-zero goal by 2050, has explored policies that encourage CCS deployment in the power sector. The state’s 2022 Climate Action Plan proposes a Renewable and Clean Portfolio Standard requiring 100 percent renewable or clean energy by 2035.
353That proposal defines power 
plants achieving 90 percent carbon capture as a qualifying clean energy resource that can be used to meet the standard. Pennsylvania’s 2021 Climate Action 
Plan notes that the state is well positioned to install CCS to transition the state’s electric fleet to a zero-carbon economy.
354The state also established 
an interagency workgroup in 2019 to identify ways to speed the deployment of CCS. 
The Governor of North Dakota 
announced in 2021 an economy-wide carbon neutral goal by 2030.
355The 
announcement singled out the Project Tundra Initiative, which is working to apply CCS technology to the state’s Milton R. Young Power Station. 
The Governor of Wyoming has 
broadly promoted a Decarbonizing the West initiative that includes the study of CCS technologies to reduce carbon emissions from the region.
356A 2024 
Wyoming law also requires utilities in the state to install CCS technologies on a portion of their existing coal-fired power plants by 2033.
357 
(6) Variable Load and Startups and Shutdowns 
In this section of the preamble, the 
EPA considers the effects of variable load and startups and shutdowns on the achievability of 90 percent capture. First, the coal-fired steam generating unit can itself turndown
358to only 
about 40 percent of its maximum design capacity. Due to this, coal-fired EGUs have relatively high duty cycles
359— 
that is, they do not cycle as frequently as other sources and typically have high average loads when operating. In 2021, coal-fired steam generating units had an average duty cycle of 70 percent, and more than 75 percent of units had duty cycles greater than 60 percent.
360Prior 
demonstrations of CO 2capture plants on 
coal-fired steam generating units have 
had turndown limits of approximately 60 percent of throughput for Boundary Dam Unit 3
361and about 70 percent 
throughput for Petra Nova.362Based on 
the technology currently available, turndown to throughputs of 50 percent
363are achievable for a single 
capture train.364Considering that coal 
units can typically only turndown to 40 percent, a 50 percent turndown ratio for the CO
2capture plant is likely sufficient 
for most sources, although utilizing two CO
2capture trains would allow for 
turndown to as low as 25 percent of 
throughput. When operating at less than maximum throughputs, the CO
2capture 
facility actually achieves higher capture efficiencies, as evidenced by the data collected at Boundary Dam Unit 3.
365 
Data from the Shand Feasibility Report suggests that, for a solvent and design achieving 90 percent capture at 100 percent of net load, 97.5 percent capture is achievable at 62.5 percent of net load.
366Considering these factors, CO 2 
capture is, in general, able to meet the variable load of coal-fired steam generating units without any adverse impact on the CO
2capture rate. In fact, 
operation at lower loads may lead to 
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367Laum, Jason. Subtask 2.4—Overcoming 
Barriers to the Implementation of Postcombustion 
Carbon Capture. https://www.osti.gov/biblio/ 1580659. 
368W.A. Parish Post-Combustion CO 2Capture 
and Sequestration Demonstration Project, Final Scientific/Technical Report (March 2020). https:// www.osti.gov/servlets/purl/1608572. 
369U.S. Department of Energy (DOE). National 
Energy Technology Laboratory (NETL). https:// www.netl.doe.gov/node/1741. 
370Dooley, J.J., et al. (2009). ‘‘An Assessment of 
the Commercial Availability of Carbon Dioxide Capture and Storage Technologies as of June 2009.’’ U.S. DOE, Pacific Northwest National Laboratory, under Contract DE–AC05–76RL01830. 
371Id. 
372Id. 
373Reddy, et al. Energy Procedia, 37 (2013) 6216– 
6225. 374Project Tundra—Progress, Minnkota Power 
Cooperative, 2023. https://www.projecttundrand.com. 
375Project Diamond Vault Overview. https://
www.cleco.com/docs/default-source/diamond- vault/project_ diamond_ vault_ overview.pdf. 
3762023 Integrated Resource Plan Update, 
PacifiCorp, April 1, 2024, https://www.pacificorp.com/content/dam/pcorp/ documents/en/pacificorp/energy/integrated- resource-plan/2023_ IRP_ Update.pdf. higher achievable capture rates over 
long periods of time. 
Coal-fired steam generating units also 
typically have few startups and shutdowns per year, and CO
2emissions 
during those periods are low. Although capacity factor has declined in recent years, as noted in section IV.D.3 of the preamble, the number of startups per year has been relatively stable. In 2011, coal-fired sources had about 10 startups on average. In 2021, coal-fired steam generating units had only 12 startups on average, see the final TSD, GHG Mitigation Measures for Steam Generating Units, available in the docket. Prior to generation of electricity, coal-fired steam generating units use natural gas or distillate oil—which have a lower carbon content than coal— because of their ignition stability and low ignition temperature. Heat input rates during startup are relatively low, to slowly raise the temperature of the boiler. Existing natural gas- or oil-fired ignitors designed for startup purposes are generally sized for up to 15 percent of the maximum heat-input. Considering the low heat input rate, use of fuel with a lower carbon content, and the relatively few startups per year, the contribution of startup to total GHG emissions is relatively low. Shutdowns are relatively short events, so that the contribution to total emissions are also low. The emissions during startup and shutdown are therefore small relative to emissions during normal operation, so that any impact is averaged out over the course of a year. 
Furthermore, the IRC section 45Q tax 
credit provides incentive for units to operate more. Sources operating at higher capacity factors are likely to have fewer startups and shutdowns and spend less time at low loads, so that their average load would be higher. This 
would further minimize the insubstantial contribution of startups and shutdowns to total emissions. Additionally, as noted in the preceding sections of the preamble, new solvents achieve capture rates of 95 percent at full load, and ongoing projects are targeting capture rates of 95 percent. Considering all of these factors, startup and shutdown, in general, do not affect the achievability of 90 percent capture over long periods (i.e., a year). 
(7) Coal Rank 
CO
2capture at coal-fired steam 
generating units achieves 90 percent capture, for the reasons detailed in sections VII.C.1.a.i(B)(1) through (6) of this preamble. Moreover, 90 percent capture is achievable for all coal types because amine solvents have been used to remove CO
2from a variety of flue gas compositions including a broad range of 
different coal ranks, differences in CO 2 
concentration are slight and the capture process can be designed to the appropriate scale, amine solvents have been used to capture CO
2from flue gas 
with much lower CO 2concentrations, 
and differences in flue gas impurities due to different coal compositions can be managed or mitigated by controls. 
As detailed in the preceding sections, 
CO
2capture has been operated on flue 
gas from the combustion of a broad range of coal ranks including lignite, bituminous, subbituminous, and anthracite coals. Post-combustion CO
2 
capture from the flue gas of an EGU firing lignite has been demonstrated at the Boundary Dam Unit 3 EGU (Saskatchewan, Canada). Most lignites have a higher ash and moisture content than other coal types and, in that respect, the flue gas can be more challenging to manage for CO
2capture. 
Amine CO 2capture has also been used 
to treat lignite post-combustion flue gas in pilot studies at the Milton R. Young station (North Dakota).
367CO 2capture 
solvents have been used to treat subbituminous post-combustion flue gas from W.A. Parish Generating Station (Texas),
368and the bituminous post- 
combustion flue gas from Plant Barry (Mobile, Alabama),
369Warrior Run 
(Maryland),370and Argus Cogeneration 
Plant (California).371Amine solvents 
have also been used to remove CO 2from 
the flue gas of the bituminous- and subbituminous-fired Shady Point plant.
372CO 2capture solvents have 
been used to treat anthracite post- combustion flue gas at the Wilhelmshaven power plant (Germany).
373There are also ongoing 
projects that will apply CCS to the flue gas of coal-fired steam generating units. The EPA considers these ongoing projects to be indicative of the confidence that industry stakeholders 
have in CCS. These include Project Tundra at the lignite-fired Milton R. Young station (North Dakota),
374Project 
Diamond Vault at the petroleum coke- and subbituminous-fired Brame Energy Center Madison Unit 3 (Louisiana)
375 
and two units at the Jim Bridger Plant (Wyoming).
376 
Different coal ranks have different 
carbon contents, affecting the concentration of CO
2in flue gas. In 
general, however, CO 2concentration of 
coal combustion flue gas varies only between 13 and 15 percent. Differences in CO
2concentration can be accounted 
for by appropriately designing the capture equipment, including sizing the absorber columns. As detailed in section VIII.F.4.c.iv of the preamble, CO
2has 
been captured from the post-combustion flue gas of NGCCs, which typically have a CO
2concentration of 4 percent. 
Prior to emission controls and pre- 
conditioning, characteristics of different coal ranks and boiler design result in other differences in the flue gas composition, including in the concentration of SO
2, NO X, PM, and 
trace impurities. Such impurities in the flue gas can react with the solvent or cause fouling of downstream processes. However, in general, most existing coal- fired steam generating units in the U.S. have controls that are necessary for the pre-conditioning of flue gas prior to the CO
2capture plant, including PM and 
SO 2controls. For those sources without 
an FGD for SO 2control, the EPA 
included the costs of adding an FGD in its cost analysis. Other marginal differences in flue gas impurities can be managed by appropriately designing the polishing column (direct contact cooler) for the individual source’s flue gas. Trace impurities can be mitigated using conventional controls in the solvent reclaiming process (e.g., an activated 
carbon bed). 
Considering the broad range of coal 
post-combustion flue gases amine solvents have been operated with, that solvents capture CO
2from flue gases 
with lower CO 2concentrations, that the 
capture process can be designed for different CO
2concentrations, and that 
flue gas impurities that may differ by coal rank can be managed by controls, the EPA therefore concludes that 90 percent capture is achievable across all coal ranks, including waste coal. 
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377PHMSA submitted the associated Notice of 
Proposed Rulemaking to the White House Office of 
Management and Budget on February 1, 2024 for pre-publication review. The notice stated that the proposed rulemaking would enhance safety regulations to ‘‘accommodate an anticipated increase in the number of carbon dioxide pipelines and volume of carbon dioxide transported.’’ Office of Management and Budget. https://www.reginfo.gov/public/do/ eAgendaViewRule?pubId=202310&RIN=2137-AF60. 
378Individual saline formations would require 
site-specific characterization to determine their 
suitability for geologic sequestration and the potential capacity for storage. 379PHMSA additionally initiated a rulemaking in 
2022 to develop and implement new measures to 
strengthen its safety oversight of CO 2pipelines 
following investigation into a CO 2pipeline failure 
in Satartia, Mississippi in 2020. For more information, see: https://www.phmsa.dot.gov/news/ phmsa-announces-new-safety-measures-protect- americans-carbon-dioxide-pipeline-failures. 
380For additional information on CO 2 
transportation infrastructure project timelines, costs and other details, please see EPA’s final TSD, GHG Mitigation Measures for Steam Generating Units. 
381U.S. Department of Transportation, Pipeline 
and Hazardous Material Safety Administration, ‘‘Hazardous Annual Liquid Data.’’ 2022. https://www.phmsa.dot.gov/data-and-statistics/pipeline/ gas-distribution-gas-gathering-gas-transmission- hazardous-liquids. (8) Natural Gas-Fired Combustion 
Turbines 
Additional information supporting 
the EPA’s determination that 90 percent capture of CO
2from steam generating 
units is adequately demonstrated is the experience from CO
2capture from 
natural gas-fired combustion turbines. The EPA describes this information in section VIII.F.4.c.iv(B)(1), including explaining how information about CO
2 
capture from coal-fired steam generating units also applies to natural gas-fired combustion turbines. The reverse is true as well; information about CO
2capture 
from natural gas-fired turbines can be applied to coal fired-units, for much the same reasons. 
(9) Summary of Evidence Supporting 
BSER Determination Without EPAct05- Assisted Projects 
As noted above, under the EPA’s 
interpretation of the EPAct05 provisions, the EPA may not rely on capture projects that received assistance under EPAct05 as the sole basis for a determination of adequate demonstration, but the EPA may rely on those projects to support or corroborate other information that supports such a determination. The information described above that supports the EPA’s determination that 90 percent CO
2 
capture from coal-fired steam generating units is adequately demonstrated, without consideration of the EPAct05- assisted projects, includes (i) the information concerning Boundary Dam, coupled with engineering analysis concerning key improvements that can be implemented in future CCS deployments during initial design and construction (i.e., all the information in 
section VII.C.1.a.i.(B)(1)(a) and the information concerning Boundary Dam in section VII.C.1.a.i.(B)(1)(b)); (ii) the information concerning other coal-fired demonstrations, including the Argus Cogeneration Plant and AES’s Warrior Run (i.e., all the information concerning 
those sources in section VII.C.1.a.i.(B)(1)(a)); (iii) the information concerning industrial applications of CCS (i.e., all the information in section 
VII.C.1.a.i.(A)(1); (iv) the information concerning CO
2capture technology 
vendor statements (i.e., all the 
information in section VII.C.1.a.i.(B)(3)); (v) information concerning carbon capture at natural gas-fired combustion turbines other than EPAct05-assisted projects (i.e., all the information other 
than information about EPAct05- assisted projects in section VIII.F.4.c.iv.(B)(1)). All this information by itself is sufficient to support the EPA’s determination that 90 percent CO
2capture from coal-fired steam 
generating units is adequately 
demonstrated. Substantial additional information from EPAct05-assisted projects, as described in section VII.C.1.a.i.(B), provides additional support and confirms that 90 percent CO
2capture from coal-fired steam 
generating units is adequately demonstrated. 
(C) CO
2Transport 
The EPA is finalizing its 
determination that CO 2transport by 
pipelines as a component of CCS is 
adequately demonstrated. The EPA anticipates that in the coming years, a large-scale interstate pipeline network may develop to transport CO
2. Indeed, 
PHMSA is currently engaged in a rulemaking to update and strengthen its safety regulations for CO
2pipelines, 
which assumes that such a pipeline network will develop.
377For purposes 
of determining the CCS BSER in this final action, however, the EPA did not base its analysis of the availability of CCS on the projected existence of a large-scale interstate pipeline network. Instead, the EPA adopted a more conservative approach. The BSER is premised on the construction of relatively short lateral pipelines that extend from the source to the nearest geologic storage reservoir. While the EPA anticipates that sources would likely avail themselves of an existing interstate pipeline network if one were constructed and that using an existing network would reduce costs, the EPA’s analysis focuses on steps that an individual source could take to access CO
2storage independently. 
EGUs that do not currently capture 
and transport CO 2will need to construct 
new CO 2pipelines to access CO 2storage 
sites, or make arrangements with pipeline owners and operators who can do so. Most coal-fired steam EGUs, however, are located in relatively close proximity to deep saline formations that have the potential to be used as long- term CO
2storage sites.378Of existing 
coal-fired steam generating capacity with planned operation during or after 2039, more than 50 percent is located less than 32 km (20 miles) from potential deep saline sequestration sites, 73 percent is located within 50 km (31 miles), 80 percent is located within 100 km (62 miles), and 91 percent is within 160 km (100 miles). While the EPA’s analysis focuses on the geographic availability of deep saline formations, unmineable coal seams and depleted oil and gas reservoirs could also potentially serve as storage formations depending on site-specific characteristics. Thus, for the majority of sources, only relatively short pipelines would be needed for transporting CO
2from the source to the 
sequestration site. For the reasons described below, the EPA believes that both new and existing EGUs are capable of constructing CO
2pipelines as needed. 
New EGUs may also be planned to be co-located with a storage site so that minimal transport of the CO
2is 
required. The EPA has assurance that the necessary pipelines will be safe because the safety of existing and new supercritical CO
2pipelines is 
comprehensively regulated by PHMSA.
379 
(1) CO 2Transport Demonstrations 
The majority of CO 2transported in the 
United States is moved through 
pipelines. CO 2pipelines have been in 
use across the country for nearly 60 years. Operation of this pipeline infrastructure for this period of time establishes that the design, construction, and operational requirements for CO
2 
pipelines have been adequately demonstrated.
380PHMSA reported that 
8,666 km (5,385 miles) of CO 2pipelines 
were in operation in 2022, a 14 percent increase in CO
2pipeline miles since 
2011.381This pipeline infrastructure 
continues to expand with a number of anticipated projects underway. 
The U.S. CO
2pipeline network 
includes major trunkline (i.e., large 
capacity) pipelines as well as shorter, smaller capacity lateral pipelines connecting a CO
2source to a larger 
trunkline or connecting a CO 2source to 
a nearby CO 2end use. While CO 2 
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382Sequestration potential as it relates to distance 
from existing resources is a key part of the EPA’s 
regular power sector modeling development, using data from DOE/NETL studies. For details, please see chapter 6 of the IPM documentation. https://www.epa.gov/system/files/documents/2021-09/ chapter-6-co2-capture-storage-and-transport.pdf. 
383The pipeline diameter was sized for this to be 
achieved without the need for recompression stages along the pipeline length. 384Note that multiple coal-fired EGUs may be 
located at each power plant. 
385CO 2Pipeline Analysis for Existing Coal-Fired 
Powerplants. Chen et. al. Los Alamos National Lab. 
2024. https://permalink.lanl.gov/object/ 
tr?what=info:lanl-repo/lareport/LA-UR-24-23321. 
386In the EPA’s representative timeline, the CO 2 
pipeline is constructed in an 18-month period. In practice, all CO
2pipeline construction projects 
would be spread over a larger time period. In the Transport and Storage Timeline Summary, ICF (2024), available in Docket ID EPA–HQ–OAR– 2023–0072, permitting is 1.5 years. Some CO
2 
pipeline construction would therefore likely begin by the start of 2028, or even earlier considering on- going projects. With the one-year compliance extension for delays outside of the owner/operators control that would provide extra time if there were challenges in building pipelines, the construction on CO
2pipelines could occur during 2032. 387U.S. Department of Transportation, Pipeline 
and Hazardous Material Safety Administration, ‘‘Hazardous Annual Liquid Data.’’ 2022. https://www.phmsa.dot.gov/data-and-statistics/pipeline/ gas-distribution-gas-gathering-gas-transmission- hazardous-liquids. 
388Noothout, Paul. Et. Al. (2014). ‘‘CO 2Pipeline 
infrastructure—lessons learnt.’’ https:// www.sciencedirect.com/science/article/pii/ S187661021402864. 
389Rassenfoss, Stephen. (2014). ‘‘Carbon Dioxide: 
From Industry to Oil Fields.’’ ttps://jpt.spe.org/ carbon-dioxide-industry-oil-fields. 
390GlobeNewswire. ‘‘Chaparral Energy Agrees to 
a CO2 Purchase and Sale Agreement with CVR Energy for Capture of CO
2for Enhanced Oil 
Recovery.’’ March 29, 2011. https://www.globenewswire.com/news-release/2011/03/29/ 443163/10562/en/Chaparral-Energy-Agrees-to-a- CO2-Purchase-and-Sale-Agreement-With-CVR- pipelines are generally more 
economical, other methods of CO 2 
transport may also be used in certain circumstances and are detailed in the final TSD, GHG Mitigation Measures for Steam Generating Units. 
(a) Distance of CO
2Transport for Coal- 
Fired Power Plants 
An important factor in the 
consideration of the feasibility of CO 2 
transport from existing coal-fired steam 
generating units to sequestration sites is the distance the CO
2must be 
transported. As discussed in section VII.C.1.a.i(D), potential sequestration formations include deep saline formations, unmineable coal seams, and oil and gas reservoirs. Based on data from DOE/NETL studies of storage resources, of existing coal-fired steam generating capacity with planned operation during or after 2039, 80 percent is within 100 km (62 miles) of potential deep saline sequestration sites, and another 11 percent is within 160 km (100 miles).
382In other words, 91 
percent of this capacity is within 160 km (100 miles) of potential deep saline sequestration sites. In gigawatts, of the 81 GW of coal-fired steam generation capacity with planned operation during or after 2039, only 16 GW is not within 100 km (62 miles) of a potential saline sequestration site, and only 7 GW is not within 160 km (100 mi). The vast majority of these units (on the order of 80 percent) can reach these deep saline sequestration sites by building an intrastate pipeline. This distance is consistent with the distances referenced in studies that form the basis for transport cost estimates for this final rule.
383While the EPA’s analysis 
focuses on the geographic availability of deep saline formations, unmineable coal seams and depleted oil and gas reservoirs could also potentially serve as storage formations depending on site- specific characteristics. 
Of the 9 percent of existing coal-fired 
steam generating capacity with planned operation during or after 2039 that is not within 160 km (100 miles) of a potential deep saline sequestration site, 5 percent is within 241 km (150 miles) of potential saline sequestration sites, an additional 3 percent is within 322 km (200 miles) of potential saline sequestration sites, and another 1 percent is within 402 km (250 miles) of 
potential sequestration sites. In total, assuming all existing coal-fired steam generating capacity with planned operation during or after 2039 adopts CCS, the EPA analysis shows that approximately 8,000 km (5,000 miles) of CO
2pipelines would be constructed by 
2032. This includes units located at any distance from sequestration. Note that this value is not optimized for the least total pipeline length, but rather represents the approximate total pipeline length that would be required if each power plant constructed a lateral pipeline connecting their power plant to the nearest potential saline sequestration site.
384 
Additionally, the EPA’s compliance 
modeling projects 3,300 miles of CO 2 
pipeline buildout in the baseline and 4,700 miles of pipeline buildout in the policy scenario. This is comparable to the 4,700 to 6,000 miles of CO
2pipeline 
buildout estimated by other simulations examining similar scenarios of coal CCS deployment.
385Over 5 years, this total 
projected CO 2pipeline capacity would 
amount to about 660 to 940 miles per year on average.
386This projected 
pipeline mileage is comparable to other types of pipelines that are regularly constructed in the United States each year. For example, based on data collected by EIA, the total annual mileage of natural gas pipelines constructed over the 2017–2021 period ranged from approximately 1,000 to 2,500 miles per year. The projected annual average CO
2pipeline mileage is 
less than each year in this historical natural gas pipeline range, and significantly less than the upper end of this range. 
The EPA also notes that the pipeline 
construction estimates presented in this section are not additive with the natural gas co-firing pipeline construction estimates presented below because individual sources will not elect to utilize both compliance methods. In other words, more pipeline buildout for one compliance method necessarily means less pipeline buildout for the other method. Therefore, there is no compliance scenario in which the total pipeline construction is equal to the sum of the CCS and natural gas co-firing pipeline estimates presented in this preamble. 
While natural gas line construction 
may be easier in some circumstances given the uniform federal regulation that governs those such construction, the historical trends support the EPA’s conclusion that constructing less CO
2 
pipeline length over a several year period is feasible. 
(b) CO
2Pipeline Examples 
PHMSA reported that 8,666 km (5,385 
miles) of CO 2pipelines were in 
operation in 2022.387Due to the unique 
nature of each project, CO 2pipelines 
vary widely in length and capacity. 
Examples of projects that have utilized CO
2pipelines include the following: 
Beaver Creek (76 km), Monell (52.6 km), Bairoil (258 km), Salt Creek (201 km), Sheep Mountain (656 km), Slaughter (56 km), Cortez (808 km), Central Basin (231 km), Canyon Reef Carriers (354 km), and Choctaw (294 km). These pipelines range in capacity from 1.6 million tons per year to 27 million tons per year, and transported CO
2for uses such as 
EOR.388 
Most sources deploying CCS are 
anticipated to construct pipelines that run from the source to the sequestration site. Similar CO
2pipelines have been 
successfully constructed and operated in the past. For example, a 109 km (68 mile) CO
2pipeline was constructed 
from a fertilizer plant in Coffeyville, Kansas, to the North Burbank Unit, an EOR operation in Oklahoma.
389 
Chaparral Energy entered a long-term CO
2purchase and sale agreement with 
a subsidiary of CVR Energy for the capture of CO
2from CVR’s nitrogen 
fertilizer plant in 2011.390The pipeline 
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Energy-for-Capture-of-CO2-for-Enhanced-Oil- 
Recovery.html. 
391Chaparral Energy. ‘‘A ‘CO 2Midstream’ 
Overview: EOR Carbon Management Workshop.’’ December 10, 2013. https://www.co2conference.net/ wp-content/uploads/2014/01/13-Chaparral-CO2- Midstream-Overview-2013.12.09new.pdf. 
392‘‘Val Verde Fact Sheet: Commercial EOR using 
Anthropogenic Carbon Dioxide.’’ https://sequestration.mit.edu/tools/projects/val_verde.html. 
393Kemper County IGCC Fact Sheet: Carbon 
Dioxide Capture and Storage Project. https://sequestration.mit.edu/tools/projects/kemper.html. 
394Office of Fossil Energy and Carbon 
Management. Southern Company—Kemper County, Mississippi. https://www.energy.gov/fecm/ 
southern-company-kemper-county-mississippi. 
395Citronelle Project. National Energy 
Technology Laboratory. (2018). https://www.netl.doe.gov/sites/default/files/2018-11/ Citronelle-SECARB-Project.PDF. 
396Jacobs, Trent. (2023). ‘‘A New Day Begins for 
Shuttered Petra Nova CCUS.’’ https://jpt.spe.org/a- new-day-begins-for-shuttered-petra-nova-ccus. 397Technical Review of Subpart RR MRV Plan for 
Petra Nova West Ranch Unit. (2021). https:// www.epa.gov/system/files/documents/2021-09/ wru_ decision.pdf. 
398Technical Review of Subpart RR MRV Plan for 
Archer Daniels Midland Illinois Industrial Carbon Capture and Storage Project. (2017). https:// www.epa.gov/sites/default/files/2017-01/ documents/adm_ final_ decision.pdf. 
399Red Trail Energy Subpart RR Monitoring, 
Reporting, and Verification (MRV) Plan. (2022). https://www.epa.gov/system/files/documents/2022- 04/rtemrvplan.pdf. 
400Technical Review of Subpart RR MRV Plan for 
Tundra SGS LLC at the Milton R. Young Station. (2022). https://www.epa.gov/system/files/ 
documents/2022-04/tsgsdecision.pdf. 
401Denbury. Detailed Pipeline and Ownership 
Information. (2022) https://www.denbury.com/wp- content/uploads/2022/11/DEN-Pipeline- Schedule.pdf. 402AP News. Officials mark start of CO 2pipeline 
used for oil recovery. (2022) https://apnews.com/ 
article/business-texas-north-dakota-plano- 25f1dbf9a924613a56827c1c83e4ba68. 
403Denbury. Detailed Pipeline and Ownership 
Information. (2022) https://www.denbury.com/wp- content/uploads/2022/11/DEN-Pipeline- Schedule.pdf. 
404Tallgrass. Tallgrass to Capture and Sequester 
CO 2Emissions from ADM Corn Processing Complex 
in Nebraska. (2022). https://tallgrass.com/ 
newsroom/press-releases/tallgrass-to-capture-and- sequester-co2-emissions-from-adm-corn-processing- complex-in-nebraska. 
405https://boldnebraska.org/upcoming-meetings- 
understanding-the-new-tallgrass-carbon-pipeline- community-benefits-agreement/. was then constructed, and operations 
started in 2013.391Furthermore, a 132 
km (82 mile) pipeline was constructed from the Terrell Gas facility (formerly Val Verde) in Texas to supply CO
2for 
EOR projects in the Permian Basin.392 
Additionally, the Kemper Country CCS project in Mississippi, was designed to capture CO
2from an integrated 
gasification combined cycle power plant, and transport CO
2via a 96 km (60 
mile) pipeline to be used in EOR.393 
Construction for this facility commenced in 2010 and was completed in 2014.
394Furthermore, the Citronelle 
Project in Alabama, which was the largest demonstration of a fully integrated, pulverized coal-fired CCS project in the United States as of 2016, utilized a dedicated 19 km (12 mile) pipeline constructed by Denbury Resources in 2011 to transport CO
2to a 
saline storage site.395 
(c) EPAct05-Assisted CO 2Pipelines for 
CCS 
Consistent with the EPA’s legal 
interpretation that the Agency can rely on experience from EPAct05 funded facilities in conjunction with other information, this section provides additional examples of CO
2pipelines 
with EPAct05 funding. CCS projects with EPAct05 funding have built pipelines to connect the captured CO
2 
source with sequestration sites, including Illinois Industrial Carbon Capture and Storage in Illinois, Petra Nova in Texas, and Red Trail Energy in North Dakota. The Petra Nova project, which restarted operations in September 2023,
396transports CO 2via a 131 km (81 
mile) pipeline to the injection site, while the Illinois Industrial Carbon Capture project and Red Trail Energy transport CO
2using pipelines under 8 km (5 miles) long.397 398 399 Additionally, 
Project Tundra, a saline sequestration project planned at the lignite-fired Milton R. Young Station in North Dakota will transport CO
2via a 0.4 km 
(0.25 mile) pipeline.400 
(d) Existing and Planned CO 2 
Trunklines 
Although the BSER is premised on the 
construction of pipelines that connect the CO
2source to the sequestration site, 
in practice some sources may construct short laterals to existing CO
2trunklines, 
which can reduce the number of miles of pipeline that may need to be constructed. A map displaying both existing and planned CO
2pipelines, 
overlayed on potential geologic sequestration sites, is available in the final TSD, GHG Mitigation Measures for Steam Generating Units. Pipelines connect natural CO
2sources in south 
central Colorado, northeast New Mexico, and Mississippi to oil fields in Texas, Oklahoma, New Mexico, Utah, and Louisiana. The Cortez pipeline is the longest CO
2pipeline, and it 
traverses over 800 km (500) miles from southwest Colorado to Denver City, Texas CO
2Hub, where it connects with 
several other CO 2pipelines. Many 
existing CO 2pipelines in the U.S. are 
located in the Permian Basin region of west Texas and eastern New Mexico. CO
2pipelines in Wyoming, Texas, and 
Louisiana also carry CO 2captured from 
natural gas processing plants and refineries to EOR projects. Additional pipelines have been constructed to meet the demand for CO
2transportation. A 
170 km (105 mile) CO 2pipeline owned 
by Denbury connecting oil fields in the Cedar Creek Anticline (located along the Montana-North Dakota border) to CO
2 
produced in Wyoming was completed in 2021, and a 30 km (18 mile) pipeline also owned by Denbury connects to the same oil field and was completed in 2022.
401 402 These pipelines form a network with existing pipelines in the 
region—including the Denbury Greencore pipeline, which was completed in 2012 and is 232 miles long, running from the Lost Cabin gas plant in Wyoming to Bell Creek Field in Montana.
403 
In addition to the existing pipeline 
network, there are a number of large CO
2trunklines that are planned or in 
progress, which could further reduce the number of miles of pipeline that a source may need to construct. Several major projects have recently been announced to expand the CO
2pipeline 
network across the United States. For example, the Summit Carbon Solutions Midwest Carbon Express project has proposed to add more than 3,200 km (2,000) miles of dedicated CO
2pipeline 
in Iowa, Nebraska, North Dakota, South Dakota, and Minnesota. The Midwest Carbon Express is projected to begin operations in 2026. Further, Wolf Carbon Solutions has recently announced that it plans to refile permit applications for the Mt. Simon Hub, which will expand the CO
2pipeline by 
450 km (280 miles) in the Midwest. Tallgrass announced in 2022 a plan to convert an existing 630 km (392 mile) natural gas pipeline to carry CO
2from 
an ADM ethanol production facility in Nebraska to a planned commercial-scale CO
2sequestration hub in Wyoming 
aimed for completion in 2024.404 
Recently, as part of agreeing to a communities benefits plan, a number of community groups have agreed that they will support construction of the Tallgrass pipeline in Nebraska.
405While 
the construction of larger networks of trunklines could facilitate CCS for power plants, the BSER is not predicated on the buildout of a trunkline network and the existence of future trunklines was not assumed in the EPA’s feasibility or costing analysis. The EPA’s analysis is conservative in that it does not presume the buildout of trunkline networks. The development of more robust and interconnected pipeline systems over the next several years would merely lower the EPA’s 
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406Office of Fossil Energy and Carbon 
Management. ‘‘Project Selections for FOA 2730: 
Carbon Dioxide Transport Engineering and Design (Round 1).’’ https://www.energy.gov/fecm/project- selections-foa-2730-carbon-dioxide-transport- engineering-and-design-round-1. 
407https://www.energy.gov/lpo/carbon-dioxide- 
transportation-infrastructure. 408Congressional Research Service.2022. Carbon 
Dioxide Pipelines: Safety Issues, CRS Reports, June 
3, 2022. https://crsreports.congress.gov/product/ pdf/IN/IN11944. 
409Great Plains Institute State Legislative Tracker 
2023. Carbon Management State Legislative Program Tracker. https://www.quorum.us/ spreadsheet/external/fVOjsTvwyeWkIqVlNmoq/ ?mc_ cid=915706f2bc&. 
410National Association of Regulatory Utility 
Commissioners (NARUC). (2023). Onshore U.S. Carbon Pipeline Deployment: Siting, Safety. and Regulation. https://pubs.naruc.org/pub/F1EECB6B- 
CD8A-6AD4-B05B-E7DA0F12672E. 
411Martin Lockman. Permitting CO 2Pipelines. 
Sabin Center for Climate Change Law (2023). https://scholarship.law.columbia.edu/cgi/ viewcontent.cgi?article=1208&context=sabin_climate_ change. 
412The 17 states are: Arizona, Illinois, Indiana, 
Iowa, Kentucky, Louisiana, Michigan, Mississippi, Missouri, Montana, New Mexico, North Carolina, North Dakota, Pennsylvania, South Dakota, Texas, and Wyoming. National Association of Regulatory Utility Commissioners (NARUC). (2023). Onshore 
U.S. Carbon Pipeline Deployment: Siting, Safety. and Regulation. https://pubs.naruc.org/pub/ F1EECB6B-CD8A-6AD4-B05B-E7DA0F12672E. 413Martin Lockman. Permitting CO 2Pipelines. 
Sabin Center for Climate Change Law (Sept. 2023). https://scholarship.law.columbia.edu/cgi/ viewcontent.cgi?article=1208&context=sabin_climate_ change. 
414South Dakota Public Broadcasting. ‘‘Summit 
reaches land deals on more than half of CO 2 
pipeline route.’’ (2022). https://listen.sdpb.org/ business-economics/2022-11-08/summit-reaches- land-deals-on-more-than-half-of-co2-pipeline-route. 
415Summit CEO: CO2 Pipeline’s Time is Now. 
(2024). https://www.dtnpf.com/agriculture/web/ag/ 
news/business-inputs/article/2024/02/23/summit- ceo-blank-says-company-toward. 
416Summit Carbon Solutions. Summit Carbon 
Solutions Signs 80 Percent of North Dakota Landowners. (2023). https://summitcarbonsolutions.com/summit-carbon- solutions-signs-80-percent-of-north-dakota- landowners/. 
417Summit Carbon Solutions. Summit Carbon 
Solutions Announces Progress on Carbon Capture and Storage Project. (2022). https://summitcarbonsolutions.com/summit-carbon- solutions-announces-progress-on-carbon-capture- and-storage-project/. cost projections and create additional 
CO 2transport options for power plants 
that do CCS. 
Moreover, pipeline projects have 
received funding under the IIJA to 
conduct front-end engineering and design (FEED) studies.
406Carbon 
Solutions LLC received funding to conduct a FEED study for a commercial- scale pipeline to transport CO
2in 
support of the Wyoming Trails Carbon Hub as part of a statewide pipeline system that would be capable of transporting up to 45 million metric tons of CO
2per year from multiple 
sources. In addition, Howard Midstream Energy Partners LLC received funding to conduct a FEED study for a 965 km (600 mi) CO
2pipeline system on the Gulf 
Coast that would be capable of moving at least 250 million metric tons of CO
2 
annually and connecting carbon sources within 30 mi of the trunkline. 
Other programs were created by the 
IIJA to facilitate the buildout of large pipelines to carry carbon dioxide from multiple sources. For example, the Carbon Dioxide Transportation Infrastructure Finance and Innovation Act (CIFIA) was incorporated into the IIJA and provided $2.1 billion to DOE to finance projects that build shared (i.e., common carrier) transport infrastructure to move CO
2from points of capture to 
conversion facilities and/or storage wells. The program offers direct loans, loan guarantees, and ‘‘future growth grants’’ to provide cash payments to specifically for eligible costs to build additional capacity for potential future demand.
407 
(2) Permitting and Rights of Way 
The permitting process for CO 2 
pipelines often involves a number of private, local, state, tribal, and/or Federal agencies. States and local governments are directly involved in siting and permitting proposed CO
2 
pipeline projects. CO 2pipeline siting 
and permitting authorities, landowner rights, and eminent domain laws are governed by the states and vary by state. 
State laws determine pipeline siting 
and the process for developers to acquire rights-of-way needed to build. Pipeline developers may secure rights- of-way for proposed projects through voluntary agreements with landowners; pipeline developers may also secure rights-of-way through eminent domain authority, which typically accompanies 
siting permits from state utility regulators with jurisdiction over CO
2 
pipeline siting.408The permitting 
process for interstate pipelines may take longer than for intrastate pipelines. Whereas multiple state regulatory agencies would be involved in the permitting process for an interstate pipeline, only one primary state regulatory agency would be involved in the permitting process for an intrastate pipeline. 
Most regulation of CO
2pipeline siting 
and development is conducted at the state level, and under state specific regulatory regimes. As the interest in CO
2pipelines has grown, states have 
taken steps to facilitate pipeline siting and construction. State level regulation related to CO
2sequestration and 
transport is an very active area of legislation across states in all parts of the country, with many states seeking to facilitate pipeline siting and construction.
409Many states, including 
Kentucky, Michigan, Montana, Arkansas, and Rhode Island, treat CO
2 
pipeline operators as common carriers or public utilities.
410This is an 
important classification in some jurisdictions where it may be required for pipelines seeking to exercise eminent domain.
411Currently, 17 states 
explicitly allow CO 2pipeline operators 
to exercise eminent domain authority for acquisition of CO
2pipeline rights-of- 
way, should developers not secure them through negotiation with landowners.
412 
Some states have recognized the need for a streamlined CO
2pipeline 
permitting process when there are multiple layers of regulation and developed joint permit applications. Illinois, Louisiana, New York, and Pennsylvania have created a joint permitting form that allows applicants to file a single application for pipeline projects covering both state and federal permitting requirements.
413Even in 
states without this streamlined process, pipeline developers can pursue required state permits concurrently with federal 
permits, NEPA review (as applicable), and the acquisition of rights-of-way. 
Pipeline developers have been able to 
successfully secure the necessary rights- of way for CO
2pipeline projects. For 
example, Summit Carbon Solutions, which has proposed to add more than 3,200 km (2,000 mi) of dedicated CO
2 
pipeline in Iowa, Nebraska, North Dakota, South Dakota, and Minnesota, has stated that as of November 7, 2023, it had reached easement agreements with 2,100 landowners along the route.
414As of February 23, 2024, 
Summit Carbon Solutions stated that it had acquired about 75 percent of the rights of way needed in Iowa, about 80 percent in North Dakota, about 75 percent in South Dakota, and about 89 percent in Minnesota. The company has successfully navigated hurdles, such as rerouting the pipelines in certain counties where necessary.
415 416 The 
EPA notes that this successful acquisition of right-of-way easements for thousands of miles of pipeline across five states has taken place in just the three years since the project launched in 2021.
417In addition, the Citronelle 
Project, which was constructed in Alabama in 2011, successfully acquired rights-of-way through 9 miles of forested and commercial timber land and 3 miles of emergent shrub and forested wetlands. The Citronelle Project was able to attain rights-of-way through the habitat of an endangered species by mitigating potential environmental 
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418SECARB. (2021). Final Project Report— 
SECARB Phase III, September 2021. https://
www.osti.gov/servlets/purl/1823250. 
419Great Falls Tribune. Texas company plans 
110-mile CO 2pipeline to enhance Montana oil 
recovery. (2018). https://www.greatfallstribune.com/story/news/2018/10/09/texas-company-plans- co-2-pipeline-injection-free-montana-oil/ 1577657002/. 
420U.S. D.O.I B.L.M. Denbury-Green Pipeline-MT, 
LLC, Denbury Onshore, LLC Cedar Creek Anticline CO
2Pipeline and EOR Development Project 
Scoping Report. https://eplanning.blm.gov/public_projects/nepa/89883/137194/167548/BLM_Denbury_ Projects_ Scoping_ Report_ March2018.pdf. 
421AP News. Officials mark start of CO 2pipeline 
used for oil recovery. (2022) https://apnews.com/ article/business-texas-north-dakota-plano- 25f1dbf9a924613a56827c1c83e4ba68. 
422Council on Environmental Quality. (2024). 
CEQ NEPA Regulations. https://ceq.doe.gov/laws- regulations/regulations.html. 
423Council of Environmental Quality. (2023). 
Agency NEPA Implementing Procedures. https://ceq.doe.gov/laws-regulations/agency_implementing_ procedures.html. 424Public Law 118–5 (June 3, 2023). 
425NEPA Sec. 107(g)(1); 42 U.S.C. 4336a(g)(1). 
426NEPA sec. 107(g)(2); 42 U.S.C. 4336a(g)(2). 
427Massachusetts Institute of Technology. (2014). 
Decatur Fact Sheet: Carbon Dioxide Capture and Storage Project. https://sequestration.mit.edu/tools/ projects/decatur.html. 
428NETL. ‘‘CO2 Capture from Biofuels Production 
and Sequestration into the Mt. Simon Sandstone.’’ Award #DE–FE0001547. https://www.usaspending.gov/award/ASST_ NON_ DEFE0001547_ 8900. 
429Air Products. Carbon Capture. https://
www.airproducts.com/company/innovation/carbon- capture. 
430Department of Energy. (2011). Final 
Environmental Assessment for Air Products and Chemicals, Inc. Recovery Act: Demonstration of 
CO 2Capture and Sequestration of Steam Methane 
Reforming Process Gas Used for Large Scale Hydrogen Production. https://netl.doe.gov/sites/ default/files/environmental-assessments/20110622_APCI_ PtA_ CO2_ FEA.pdf. 
431Department of Energy, Office of NEPA Policy 
and Compliance. (2013). EIS–0473: Record of Decision. https://www.energy.gov/nepa/articles/eis- 
0473-record-decision. 
432Department of Energy. (2017). Petra Nova 
W.A. Parish Project. https://www.energy.gov/fecm/ 
petra-nova-wa-parish-project. 
433Kennedy, Greg. (2020). ‘‘W.A. Parish Post 
Combustion CO 2Capture and Sequestration 
Demonstration Project.’’ Final Technical Report. https://www.osti.gov/biblio/1608572/. 
434CEQ. (2021). ‘‘Council on Environmental 
Quality Report to Congress on Carbon Capture, Utilization, and Sequestration.’’ https://www.whitehouse.gov/wp-content/uploads/2021/06/ CEQ-CCUS-Permitting-Report.pdf. impacts.418Even projects that require 
rights-of-way across multiple ownership 
regimes including state, private, and federally owned land have been successfully developed. The 170 km (105 mile) Cedar Creek Anticline CO
2 
pipeline owned by Denbury required easements for approximately 10 km (6.2 mi) to cross state school trust lands in Montana, 27 km (17 mi) across Federal land and the remaining miles across private lands.
419 420 The pipeline was 
completed in 2021.421 
Federal actions (e.g., funding a CCS 
project) must generally comply with NEPA, which often requires that an environmental assessment (EA) or environmental impact statement (EIS) be conducted to consider environmental 
impacts of the proposed action, including consideration of reasonable alternatives.
422An EA determines 
whether or not a Federal action has the potential to cause significant environmental effects. Each Federal agency has adopted its own NEPA procedures for the preparation of EAs.
423If the agency determines that the 
action will not have significant environmental impacts, the agency will issue a Finding of No Significant Impact (FONSI). Some projects may also be ‘‘categorically excluded’’ from a detailed environmental analysis when the Federal action normally does not have a significant effect on the human environment. Federal agencies prepare an EIS if a proposed Federal action is determined to significantly affect the quality of the human environment. The regulatory requirements for an EIS are more detailed and rigorous than the requirements for an EA. The determination of the level of NEPA review depends on the potential for significant environmental impacts considering the whole project (e.g., 
crossings of sensitive habitats, cultural resources, wetlands, public safety concerns). Consequently, whether a pipeline project is covered by NEPA and the associated permitting timelines may vary depending on site characteristics (e.g., pipeline length, whether a project 
crosses a water of the U.S.) and funding source. Pipelines through Bureau of Land Management (BLM) land, U.S. Forest Service (USFS) land, or other Federal land would be subject to NEPA. To ensure that agencies conduct NEPA reviews as efficiently and expeditiously as practicable, the Fiscal Responsibility Act
424amendments to NEPA 
established deadlines for the preparation of environmental assessments and environmental impact statements. Environmental assessments must be completed within 1 year and environmental impact statements must 
be completed within 2 years
425A lead 
agency that determines it is not able to meet the deadline may extend the deadline, in consultation with the applicant, to establish a new deadline that provides only so much additional time as is necessary to complete such environmental impact statement or environmental assessment.
426 
As discussed above, it is anticipated 
that most EGUs would need shorter, intrastate pipeline segments. For example, ADM’s Decatur, Illinois, pipeline, which spans 1.9 km (1.18 miles), was constructed after Decatur was selected for the DOE Phase 1 research and development grants in October 2009.
427Construction of the 
CO 2compression, dehydration, and 
pipeline facilities began in July 2011 and was completed in June 2013.
428The 
ADM project required only an EA. Additionally, Air Products operates a large-scale system to capture CO
2from 
two steam methane reformers located within the Valero Refinery in Port Arthur, Texas. The recovered and purified CO
2is delivered by pipeline for 
use in enhanced oil recovery operations.
429This 12-mile pipeline 
required only an EA.430Conversely, the Petra Nova project in Texas required an 
EIS to evaluate the potential environmental impacts associated with DOE’s proposed action of providing financial assistance for the project. This EIS addressed potential impacts from both the associated 131 km (81 mile) pipeline and other aspects of the larger CCS system, including the post- combustion CO
2.431For Petra Nova, a 
notice of intent to issue an EIS was published on November 14, 2011, and the record of decision was issued less than 2 years later, on May 23, 2013.
432 
Construction of the CO 2pipeline for 
Petra Nova from the W.A. Parish Power Plant to the West Ranch Oilfield in Jackson County, TX began in July 2014 and was completed in July 2016.
433 
Compliance with section 7 of the 
Endangered Species Act related to Federal agency consultation and biological assessment is also required for projects on Federal lands. Specifically, the Endangered Species Act requires consultation with the Department of Interior’s Fish and Wildlife Service and Department of Commerce’s NOAA Fisheries, in order to avoid or mitigate impacts to any threatened or endangered species and their habitats.
434This agency 
consultation process and biological assessment are generally conducted during preparation of the NEPA documentation (EIS or EA) for the Federal project and generally within the regulatory timeframes for environmental assessment or environmental impact statement preparation. Consequently, the EPA does not anticipate that compliance with the Endangered Species Act will change the anticipated timeline for most projects. 
The EPA notes that the Fixing 
America’s Surface Transportation Act (FAST Act) is also relevant to CCS projects and pipelines. Title 41 of this Act (42 U.S.C. 4370m et seq.), referred to as ‘‘FAST–41,’’ created a new 
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435Federal Permitting Improvement Steering 
Council. (2022). FAST–41 Fact Sheet. https://
www.permits.performance.gov/documentation/fast- 
41-fact-sheet. 
436Galford, Chris. USE IT carbon capture bill 
becomes law, incentivizing development and deployment. (2020). https://dailyenergyinsider.com/news/28522-use-it-carbon- capture-bill-becomes-law-incentivizing- development-and-deployment/. 
437Permitting Dashboard Federal Infrastructure 
Projects. https://permits.performance.gov/. 
438EPA. ‘‘FAST–41 Coordination.’’ (2023). 
https://www.epa.gov/sustainability/fast-41- coordination. 
439‘‘CCS Pipeline Route Planning Database V1— 
EDX.’’ https://edx.netl.doe.gov/dataset/ccs- 
pipeline-route-planning-database-v1. 
440‘‘CCS Pipeline Route Planning Database V1— 
EDX.’’ https://edx.netl.doe.gov/dataset/ccs- 
pipeline-route-planning-database-v1. 
441Department of Energy. ‘‘CCS Pipeline Route 
Planning Database V1—EDX.’’ https://edx.netl.doe.gov/dataset/ccs-pipeline-route- planning-database-v1. 442See generally 49 CFR 190–199. 
443Congressional Research Service. 2022. Carbon 
Dioxide Pipelines: Safety Issues, CRS Reports, June governance structure, set of procedures, 
and funding authorities to improve the Federal environmental review and authorization process for covered infrastructure projects.
435The Utilizing 
Significant Emissions with Innovative Technologies (USE IT) Act, among other actions, clarified that CCS projects and CO
2pipelines are eligible for this more 
predictable and transparent review process.
436FAST–41 created the Federal 
Permitting Improvement Steering Council (Permitting Council), composed of agency Deputy Secretary-level members and chaired by an Executive Director appointed by the President. FAST–41 establishes procedures that standardize interagency consultation and coordination practices. FAST–41 codifies into law the use of the Permitting Dashboard
437to track project 
timelines, including qualifying actions that must be taken by the EPA and other Federal agencies. Project sponsor participation in FAST–41 is voluntary.
438 
Community engagement also plays a 
role in the safe operation and construction of CO
2pipelines. These 
efforts can be supported using the CCS Pipeline Route Planning Database that was developed by NETL, a public resource designed to support pipeline routing decisions and increase transportation safety.
439The database 
includes state-specific regulations and restrictions, energy and social justice factors, land use requirements, existing infrastructure, and areas of potential risk. The database produces weighted values ranging from zero to one, where zero represents acceptable areas for pipeline placement and one represents areas that should be avoided.
440The 
database will be a key input for the CCS Pipeline Route Planning Tool under development by NETL.
441The purpose of the siting tool is to aid pipeline 
routing decisions and facilitate avoidance of areas that would pose permitting challenges. 
In sum, the permitting process for CO
2 
pipelines often involves private, local, state, tribal, and/or Federal agencies, and permitting timelines may vary depending on site characteristics. Projects that opt in to the FAST–41 process are eligible for a more transparent and predictable review process. EGUs can generally proceed to obtain permits and rights-of-way simultaneously, and the EPA anticipates that, in total, the permitting process would only take around 2.5 years for pipelines that only need an EA, with a possible additional year if the project requires an EIS (see the final TSD, GHG Mitigation Measures for Steam Generating Units for additional information). This is consistent with the anticipated timelines for CCS discussed in section VII.C.1.a.i(E). Furthermore, the EPA notes that there is over 60 years of experience in the CO
2pipeline 
industry designing, permitting, building and operating CO
2pipelines, and that 
this expertise can be applied to the CO 2 
pipelines that would be constructed to connect to sequestration sites and units. 
As discussed above in section 
VII.C.1.a.i.(C)(1)(a), the core of the EPA’s analysis of pipeline feasibility focuses on units located within 100 km (62 miles) of potential deep saline sequestration formations. The EPA notes that the majority (80 percent) of the coal-fired steam generating capacity with planned operation during or after 2039 is located within 100 km (62 miles) of the nearest potential deep saline sequestration site. For these sources, as explained, units would be required only to build relatively short pipelines, and such buildout would be feasible within the required timeframe. For the capacity that is more than 100 km (62 miles) away from sequestration, building a pipeline may become more complex. Almost all (98 percent) of this capacity’s closest sequestration site is located outside state boundaries, and access to the nearest sequestration site would require building an interstate pipeline and coordinating with multiple state authorities for permitting purposes. Conversely, for capacity where the distance to the nearest potential sequestration site is less than 100 km (62 miles), only about 19 percent would require the associated pipeline to cross state boundaries. Therefore, the EPA believes that distance to the nearest sequestration site is a useful proxy for considerations related to the complexity of pipeline construction and how long it will take 
to build a pipeline. 
A unit that is located more than 100 
km away from sequestration may face complexities in pipeline construction, including additional permitting hurdles, 
difficulties in obtaining the necessary rights of way over such a distance, or other considerations, that may make it unreasonable for that unit to meet the compliance schedule that is generally reasonable for sources in the subcategory as a whole. Pursuant to the RULOF provisions of 40 CFR 60.2a(e)– (h), if a state can demonstrate that there is a fundamental difference between the information relevant to a particular affected EGU and the information the EPA considered in determining the compliance deadline for sources in the long-term subcategory, and that this difference makes it unreasonable for the EGU to meet the compliance deadline, a longer compliance schedule may be warranted. The EPA does not believe that the fact that a pipeline crosses state boundaries standing alone is sufficient to show that an extended timeframe would be appropriate—many such pipelines could be reasonably accomplished in the required timeframe. Rather, it is the confluence of factors, including that a pipeline crosses state boundaries, along with others that may make RULOF appropriate. 
(3) Security of CO
2Transport 
As part of its analysis, the EPA also 
considered the safety of CO 2pipelines. 
The safety of existing and new CO 2 
pipelines that transport CO 2in a 
supercritical state is regulated by 
PHMSA. These regulations include standards related to pipeline design, pipeline construction and testing, pipeline operations and maintenance, operator reporting requirements, operator qualifications, corrosion control and pipeline integrity management, incident reporting and response, and public awareness and communications. PHMSA has regulatory authority to conduct inspections of supercritical CO
2 
pipeline operations and issue notices to operators in the event of operator noncompliance with regulatory requirements.
442 
CO 2pipelines have been operating 
safely for more than 60 years. In the past 20 years, 500 million metric tons of CO
2 
moved through over 5,000 miles of CO 2 
pipelines with zero incidents involving fatalities.
443PHMSA reported a total of 
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3, 2022. https://crsreports.congress.gov/product/ 
pdf/IN/IN11944. 
444NARUC. (2023). Onshore U.S. Carbon Pipeline 
Deployment: Siting, Safety. and Regulation. Prepared by Public Sector Consultants for the National Association of Regulatory Utility Commissioners (NARUC). June 2023. https://pubs.naruc.org/pub/F1EECB6B-CD8A-6AD4-B05B- E7DA0F12672E. 
445Failure Investigation Report—Denbury Gulf 
Coast Pipeline, May 2022. https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/ 2022-05/Failure%20Investigation%20Report%20- %20Denbury%20Gulf%20Coast%20Pipeline.pdf. 
446PHMSA. (2022). ‘‘PHMSA Announces New 
Safety Measures to Protect Americans From Carbon Dioxide Pipeline Failures After Satartia, MS Leak.’’ https://www.phmsa.dot.gov/news/phmsa- announces-new-safety-measures-protect-americans- carbon-dioxide-pipeline-failures. 
447Columbia Law School. (2024). PHMSA 
Advances CO2 Pipeline Safety Regulations. https:// 
climate.law.columbia.edu/content/phmsa- 
advances-co2-pipeline-safety-regulations. 448Department of Transportation. (2023). Consent 
Order, Denbury Gulf Coast Pipelines, LLC, CPF No. 
4–2022–017–NOPV https://primis.phmsa.dot.gov/ 
comm/reports/enforce/CaseDetail_ cpf_
42022017NOPV.html?nocache=7208. 
449Ibid. 
450New Mexico Public Regulation Commission. 
2023. Transportation Pipeline Safety. New Mexico 
Public Regulation Commission, Bureau of Pipeline Safety. https://www.nm-prc.org/transportation/ 
pipeline-safety. 
451Texas Railroad Commission. 2023. Oversight & 
Safety Division. Texas Railroad Commission. https://www.rrc.texas.gov/about-us/organization- and-activities/rrc-divisions/oversight-safety- division. 
452NARUC. (2023). Onshore U.S. Carbon Pipeline 
Deployment: Siting, Safety. and Regulation. Prepared by Public Sector Consultants for the National Association of Regulatory Utility Commissioners (NARUC). June 2023. https://pubs.naruc.org/pub/F1EECB6B-CD8A-6AD4-B05B- E7DA0F12672E. 
453PHMSA. (2023). ‘‘PHMSA Issues Letters to 
Wolf Carbon, Summit, and Navigator Clarifying Federal, State, and Local Government Pipeline Authorities.’’ https://www.phmsa.dot.gov/news/ 
phmsa-issues-letters-wolf-carbon-summit-and- navigator-clarifying-federal-state-and-local. 
454PHMSA, ‘‘PHMSA Issues Letters to Wolf 
Carbon, Summit, and Navigator Clarifying Federal, State, and Local Government Pipeline Authorities.’’ 2023. https://www.phmsa.dot.gov/news/phmsa- 
issues-letters-wolf-carbon-summit-and-navigator- clarifying-federal-state-and-local. 
455Carbon Capture Coalition. ‘‘PHMSA/Pipeline 
Safety Fact Sheet,’’ November 2023. https://carboncapturecoalition.org/wp-content/uploads/ 2023/11/Pipeline-Safety-Fact-Sheet.pdf. 456Summit Carbon Solutions. Summit Carbon 
Solutions Signs 80 Percent of North Dakota 
Continued 102 CO 2pipeline incidents between 
2003 and 2022, with one injury 
(requiring in-patient hospitalization) and zero fatalities.
444 
As noted previously in this preamble, 
a significant CO 2pipeline rupture 
occurred in 2020 in Satartia, Mississippi, following heavy rains that resulted in a landslide. Although no one required in-patient hospitalization as a result of this incident, 45 people received treatment at local emergency rooms after the incident and 200 hundred residents were evacuated. Typically, when CO
2is released into the 
open air, it vaporizes into a heavier- than-air gas and dissipates. During the Satartia incident, however, unique atmospheric conditions and the topographical features of the area delayed this dissipation. As a result, residents were exposed to high concentrations of CO
2in the air after the 
rupture. Furthermore, local emergency responders were not informed by the operator of the rupture and the nature of the unique safety risks of the CO
2 
pipeline.445 
PHMSA initiated a rulemaking in 
2022 to develop and implement new measures to strengthen its safety oversight of supercritical CO
2pipelines 
following the investigation into the CO 2 
pipeline failure in Satartia.446PHMSA 
submitted the associated Notice of Proposed Rulemaking to the White House Office of Management and Budget on February 1, 2024 for pre- publication review.
447Following the 
Satartia incident, PHMSA also issued a Notice of Probable Violation, Proposed Civil Penalty, and Proposed Compliance 
Order (Notice) to the operator related to probable violations of Federal pipeline safety regulations. The Notice was ultimately resolved through a Consent Agreement between PHMSA and the operator that includes the assessment of civil penalties and identifies actions for 
the operator to take to address the alleged violations and risk conditions.
448PHMSA has further 
issued an updated nationwide advisory bulletin to all pipeline operators and solicited research proposals to strengthen CO
2pipeline safety.449Given 
the Federal and state regulation of CO 2 
pipelines and the steps that PHMSA is taking to further improve pipeline safety, the EPA believes CO
2can be 
safely transported by pipeline. 
Certain states have authority 
delegated from the U.S. Department of Transportation to conduct safety inspections and enforce state and Federal pipeline safety regulations for intrastate CO
2pipelines.450 451 452  
PHMSA’s state partners employ about 70 percent of all pipeline inspectors, which covers more than 80 percent of regulated pipelines.
453Federal law 
requires certified state authorities to adopt safety standards at least as stringent as the Federal standards.
454 
Further, there are required steps that CO
2pipeline operators must take to 
ensure pipelines are operated safely under PHMSA standards and related state standards, such as the use of pressure monitors to detect leaks or initiate shut-off valves, and annual reporting on operations, structural integrity assessments, and inspections.
455These CO 2pipeline controls and PHMSA standards are 
designed to ensure that captured CO 2 
will be securely conveyed to a sequestration site. 
(4) Comments Received on CO
2 
Transport and Responses 
The EPA received comments on CO 2 
transport, including CO 2pipelines. 
Those comments, and the EPA’s 
responses, are as follows. 
Comment: Some commenters 
identified challenges to the deployment of a national, interstate CO
2pipeline 
network. In particular, those commenters discussed the experience faced by long (e.g., over 1,000 miles) 
CO
2pipelines seeking permitting and 
right-of-way access in Midwest states including Iowa and North Dakota. Commenters claimed those challenges make CCS as BSER infeasible. Some commenters argued that the existing CO
2pipeline capacity is not adequate to 
meet potential demand caused by this rule and that the ability of the network to grow and meet future potential demand is hindered by significant public opposition. 
Response: The EPA acknowledges the 
challenges that some large multi-state pipeline projects have faced, but does not agree that those experiences show that the BSER is not adequately demonstrated or that the standards finalized in these actions are not achievable. As detailed in the preceding subsections of the preamble, the BSER is not premised on the buildout of a national, trunkline CO
2pipeline 
network. Most coal-fired steam generating units are in relatively close proximity to geologic storage, and those shorter pipelines would not likely be as challenging to permit and build as demonstrated by the examples of smaller pipeline discussed above. 
The EPA acknowledges that some 
larger trunkline CO
2pipeline projects, 
specifically the Heartland Greenway project, have recently been delayed or canceled. However, many projects are still moving forward and several major projects have recently been announced to expand the CO
2pipeline network 
across the United States. The EPA notes that there are often opportunities to reroute pipelines to minimize permitting challenges and landowner concerns. For example, Summit Carbon Solutions changed their planned pipeline route in North Dakota after their initial permit was denied, leading to successful acquisition of rights of way.
456Additionally, Tallgrass, which 
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Landowners. (2023). https://
summitcarbonsolutions.com/summit-carbon- solutions-signs-80-percent-of-north-dakota- landowners/. 
457Hammel, Paul. (2024). Pipeline company, 
Nebraska environmental group strike unique ‘community benefits’ agreement. https://www.desmoinesregister.com/story/tech/science/ environment/2024/04/11/nebraska- environmentalist-forge-peace-pact-with-pipeline- company/73282852007/. 
458Sequestration potential as it relates to distance 
from existing resources is a key part of the EPA’s regular power sector modeling development, using data from DOE/NETL studies. For details, please see chapter 6 of the IPM documentation. https://www.epa.gov/system/files/documents/2021-09/ chapter-6-co2-capture-storage-and-transport.pdf. 459The pipeline diameter was sized for this to be 
achieved without the need for recompression stages along the pipeline length. 
460Ogland-Hand, Jonathan D. et. al. 2022. 
Screening for Geologic Sequestration of CO 2: A 
Comparison Between SCO2TPRO and the FE/NETL CO
2Saline Storage Cost Model. International 
Journal of Greenhouse Gas Control, Volume 114, February 2022, 103557. https://www.sciencedirect.com/science/article/pii/ S175058362100308X. 461NETL. (2010). Carbon Dioxide Enhanced Oil 
Recovery. https://www.netl.doe.gov/sites/default/ 
files/netl-file/co2_ eor_primer.pdf. is planning to convert a 630 km (392 
mile) natural gas pipeline to carry CO 2, 
announced that they had reach a community benefits agreement, in which certain organizations have agreed not to oppose the pipeline project while Tallgrass has agreed to terms such as contributing funds to first responders along the pipeline route and providing royalty checks to landowners.
457See 
section VII.C.1.a.i(C)(1)(d) for additional discussion of planned CO
2pipelines. 
While access to larger trunkline projects would not be required for most EGUs, at least some larger trunkline projects are likely to be constructed, which would increase opportunities for connecting to pipeline networks. 
Comment: Some commenters 
disagreed with the modeling assumption that 100 km is a typical pipeline distance. The commenters asserted that there is data showing the actual locations of the power plants affected by the rule, and the required pipeline distance is not always 100 km. 
Response: The EPA acknowledges 
that the physical locations of EGUs and the physical locations of carbon sequestration capacity and corresponding pipeline distance will not be 100 km in all cases. As discussed previously in section VII.C.1.a.i(C)(1)(a), the EPA modeled the unique approximate distance from each existing coal-fired steam generating capacity with planned operation during or after 2039 to the nearest potential saline sequestration site, and found that the majority (80 percent) is within 100 km (62 miles) of potential saline sequestration sites, and another 11 
percent is within 160 km (100 miles).
458 
Furthermore, the EPA disagrees with the comments suggesting that the use of 100 km is an inappropriate economic modeling assumption. The 100 km assumption was not meant to encompass the physical location of every potentially affected EGU. The 100 km assumption is intended as an economic modeling assumption and is based on similar assumptions applied in NETL studies used to estimate CO
2 
transport costs. The EPA carefully reviewed the assumptions on which the NETL transport cost estimates are based and continues to find them reasonable. The NETL studies referenced in section VII.C.1.a.ii based transport costs on a generic 100 km (62 mile) pipeline and a generic 80 km pipeline.
459For most 
EGUs, the necessary pipeline distance is anticipated to be less than 100 km and therefore the associated costs could also be lower than these assumptions. Other published economic models applying different assumptions have also reached the conclusion that CO
2transport and 
sequestration are adequately demonstrated.
460 
Comment: Commenters also stated 
that the permitting and construction processes can be time-consuming. 
Response: The EPA acknowledges 
building CO
2pipelines requires capital 
expenditure and acknowledges that the timeline for siting, engineering design, permitting, and construction of CO
2 
pipelines depends on factors including the pipeline capacity and pipeline length, whether the pipeline route is intrastate or interstate, and the specifics of the state pipeline regulator’s regulatory requirements. In the BSER analysis, individual EGUs that are subject to carbon capture requirements are assumed to take a point-to-point approach to CO
2transport and 
sequestration. These smaller-scale projects require less capital and may present less complexity than larger projects. The EPA considers the timeline to permit and install such pipelines in section VII.C.1.a.i(E) of the preamble, and has determined that a compliance date of January 1, 2032 allows for a sufficient amount of time. 
Comment: Some commenters 
expressed significant concerns about the safety of CO
2pipelines following the 
CO 2pipeline failure in Satartia, 
Mississippi in 2020. 
Response: For a discussion of the 
safety of CO 2pipelines and the Satartia 
pipeline failure, see section VII.C.1.a.i(C)(3). The EPA believes that the framework of Federal and state regulation of CO
2pipelines and the 
steps that PHMSA is taking to further improve pipeline safety, is sufficient to ensure CO
2can be safely transported by 
pipeline. 
(D) Geologic Sequestration of CO 2 
The EPA is finalizing its 
determination that geologic 
sequestration (i.e., the long-term 
containment of a CO 2stream in 
subsurface geologic formations) is adequately demonstrated. In this section, we provide an overview of the availability of sequestration sites in the U.S., discuss how geologic sequestration of CO
2is well proven and broadly 
available throughout the U.S, explain the effectiveness of sequestration, discuss the regulatory framework for UIC wells, and discuss the timing of permitting for sequestration sites. We then provide a summary of key comments received concerning geologic sequestration and our responses to those comments. 
(1) Sequestration Sites for Coal-Fired 
Power Plants Subject to CCS Requirements 
(a) Broad Availability of Sequestration 
Sequestration is broadly available in 
the United States, which makes clear 
that it is adequately demonstrated. By far the most widely available and well understood type of sequestration is that 
in deep saline formations. These formations are common in the U.S. These formations are numerous and only a small subset of the existing saline storage capacity would be required to store the CO
2from EGUs. Many projects 
are in the process of completing thorough subsurface studies of these deep saline formations to determine their suitability for regional-scale storage. Furthermore, sequestration formations could also include unmineable coal seams and oil and gas reservoirs. CO
2may be stored in oil and 
gas reservoirs in association with EOR and enhanced gas recovery (EGR) technologies, collectively referred to as enhanced recovery (ER), which include the injection of CO
2in oil and gas 
reservoirs to increase production. ER is a technology that has been used for decades in states across the U.S.
461 
Geologic sequestration is based on a 
demonstrated understanding of the trapping and containment processes that retain CO
2in the subsurface. The 
presence of a low permeability seal is an important component of demonstrating secure geologic sequestration. Analyses of the potential availability of geologic sequestration capacity in the United States have been conducted by DOE, 
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462U.S. DOE NETL. (2015). Carbon Storage Atlas, 
Fifth Edition, September 2015. https://
www.netl.doe.gov/research/coal/carbon-storage/ atlasv. 
463U.S. Geological Survey Geologic Carbon 
Dioxide Storage Resources Assessment Team. (2013). National assessment of geologic carbon dioxide storage resources—Summary: U.S. Geological Survey Factsheet 2013–3020. http://pubs.usgs.gov/fs/2013/3020/. 
464Vickers, Clayton. (2024). ‘‘Last coal plants in 
New England to close; renewables take their place.’’ https://thehill.com/policy/energy-environment/ 4560375-new-hampshire-coal-plants-closing/. 465For detailed information on the estimated 
emissions reductions from this rule, see section 3 of the RIA, available in the rulemaking docket. 466Godec, Koperna, and Gale. (2014). ‘‘CO 2- 
ECBM: A Review of its Status and Global Potential’’, Energy Procedia, Volume 63. https://doi.org/10.1016/j.egypro.2014.11.619. 
467For details, please see Chapter 6 of the IPM 
documentation. https://www.epa.gov/system/files/ 
documents/2021-09/chapter-6-co2-capture-storage- and-transport.pdf. and the U.S. Geological Survey (USGS) 
has also undertaken a comprehensive assessment of geologic sequestration resources in the United States.
462 463  
Geologic sequestration potential for CO 2 
is widespread and available throughout the United States. Nearly every state in the United States has or is in close proximity to formations with geologic sequestration potential, including areas offshore. There have been numerous efforts demonstrating successful geologic sequestration projects in the United States and overseas, and the United States has developed a detailed set of regulatory requirements to ensure the security of sequestered CO
2. 
Moreover, the amount of storage potential can readily accommodate the amount of CO
2for which sequestration 
could be expected under this final rule. 
The EPA has performed a geographic 
availability analysis in which the Agency examined areas of the U.S. with sequestration potential in deep saline formations, unmineable coal seams, and oil and gas reservoirs; information on existing and probable, planned or under study CO
2pipelines; and areas within a 
100 km (62-mile) area of potential 
sequestration sites. This availability analysis is based on resources from the DOE, the USGS, and the EPA. The distance of 100 km is consistent with the assumptions underlying the NETL cost estimates for transporting CO
2by 
pipeline. The scoping assessment by the EPA found that at least 37 states have geologic characteristics that are amenable to deep saline sequestration, and an additional 6 states are within 100 kilometers of potentially amenable deep saline formations in either onshore or offshore locations. Of the 7 states that are further than 100 km (62 mi) of onshore or offshore storage potential in deep saline formations, only New Hampshire has coal EGUs that were assumed to be in operation after 2039, with a total capacity of 534 MW. However, the EPA notes that as of March 27, 2024, the last coal-fired steam EGUs in New Hampshire announced that they would cease operation by 2028.
464Therefore, the EPA anticipates 
that there will no existing coal-fired steam EGUs located in states that are 
further than 100 km (62 mi) of potential geologic sequestration sites. Furthermore, as described in section VII.C.1.a.i(C), new EGUs would have the ability to consider proximity and access to geologic sequestration sites or CO
2 
pipelines in the siting process. 
The DOE and the United States 
Geological Survey (USGS) have independently conducted preliminary analyses of the availability and potential CO
2sequestration resources in the 
United States. The DOE estimates are compiled in the DOE’s National Carbon Sequestration Database and Geographic Information System (NATCARB) using volumetric models and are published in its Carbon Utilization and Sequestration Atlas (NETL Atlas). The DOE estimates that areas of the United States with 
appropriate geology have a sequestration potential of at least 2,400 billion to over 21,000 billion metric tons of CO
2in deep saline formations, 
unmineable coal seams, and oil and gas reservoirs. The USGS assessment estimates a mean of 3,000 billion metric tons of subsurface CO
2sequestration 
potential across the United States. With respect to deep saline formations, the DOE estimates a sequestration potential of at least 2,200 billion metric tons of CO
2in these formations in the United 
States. The EPA estimates that the CO 2 
emissions reductions for this rule (which is similar to the amount of CO
2 
may be sequestered under this rule) are estimated in the range of 1.3 to 1.4 billion metric tons over the 2028 to 2047 timeframe.
465This volume of 
sequestered CO 2is less than a tenth of 
a percent of the storage capacity in deep saline formations estimated to be available by DOE. 
Unmineable coal seams offer another 
potential option for geologic sequestration of CO
2. Enhanced coalbed 
methane recovery is the process of injecting and storing CO
2in unmineable 
coal seams to enhance methane recovery. These operations take advantage of the preferential chemical affinity of coal for CO
2relative to the 
methane that is naturally found on the surfaces of coal. When CO
2is injected, 
it is adsorbed to the coal surface and releases methane that can then be captured and produced. This process effectively ‘‘locks’’ the CO
2to the coal, 
where it remains stored. States with the potential for sequestration in unmineable coal seams include Iowa and Missouri, which have little to no saline sequestration potential and have existing coal-fired EGUs. Unmineable 
coal seams have a sequestration potential of at least 54 billion metric tons of CO
2, or 2 percent of total 
potential in the United States, and are located in 22 states. 
The potential for CO
2sequestration in 
unmineable coal seams has been demonstrated in small-scale demonstration projects, including the Allison Unit pilot project in New 
Mexico, which injected a total of 270,000 tons of CO
2over a 6-year period 
(1995–2001). Further, DOE Regional Carbon Sequestration Partnership projects have injected CO
2volumes in 
unmineable coal seams ranging from 90 tons to 16,700 tons, and completed site characterization, injection, and post- injection monitoring for sites. DOE has included unmineable coal seams in the NETL Atlas. One study estimated that in the United States, 86.16 billion tons of CO
2could be permanently stored in 
unmineable coal seams.466Although the 
large-scale injection of CO 2in coal 
seams can lead to swelling of coal, the literature also suggests that there are available technologies and techniques to compensate for the resulting reduction in injectivity. Further, the reduced injectivity can be anticipated and accommodated in sizing and characterizing prospective sequestration sites. 
Depleted oil and gas reservoirs 
present additional potential for geologic sequestration. The reservoir characteristics of developed fields are well known as a result of exploration and many years of hydrocarbon production and, in many areas, infrastructure already exists which could be evaluated for conversion to CO
2transportation and sequestration 
service. Other types of geologic formations such as organic rich shale and basalt may also have the ability to store CO
2, and DOE is continuing to 
evaluate their potential sequestration capacity and efficacy. 
(b) Inventory of Coal-Fired Power Plants 
That Are Candidates for CCS 
Sequestration potential as it relates to 
distance from existing coal-fired steam generating units is a key part of the EPA’s regular power sector modeling, using data from DOE/NETL studies.
467 
As discussed in section VII.C.1.a.i(D)(1)(a), the availability 
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468Sequestration potential as it relates to distance 
from existing resources is a key part of the EPA’s 
regular power sector modeling development, using data from DOE/NETL studies. For details, please see chapter 6 of the IPM documentation. https://www.epa.gov/system/files/documents/2021-09/ chapter-6-co2-capture-storage-and-transport.pdf. 
469Regional Sequestration Partnership Overview. 
https://netl.doe.gov/carbon-management/carbon- storage/RCSP. 
470National Energy Technology Laboratory. 
CarbonSAFE Initiative. https://netl.doe.gov/carbon- management/carbon-storage/carbonsafe. 471Global CCS Institute. (2024). Global Status of 
CCS 2023. https://www.globalccsinstitute.com/wp- content/uploads/2024/01/Global-Status-of-CCS- Report-1.pdf. 
472Basin Electric Power Cooperative. (2021). 
‘‘Great Plains Synfuels Plant Potential to Be Largest Coal-Based Carbon Capture and Storage Project to Use Geologic Storage’’. https://www.basinelectric.com/News-Center/news-releases/ Great-Plains-Synfuels-Plant-potential-to-be-largest- coal-based-carbon-capture-and-storage-project-to- use-geologic-storage. 
473UIC regulations for Class VI wells authorize 
the injection of CO 2for geologic sequestration while 
protecting human health by ensuring the protection of underground sources of drinking water. The major components to be included in UIC Class VI permits are detailed further in section VII.C.1.a.i(D)(4). 
474U.S. EPA Class VI Underground Injection 
Control (UIC) Class VI Wells Permitted by EPA as of January 25, 2024. https://www.epa.gov/uic/table- epas-draft-and-final-class-vi-well-permits Last 
updated January 19, 2024. 
475U.S. EPA Current Class VI Projects under 
Review at EPA. 2024. https://www.epa.gov/uic/ current-class-vi-projects-under-review-epa. 
476U.S. EPA. Current Class VI Projects under 
Review at EPA. 2024. https://www.epa.gov/uic/ current-class-vi-projects-under-review-epa. 477Wyoming DEQ, Water Quality. Wyoming 
grants its first three Class VI permits. By Kimberly 
Mazza, December 14, 2023 https://deq.wyoming.gov/2023/12/wyoming-grants-its-first- three-class-vi-permits/. 
478Wyoming DEQ Class VI Permit Applications. 
Trailblazer permit application. https://deq.wyoming.gov/water-quality/groundwater/uic/ class-vi. 
479North Dakota Oil and Gas Division, Class VI— 
Geologic Sequestration Wells. https://www.dmr.nd.gov/dmr/oilgas/ClassVI. 
480EPA Approves Permits to Begin Construction 
of Wabash Carbon Services Underground Injection Wells in Indiana’s Vermillion and Vigo Counties. (2024) https://www.epa.gov/uic/epa-approves- 
permits-wabash-carbon-services-underground- injection-wells-indianas-vigo-and 
481U.S. EPA Current Class VI Projects under 
Review at EPA. 2024. https://www.epa.gov/uic/ 
current-class-vi-projects-under-review-epa. 
482U.S. EPA Class VI Permit Application. ‘‘Intent 
to Issue Four (4) Class VI Geologic Carbon Sequestration Underground Injection Control (UIC) analysis shows that of the coal-fired 
steam generating capacity with planned operation during or after 2039, more than 50 percent is less than 32 km (20 miles) from potential deep saline sequestration sites, 73 percent is located within 50 km (31 miles), 80 percent is located within 100 km (62 miles), and 91 percent is within 160 km (100 miles).
468 
(2) Geologic Sequestration of CO 2Is 
Adequately Demonstrated 
Geologic sequestration is based on a 
demonstrated understanding of the processes that affect the fate of CO
2in 
the subsurface. Existing project and regulatory experience, along with other information, indicate that geologic sequestration is a viable long-term CO
2 
sequestration option. As discussed in this section, there are many examples of projects successfully injecting and containing CO
2in the subsurface. 
Research conducted through the 
Department of Energy’s Regional Carbon Sequestration Partnerships has demonstrated geologic sequestration through a series of field research projects that increased in scale over time, injecting more than 12 million tons of CO
2with no indications of 
negative impacts to either human health 
or the environment.469Building on this 
experience, DOE launched the Carbon Storage Assurance Facility Enterprise (CarbonSAFE) Initiative in 2016 to demonstrate how knowledge from the Regional Carbon Sequestration Partnerships can be applied to commercial-scale safe storage. This initiative is furthering the development and refinement of technologies and techniques critical to the characterization of sites with the potential to sequester greater than 50 million tons of CO
2.470In Phase I of 
CarbonSAFE, thirteen projects conducted economic feasibility analyses, collected, analyzed, and modeled extensive regional data, evaluated multiple storage sites and infrastructure, and evaluated business plans. Six projects were funded for Phase II which involves storage complex feasibility studies. These projects evaluate initial reservoir characteristics to determine if the reservoir is suitable 
for geologic sequestration sites of more than 50 million tons of CO
2, address 
technical and non-technical challenges that may arise, develop a risk assessment and CO
2management 
strategy for the project; and assist with the validation of existing tools. Five projects have been funded for CarbonSAFE Phase III and are currently performing site characterization and permitting. 
The EPA notes that, while only 
sequestration facilities with Federal funding are currently operational in the United States, multiple commercial sequestration facilities, other than those funded under EPAct05, are in construction or advanced development, with some scheduled to open for operation as early as 2025.
471These 
facilities have proposed sequestration capacities ranging from 0.03 to 6 million tons of CO
2per year. The Great Plains 
Synfuel Plant currently captures 2 million metric tons of CO
2per year, 
which is exported to Canada for use in EOR; a planned addition of sequestration in a saline formation for this facility is expected to increase the amount of CO
2captured and 
sequestered (through both geologic sequestration and EOR) to 3.5 million metric tons of CO
2per year.472The EPA 
and states with approved UIC Class VI programs (including Wyoming, North Dakota, and Louisiana) are currently reviewing UIC Class VI geologic sequestration well permit applications 
for proposed sequestration sites in fourteen states.
473 474 475 As of March 15, 
2024, 44 projects with 130 injection wells are under review by the EPA.
476 Currently, there are planned geologic 
sequestration facilities across the United 
States in various phases of development, construction, and operation. The Wyoming Department of Environmental Quality issued three UIC Class VI permits in December 2023 to Frontier Carbon Solutions. The Frontier Carbon Solutions project will sequester 5 million metric tons of CO
2/year.477 
Additionally, UIC Class VI permit applications have been submitted to the Wyoming Department of Environmental Quality for a proposed Eastern Wyoming Sequestration Hub project that would sequester up to 3 million metric tons of CO
2/year.478The North 
Dakota Oil and Gas Division has issued UIC Class VI permits to 6 sequestration projects that collectively will sequester 18 million metric tons of CO
2/year.479 
Since 2014, the EPA has issued two UIC Class VI permits to Archer Daniels Midland (ADM) in Decatur, Illinois, which authorize the injection of up to 7 million metric tons of CO
2. One of the 
AMD wells is in the injection phase while the other is in the post-injection phase. In January 2024, the EPA issued two UIC Class VI permits to Wabash Carbon Services LLC for a project that will sequester up to 1.67 million metric tons of CO
2/year over an injection 
period of 12 years.480In December 2023, 
the EPA released for public comment four UIC Class VI draft permits for the Carbon TerraVault projects, to be located in California.
481These projects 
propose to sequester CO 2captured from 
multiple different sources in California including a hydrogen plant, direct air capture, and pre-combustion gas treatment. TerraVault plans to inject 1.46 million metric tons of CO
2annually 
into the four proposed wells over a 26- year injection period with a total potential capacity of 191 million metric tons.
482 483 One of the proposed wells is 
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Permits for Carbon TerraVault JV Storage Company 
Sub 1, LLC. EPA–R09–OW–2023–0623.’’ https://www.epa.gov/publicnotices/intent-issue-class-vi- underground-injection-control-permits-carbon- terravault-jv. 
483California Resources Corporation. ‘‘Carbon 
TerraVault Potential Storage Capacity.’’https://www.crc.com/carbon-terravault/Vaults/ default.aspx. 
484U.S. EPA Class VI Permit Application. ‘‘Intent 
to Issue Four (4) Class VI Geologic Carbon Sequestration Underground Injection Control (UIC) Permits for Carbon TerraVault JV Storage Company Sub 1, LLC. EPA–R09–OW–2023–0623. 
485Intergovernmental Panel on Climate Change. 
(2005). Special Report on Carbon Dioxide Capture and Storage. https://www.ipcc.ch/report/carbon- dioxide-capture-and-storage/. 
486Global CCS Institute. (2024). Global Status of 
CCS 2023. https://www.globalccsinstitute.com/wp- content/uploads/2024/01/Global-Status-of-CCS- Report-1.pdf. 
487BD3 Status Update: Q3 2023. https://
www.saskpower.com/about-us/our-company/blog/ 2023/bd3-status-update-q3-2023. 
488Global CCS Institute. (2024). Global Status of 
CCS 2023. https://www.globalccsinstitute.com/wp- content/uploads/2024/01/Global-Status-of-CCS- Report-1.pdf. 
489CarbFix Operations. (2024). https://
www.carbfix.com/. 490NETL. (2010). Carbon Dioxide Enhanced Oil 
Recovery. https://www.netl.doe.gov/sites/default/ 
files/netl-file/co2_ eor_primer.pdf. 
491Global CCS Institute. (2024). Global Status of 
CCS 2023. https://www.globalccsinstitute.com/wp- 
content/uploads/2024/01/Global-Status-of-CCS- Report-1.pdf. 
492Greenhouse Gas Reporting Program 
monitoring reports for these facilities are available at https://www.epa.gov/ghgreporting/subpart-rr- 
geologic-sequestration-carbon-dioxide#decisions. 
493U.S. DOE NETL, Carbon Storage Atlas, Fifth 
Edition, September 2015. https://www.netl.doe.gov/ research/coal/carbon-storage/atlasv. 
49480 FR 64541–42 (October 23, 2015). 
495Clean Air Task Force. (August 3, 2023). U.S. 
Carbon Capture Activity and Project Map. https:// 
www.catf.us/ccsmapus/. 
496Global CCS Institute. (2024). Global Status of 
CCS 2023. https://www.globalccsinstitute.com/wp- content/uploads/2024/01/Global-Status-of-CCS- Report-1.pdf. 497Reuters. (September 14, 2023) ‘‘Carbon capture 
project back at Texas coal plant after 3-year 
shutdown’’. https://www.reuters.com/business/ 
energy/carbon-capture-project-back-texas-coal- plant-after-3-year-shutdown-2023-09-14/. 
498Clean Air Task Force. (August 3, 2023). U.S. 
Carbon Capture Activity and Project Map. https:// 
www.catf.us/ccsmapus/. 
499Global CCS Institute. (2024). Global Status of 
CCS 2023. https://www.globalccsinstitute.com/wp- content/uploads/2024/01/Global-Status-of-CCS- Report-1.pdf. 
500Ibid. 
501Ibid. 
502EPA Greenhouse Gas Reporting Program. Data 
reported as of August 12, 2022. 
503University of Illinois Urbana-Champaign, 
Prairie Research Institute. (2022). Data from landmark Illinois Basin carbon storage project are now available. https://blogs.illinois.edu/view/7447/ 54118905. 
504In addition, Denbury Resources injected CO 2 
into a depleted oil and gas reservoir at a rate greater than 1.2 million tons/year as part of a DOE Southeast Regional Carbon Sequestration Partnership study. The Texas Bureau of Economic Geology tested a wide range of surface and subsurface monitoring tools and approaches to document sequestration efficiency and sequestration permanence at the Cranfield oilfield in Mississippi. Texas Bureau of Economic Geology, ‘‘Cranfield Log.’’ https://www.beg.utexas.edu/gccc/ research/cranfield. 
505EPA Class VI Permit Tracker. https://
www.epa.gov/system/files/documents/2024-02/ class-vi-permit-tracker_ 2-5-24.pdf. Accessed 
February 5, 2024. 
506Project Tundra. ‘‘Project Tundra.’’ https://
www.projecttundrand.com/. an existing UIC Class II well that would 
be converted to a UIC Class VI well for the TerraVault project.
484 
Geologic sequestration has been 
proven to be successful and safe in projects internationally. In Norway, facilities conduct offshore sequestration under the Norwegian continental shelf.
485In addition, the Sleipner CO 2 
Storage facility in the North Sea, which began operations in 1996, injects around 1 million metric tons of CO
2per year 
from natural gas processing.486The 
Snohvit CO 2Storage facility in the 
Barents Sea, which began operations in 2008, injects around 0.7 million metric tons of CO
2per year from natural gas 
processing. The SaskPower carbon capture and sequestration facility at Boundary Dam Power Station in Saskatchewan, Canada had, as of the end of 2023, captured 5.6 million metric tons of CO
2since it began operating in 
2014.487Other international 
sequestration facilities in operation include Glacier Gas Plant MCCS (Canada),
488Quest (Canada), and Qatar 
LNG CCS (Qatar). The CarbFix project in Iceland injects CO
2into a geologic 
formation in which the CO 2reacts with 
basalt rock formations to form stone. 
The CarbFix project has injected approximately 100,000 metric tons of CO
2into geologic formations since 
2014.489 
EOR, the process of injecting CO 2into 
oil and gas formations to extract additional oil and gas, has been successfully used for decades at numerous production fields throughout the United States to increase oil and gas recovery. The oil and gas industry in the United States has nearly 60 years of 
experience with EOR.
490This 
experience provides a strong foundation for demonstrating successful CO
2 
injection and monitoring technologies, which are needed for safe and secure geologic sequestration that can be used for deployment of CCS across geographically diverse areas. The amount of CO
2that can be injected for 
an EOR project and the duration of operations are of similar magnitude to the duration and volume of CO
2that is 
expected to be captured from fossil fuel- fired EGUs. The Farnsworth Unit, the Camrick Unit, the Shute Creek Facility, and the Core Energy CO
2-EOR facility 
are all examples of operations that store anthropogenic CO
2as a part of EOR 
operations.491 492 Currently, 13 states 
have active EOR operations, and these states also have areas that are amenable to deep saline sequestration in either onshore or offshore locations.
493 
(3) EPAct05-Assisted Geologic Sequestration Projects 
Consistent with the EPA’s legal 
interpretation that the Agency can rely on experience from EPAct05 funded facilities in conjunction with other information, this section provides examples of EPAct05-assisted geologic sequestration projects. While the EPA has determined that the sequestration component of CCS is adequately demonstrated based on the non-EPAct05 examples discussed above, adequate demonstration of geologic sequestration is further corroborated by planned and operational geologic sequestration projects assisted by grants, loan guarantees, and the IRC section 48A federal tax credit for ‘‘clean coal technology’’ authorized by the EPAct05.
494 
At present, there are 13 operational 
and one post-injection phase commercial carbon sequestration facilities in the United States.
495 496 Red Trail Energy CCS Project in North 
Dakota and Illinois Industrial Carbon Capture and Storage in Illinois are dedicated saline sequestration facilities, while the other facilities, including Petra Nova in Texas, are sequestration via EOR.
497 498 Several other facilities 
are under development.499The Red 
Trail Energy CCS facility in North Dakota began injecting CO
2captured 
from ethanol production plants in 2022.
500This project is expected to 
inject 180,000 tons of CO 2per year.501 
The Illinois Industrial Carbon Capture and Storage Project began injecting CO
2 
from ethanol production into the Mount Simon Sandstone in April 2017. According to the facility’s report to the EPA’s Greenhouse Gas Reporting Program (GHGRP), as of 2022, 2.9 million metric tons of CO
2had been 
injected into the saline reservoir.502CO 2 
injection for one of the two permitted Class VI wells ceased in 2021 and this well is now in the post-operation data collection phase.
503 
There are additional planned geologic 
sequestration projects under review by the EPA and across the United States.
504 505 Project Tundra, a saline 
sequestration project planned at the lignite-fired Milton R. Young Station in North Dakota is projected to capture 4 million metric tons of CO
2annually.506 
In Wyoming, Class VI permit 
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507Wyoming DEQ Class VI Permit Applications. 
https://deq.wyoming.gov/water-quality/ 
groundwater/uic/class-vi/. 
508Id. 
509Calpine. (2023). Calpine Carbon Capture, 
Bayton, Texas. https://calpinecarboncapture.com/ wp-content/uploads/2023/04/Calpine-Baytown- One-Pager-English-1.pdf. 
510Global CCS Institute. (2024). Global Status of 
CCS 2023. https://www.globalccsinstitute.com/wp- content/uploads/2024/01/Global-Status-of-CCS- Report-1.pdf. 511CEQ. (2021). ‘‘Council on Environmental 
Quality Report to Congress on Carbon Capture, 
Utilization, and Sequestration.’’ https://www.whitehouse.gov/wp-content/uploads/2021/06/ CEQ-CCUS-Permitting-Report.pdf. 
512EPA. 2023. Regulatory and Statutory 
Authorities Relevant to Carbon Capture and Sequestration (CCS) Projects. https://www.epa.gov/ system/files/documents/2023-10/regulatory-and- 
statutory-authorities-relevant-to-carbon-capture- and-sequestration-ccs-projects.pdf. 
513This table serves as a reference of many 
possible authorities that may affect a CCS project (including site selection, capture, transportation, and sequestration). Many of the authorities listed in this table would apply only in specific circumstances. 
514CEQ. ‘‘Council on Environmental Quality 
Report to Congress on Carbon Capture, Utilization, and Sequestration.’’ 2021. https://www.whitehouse.gov/wp-content/uploads/2021/06/ CEQ-CCUS-Permitting-Report.pdf. 
515Department of the Interior. (2023). BSEE 
Budget. https://www.doi.gov/ocl/bsee-budget. 516National Policy for the Right-of-Way 
Authorizations Necessary for Site Characterization, Capture, Transportation, Injection, and Permanent Geologic Sequestration of Carbon Dioxide in Connection with Carbon Sequestration Projects. BLM IM 2022–041 Instruction Memorandum, June 8, 2022. https://www.blm.gov/policy/im-2022-041. 
517EPA. Underground Injection Control Class VI 
Wells Memorandum. (December 9, 2022). https://www.epa.gov/system/files/documents/2022-12/ AD.Regan_ .GOVS_ .Sig_ .Class%20VI.12-9-22.pdf. 
518Per 40 CFR 146.84(a), the area of review is the 
region surrounding the geologic sequestration project where USDWs may be endangered by the injection activity. The area of review is delineated using computational modeling that accounts for the physical and chemical properties of all phases of the injected carbon dioxide stream and is based on available site characterization, monitoring, and operational data. 
519UIC permitting authorities may require 
corrective action for existing wells within the area of review to ensure protection of underground sources of drinking water. applications have been issued by the 
Wyoming Department of Environmental Quality for the proposed Eastern Wyoming Sequestration Hub project, a saline sequestration facility proposed to be located in Southwestern Wyoming.
507At full capacity, the 
facility would permanently store up to 5 million metric tons of CO
2captured 
from industrial facilities annually in the Nugget saline sandstone reservoir.
508In 
Texas, three NGCCs plan to add carbon capture equipment. Deer Park NGCC plans to capture 5 million tons per year, Quail Run NGCC plans to capture 1.5 million tons of CO
2per year, and 
Baytown NGCC plans to capture up to 2 million tons of CO
2per year.509 510  
(4) Security of Geologic Sequestration and Related Regulatory Requirements 
As discussed in section 
VII.C.1.a.i(D)(2) of this preamble, there have been numerous instances of geologic sequestration in the U.S. and overseas, and the U.S. has developed a detailed set of regulatory requirements to ensure the security of sequestered CO
2. This regulatory framework 
includes the UIC well regulations pursuant to SDWA authority, and the GHGRP pursuant to CAA authority. 
Regulatory oversight of geologic 
sequestration is built upon an understanding of the proven mechanisms by which CO
2is retained 
in geologic formations. These mechanisms include (1) Structural and stratigraphic trapping (generally trapping below a low permeability confining layer); (2) residual CO
2 
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). 
(a) Overview of Legal and Regulatory 
Framework 
For the reasons detailed below, the 
UIC Program, the GHGRP, and other regulatory requirements comprise a detailed regulatory framework for 
geologic sequestration in the United States. This framework is analyzed in a 2021 report from the Council on Environmental Quality (CEQ),
511and 
statutory and regulatory frameworks that may be applicable for CCS are summarized in the EPA CCS Regulations Table.
512 513 This regulatory 
framework includes the UIC regulations, promulgated by the EPA under the authority of the Safe Drinking Water Act (SDWA); and the GHGRP, promulgated by the EPA under the authority of the CAA. The requirements of the UIC and GHGRP programs work together to ensure that sequestered CO
2will remain 
securely stored underground. Furthermore, geologic sequestration efforts on Federal lands as well as those efforts that are directly supported with Federal funds would need to comply with the NEPA and other Federal laws and regulations, depending on the nature of the project.
514In cases where 
sequestration is conducted offshore, the SDWA, the Marine Protection, Research, and Sanctuaries Act (MPRSA) or the Outer Continental Shelf Lands Act (OCSLA) may apply. The Department of Interior Bureau of Safety and Environmental Enforcement and Bureau of Ocean Energy Management are developing new regulations and creating a program for oversight of carbon sequestration activities on the outer continental shelf.
515Furthermore, Title 
V of the Federal Land Policy and Management Act of 1976 (FLPMA) and its implementing regulations, 43 CFR part 2800, authorize the Bureau of Land Management (BLM) to issue rights-of- way (ROWs) to geologically sequester CO
2in Federal pore space, including 
BLM ROWs for the necessary physical infrastructure and for the use and occupancy of the pore space itself. The BLM has published a policy defining access to pore space on BLM lands, 
including clarification of Federal policy for situations where the surface and pore space are under the control of different Federal agencies.
516 
(b) Underground Injection Control (UIC) Program 
The UIC regulations, including the 
Class VI program, authorize the injection of CO
2for geologic 
sequestration while protecting human health by ensuring the protection of underground sources of drinking water (USDW). These regulations are built upon nearly a half-century of Federal experience regulating underground injection wells, and many additional years of state UIC program expertise. The IIJA established a $50 million grant program to assist states and tribal regulatory authorities in developing and implementing UIC Class VI programs.
517 
Major components included in UIC Class VI permits are site characterization, area of review,
518 
corrective action,519well construction 
and operation, testing and monitoring, financial responsibility, post-injection site care, well plugging, emergency and remedial response, and site closure. The EPA’s UIC regulations are included in 40 CFR parts 144–147. The UIC regulations ensure that injected CO
2 
does not migrate out of the authorized injection zone, which in turn ensures that CO
2is securely stored 
underground. 
Review of a UIC permit application by 
the permitting authority, including for Class VI geologic sequestration, entails a multidisciplinary evaluation to determine whether the application includes the required information, is technically accurate, and supports a determination that USDWs will not be endangered by the proposed injection 
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520EPA. EPA Report to Congress: Class VI 
Permitting. 2022. https://www.epa.gov/system/files/ 
documents/2022-11/ EPAClassVIPermittingReporttoCongress.pdf. 
521See 40 CFR parts 124, 144–147. 
522EPA. (2010). Federal Requirements Under the 
Underground Injection Control (UIC) Program for Carbon Dioxide (CO2) Geologic Sequestration (GS) Wells; Final Rule, 75 FR 77230, December 10, 2010 (codified at 40 CFR part 146, subpart H). 523See 40 CFR 144.12(b) (prohibition of 
movement of fluid into USDWs); 40 CFR 146.86(a)(1) (Class VI injection well construction requirements); 40 CFR 146(a) (Class VI injection well operation requirements); 40 CFR 146.94 (emergency and remedial response). 
524EPA. (2020). Underground Injection Control 
Program. https://www.epa.gov/sites/default/files/ 
2020-04/documents/uic_ fact_ sheet.pdf. 525See 40 CFR 146.82(a)(3)(v) (requiring the 
permit applicant to submit and the permitting authority to consider information on the seismic history including the presence and depth of seismic sources and a determination that the seismicity would not interfere with containment); EPA. (2018). Geologic Sequestration of Carbon Dioxide Underground Injection Control (UIC) Program Class VI Implementation Manual for UIC Program Directors. U.S. Environmental Protection Agency Office of Water (4606M) EPA 816–R–18–001. https://www.epa.gov/sites/default/files/2018-01/ documents/implementation_ manual_ 508_
010318.pdf. 
526National Research Council. (2013). Induced 
Seismicity Potential in Energy Technologies. Washington, DC: The National Academies Press. https://doi.org/10.17226/13355. 
527Ground Water Protection Council and 
Interstate Oil and Gas Compact Commission. (2021). Potential Induced Seismicity Guide: A Resource of Technical and Regulatory Considerations Associated with Fluid Injection. https://www.gwpc.org/wp-content/uploads/2022/12/ FINAL_ Induced_ Seismicity_ 2021_ Guide_ 33021.pdf. 
528EPA. (2015). Minimizing and Managing 
Potential Impacts of Injection-Induced Seismicity from Class II Disposal Wells: Practical Approaches. https://www.epa.gov/sites/default/files/2015-08/ documents/induced-seismicity-201502.pdf. 
529EPA. (2018). Geologic Sequestration of Carbon 
Dioxide: Underground Injection Control (UIC) Program Class VI Implementation Manual for UIC Program Directors. EPA 816–R–18–001. https://www.epa.gov/sites/default/files/2018-01/ 
Continued activity.520The EPA promulgated UIC 
regulations to ensure underground 
injection wells are constructed, operated, and closed in a manner that is protective of USDWs and to address potential risks to USDWs associated with injection activities.
521The UIC 
regulations address the major pathways by which injected fluids can migrate into USDWs, including along the injection well bore, via improperly completed or plugged wells in the area near the injection well, direct injection into a USDW, faults or fractures in the confining strata, or lateral displacement into hydraulically connected USDWs. States may apply to the EPA to be the UIC permitting authority in the state and receive primary enforcement authority (primacy). Where a state has not obtained primacy, the EPA is the UIC permitting authority. 
Recognizing that CO
2injection, for the 
purpose of geologic sequestration, poses unique risks relative to other injection activities, the EPA promulgated Federal Requirements Under the UIC Program for Carbon Dioxide GS Wells, known as the Class VI Rule, in December 2010.
522 
The Class VI Rule created and set requirements for a new class of injection wells, Class VI. The Class VI Rule builds upon the long-standing protective framework of the UIC Program, with requirements that are tailored to address issues unique to large-scale geologic sequestration, including large injection volumes, higher reservoir pressures relative to other injection formations, the relative buoyancy of CO
2, the 
potential presence of impurities in captured CO
2, the corrosivity of CO 2in 
the presence of water, and the mobility of CO
2within subsurface geologic 
formations. These additional protective requirements include more extensive geologic testing, detailed computational modeling of the project area and periodic re-evaluations, detailed requirements for monitoring and tracking the CO
2plume and pressure in 
the injection zone, unique financial responsibility requirements, and extended post-injection monitoring and site care. 
UIC Class VI permits are designed to 
ensure that geologic sequestration does not cause the movement of injected CO
2 
or formation fluids outside the authorized injection zone; if monitoring indicates leakage of injected CO
2from 
the injection zone, the leakage may trigger a response per the permittee’s Class VI Emergency and Remedial Response Plan including halting injection, and the permitting authority may prescribe additional permit requirements necessary to prevent such movement to ensure USDWs are protected or take appropriate enforcement action if the permit has been violated.
523Class II EOR permits 
are also designed to ensure the protection of USDWs with requirements appropriate for the risks of the enhanced recovery operation. In general, the EPA believes that the protection of USDWs by preventing leakage of injected CO
2 
out of the injection zone will also ensure that CO
2is sufficiently 
sequestered in the subsurface, and therefore will not leak from the subsurface to the atmosphere. 
The UIC program works with 
injection well operators throughout the life of the well to confirm practices do not pose a risk to USDWs. The program conducts inspections to verify compliance with the UIC permit, including checking for leaks.
524 
Inspections are only one way that programs deter noncompliance. Programs also evaluate periodic monitoring reports submitted by operators and discuss potential issues with operators. If a well is found to be out of compliance with applicable requirements in its permit or UIC regulations, the program will identify specific actions that an operator must take to address the issues. The UIC program may assist the operator in returning the well to compliance or use administrative or judicial enforcement to return a well to compliance. 
UIC program requirements address 
potential safety concerns with induced seismicity. More specifically, through the UIC Class VI program, the EPA has put in place mechanisms to identify, monitor, and reduce risks associated with induced seismicity in any areas within or surrounding a sequestration site through permit and program requirements such as site characterization and monitoring, and the requirement for applicants to demonstrate that induced seismic activity will not endanger USDWs.
525 
The National Academy of Sciences 
released a report in 2012 on induced seismicity from CCS and determined that with appropriate site selection, a monitoring program, a regulatory system, and the appropriate use of remediation methods, the induced seismicity risks of geologic sequestration could be mitigated.
526 
Furthermore, the Ground Water 
Protection Council and Interstate Oil and Gas Compact Commission have published a ‘‘Potential Induced Seismicity Guide.’’ This report found that the strategies for avoiding, mitigating, and responding to potential risks of induced seismicity should be determined based on site-specific characteristics (i.e., local geology). 
These strategies could include supplemental seismic monitoring, altering operational parameters (such as rates and pressures) to reduce the ground motion hazard and risk, permit modification, partial plug back of the well, controlled restart (if feasible), suspending or revoking injection authorization, or stopping injection and shutting in a well.
527The EPA’s UIC 
National Technical Workgroup released technical recommendations in 2015 to address induced seismicity concerns in Class II wells and elements of these recommendations have been utilized in developing Class VI emergency and remedial response plans for Class VI permits.
528 529 For example, as identified 
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documents/implementation_ manual_ 508_
010318.pdf. 
530‘‘Confining zone’’ means a geological 
formation, group of formations, or part of a 
formation that is capable of limiting fluid movement above an injection zone. 40 CFR 146.3. 
531EPA. (2015). Minimizing and Managing 
Potential Impacts of Injection-Induced Seismicity from Class II Disposal Wells: Practical Approaches. https://www.epa.gov/sites/default/files/2015-08/ documents/induced-seismicity-201502.pdf. 
532See EPA. Emergency and Remedial Response 
Plan: 40 CFR 146.94(a) template. https://
www.epa.gov/system/files/documents/2022-03/err_plan_ template.docx. See also EPA. (2018). Geologic 
Sequestration of Carbon Dioxide: Underground Injection Control (UIC) Program Class VI Implementation Manual for UIC Program Directors. EPA 816–R–18–001. https://www.epa.gov/sites/ default/files/2018-01/documents/implementation_manual_ 508_ 010318.pdf. 
53340 CFR 146.82(a)(3)(v). 534EPA. (2023). Environmental justice Guidance 
for UIC Class VI Permitting and Primacy. https://
www.epa.gov/system/files/documents/2023-08/ Memo%20and%20EJ%20Guidance%20for%20UIC%20Class%20VI _August%202023.pdf; see 
also EPA. Letter from the EPA Administrator 
Michael S. Regan to U.S. State Governors. December 9, 2022. https://www.epa.gov/system/files/ documents/2022-12/AD.Regan_ .GOVS_ .Sig_
.Class%20VI.12-9-22.pdf. 
535EPA. (2023). Targeted UIC program grants for 
Class VI Wells. https://www.epa.gov/uic/ underground-injection-control-grants#ClassVI_Grants. 
536EPA. (2023). Environmental justice Guidance 
for UIC Class VI Permitting and Primacy. https://www.epa.gov/system/files/documents/2023-08/ Memo%20and%20EJ%20Guidance%20for%20UIC%20Class%20VI _August%202023.pdf. 
537EPA. (2011). Geologic Sequestration of Carbon 
Dioxide—UIC Quick Reference Guide. https://
www.epa.gov/sites/default/files/2015-07/ documents/epa816r11002.pdf. 538EPA. (2023). Environmental justice Guidance 
for UIC Class VI Permitting and Primacy. https://
www.epa.gov/system/files/documents/2023-08/ Memo%20and%20EJ%20Guidance%20for%20UIC%20Class%20VI _August%202023.pdf. 
539EPA Report to Congress: Class VI Permitting. 
2022. https://www.epa.gov/system/files/documents/ 
2022-11/ EPAClassVIPermittingReporttoCongress.pdf. 
540EPA Report to Congress: Class VI Permitting. 
2022. https://www.epa.gov/system/files/documents/ 
2022-11/ EPAClassVIPermittingReporttoCongress.pdf. by the EPA’s UIC National Technical 
Workgroup, sufficient pressure buildup from disposal activities, the presence of Faults of Concern (i.e., a fault optimally 
oriented for movement and located in a critically stressed region), and the existence of a pathway for allowing the increased pressure to communicate with the fault contribute to the risk of injection-induced seismicity. The UIC requirements, including site characterization (e.g., ensuring the 
confining zone
530is free of faults of 
concern) and operating requirements (e.g., ensuring injection pressure in the 
injection zone is below the fracture pressure), work together to address these components and reduce the risk of injection-induced seismicity, particularly any injection-induced seismicity that could be felt by people at the surface.
531Additionally, the EPA 
recommends that Class VI permits include an approach for monitoring for seismicity near the site, including seismicity that cannot be felt at the surface, and that injection activities be stopped or reduced in certain situations if seismic activity is detected to ensure that no seismic activity will endanger USDWs.
532This also reduces the 
likelihood of any future injection- induced seismic activity that will be felt at the surface. 
Furthermore, during site 
characterization, if any of the geologic or seismic data obtained indicate a substantial likelihood of seismic activity, the EPA may require further analyses, potential planned operational changes, and additional monitoring.
533 
The EPA has the authority to require seismic monitoring as a condition of the UIC permit if appropriate, or to deny the permit if the injection-induced seismicity risk could endanger USDWs. 
The EPA believes that meaningful 
engagement with local communities is an important step in the development of geologic sequestration projects and has programs and public participation 
requirements in place to support this process. The EPA is committed to advancing EJ for overburdened communities in all its programs, including the UIC Class VI program.
534 
The EPA is also committed to 
supporting states’ and tribes’ efforts to obtain UIC Class VI primacy and strongly encourages such states and tribes to incorporate environmental justice principles and equity into proposed UIC Class VI programs.
535The 
EPA is taking steps to address EJ in 
accordance with Presidential Executive Order 14096, Revitalizing Our Nation’s Commitment to Environmental Justice for All (88 FR 25251, April 26, 2023). In 2023, the EPA released Environmental Justice Guidance for UIC Class VI Permitting and Primacy that builds on the 2011 UIC Quick Reference Guide: Additional Tools for UIC Program Directors Incorporating Environmental Justice Considerations into the Class VI Injection Well Permitting Process.
536 537  
The 2023 guidance serves as an operating framework for identifying, analyzing, and addressing EJ concerns in the context of implementing and overseeing UIC permitting and primacy programs, including primacy approvals. The EPA notes that while this guidance is focused on the UIC Class VI program, EPA Regions should apply them to the other five injection well classes wherever possible, including class II. The guidance includes recommended actions across five themes to address various aspects of EJ in UIC Class VI permitting including: (1) identify communities with potential EJ concerns, (2) enhance public involvement, (3) conduct appropriately scoped EJ assessments, (4) enhance transparency throughout the permitting process, and (5) minimize adverse effects to USDWs 
and the communities they may serve.
538 
As a part of the UIC Class VI permit 
application process, applicants and the EPA Regions should complete an EJ review using the EPA’s EJScreen Tool, an online mapping tool that integrates numerous demographic, socioeconomic, and environmental data sets that are overlain on an applicant’s UIC Area of Review to identify whether any disadvantaged communities are encompassed.
539If the results indicate a 
potential EJ impact, applicants and the EPA Regions should consider potential measures to mitigate the impacts of the UIC Class VI project on identified vulnerable communities and enhance the public participation process to be inclusive of all potentially affected communities (e.g., conduct early 
targeted outreach to communities and identify and mitigate any communication obstacles such as language barriers or lack of technology resources).
540 
ER technologies are used in oil and 
gas reservoirs to increase production. Injection wells used for ER are regulated through the UIC Class II program. Injection of CO
2is one of several 
techniques used in ER. Sometimes ER uses CO
2from anthropogenic sources 
such as natural gas processing, ammonia and fertilizer production, and coal gasification facilities. Through the ER process, much of the injected CO
2is 
recovered from production wells and can be separated and reinjected into the subsurface formation, resulting in the storage of CO
2underground. The EPA’s 
Class II regulations were designed to regulate ER injection wells, among other injection wells associated with oil and natural gas production. See e.g., 40 CFR 
144.6(b)(2). The EPA’s Class II program is designed to prevent Class II injection activities from endangering USDWs. The Class II programs of states and tribes must be approved by the EPA and must meet the EPA regulatory requirements for Class II programs, 42 U.S.C. 300h–1, or otherwise represent an effective program to prevent endangerment of USDWs. 42 U.S.C 300h–4. 
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541EPA. (2015). Key Principles in EPA’s 
Underground Injection Control Program Class VI 
Rule Related to Transition of Class II Enhanced Oil or Gas Recovery Wells to Class VI. https://www.epa.gov/sites/default/files/2015-07/ documents/class2eorclass6memo_ 1.pdf. 542See 40 CFR 98.440. 
54340 CFR 98.440. 
544As discussed in section X.C.5.b, entities 
conducting CCS to comply with this rule would be required to send the captured CO
2to a facility that 
reports data under subpart RR or subpart VV. 
54540 CFR 98.446. 
54640 CFR 98.448. 
54740 CFR 98.446(f)(9) and (10). 
54840 CFR 98.446(f)(12). 54940 CFR 98.448(a). 
550EPA. (2024). Rulemaking Notices for GHG 
Reporting. https://www.epa.gov/ghgreporting/ 
rulemaking-notices-ghg-reporting. 
551EPA. (2024). Rulemaking Notices for GHG 
Reporting. https://www.epa.gov/ghgreporting/ 
rulemaking-notices-ghg-reporting. 
552‘‘Report of the Interagency Task Force on 
Carbon Capture and Storage.’’ 2010. https://www.osti.gov/servlets/purl/985209. 
553See, e.g., Intergovernmental Panel on Climate 
Change. (2005). Special Report on Carbon Dioxide Capture and Storage. In promulgating the Class VI 
regulations, the EPA recognized that if 
the business model for ER shifts to focus on maximizing CO
2injection volumes 
and permanent storage, then the risk of endangerment to USDWs is likely to increase. As an ER project shifts away from oil and/or gas production, injection zone pressure and carbon dioxide volumes will likely increase if carbon dioxide injection rates increase, and the dissipation of reservoir pressure will decrease if fluid production from the reservoir decreases. Therefore, the EPA’s regulations require the operator of a Class II well to obtain a Class VI permit when there is an increased risk to USDWs. 40 CFR 144.19.
541While the 
EPA’s regulations require the Class II well operator to assess whether there is an increased risk to USDWs (considering factors identified in the EPA’s regulations), the permitting authority can also make this assessment and, in the event that an operator makes changes to Class II operations such that the increased risk to USDWs warrants transition to Class VI and the operator does not notify the permitting authority, the operator may be subject to SDWA enforcement and compliance actions to protect USDWs, including cessation of injection. The determination of whether there is an increased risk to USDWs would be based on factors specified in 40 CFR 144.19(b), including increase in reservoir pressure within the injection zone; increase in CO
2injection rates; 
and suitability of the Class II Area of Review (AoR) delineation. 
(c) Greenhouse Gas Reporting Program 
(GHGRP) 
The GHGRP requires reporting of 
greenhouse gas (GHG) data and other relevant information from large GHG emission sources, fuel and industrial gas suppliers, and CO
2injection sites in the 
United States. Approximately 8,000 facilities are required to report their emissions, injection, and/or supply activity annually, and the non- confidential reported data are made available to the public around October of each year. To complement the UIC regulations, the EPA included in the GHGRP air-side monitoring and reporting requirements for CO
2capture, 
underground injection, and geologic sequestration. These requirements are included in 40 CFR part 98, subpart RR and subpart VV, also referred to as ‘‘GHGRP subpart RR’’ and ‘‘GHGRP 
subpart VV.’’ 
GHGRP subpart RR applies to ‘‘any 
well or group of wells that inject a CO
2 
stream for long-term containment in subsurface geologic formations’’
542and 
provides the monitoring and reporting mechanisms to quantify CO
2storage and 
to identify, quantify, and address potential leakage. The EPA designed GHGRP subpart RR to complement the UIC monitoring and testing requirements. See e.g., 40 CFR 146.90– 
91. Reporting under GHGRP subpart RR is required for, but not limited to, all facilities that have received a UIC Class VI permit for injection of CO
2.543Under 
existing GHGRP regulations, facilities that conduct ER in Class II wells are not subject to reporting data under GHGRP subpart RR unless they have chosen to submit a proposed monitoring, reporting, and verification (MRV) plan to the EPA and received an approved plan from the EPA. Facilities conducting ER and who do not choose to submit a subpart RR MRV plan to the EPA would otherwise be required to report CO
2data under subpart UU.544 
GHGRP 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 CO
2received for injection; 
develop and implement an EPA- approved monitoring, reporting, and verification (MRV) plan; report the mass of CO
2sequestered using a mass balance 
approach; and report annual monitoring activities.
545 546 547 548 Extensive 
subsurface monitoring is required for UIC Class VI wells at 40 CFR 146.90 and is the primary means of determining if the injected CO
2remains in the 
authorized injection zone and otherwise does not endanger any USDW, and monitoring under a GHGRP subpart RR MRV Plan complements these requirements. The MRV plan includes 
five major components: a delineation of monitoring areas based on the CO
2 
plume location; an identification and evaluation of the potential surface leakage pathways and an assessment of the likelihood, magnitude, and timing, of surface leakage of CO
2through these 
pathways; a strategy for detecting and quantifying any surface leakage of CO
2 
in the event leakage occurs; an approach for establishing the expected baselines 
for monitoring CO 2surface leakage; and, 
a summary of considerations made to calculate site-specific variables for the mass balance equation.
549 
In April 2024, the EPA finalized a 
new GHGRP subpart, ‘‘Geologic Sequestration of Carbon Dioxide with Enhanced Oil Recovery (EOR) Using ISO 27916’’ (or GHGRP subpart VV).
550 
GHGRP subpart VV applies to facilities that quantify the geologic sequestration of CO
2in association with EOR 
operations in conformance with the ISO standard designated as CSA/ANSI ISO 27916:2019, Carbon Dioxide Capture, Transportation and Geological Storage— Carbon Dioxide Storage Using Enhanced Oil Recovery. Facilities that have chosen to submit an MRV plan and report under GHGRP subpart RR must not report data under GHGRP subpart VV. GHGRP subpart VV is largely modeled after the requirements in this ISO standard and focuses on quantifying storage of CO
2. Facilities subject to 
GHGRP subpart VV must include in their GHGRP annual report a copy of their EOR Operations Management Plan (EOR OMP). The EOR OMP includes a description of the EOR complex and engineered system, establishes that the EOR complex is adequate to provide safe, long-term containment of CO
2, and 
includes site-specific and other information including a geologic characterization of the EOR complex, a description of the facilities within the EOR project, a description of all wells and other engineered features in the EOR project, and the operations history of the project reservoir.
551 
Based on the understanding 
developed from existing projects, the security of sequestered CO
2is expected 
to increase over time after injection ceases.
552This is due to trapping 
mechanisms that reduce CO 2mobility 
over time (e.g., physical CO 2trapping by 
a low-permeability geologic seal or chemical trapping by conversion or adsorption).
553The EPA acknowledges 
the potential for some leakage of CO 2to 
the atmosphere at sequestration sites, primarily while injection operations are active. For example, small quantities of the CO
2that were sent to the 
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554Based on subpart RR data retrieved from the 
EPA Facility Level Information on Greenhouse 
Gases Tool (FLIGHT), at https://ghgdata.epa.gov/ ghgp/main.do. Retrieved March 2024. 
555See 40 CFR part 145 (State UIC Program 
Requirements), 40 CFR part 147 (State, Tribal, and EPA-Administered Underground Injection Control Programs). 
556EPA. (2023). Targeted UIC program grants for 
Class VI Wells https://www.epa.gov/uic/ underground-injection-control-grants#ClassVI_Grants. 557EPA. (2023). Testimony Of Mr. Bruno Pigott, 
Principal Deputy Assistant Administrator for Water, U.S. Environmental Protection Agency, Hearing On Carbon Capture And Storage. https://www.epa.gov/ system/files/documents/2023-11/testimony-pigott- senr-hearing-nov-2-2023_ -cleared.pdf. 558EPA. (2023). Geologic Sequestration Data Tool 
(GSDT). https://www.epa.gov/system/files/ 
documents/2023-10/geologic-sequestration-data- tool_ factsheet_ oct2023.pdf. 
559EPA. (2023). Final Class VI Guidance 
Documents. https://www.epa.gov/uic/final-class-vi- 
guidance-documents. 
560EPA Report to Congress: Class VI Permitting. 
2022. https://www.epa.gov/system/files/documents/ 
2022-11/ EPAClassVIPermittingReporttoCongress.pdf. 
561EPA. (2024). Current Class VI Projects under 
Review at EPA. https://www.epa.gov/uic/current- class-vi-projects-under-review-epa. sequestration site may be emitted from 
leaks in pipes and valves that are traversed before the CO
2actually 
reaches the sequestration formation. However, the EPA’s robust UIC regulatory protections protect against leakage out of the injection zone. Relative to the 46.75 million metric tons of CO
2reported as sequestered under 
subpart RR of the GHGRP between 2016 to 2022, only 196,060 metric tons were reported as leakage/emissions to the atmosphere in the same time period (representing less than 0.5% of the sequestration amount). Of these emissions, most were from equipment leaks and vented emissions of CO
2from 
equipment located on the surface rather than leakage from the subsurface.
554 
Furthermore, any leakage of CO 2at a 
sequestration facility would be required to be quantified and reported under the GHGRP subpart RR or subpart VV, and such data are made publicly available on the EPA’s website. 
(5) Timing of Permitting for 
Sequestration Sites 
As previously discussed, the EPA is 
the Class VI permitting authority for states, tribes, and territories that have not obtained primacy over their Class VI programs.
555The EPA is committed to 
reviewing UIC Class VI permits as expeditiously as possible when the agency is the permitting authority. The EPA has the experience to properly regulate and review permits for UIC Class VI injection wells, and technical experts of multiple disciplines to review permit applications submitted to the EPA. 
The EPA has seen a considerable 
uptick in Class VI permit applications over the past few years. The 2018 passage of revisions and enhancements to the IRC section 45Q tax credit that provides tax credits for carbon oxide (including CO
2) sequestration has led to 
an increase in Class VI permit applications submitted to the EPA. The 2022 IRA further expanded the IRC 
section 45Q tax credit and the 2021 IIJA established a $50 million program for grants to help states and tribes in developing and implementing a UIC Class VI primacy program, leading to even more interest in this area.
556 Between 2011, when the Class VI rule 
went into effect, and 2020, the EPA received a total of 8 permit applications for Class VI wells. The EPA then received 12 Class VI permit applications in 2021, 44 in 2022, and 123 in 2023. As of March 2024, the EPA has 130 Class VI permit applications under review (56 permit applications were transferred to Louisiana in February 2024 when the EPA rule granting Class VI primacy to the state became effective). The majority of those 130 permit applications (63%) were submitted to the EPA within the past 12 months. Also, as of March 2024, the EPA has issued eight Class VI permits, including six for projects in Illinois and two for projects in Indiana, and has released for public comment four additional draft permits for proposed projects in California. Two of the permits are in the pre-operation phase, one is in the injection phase, and one is in the post-injection monitoring phase. 
In light of the recent flurry of interest 
in this area, the EPA is devoting increased resources to the Class VI program, including through increased staffing levels in order to meet the increased demand for action on Class VI permit applications.
557Reviewing a 
Class VI permit application entails a multidisciplinary evaluation to determine whether the application includes the required information, is technically accurate, and supports a risk-based determination that underground sources of drinking water will not be endangered by the proposed injection activity. A wide variety of technical experts—from geologists to engineers to physical scientists—review permit applications submitted to the EPA. The EPA has been working to develop staff expertise and increase capacity in the UIC program, and the agency has effectively deployed appropriated resources over the last five years to scale UIC program staff from a few employees to the equivalent of more than 25 full-time employees across the agency’s headquarters and regional offices. We expect that the additional resources and staff capacity for the Class VI program will lead to increased efficiencies in the Class VI permitting process. 
In addition to increased staffing 
resources, the EPA has made considerable improvements to the Class VI permitting process to reduce the time 
needed to make final permitting decisions for Class VI wells while 
maintaining a robust and thorough review process that ensures USDWs are protected. The EPA has created additional resources for applicants including upgrading the Geologic Sequestration Data Tool (GSDT) to guide applicants through the application process.
558The EPA has also created 
resources for permit writers including training series and guidance documents to build capacity for Class VI permitting.
559Additionally, the EPA 
issued internal guidelines to streamline and create uniformity and consistency in the Class VI permitting process, which should help to reduce permitting timeframes. These internal guidelines include the expectation that EPA Regions will classify all Class VI well applications received on or after December 12, 2023, as applications for major new UIC injection wells, which requires the Regions to develop project decision schedules for reviewing Class VI permit applications. The guidelines also set target timeframes for components of the permitting process, such as the number of days EPA Regions should set for public comment periods and for developing responses to comments and final permit decisions. The EPA will continue to evaluate its internal UIC permitting processes to identify potential opportunities for streamlining and other improvements over time. Although the available data for Class VI wells is limited, the 
timeframe for processing Class I wells, which follows a similar regulatory structure, is typically less than 2 years.
560 
The EPA notes that a Class VI permit 
tracker is available on its website.561 
This tracker shows information for the 44 projects (representing 130 wells) that have submitted Class VI applications to the EPA, including details such as the current permit review stage, whether a project has been sent a Notice of Deficiency (NOD) or Request for Additional Information (RAI), and the applicant’s response time to any NODs or RAIs. As mentioned above, most of the permits submitted to the EPA have been submitted within the past 12 
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562On December 28, 2023, the EPA Administrator 
signed a final rule granting Louisiana’s request for 
primacy for UIC Class VI junction wells located within the state. See EPA. (2023). Underground Injection Control (UIC) Primary Enforcement Authority for the Underground Injection Control Program. U.S. Environmental Protection Agency. https://www.epa.gov/uic/primary-enforcement- authority-underground-injection-control-program-0. 
563Wyoming Department of Environmental 
Quality. (2023). Wyoming grants its first three Class VI permits. https://deq.wyoming.gov/2023/12/ wyoming-grants-its-first-three-class-vi-permits/. 
564Ibid. 
565Arnold & Porter. (2023). EPA Provides 
Increased Transparency in Class VI Permitting Process; Now Incorporated in Update to Interactive CCUS State Tracker. https://www.arnoldporter.com/ en/perspectives/blogs/environmental-edge/2023/11/ ccus-state-legislative-tracker. 
566EPA. (2023). Underground Injection Control 
(UIC) Primary Enforcement Authority for the Underground Injection Control Program. U.S. Environmental Protection Agency. https://www.epa.gov/uic/primary-enforcement-authority- underground-injection-control-program-0. 567Arizona Department of Environmental 
Quality. (2024). Underground Injection Control (UIC) Program. https://azdeq.gov/UIC. 
568EPA. (2023). Underground Injection Control 
(UIC) Primary Enforcement Authority for the Underground Injection Control Program. U.S. Environmental Protection Agency. https://www.epa.gov/uic/primary-enforcement-authority- underground-injection-control-program-0. 
569EPA. (2023). Underground Injection Control 
(UIC) Class VI Grant Program. https://www.epa.gov/ system/files/documents/2023-11/uic-class-vi-grant- fact-sheet.pdf. 
570Global CCS Institute. (2024). Global Status of 
CCS 2023. https://www.globalccsinstitute.com/wp- content/uploads/2024/01/Global-Status-of-CCS- Report-1.pdf. 571UIC regulations for Class VI wells authorize 
the injection of CO 2for geologic sequestration while 
protecting human health by ensuring the protection of underground sources of drinking water. The major components to be included in UIC Class VI permits are detailed further in section VII.C.1.a.i(D)(4). 
572U.S. EPA Class VI Underground Injection 
Control (UIC) Class VI Wells Permitted by EPA as of January 25, 2024. https://www.epa.gov/uic/table- epas-draft-and-final-class-vi-well-permits Last 
updated January 19, 2024. 
573EPA. (2024). Current Class VI Projects under 
Review at EPA. https://www.epa.gov/uic/current- class-vi-projects-under-review-epa. 
574Ibid. months. The EPA aims to review 
complete Class VI applications and issue permits when appropriate within approximately 24 months. This timeframe is dependent on several factors, including the complexity of the project and the quality and completeness of the submitted 
application. It is important for the applicant to submit a complete application and provide any information requested by the permitting agency in a timely manner so as not to extend the overall time for the review. 
States may apply to the EPA for 
primacy to administer the Class VI programs within their states. The primacy application process has four phases: (1) pre-application activities, (2) completeness review and determination, (3) application evaluation, and (4) rulemaking and codification. To date, three states have been granted primacy for Class VI wells, including North Dakota, Wyoming, and most recently Louisiana.
562As discussed above, North 
Dakota has issued 6 Class VI permits since receiving Class VI primacy in 2018, and Wyoming issued its first three Class VI permits in December 2023.
563 564 565 The EPA finalized a rule 
granting Louisiana Class VI primacy in January 2024 and the state’s program became effective in February 2024. At that time, EPA Region 6 transferred 56 Class VI permit applications for projects in Louisiana to the state for continued review and permit issuance if appropriate. Prior to receiving primacy, the state worked with the EPA in understanding where each application was in the evaluation process. Currently, the EPA is working with the states of Texas, Arizona, and West Virginia as they are developing their UIC primacy applications.
566Arizona submitted a primacy application to the 
EPA on February 13, 2024.567Texas and 
West Virginia are engaging with the EPA to complete pre-application activities.
568If more states apply for and 
receive Class VI primacy, the number of permits in EPA review is expected to be reduced. The EPA has also created resources for regulators including training series and guidance documents to build capacity for Class VI permitting within UIC programs across the U.S. Through state primacy for Class VI programs, state expertise and capacity can be leveraged to support effective and efficient permit application reviews. The IIJA established a $50 million grant program to support states, Tribes, and territories in developing and implementing UIC Class VI programs. The EPA has allocated $1,930,000 to each state, tribe, and territory that submitted letters of intent.
569 
(6) Comments Received on Geologic Sequestration and Responses 
The EPA received comments on 
geologic sequestration. Those comments, and the EPA’s responses, are as follows. 
Comment: Some commenters 
expressed concerns that the EPA has not demonstrated the adequacy of carbon sequestration at a commercial scale. 
Response: The EPA disagrees that 
commercial carbon sequestration capacity will be inadequate to support this rule. As detailed in section VII.C.1.a.i(D)(1), commercial geologic sequestration capacity is growing in the United States. Multiple commercial sequestration facilities, other than those funded under EPAct05, are in construction or advanced development, with some scheduled to open for operation as early as 2025.
570These 
facilities have proposed sequestration capacities ranging from 0.03 to 6 million tons of CO
2per year. The EPA and states 
with approved UIC Class VI programs (including Wyoming, North Dakota, and Louisiana) are currently reviewing UIC Class VI geologic sequestration well permit applications for proposed sequestration sites in fourteen 
states.
571 572 573 As of March 2024, there 
are 44 projects with 130 injection wells are under review by the EPA.
574 
Furthermore, the EPA anticipates that as the demand for commercial sequestration grows, more commercial sites will be developed in response to financial incentives. 
Comment: Some commenters 
expressed concern about leakage of CO
2 
from sequestration sites. 
Response: The EPA acknowledges the 
potential for some leakage of CO 2to the 
atmosphere at sequestration sites (such as leaks through valves before the CO
2 
reaches the injection formation). However, as detailed in the preceding sections of preamble, the EPA’s robust UIC permitting process is adequate to protect against CO
2escaping the 
authorized injection zone (and then entering the atmosphere). As discussed in the preceding section, leakage out of the injection zone could trigger emergency and remedial response action including ceasing injection, possible permit modification, and possible enforcement action. Furthermore, the GHGRP subpart RR and subpart VV regulations prescribe accounting methodologies for facilities to quantify and report any potential leakage at the surface, and the EPA makes sequestration data and related monitoring plans publicly available on its website. The reported emissions/ leakage from sequestration sites under subpart RR is a comparatively small fraction (less than 0.5 percent) of the associated sequestration volumes, with most of these reported emissions attributable to leaks or vents from surface equipment. 
Comment: Some commenters 
expressed concern over safety due to induced seismicity. 
Response: The EPA believes that the 
UIC program requirements adequately address potential safety concerns with induced seismicity at site-adjacent communities. More specifically, through the UIC Class VI program the EPA has put in place mechanisms to identify, 
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575EPA. (2018). Geologic Sequestration of Carbon 
Dioxide: Underground Injection Control (UIC) 
Program Class VI Implementation Manual for UIC Program Directors. EPA 816–R–18–001. https://www.epa.gov/sites/default/files/2018-01/ documents/implementation_ manual_ 508_
010318.pdf. 
576EPA. (2015). Minimizing and Managing 
Potential Impacts of Injection-Induced Seismicity from Class II Disposal Wells: Practical Approaches. https://www.epa.gov/sites/default/files/2015-08/ documents/induced-seismicity-201502.pdf. 
57740 CFR 146.82(a)(3)(v). 
578EPA. (2023). Environmental justice Guidance 
for UIC Class VI Permitting and Primacy. https://www.epa.gov/system/files/documents/2023-08/ Memo%20and%20EJ%20Guidance%20for%20UIC%20Class%20VI_August%202023.pdf; see also EPA. Letter from the EPA Administrator Michael S. Regan to U.S. State Governors. December 9, 2022. https://www.epa.gov/ system/files/documents/2022-12/AD.Regan_.GOVS_ .Sig_ .Class%20VI.12-9-22.pdf. 
579EPA. (2023). Environmental Justice Guidance 
for UIC Class VI Permitting and Primacy. https://www.epa.gov/system/files/documents/2023-08/ Memo%20and%20EJ%20Guidance%20for%20UIC%20Class%20VI_August%202023.pdf. 
580Letter from U.S. Treasury Inspector General 
for Tax Administration (TIGTA). (2020). https://www.menendez.senate.gov/imo/media/doc/ TIGTA%20IRC%2045Q%20Response%20Letter%20FINAL%2004-15-2020.pdf. monitor, and mitigate risks associated 
with induced seismicity in any areas within or surrounding a sequestration site through permit and program requirements, such as site characterization and monitoring, and the requirement for applicants to demonstrate that induced seismic activity will not endanger USDWs.
575 
See section VII.C.1.a.i(D)(4)(b) for further discussion of mitigating induced seismicity risk. Although the UIC Class II program does not have specific requirements regarding seismicity, it includes discretionary authority to add additional conditions to a UIC permit on a case-by-case basis. The EPA created a document outlining practical approaches for UIC Directors to use to minimize and manage injection-induced seismicity in Class II wells.
576 
Furthermore, during site characterization, if any of the geologic or seismic data obtained indicate a substantial likelihood of seismic 
activity, further analyses, potential planned operational changes, and additional monitoring may be required.
577The EPA has the authority 
to require seismic monitoring as a condition of the UIC permit if appropriate, or to deny the permit if the injection-induced seismicity risk could endanger USDWs. 
Comment: Some commenters have 
expressed concern that the EPA has not meaningfully engaged with historically disadvantaged and overburdened communities who may be impacted by environmental changes due to geologic sequestration. 
Response: The EPA acknowledges 
that meaningful engagement with local communities is an important step in the development of geologic sequestration projects and has programs and public participation requirements in place to support this process. The EPA is committed to advancing environmental justice for overburdened communities in all its programs, including the UIC Class VI program.
578The EPA’s environmental justice guidance for Class VI permitting and primacy states that many of the expectations are broadly applicable, and EPA Regions should apply them to the other five injection well classes, including Class II, wherever possible.
579See section 
VII.C.1.a.i(D)(4) for a detailed discussion of environmental justice requirements and guidance. 
Comment: Commenters expressed 
concern that companies are not always in compliance with reporting requirements for subpart RR when required for other Federal programs. 
Response: The EPA recognizes the 
need for geologic sequestration facilities to comply with the reporting requirements of the GHGRP, and acknowledges that there have been instances of entities claiming geologic sequestration under non-EPA programs (e.g., to qualify for IRC section 45Q tax 
credits) while not having an EPA- approved MRV plan or reporting data under subpart RR.
580The EPA does not 
implement the IRC section 45Q tax credit program, and it is not privy to taxpayer information. Thus, the EPA has no role in implementing or enforcing these tax credit claims, and it is unclear, for example, whether these companies would have been required by GHGRP regulations to report data under subpart RR, or if they would have been required only by the IRC section 45Q rules to opt- in to reporting under subpart RR. The EPA disagrees that compliance with the GHGRP would be a problem for this rule because the rule requires any affected unit that employs CCS technology that captures enough CO
2to meet the 
proposed standard and injects the captured CO
2underground to report 
under GHGRP subpart RR or GHGRP subpart VV. Unlike the IRC section 45Q tax credit program, which is implemented by the Internal Revenue Service (IRS), the EPA will have the information necessary to discern whether a facility is in compliance with any applicable GHGRP requirements. If the emitting EGU sends the captured CO
2offsite, it must transfer the CO 2to 
a facility that reports in accordance with GHGRP subpart RR or GHGRP subpart 
VV. For more information on the relationship to GHGRP requirements, see section X.C.5 of this preamble. 
Comment: Commenters expressed 
concerns that UIC regulations allow Class II wells to be used for long-term CO
2storage if the operator assesses that 
a Class VI permit is not required and asserted that Class II regulations are less protective than Class VI regulations. 
Response: The EPA acknowledges 
that Class II wells for EOR may be used to inject CO
2including CO 2captured 
from an EGU. However, the EPA disagrees that the use of Class II wells for ER will be less protective of human health than the use of Class VI wells for geologic sequestration. Class II wells are used only to inject fluids associated with oil and natural gas production, and Class II ER wells are used specifically for the injection of fluids, including CO
2,for the purpose of enhanced 
recovery of oil or natural gas. The EPA’s UIC Class II program is designed to prevent Class II injection activities from endangering USDWs. Any leakage out of the designated injection zone could pose a risk to USDWs and therefore could be subject to enforcement action or permit modification. Therefore, the EPA believes that UIC protections for USDWs would also ensure that the injected CO
2is contained in the 
subsurface formations. The Class II programs of states and tribes must be approved by the EPA and must meet EPA regulatory requirements for Class II programs, 42 U.S.C. 300h–1, or otherwise represent an effective program to prevent endangerment of USDWs. 42 U.S.C 300h–4. The EPA’s regulations require the operator of a Class II well to obtain a Class VI permit when operations shift to geologic sequestration and there is consequently an increased risk to USDWs. 40 CFR 144.19. UIC Class VI regulations require that owners or operators must show that the injection zone has sufficient volume to contain the injected carbon dioxide stream and report any fluid migration out of the injection zone and into or between USDWs. 40 CFR 146.83 and 40 CFR 146.91. The EPA emphasizes that while CO
2captured from an EGU can be 
injected into a Class II ER injection well, it cannot be injected into the other two 
types of Class II wells, which are Class II disposal wells and Class II wells for the storage of hydrocarbons. 40 CFR 144.6(b). 
Comment: Some commenters 
expressed concern that because few Class VI permits have been issued, the EPA’s current level of experience in properly regulating and reviewing permits for these wells is limited. 
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581EPA. (2023). Underground Injection Control 
Class VI (Geologic Sequestration) Contact 
Information. https://www.epa.gov/uic/underground- 
injection-control-class-vi-geologic-sequestration- contact-information. 
582Report of the Interagency Task Force on 
Carbon Capture and Storage. 2010. https://www.energy.gov/fecm/articles/ccstf-final-report. 583Council on Environmental Quality Report to 
Congress on Carbon Capture, Utilization, and 
Sequestration. 2021. https://www.whitehouse.gov/ wp-content/uploads/2021/06/CEQ-CCUS- Permitting-Report.pdf. 
584National Policy for the Right-of-Way 
Authorizations Necessary for Site Characterization, 
Capture, Transportation, Injection, and Permanent Geologic Sequestration of Carbon Dioxide in Connection with Carbon Sequestration Projects. BLM IM 2022–041 Instruction Memorandum, June 8, 2022. https://www.blm.gov/policy/im-2022-041. 
585ND DMR 2023. Pore Space in North Dakota. 
North Dakota Department of Mineral Resources https://www.dmr.nd.gov/oilgas/ND_ DMR_ Pore_
Space_ Information.pdf. 
586Ibid. 
587Summit Carbon Solutions. (2021). Summit 
Carbon Solutions Announces Significant Carbon Storage Project Milestones. (2021). https://summitcarbonsolutions.com/summit-carbon- solutions-announces-significant-carbon-storage- project-milestones/. 
588Wyo. Stat § 34–1–152 (2022). 589Benson, S.M. (2007). Carbon dioxide capture 
and storage: research pathways, progress and potential. Presentation given at the Global Climate & Energy Project Annual Symposium, October 1, 2007. https://drive.google.com/file/d/ 
1ZvfRW92OqvBBAFs69SPHIWoYFGySMgtD/view. Response: The EPA disagrees that the 
Agency lacks experience to properly 
regulate, and review permits for Class VI injection wells. We expect that the additional resources that have been allocated for the Class VI program will lead to increased efficiencies in the Class VI permitting process and timeframes. For a more detailed discussion of Class VI permitting and timeframes, see sections VII.C.1.a.i(D)(4)(b) and VII.C.1.a.i(D)(5) 
of this preamble. The EPA emphasizes that incomplete or insufficient application materials can result in substantially delayed permitting decisions. When the EPA receives incomplete or insufficient permit applications, the EPA communicates the deficiencies, waits to receive additional materials from the applicant, and then reviews any new data. This back and forth can result in longer permitting timeframes. The EPA therefore encourages applicants to contact their permitting authority early on so applicants can gain a thorough understanding of the Class VI permitting process and the permitting authority’s expectations. To assist potential permit applicants, the EPA maintains a list of UIC contacts within each EPA Regional Office on the Agency’s website.
581The 
EPA has met with more than 100 companies and other interested parties. 
Comment: Some commenters claimed 
that various legal uncertainties preclude a finding that geologic sequestration of CO
2has been adequately demonstrated. 
This concern has been raised in particular with issues of pore space ownership and the lack of long-term liability insurance and noted uncertainties regarding long-term liability generally. 
Response: The EPA disagrees that 
these uncertainties are sufficient to prohibit the development of geologic sequestration projects. An interagency CCS task force examined sequestration- related legal issues thoroughly and concluded that early CCS projects could proceed under the existing legal framework with respect to issues such as property rights and liability.
582The 
development of CCS projects may be more complex in certain regions, due to distinct pore space ownership regulatory regimes at the state level, 
except on Federal lands.
583 
As discussed in section 
VII.C.1.a.i.(D)(4) of this preamble, Title V of the FLPMA and its implementing regulations, 43 CFR part 2800, authorize the BLM to issue ROWs to geologically sequester CO
2in Federal pore space, 
including BLM ROWs for the necessary physical infrastructure and for the use and occupancy of the pore space itself. The BLM has published a policy defining access to pore space on BLM lands, including clarification of Federal policy for situations where the surface and pore space are under the control of different Federal agencies.
584 
States have established legislation and 
regulations defining pore space ownership and providing clarification to prospective users of surface pore space. For example, in North Dakota, the surface owner also owns the pore space underlying their surface estate.
585North 
Dakota state courts have determined that in situations where the surface ownership and mineral ownership have been legally severed the mineral estate is the dominant estate and has the right to use as much of the surface estate as reasonably necessary. The North Dakota legislature codified this interpretation in 2019.
586Summit Carbon Solutions, 
which is developing a carbon storage hub in North Dakota to store an estimated one billion tons of CO
2, 
indicated that they had secured the majority of the pore space needed through long term leases with landowners.
587Wyoming defines 
ownership of pore space underlying surfaces within the state.
588Other states 
have also established laws, implementing regulations and guidance defining ownership and access to pore space. The EPA notes that many states are actively enacting legislation addressing pore space ownership. See e.g., Wyoming H.B. No. 89 (2008) (Wyo. 
Stat. § 34–1–152); Montana S.B. No. 498 (2009) (Mont. Code Ann. 82–11–180); North Dakota S.B. No. 2139 (2009) (N.D. Cent. Code § 47–31–03); Kentucky H.B. 259 (2011) (Ky. Rev. Stat. Ann. § 353.800); West Virginia H.B. 4491 (2022) (W. Va. Code § 22–11B–18); California S.B. No. 905 (2022) (Cal. Pub. Res. Code § 71462); Indiana Public Law 163 (2022) (Ind. Code § 14–39–2–3); Utah H.B. 244 (2022) (Utah Code § 40– 6–20.5). 
Liability during operation is usually 
assumed by the project operator, so liability concerns primarily arise after the period of operations. Research has previously shown that the environmental risk is greatest before injection stops.
589In terms of long-term 
liability and permittee obligations under the SDWA, the EPA’s Class VI regulations impose various requirements on permittees even after injection ceases, including regarding injection well plugging (40 CFR 146.92), post-injection site care (PISC), and site closure (40 CFR 146.93). The default time period for post-injection site care is 50 years, during which the permittee must monitor the position of the CO
2 
plume and pressure front and demonstrate that USDWs are not being endangered. 40 CFR 146.93. The permittee must also generally maintain financial responsibility sufficient to cover injection well plugging, corrective action, emergency and remedial response, PISC, and site closure until the permitting authority approves site closure. 40 CFR 146.85(a)&(b). Even after the former permittee has fulfilled all its UIC regulatory obligations, it may still be held liable for previous regulatory noncompliance, such as where the permittee provided erroneous data to support approval of site closure. A former permittee may always be subject to an order that the EPA Administrator deems necessary to protect public health if there is fluid migration that causes or threatens imminent and substantial endangerment to a USDW. 42 U.S.C. 300i; 40 CFR 144.12(e). 
The EPA notes that many states are 
enacting legislation addressing long term liability. See e.g., Montana S.B. No. 
498 (2009) (Mont. Code Ann. 82–11– 183); Texas H.B. 1796 (2009) (Tex. Health & Safety Code Ann. § 382.508); North Dakota S.B. No. 2095 (2009) (N.D. 
Cent. Code § 38–22–17); Kansas H.B. 
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590CO 2Capture Project Schedule and Operations 
Memo, Sargent & Lundy (2024). Available in Docket 
ID EPA–HQ–OAR–2023–0072. 
591Transport and Storage Timeline Summary, ICF 
(2024). Available in Docket ID EPA–HQ–OAR– 2023–0072. 592NETL Develops Pipeline Route Planning 
Database To Guide CO 2Transport Decisions. May 
31, 2023. https://netl.doe.gov/node/12580. 2418 (2010) (Kan. Stat. Ann. § 55– 
1637(h)); Wyoming S.F. No. 47 (2022) (Wyo. Stat. §§ 35–11–319); Louisiana H.B. 661 (2009) & H.B. 571 (2023) (La. Stat. Ann. § 30:1109). Because states are actively working to address pore space and liability uncertainties, the EPA does not believe these to be issues that would delay project implementation beyond the timelines discussed in this preamble. 
(E) Compliance Date for Long-Term 
Coal-Fired Steam Generating Units 
The EPA proposed a January 1, 2030 
compliance date for long-term coal fired steam generating units subject to a CCS BSER. That compliance date assumed installation of CCS was concurrent with development of state plans. While several commenters were supportive of the proposed compliance date, the EPA also received comments on the proposed rule that stated that the proposed compliance date was not achievable. Commenters referenced longer project timelines for CO
2capture. 
Commenters also requested that the EPA should account for the state plan process in determining the appropriate compliance date. 
The EPA has considered the 
comments and information available and is finalizing a compliance date of January 1, 2032, for long-term coal-fired steam generating units. The EPA is also finalizing a mechanism for a 1-year compliance date extension in cases where a source faces delays outside its control, as detailed in section X.C.1.d of this preamble. The justification for the January 1, 2032 compliance date does not require substantial work to be done during the state planning process. Rather, the justification for the compliance date reflects the assumption that only the initial feasibility work which is necessary to inform the state planning process would occur during state plan development, with the start of more substantial work beginning after 
the due date for state plan submission, and a longer timeline for installation of CCS than at proposal. In total, this allows for 6 years and 7 months for both initial feasibility and more substantial work to occur after issuance of this rule. This is consistent with the approximately 6 years from start to finish for Boundary Dam Unit 3 and Petra Nova. 
The timing for installation of CCS on 
existing coal-fired steam generating units is based on the baseline project schedule for the CO
2capture plant 
developed by Sargent and Lundy (S&L590and a review of the available 
information for installation of CO 2 
pipelines and sequestration sites.591 
Additional details on the timeline are in 
the TSD GHG Mitigation Measures for Steam Generating Units, available in the docket. The dates for intermediate steps are for reference. The specific sequencing of steps may differ slightly, and, for some sources, the duration of one step may be shorter while another may be longer, however the total duration is expected to be the same. The resulting timeline is therefore an accurate representation of the time necessary to install CCS in general. 
The EPA assumes that feasibility 
work, amounting to less than 1 year (June 2024 through June 2025) for each component of CCS (capture, transport, and storage) occurs during the state plan development period (June 2024 through June 2026). This feasibility work is limited to initial conceptual design and other preliminary tasks, and the costs of the feasibility work in general are substantially less than other components of the project schedule. The EPA determined that it was appropriate to assume that this work would take place during the state plan development period because it is necessary for evaluating the controls that the state may determine to be appropriate for a source and is necessary for determining the resulting standard of performance that the state may apply to the source on the basis of those controls. In other words, without such feasibility and design work, it would be very difficult for a state to determine whether CCS is appropriate for a given source or the resulting standard of performance. While the EPA accounts for up to 1 year for feasibility for the capture plant, the S&L baseline schedule estimates this initial design activity can be completed in 6 months. For the capture plant, feasibility includes a preliminary technical evaluation to review the available utilities and siting footprint for the capture plant, as well as screening of the available capture technologies and vendors for the project, with an associated initial economic estimate. For sequestration, in many cases, general geologic characterization of regional areas has already been conducted by U.S. DOE and regional initiatives; however, the EPA assumes an up to 1 year period for a storage complex feasibility study. For the pipeline, the feasibility includes the initial pipeline routing analysis, taking less than 1 year. This exercise involves using software to review existing right- of-way and other considerations to develop an optimized pipeline route. Inputs to that analysis have been made publicly available by DOE in NETL’s Pipeline Route Planning Database.
592 
When state plans are submitted 24 
months after publication of the final rule, requirements included within those state plans should be effective at the state level. On that basis, the EPA 
assumes that sources installing CCS are fully committed, and more substantial work (e.g., FEED study for the capture 
plant, permitting, land use and right-of- way acquisition) resumes in June 2026. The EPA notes, however, that it would be possible that a source installing CCS would choose to continue these activities as soon as the initial feasibility work is completed even if not yet required to do so, rather than wait for state plan submission to occur for the reasons explained in full below. 
Of the components of CCS, the CO
2 
capture plant is the more technically involved and time consuming, and therefore is the primary driver for determining the compliance date. The EPA assumes substantial work commences only after submission due date for state plans. The S&L baseline timeline accounts for 5.78 years (301 weeks) for final design, permitting, and installation of the CO
2capture plant. 
First, the EPA describes the timeline that is consistent with the S&L baseline for substantial work. Subsequently, the EPA describes the rationale for slight adjustments that can be made to that timeline based upon an examination of actual project timelines. 
In the S&L baseline, substantial work 
on the CO
2capture plant begins with a 
1-year FEED study (June 2026 to June 2027). The information developed in the FEED study is necessary for finalizing commercial arrangements. In the S&L baseline, the commercial arrangements can take up to 9 months (June 2027 to March 2028). Commercial arrangements include finalizing funding as well as finalizing contracts with a CO
2capture 
technology provider and engineering, procurement, and construction companies. The S&L baseline accounts for 1 year for permitting, beginning when commercial arrangements are nearly complete (December 2027 to December 2028). After commercial arrangements are complete, a 2-year period for engineering and procurement begins (March 2028 to March 2030). 
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593Project Diamond Vault Overview. https://
www.cleco.com/docs/default-source/diamond- 
vault/project_ diamond_ vault_ overview.pdf. 594The summary timeline for CO 2pipelines 
assumes feasibility for pipelines is 1 year, followed by 1.5 years for permitting, with the pipeline feasibility beginning 1 year after permitting for sequestration starts. The EPA assumes initial pipeline feasibility occurs up-front, with a longer period for final routing, permitting, and right-of- way acquisition. 
595Petra Nova W.A. Parish Project. https://
www.energy.gov/fecm/petra-nova-wa-parish- project. Detailed engineering starts after 
commercial arrangements are complete because engineers must consider details regarding the selected CO
2capture 
technology, equipment providers, and coordination with construction. Shortly after permitting is complete, 6 months of sitework (March 2029 to September 2029) occur. Sitework is followed by 2 years of construction (July 2029 to July 2031). Approximately 8 months prior to the completion of construction, a roughly 14 month (60 weeks) period for startup and commissioning begins (January 2031 to March 2032). 
In many cases, the EPA believes that 
sources are positioned to install CO
2 
capture on a slightly faster timeline than the baseline S&L timeline detailed in the prior paragraph, because CCS projects have been developed in a shorter timeframe. Including these minor adjustments, the total time for detailed engineering, procurement, construction, startup and commissioning is 4 years, which is consistent with completed projects (Boundary Dam Unit 3 and Petra Nova) and project schedules developed in 
completed FEED studies, see the final TSD, GHG Mitigation Measures for 
Steam Generating Units for additional details. In addition, the IRC tax credits incentivize sources to begin complying earlier to reap economic benefits earlier. Sources that have already completed feasibility or FEED studies, or that have FEED studies ongoing are likely to be able to have CCS fully operational well in advance of January 1, 2032. Ongoing projects have planned dates for commercial operation that are much earlier. For example, Project Diamond Vault has plans to be fully operational in 2028.
593While the EPA assumes 
FEED studies start after the date for state plan submission, in practice sources are likely to install CO
2capture as 
expeditiously as practicable. Moreover, the preceding timeline is derived from project schedules developed in the absence of any regulatory impetus. Considering these factors, sources have opportunities to slightly condense the duration, overlap, or sequencing of steps so that the total duration for completing substantial work on the capture plant is reduced by 2 months. For example, by expediting the duration for commercial arrangements from 9 months to 7 months, reasonably assuming sources immediately begin sitework as soon as permitting is complete, and accounting for 13 months (rather than 14) for startup and testing, the CO
2capture plant will be fully operational by January 2032. Therefore, the EPA concludes that CO
2capture can be fully 
operational by January 1, 2032. To the extent additional time is needed to take into account the particular circumstances of a particular source, the state may take those circumstances into account to provide a different compliance schedule, as detailed in section X.C.2 of this preamble. 
The EPA also notes that there is 
additional time for permitting than described in the S&L baseline. The key permitting that affects the timeline are air permits because of the permits’ impact on the ability to construct and operate the CCS capture equipment, in which the EPA is the expert in. The S&L baseline assumes permitting starts after the FEED study is complete while commercial arrangements are ongoing, however permitting can begin earlier allowing a more extended period for permitting. Examples of CCS permitting being completed while FEED studies are on-going include the air permits for Project Tundra, Baytown Energy Center, and Deer Park Energy Center. Therefore, while the FEED study is on-going, the EPA assumes that a 2-year process for permitting can begin. 
The EPA’s compliance deadline 
assumes that storage and pipelines for the captured CO
2can be installed 
concurrently with deployment of the capture system. Substantial work on the storage site starts with 3 years (June 2026 to June 2029) for final site characterization, pore-space acquisition, and permitting, including at least 2 years for permitting of Class VI wells during that period. Lastly, construction for sequestration takes 1 year (June 2029 to June 2030). While the EPA assumes that storage can be permitted and constructed in 4 years, the EPA notes that there is at least an additional 12 months of time available to complete construction of the sequestration site without impacting progress of the other components. 
The EPA assumes the substantial 
work on the pipeline lags the start of substantial work on the storage site by 6 months. After the 1 year of feasibility work prior to state plan submission, the general timeline for the CO
2pipeline 
assumes up to 3 years for final routing, permitting activities, and right-of-way acquisition (December 2026 to December 2029). Lastly, there are 1.5 years for pipeline construction (December 2029 to June 2031).
594 The EPA does not assume that CCS 
projects are, in general, subject to NEPA. 
NEPA review is required for reasons including sources receiving federal funding (e.g., through USDA or DOE) or 
projects on federal lands. NEPA may also be triggered for a CCS project if NEPA compliance is necessary for construction of the pipeline, such as where necessary because of a Clean Water Act section 404 permit, or for sequestration. Generally, if one aspect of a project is subject to NEPA, then the other project components could be as well. In cases where a project is subject to NEPA, an environmental assessment (EA) that takes 1 year, can be finalized concurrently during the permitting 
periods of each component of CCS (capture, pipeline, and sequestration). However, the EPA notes that the final timeline can also accommodate a concurrent 2-year period if an EIS were required under NEPA across all components of the project. The EPA also notes that, in some circumstances, NEPA review may begin prior to completion of a FEED study. For Petra Nova, a notice of intent to issue an EIS was published on November 14, 2011, and the record of decision was issued less than 2 years later, on May 23, 2013,
595while the FEED study was 
completed in 2014. 
Based on this detailed analysis, the 
EPA has concluded that January 1, 2032, is an achievable compliance date for CCS on existing coal-fired steam generating units that takes into account the state plan development period, as well as the technical and bureaucratic steps necessary to install and implement CCS and is consistent with other expert estimates and real-world experience. 
(F) Long-Term Coal-Fired Steam 
Generating Units Potentially Subject to This Rule 
In this section of the preamble, the 
EPA estimates the size of the inventory of coal-fired power plants in the long- term subcategory likely subject to CCS as the BSER. Considering that capacity, the EPA also describes the distance to storage for those sources. 
(1) Capacity of Units Potentially Subject 
to This Rule 
First, the EPA estimates the total 
capacity of units that are currently operating and that have not announced plans to retire by 2039, or to cease firing 
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596EIA December 2023 Preliminary Monthly 
Electric Generator Inventory. https://www.eia.gov/ 
electricity/data/eia860m/. 
59781 GW is derived capacity, plant type, and 
retirement dates as represented in EPA NEEDS database. Total amount of covered capacity in this category may ultimately be slightly less (approximately) due to CHP-related exemptions. 598The survey Form EIA–860 collects generator- 
level specific information about existing and planned generators and associated environmental equipment at electric power plants with 1 megawatt or greater of combined nameplate capacity. Data available at https://www.eia.gov/electricity/data/ eia860/. coal by 2030. Starting from that first 
estimate, the EPA then estimates the capacity of units that would likely be subject to the CCS requirement, based on unit age, industry trends, and economic factors. 
Currently, there are 181 GW of coal- 
fired steam generating units.
596About 
half of that capacity, totaling 87 GW, have announced plans to retire before 2039, and an additional 13 GW have announced plans to cease firing coal by that time. The remaining amount, 81 GW, are likely to be the most that could potentially be subject to requirements 
based on CCS. 
However, the capacity of affected 
coal-fired steam generating units that would ultimately be subject to a CCS BSER is likely approximately 40 GW. This determination is supported by several lines of analysis of the historical data on the size of the fleet over the past several years. Historical trends in the coal-fired generation fleet are detailed in section IV.D.3 of this preamble. As coal- fired units age, they become less efficient and therefore the costs of their electricity go up, rendering them even more competitively disadvantaged. Further, older sources require additional investment to replace worn parts. Those circumstances are likely to continue through the 2030s and beyond and become more pronounced. These factors contribute to the historical changes in the size of the fleet. 
One way to analyze historical changes 
in the size of the fleet is based on unit age. As the average age of the coal-fired fleet has increased, many sources have ceased operation. From 2000 to 2022, the average age of a unit that retired was 53 years. At present, the average age of the operating fleet is 45 years. Of the 81 GW that are presently operating and that have not announced plans to retire or convert to gas prior to 2039, 56 GW will be 53 years or older by 2039.
597 
Another line of analysis is based on 
the rate of change of the size of the fleet. The final TSD, Power Sector Trends, available in the rulemaking docket, includes analysis showing sharp and steady decline in the total capacity of the coal-fired steam generating fleet. Over the last 15 years (2009–2023), average annual coal retirements have been 8 GW/year. Projecting that retirements will continue at approximately the same pace from now until 2039 is reasonable because the 
same circumstances will likely continue or accelerate further given the incentives under the IRA. Applying this level of annual retirement would result in 45 GW of coal capacity continuing to operate by 2039. Alternatively, the TSD also includes a graph that shows what the fleet would look like assuming that coal units without an announced retirement date retire at age 53 (the average retirement age of units over the 2000–2022 period). It shows that the amount of coal-fired capacity that remains in operation by 2039 is 38 GW. 
The EPA also notes that it is often the 
case that coal-fired units announce that they plan to retire only a few years in advance of the retirement date. For instance, of the 15 GW of coal-fired EGUs that reported a 2022 retirement year in DOE’s EIA Form 860, only 0.5 GW of that capacity had announced its retirements plans when reporting in to the same EIA–860 survey 5 years earlier, in 2017.
598Thus, although many coal- 
fired units have already announced plans to retire before 2039, it is likely that many others may anticipate retiring by that date but have not yet announced it. 
Finally, the EPA observes that 
modeling the baseline circumstances, absent this final rule, shows additional 
retirements of coal-fired steam generating units. At the end of 2022, there were 189 GW of coal active in the U.S. By 2039, the IPM baseline projects that there will be 42 GW of operating coal-fired capacity (not including coal- to-gas conversions). Between 2023– 2039, 95 GW of coal capacity have announced retirement and an additional 13 have announced they will cease firing coal. Thus, of the 81 GW that have not announced retirement or conversion to gas by 2039, the IPM baseline projects 39 GW will retire by 2039 due to economic reasons. 
For all these reasons, the EPA 
considers that it is realistic to expect that 42 GW of coal-fired generating will be operating by 2039—based on announced retirements, historical trends, and model projections—and therefore constitutes the affected sources in the long-term subcategory that would be subject to requirements based on CCS. It should be noted that the EPA does not consider the above analysis to predict with precision which units will remain in operation by 2039. Rather, the two sets of sources should be 
considered to be reasonably representative of the inventory of sources that are likely to remain in operation by 2039, which is sufficient for purposes of the BSER analysis that follows. 
(2) Distance to Storage for Units 
Potentially Subject to This Rule 
The EPA believes that it is 
conservative to assume that all 81 GW of capacity with planned operation during or after 2039 would need to construct pipelines to connect to sequestration sites. As detailed in section VII.B.2 of this preamble, the EPA is finalizing an exemption for coal- fired sources permanently ceasing operation by January 1, 2032. About 42 percent (34 GW) of the existing coal- fired steam generation capacity that is currently in operation and has not announced plans to retire prior to 2039 will be 53 years or older by 2032. As discussed in section VII.C.1.a.i(F), from 2000 to 2022, the average age of a coal unit that retired was 53 years old. Therefore, the EPA anticipates that approximately 34 GW of the total capacity may permanently cease operation by 2032 despite not having yet announced plans to do so. Furthermore, of the coal-fired steam generation capacity that has not announced plans to cease operation before 2039 and is further than 100 km (62 miles) of a potential saline sequestration site, 45 percent (7 GW) will be over 53 years old in 2032. Therefore, it is possible that much of the capacity that is further than 100 km (62 miles) of a saline sequestration site and has not announced plans to retire will permanently cease operation due to age before 2032 and thus the rule would not apply to them. Similarly, of the coal- fired steam generation capacity that has not announced plans to cease operation before 2039 and is further than 160 km (100 miles) of a potential saline sequestration site, 56 percent (4 GW) will be over 53 years old in 2032. Therefore, the EPA notes that it is possible that the majority of capacity that is further than 160 km (100 miles) 
of a saline sequestration and has not announced plans to retire site will permanently cease operation due to age before 2032 and thus be exempt from the requirements of this rule. 
The EPA also notes that a majority (56 
GW) of the existing coal-fired steam generation capacity that is currently in operation and has not announced plans to permanently cease operation prior to 2039 will be 53 years or older by 2039. Of the coal-fired steam generation capacity with planned operation during 
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599Sequestration potential as it relates to distance 
from existing resources is a key part of the EPA’s 
regular power sector modeling development, using data from DOE/NETL studies. For details, please see chapter 6 of the IPM documentation available at:. https://www.epa.gov/system/files/documents/2021- 09/chapter-6-co2-capture-storage-and- transport.pdf. 
600DOE. Material Requirements for Carbon 
Capture and Storage Retrofits on Existing Coal- 
Fueled Electric Generating Units. https://www.energy.gov/policy/articles/material- requirements-carbon-capture-and-storage-retrofits- existing-coal-fueled. 
601Steel requirements were assessed for carbon 
capture, transport and storage, but cement requirements were only assessed for capture and storage. 
602DOE analyzed the resources—including 
specialized equipment, commodity materials, and, as discussed below, workforce, necessary for 73 GW of coal capacity to install CCS because that is the amount that has not announced plans to retire by January 1, 2040. As indicated in the final TSD, Power Sector Trends, a somewhat larger amount— 81 GW—has not announced plans to retire or cease firing coal by January 1, 2039, and it is this latter amount that is the maximum that, at least in theory, could be subject to the CCS requirement. DOE’s conclusions that sufficient resources are available also hold true for the larger amount. 603Although the assessment assumed that all of 
the CCS deployments would utilize MEA-based 
carbon capture technologies, future CCS deployments could potentially use different solvents, or capture technologies that do not use solvents, e.g., membranes, sorbents. A number of 
technology providers have solvents that are commercially available, as detailed in section VII.C.1.a.i.(B)(3) of this preamble. In addition, a 2022 DOE carbon capture supply chain assessment concluded that common amines used in carbon capture have robust and resilient supply chains that could be rapidly scaled, with low supply chain risk associated with the main inputs for scale-up. See U.S. Department of Energy (DOE). Supply Chain Deep Dive Assessment: Carbon Capture, Transport & Storage. https://www.energy.gov/sites/default/ files/2022-02/Carbon%20Capture%20Supply%20Chain%20Report%20- %20Final.pdf. 604DOE. Workforce Analysis of Existing Coal 
Carbon Capture Retrofits. https://www.energy.gov/ policy/articles/workforce-analysis-existing-coal- carbon-capture-retrofits. 
605Ibid. 
606SaskPower, ‘‘SaskPower CCS.’’ https://
unfccc.int/files/bodies/awg/application/pdf/01_saskatchewan_ environment_ micheal_ monea.pdf. 
For corroboration, we note similar employment numbers for two EPAct-05 assisted projects: Petra Nova estimated it would need approximately 1,100 construction-related jobs and up to 20 jobs for ongoing operations. National Energy Technology Laboratory and U.S. Department of Energy. W.A. Parish Post-Combustion CO2 Capture and Sequestration Project, Final Environmental Impact Statement. https://www.energy.gov/sites/default/ 
files/EIS-0473-FEIS-Summary-2013_ 1.pdf. Project 
Tundra projects a peak labor force of 600 to 700. National Energy Technology Laboratory and U.S. Department of Energy. Draft Environmental Assessment for North Dakota CarbonSAFE: Project Tundra. https://www.energy.gov/sites/default/files/ 
2023-08/draft-ea-2197-nd-carbonsafe-chapters- 2023-08.pdf. 
607For the purposes of evaluating the actual 
workforce and resources necessary for installation of CCS, the five-year assumption in the DOE memo is reasonable. The representative timeline for CCS includes an about 3-year period for construction activities (including site work, construction, and startup and testing) across the components of CCS (capture, pipeline, and sequestration), beginning at the end of 2028. Many sources are well positioned to install CCS, having already completed feasibility work, FEED studies, and/or permitting, and could thereby reasonably start construction activities (still 3-years in duration) by the beginning of 2028 or earlier and, as a practical matter, would likely do so notwithstanding the requirements of this rule 
Continued or after 2039 that is not located within 
100 km (62 miles) of a potential saline sequestration site, the majority (58 percent or 9 GW) of the units will be 53 years or older in 2039.
599Consequently, 
the EPA believes that many of these units may permanently cease operation due to age prior to 2039 despite not at this point having announced specific plans to do so, and thereby would likely not be subject to a CCS BSER. 
(G) Resources and Workforce To Install 
CCS 
Sufficient resources and an available 
workforce are required for installation and operation of CCS. Raw materials necessary for CCS are generally available and include common commodities such as steel and concrete for construction of the capture plant, pipelines, and storage wells. 
Drawing on data from recently 
published studies, the DOE completed an order-of-magnitude assessment of the potential requirements for specialized equipment and commodity materials for retrofitting existing U.S. coal-fueled EGUs with CCS.
600Specialized 
equipment analyzed included absorbers, strippers, heat exchangers, and compressors. Commodity materials analyzed included monoethanolamine (MEA) solvent for carbon capture, triethylene glycol (TEG) for carbon dioxide drying, and steel and cement for construction of certain aspects of the CCS value chain.
601The DOE analyzed 
one scenario in which 42 GW of coal- fueled EGUs are retrofitted with CCS and a second scenario in which 73 GW of coal-fueled EGUs are retrofitted with CCS.
602The analysis determined that in both scenarios, the maximum annual 
commodity requirements to construct and operate the CCS systems are likely to be much less than their respective global production rates. The maximum requirements are expected to be at least one order of magnitude lower than global annual production for all of the commodities considered except MEA, which was estimated to be approximately 14 percent of global annual production in the 42 GW scenario and approximately 24 percent of global annual production in the 73 GW scenario.
603For steel and cement, 
the maximum annual requirements are also expected to be at least one order of magnitude lower than U.S. annual 
production rates. Finally, the DOE analysis determined that it is unlikely that the deployment scenarios would encounter any bottlenecks in the supplies of specialized equipment (absorbers, strippers, heat exchangers, and compressors) because of the large pool of potential suppliers. 
The workforce necessary for installing 
and operating CCS is readily available. The required workforce includes construction, engineering, manufacturing, and other skilled labor (e.g., electrical, plumbing, and 
mechanical trades). The existing workforce is well positioned to meet the demand for installation and operation of CCS. Many of the skills needed to build and operate carbon capture plants are similar to those used by workers in existing industries, and this experience can be leveraged to support the workforce needed to deploy CCS. In addition, government programs, industry workforce investments, and IRC section 45Q prevailing wage and apprenticeship provisions provide additional significant support to workforce development and demonstrate that the CCS industry likely has the capacity to train and expand the available workforce to meet 
future needs.
604 
Overall, quantitative estimates of 
workforce needs indicates that the total number of jobs needed for deploying CCS on coal power plants is significantly less than the size of the existing workforce in adjacent occupations with transferrable skills in the electricity generation and fuels industries. The majority of direct jobs, approximately 90 percent, are expected to be in the construction of facilities, which tend to be project-based. The remaining 10 percent of jobs are expected to be tied to ongoing facility operations and maintenance.
605Recent 
project-level estimates bear this out. The Boundary Dam CCS facility in Canada employed 1,700 people at peak construction.
606A recent workforce 
projection estimates average annual jobs related to investment in carbon capture retrofits at coal power plants could range from 1,070 to 1,600 jobs per plant. A DOE memorandum estimates that 71,400 to 107,100 average annual jobs resulting from CCS project investments—across construction, project management, machinery installers, sales representatives, freight, and engineering occupations—would likely be needed over a five-year construction period
607to deploy CCS at 
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given the strong economic incentives provided by 
the tax credit. The representative timeline also makes conservative assumptions about the pre- construction activities for pipelines and sequestration, and for many sources construction of those components could occur earlier. Finally, to provide greater regulatory certainty and incentivize the installation of controls, the EPA is finalizing a limited one-year compliance date extension mechanism for certain circumstances as detailed in section X.C.1.d of the preamble, and it would also be reasonable to assume that, in practice, some sources use that mechanism. Considering these factors, evaluating workforce and resource requirements over a five-year period is reasonable. 
608DOE. Workforce Analysis of Existing Coal 
Carbon Capture Retrofits. https://www.energy.gov/ policy/articles/workforce-analysis-existing-coal- carbon-capture-retrofits. 
609U.S. Department of Energy. United States 
Energy & Employment Report 2023. https://www.energy.gov/sites/default/files/2023-06/ 2023%20USEER%20REPORT-v2.pdf. 610A line of cases establishes that the EPA may 
extrapolate based on its findings and project 
technological improvements in a variety of ways. First, the EPA may reasonably extrapolate from testing results to predict a lower emissions rate than has been regularly achieved in testing. See Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433 
(D.C. Cir. 1973). Second, the EPA may forecast technological improvements allowing a lower emissions rate or effective control at larger plants than those previously subject to testing, provided the agency has adequate knowledge about the 
needed changes to make a reasonable prediction. See Sierra Club v. Costle 657 F.2d 298 (1981). 
Third, the EPA may extrapolate based on testing at a particular kind of source to conclude that the technology at issue will also be effective at a different, related, source. See Lignite Energy Council v. EPA, 198 F.3d 930 (D.C. Cir. 1999). 
611There, EPA cited Portland Cement v. 
Ruckelshaus, for the proposition that ‘‘D.C. Circuit caselaw supports the proposition that CAA section 
111 authorizes the EPA to determine that controls qualify as the BSER—including meeting the ‘adequately demonstrated’ criterion—even if the controls require some amount of ‘lead time,’ which the court has defined as ‘the time in which the technology will have to be available.’ ’’ See New Source Performance Standards for Greenhouse Gas Emissions From New, Modified, and Reconstructed Fossil Fuel-Fired Electric Generating Units; Emission Guidelines for Greenhouse Gas Emissions 
From Existing Fossil Fuel-Fired Electric Generating Units; and Repeal of the Affordable Clean Energy Rule, 88 FR 33240, 33289 (May 23, 2023) (quoting 
Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 
375, 391 (D.C. Cir. 1973)). 
612The concepts of ‘‘adequately demonstrated’’ 
and ‘‘achievable’’ are closely related. As the D.C. Circuit explained in Essex Chem. Corp. v. Ruckelshaus, ‘‘[i]t is the system which must be 
adequately demonstrated and the standard which 
must be achievable.’’ 486 F.2d 427, 433 (1973). 
613The relevant EPAct05 provisions include the 
following: Section 402(i) of the EPAct05, codified at 42 U.S.C. 15962(a), provides as follows: ‘‘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), as added by EPAct05 a subset of coal power plants. The 
memorandum further estimates that 116,200 to 174,300 average annual jobs would likely be needed if CCS were deployed at all coal-fired EGUs that currently have no firm commitment to retire or convert to natural gas by 2040.
608For comparison, the DOE 
memorandum further categorizes potential workforce needs by occupation, and estimates 11,420 to 27,890 annual jobs for construction trade workers, while the U.S. Energy and Employment Report estimates that electric power generation and fuels accounted for more than 292,000 construction jobs in 2022, which is an order of magnitude greater than the potential workforce needs for CCS deployment under this rule. Overall energy-related construction activities across the entire energy industry accounted for nearly 2 million jobs, or 25 percent of all construction jobs in 2022, indicating that there is a very large pool of workers potentially available.
609 
As noted in section VII.C.1.a.i(F), the 
EPA determined that the population of sources without announced plans to cease operation or discontinue coal- firing by 2039, and that is therefore potentially subject to a CCS BSER, is not more than 81 GW, as indicated in the final TSD, Power Sector Trends. The DOE CCS Commodity Materials and Workforce Memos evaluated material resource and workforce needs for a similar capacity (about 73 GW), and determined that the resources and workforce available are more than sufficient, in most cases by an order of magnitude. Considering these factors, and the similar scale of the population of sources considered, the EPA therefore concludes that the workforce and resources available are more than sufficient to meet the demands of coal- fired steam generating units potentially 
subject to a CCS BSER. 
(H) Determination That CCS Is 
‘‘Adequately Demonstrated’’ 
As discussed in detail in section 
V.C.2.b, pursuant to the text, context, legislative history, and judicial precedent interpreting CAA section 111(a)(1), a technology is ‘‘adequately demonstrated’’ if there is sufficient evidence that the EPA may reasonably conclude that a source that applies the technology will be able to achieve the associated standard of performance under the reasonably expected operating circumstances. Specifically, an adequately demonstrated standard of performance may reflect the EPA’s reasonable expectation of what that particular system will achieve, based on analysis of available data from individual commercial scale sources, and, if necessary, identifying specific available technological improvements that are expected to improve performance.
610The law is clear in 
establishing that at the time a section 111 rule is promulgated, the system that the EPA establishes as BSER need not be in widespread use. Instead, the EPA’s responsibility is to determine that the demonstrated technology can be implemented at the necessary scale in a reasonable period of time, and to base its requirements on this understanding. 
In this case, the EPA acknowledged in 
the proposed rule, and reaffirms now, that sources will require some amount of time to install CCS. Installing CCS requires the building of capture facilities and pipelines to transport captured CO
2to sequestration sites, and 
the development of sequestration sites. This is true for both existing coal plants, which will need to retrofit CCS, and new gas plants, which must incorporate CCS into their construction planning. As the EPA explained at proposal, D.C. Circuit caselaw supports this approach.
611Moreover, the EPA has determined that there will be sufficient resources for all coal-fired power plants that are reasonably expected to be operating as of January 1, 2039, to install CCS. Nothing in the comments alters the EPA’s view of the relevant legal requirements related to the EPA’s determination of time necessary to allow for adoption of the system. 
With all of the above in mind, the 
preceding sections show that CCS technology with 90 percent capture is clearly adequately demonstrated for coal-fired steam generating units, that the 90 percent standard is achievable,
612 
and that it is reasonable for the EPA to determine that CCS can be deployed at the necessary scale in the compliance timeframe. 
(1) EPAct05 
In the proposal, the EPA noted that in 
the 2015 NSPS, the EPA had considered 
coal-fired industrial projects that had installed at least some components of CCS technology. In doing so, the EPA recognized that some of those projects had received assistance in the form of grants, loan guarantees, and Federal tax credits for investment in ‘‘clean coal technology,’’ under provisions of the Energy Policy Act of 2005 (‘‘EPAct05’’). See 80 FR 64541–42 (October 23, 2015). (The EPA refers to projects that received assistance under that legislation as ‘‘EPAct05-assisted projects.’’) The EPA further recognized that the EPAct05 included provisions that constrained how the EPA could rely on EPAct05- assisted projects in determining whether technology is adequately demonstrated for the purposes of CAA section 111.
613 
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1307(b), provides as follows: ‘‘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. . . .’’ Section 421(a) states: ‘‘No technology, or level of emission reduction, shall be treated as adequately demonstrated for purpose [sic] of section 7411 of this title, . . . solely by reason of the use of such technology, or the achievement of such emission reduction, by one or more facilities receiving assistance under section 13572(a)(1) of this title.’’ 
614In the 2015 NSPS, the EPA adopted several 
other legal interpretations of these EPAct05 provisions as well. See 80 FR 64541 (October 23, 2015). 615See Exhibit 2–18. https://netl.doe.gov/ 
projects/files/CostAndPerformanceBaseline
ForFossilEnergyPlantsVolume1BituminousCoalAndNaturalGasToElectricity_ 101422.pdf. 
616If those generators were not receiving the tax 
credit, they otherwise would cease producing power during those periods and result in a lower overall capacity factor. As noted by EIA, ‘‘Wind 
plants can offer negative prices because of the revenue stream that results from the federal production tax credit, which generates tax benefits whenever the wind plant is producing electricity, and payments from state renewable portfolio or financial incentive programs. These alternative revenue streams make it possible for wind generators to offer their wind power into the wholesale electricity market at prices lower than other generators, and even at negative prices.’’ https://www.eia.gov/todayinenergy/ detail.php?id=16831. 
617A 12-year amortization period is consistent 
with the period of time during which the IRC section 45Q tax credit can be claimed. 618See the final TSD, GHG Mitigation Measures 
for Steam Generating Units for additional details. In the 2015 NSPS, the EPA went on to 
provide a legal interpretation of those constraints. Under that legal interpretation, ‘‘these provisions [in the EPAct05] . . . preclude the EPA from relying solely on the experience of facilities that received [EPAct05] assistance, but [do] not . . . preclude the EPA from relying on the experience of such facilities in conjunction with other information.’’
614Id. at 64541–42. 
In this action, the EPA is adhering to the interpretation of these provisions that it announced in the 2015 NSPS. 
Some commenters criticized the legal 
interpretation that the EPA advanced in the 2015 NSPS, and others supported the interpretation. The EPA has responded to these comments in the Response to Comments Document, available in the docket for this rulemaking. 
ii. Costs 
The EPA has analyzed the costs of 
CCS for existing coal-fired long-term 
steam generating units, including costs for CO
2capture, transport, and 
sequestration. The EPA has determined costs of CCS for these sources are reasonable. The EPA also evaluated costs assuming shorter amortization periods. As elsewhere in this section of the preamble, costs are presented in 2019 dollars. In sum, the costs of CCS are reasonable under a variety of metrics. The costs of CCS are reasonable as compared to the costs of other controls that the EPA has required for these sources. And the costs of CCS are reasonable when looking to the dollars per ton of CO
2reduced. The 
reasonableness of CCS as an emission control is further reinforced by the fact that some sources are projected to install CCS even in the absence of any EPA rule addressing CO
2emissions—11 
GW of coal-fired EGUs install CCS in the modeling base case. 
Specifically, the EPA assessed the 
average cost of CCS for the fleet of coal- fired steam generating units with no announced retirement or gas conversion prior to 2039. In evaluating costs, the EPA accounts for the IRC section 45Q tax credit of $85/metric ton (assumes prevailing wage and apprenticeship requirements are met), a detailed discussion of which is provided in section VII.C.1.a.ii(C) of this preamble. The EPA also accounts for increases in utilization that will occur for units that apply CCS due to the incentives provided by the IRC section 45Q tax credit. In other words, because the IRC section 45Q tax credit provides a significant economic benefit, sources that apply CCS will have a strong economic incentive to increase utilization and run at higher capacity factors than occurred historically. This assumption is confirmed by the modeling, which projects that sources that install CCS run at a high capacity factor—generally, about 80 percent or even higher. The EPA notes that the NETL Baseline study assumes 85 percent as the default capacity factor assumption for coal CCS retrofits, noting that coal plants in market conditions supporting baseload operation have demonstrated the ability to operate at annual capacity factors of 85 percent or higher.
615This assumption is also 
supported by observations of wind generators who receive the IRC section 45 production tax credit who continue to operate even during periods of negative power prices.
616Therefore, the 
EPA assessed the costs for CCS retrofitted to existing coal-fired steam generating units assuming an 80 percent annual capacity factor. Assuming an 80 percent capacity factor and 12-year amortization period,
617the average costs 
of CCS for the fleet are ¥$5/ton of CO 2 
reduced or ¥$4/MWh of generation. Assuming at least a 12-year amortization period is reasonable because any unit that installs CCS and seeks to maximize its profitability will be incentivized to 
recoup the full value of the 12-year tax credit. 
Therefore for long-term coal-fired 
steam generating units—ones that operate after January 1, 2039—the costs of CCS are similar or better than the representative costs of controls detailed in section VII.C.1.a.ii(D) of this preamble (i.e., costs for SCRs and FGDs 
on EGUs of $10.60 to $18.50/MWh and the costs in the 2016 NSPS regulating GHGs for the Crude Oil and Natural Gas source category of $98/ton of CO
2e 
reduced (80 FR 56627; September 18, 2015)). 
The EPA also evaluated the costs for 
shorter amortization periods, considering the $/MWh and $/ton metrics, as well as other cost indicators, as described in section VII.C.1.a.ii.(D). Specifically, with an initial compliance date of January 1, 2032, sources operating through the end of 2039 have at least 8 years to amortize costs. For an 80 percent capacity factor and an 8-year amortization period, the average costs of CCS for the fleet are $19/ton of CO
2 
reduced or $18/MWh of generation; these costs are comparable to those costs that the EPA has previously determined to be reasonable. Sources operating through the end of 2040, 2041, and beyond (i.e., sources with 9, 10, or more 
years to amortize the costs of CCS) have even more favorable average costs per MWh and per ton of CO
2reduced. 
Sources ceasing operation by January 1, 2039, have 7 years to amortize costs. For an 80 percent capacity factor and a 7- year amortization period, the fleet average costs are $29/ton of CO
2 
reduced or $28/MWh of generation; these average costs are less comparable on a $/MWh of generation basis to those costs the EPA has previously determined to be reasonable, but substantially lower than costs the EPA has previously determined to be 
reasonable on a $/ton of CO
2reduced 
basis. The EPA further notes that the costs presented are average costs for the fleet. For a substantial amount of capacity, costs assuming a 7-year amortization period are comparable to those costs the EPA has previously determined to be reasonable on both a $/MWh basis (i.e., less than $18.50/ 
MWh) and a $/ton basis (i.e. less than 
$98/ton CO2e),
618and the EPA 
concludes that a substantial amount of capacity can install CCS at reasonable cost with a 7-year amortization 
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619As indicated in section 4.7.5 of the final TSD, 
Greenhouse Gas Mitigation Measures for Steam 
Generating Units, 24 percent of all coal-fired steam generating units in the long-term subcategory would have CCS costs below both $18.50/MWh and $98/ ton of CO
2with a 7-year amortization period (Table 
11), and that amount increases to 40 percent for those coal-fired units that, in light of their age and efficiency, are most likely to operate in the long term (and thus be subject to the CCS-based standards of performance) (Table 12). In addition, of the 9 units in the NEEDS data base that have announced plans to retire in 2039, and that therefore would have a 7-year amortization period if they installed CCS by January 1, 2032, 6 would 
have costs below both $18.50/MWh and $98/ton of CO
2. 
620The EPA determines the BSER based on 
considering information on the statutory factors, including cost, on a source category or subcategory basis. However, there may be particular sources for which, based on source-specific considerations, the cost of CCS is fundamentally different from the costs the EPA considered in making its BSER determination. If such a fundamental difference makes it unreasonable for a particular source to achieve the degree of emission limitation associated with implementing CCS with 90 percent capture, a state may provide a less stringent standard of performance (and/or longer compliance schedule, if applicable) for that source pursuant to the RULOF provisions. See section X.C.2 of this preamble for further discussion. 
621Detailed cost information, assessment of 
technology options, and demonstration of cost reasonableness can be found in the final TSD, GHG Mitigation Measures for Steam Generating Units. 622Whether an FGD and SCR or controls with 
lower costs are necessary for flue gas pretreatment prior to the CO
2capture process will in practice 
depend on the flue gas conditions of the source. 
623For additional details on CO 2transport and 
storage costs, see the final TSD, GHG Mitigation Measures for Steam Generating Units. 
624Grant, T., et al. (2019). ‘‘Quality Guidelines for 
Energy System Studies; Carbon Dioxide Transport and Storage Costs in NETL Studies.’’ National Energy Technology Laboratory. https://www.netl.doe.gov/energy-analysis/details?id=3743. 
625Grant, T., et al. ‘‘Quality Guidelines for Energy 
System Studies; Carbon Dioxide Transport and Storage Costs in NETL Studies.’’ National Energy Technology Laboratory. 2019. https://www.netl.doe.gov/energy-analysis/details?id=3743. 626National Energy Technology Laboratory 
(NETL). (2017). ‘‘FE/NETL CO 2Saline Storage Cost 
Model (2017),’’ U.S. Department of Energy, DOE/ 
NETL–2018–1871. https://netl.doe.gov/energy- 
analysis/details?id=2403. 
627Details on CO 2transportation and 
sequestration costs can be found in the final TSD, GHG Mitigation Measures for Steam Generating Units. 
628Department of Energy. ‘‘Biden-Harris 
Administration Announces $2 Billion from Bipartisan Infrastructure Law to Finance Carbon 
Dioxide Transportation Infrastructure.’’ (2022). https://www.energy.gov/articles/biden-harris- administration-announces-2-billion-bipartisan- infrastructure-law-finance. 
629Department of Energy. ‘‘Regional Direct Air 
Capture Hubs.’’ (2022). https://www.energy.gov/ oced/regional-direct-air-capture-hubs. 
630For more information, see the NETL 
announcement. https://www.netl.doe.gov/node/ 
12405. period.619Considering that a significant 
number of sources can cost reasonably 
install CCS even assuming a 7-year amortization period, the EPA concludes that sources operating in 2039 should be subject to a CCS BSER,
620and for this 
reason, is finalizing the date of January 1, 2039 as the dividing line between the medium-term and long-term subcategories. Moreover, the EPA underscores that given the strong economic incentives of the IRC section 45Q tax credit, sources that install CCS will have strong economic incentives to operate at high capacity for the full 12 years that the tax credit is available. 
As discussed in the RTC section 2.16, 
the EPA has also examined the reasonableness of the costs of this rule in additional ways: considering the total annual costs of the rule as compared to past CAA rules for the electricity sector and as compared to the industry’s annual revenues and annual capital expenditures, and considering the effects of this rule on electricity prices. Taking all of these into consideration, in addition to the cost metrics just discussed, the EPA concludes that, in general, the costs of CCS are reasonable for sources operating after January 1, 2039. 
(A) Capture Costs 
The EPA developed an independent 
engineering cost assessment for CCS 
retrofits, with support from Sargent and Lundy.
621The EPA cost analysis assumes installation of one CO 2capture 
plant for each coal-fired EGU, and that sources without SO
2controls (FGD) or 
NO Xcontrols (specifically, selective 
catalytic reduction—SCR; or selective non-catalytic reduction—SNCR) add a wet FGD and/or SCR.
622 
(B) CO 2Transport and Sequestration 
Costs 
To calculate the costs of CCS for coal- 
fired steam generating units for purposes of determining BSER as well as for EPA modeling, the EPA relied on transportation and storage costs consistent with the cost of transporting and storing CO
2from each power plant 
to the nearest saline reservoir.623For a 
power plant composed of multiple coal- fired EGUs, the EPA’s cost analysis assumes installation and operation of a single, common CO
2pipeline. 
The EPA notes that NETL has also 
developed costs for transport and storage. NETL’s ‘‘Quality Guidelines for Energy System Studies; Carbon Dioxide Transport and Sequestration Costs in NETL Studies’’ provides an estimation of transport costs based on the CO
2 
Transport Cost Model.624The CO 2 
Transport Cost Model estimates costs for a single point-to-point pipeline. Estimated costs reflect pipeline capital costs, related capital expenditures, and operations and maintenance costs.
625 
NETL’s Quality Guidelines also 
provide an estimate of sequestration costs. These costs reflect the cost of site screening and evaluation, permitting and construction costs, the cost of injection wells, the cost of injection equipment, operation and maintenance costs, pore volume acquisition expense, and long-term liability protection. Permitting and construction costs also reflect the regulatory requirements of the UIC Class VI program and GHGRP subpart RR for geologic sequestration of CO
2in deep saline formations. NETL 
calculates these sequestration costs on the basis of generic plant locations in the Midwest, Texas, North Dakota, and Montana, as described in the NETL energy system studies that utilize the coal found in Illinois, East Texas, Williston, and Powder River basins.
626 
There are two primary cost drivers for 
a CO 2sequestration project: the rate of 
injection of the CO 2into the reservoir 
and the areal extent of the CO 2plume 
in the reservoir. The rate of injection depends, in part, on the thickness of the reservoir and its permeability. Thick, permeable reservoirs provide for better injection and fewer injection wells. The areal extent of the CO
2plume depends 
on the sequestration capacity of the reservoir. Thick, porous reservoirs with a good sequestration coefficient will present a small areal extent for the CO
2 
plume and have a smaller monitoring footprint, resulting in lower monitoring costs. NETL’s Quality Guidelines model costs for a given cumulative sequestration potential.
627 
In addition, provisions in the IIJA and 
IRA are expected to significantly increase the CO
2pipeline infrastructure 
and development of sequestration sites, which, in turn, are expected to result in further cost reductions for the application of CCS at new combined cycle EGUs. The IIJA establishes a new Carbon Dioxide Transportation Infrastructure Finance and Innovation program to provide direct loans, loan guarantees, and grants to CO
2 
infrastructure projects, such as pipelines, rail transport, ships and barges.
628The IIJA also establishes a 
new Regional Direct Air Capture Hubs program that includes funds to support four large-scale, regional direct air capture hubs and more broadly support projects that could be developed into a regional or inter-regional network to facilitate sequestration or utilization.
629 
DOE is additionally implementing IIJA section 40305 (Carbon Storage Validation and Testing) through its CarbonSAFE initiative, which aims to further develop geographically widespread, commercial-scale, safe sequestration.
630The IRA increases and 
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631IRC section 39. 
632https://www.epri.com/research/products/ 
000000003002027328. 
633https://journals.sagepub.com/doi/abs/ 
10.1177/0160449X18766398. 
634DOE. Workforce Analysis of Existing Coal 
Carbon Capture Retrofits. https://www.energy.gov/ 
policy/articles/workforce-analysis-existing-coal- carbon-capture-retrofits. 635https://www.apprenticeship.gov/data-and- 
statistics. 
636https://www.apprenticeship.gov/partner- 
finder. 
637In fact, because of limits on the availability of 
the IRC section 45Q tax credit at the time of the 2015 NSPS, the EPA did not factor it into the cost calculation for partial CCS. 80 FR 64558–64 (October 23, 2015). extends the IRC section 45Q tax credit, 
discussed next. 
(C) IRC Section 45Q Tax Credit 
In determining the cost of CCS, the 
EPA is taking into account the tax credit 
provided under IRC section 45Q, as revised by the IRA. The tax credit is available at $85/metric ton ($77/ton) and offsets a significant portion of the capture, transport, and sequestration costs noted above. 
Several other aspects of the tax credit 
should be noted. A tax credit offsets tax liability dollar for dollar up to the amount of the taxpayer’s tax liability. Any credits in excess of the taxpayer’s liability are eligible to be carried back (3 years in the case of IRC section 45Q) and then carried forward up to 20 years.
631As noted above, the IRA also 
enabled additional methods to monetize tax credits in the event the taxpayer does not have sufficient tax liability, such as through credit transfer. 
The EPA has determined that it is 
likely that EGUs installing CCS will meet the 45Q prevailing wage and apprenticeship requirements. First, the requirements provide a significant economic incentive, increasing the value of the 45Q credit by five times over the base value of the credit available if the prevailing wage and apprenticeship requirements are not met. This provides a significant incentive to meet the requirements. Second, the increased cost of meeting the requirements is likely significantly less than the increase in credit value. A recent EPRI assessment found meeting the requirements for other types of power generation projects resulted in significant savings across projects,
632 
and other studies indicate prevailing wage laws and requirements for construction projects in general do not significantly affect overall construction costs.
633The EPA expects a similar 
dynamic for 45Q projects. Third, the use of registered apprenticeship programs for training new employees is generally well-established in the electric power generation sector, and apprenticeship programs are widely available to generate additional trained workers in this field.
634The overall U.S. apprentice 
market has more than doubled between 2014 and 2023, growing at an average annual rate of more than 7 percent.
635 
Additional programs support the skilled 
construction trade workforce required for CCS implementation and maintenance.
636 
As discussed in section V.C.2.c of this 
preamble, CAA section 111(a)(1) is clear that the cost that the Administrator must take into account in determining the BSER is the cost of the controls to the source. It is reasonable to take the tax credit into account because it reduces the cost of the controls to the source, which has a significant effect on the actual cost of installing and operating CCS. In addition, all sources that install CCS to meet the requirements of these final actions are eligible for the tax credit. The legislative history of the IRA makes clear that Congress was well aware that the EPA may promulgate rulemaking under CAA section 111 based on CCS and the utility of the tax credit in reducing the costs of CCUS (i.e., CCS). Rep. Frank Pallone, 
the chair of the House Energy & Commerce Committee, included a statement in the Congressional Record when the House adopted the IRA in which he explained: ‘‘The tax credit[ ] for CCUS . . . included in this Act may also figure into CAA Section 111 GHG regulations for new and existing industrial sources[.] . . . Congress anticipates that EPA may consider CCUS . . . as [a] candidate[ ] for BSER for electric generating plants ....  Further, Congress anticipates that EPA may consider the impact of the CCUS . . . tax credit[ ] in lowering the costs of [that] measure[ ].’’ 168 Cong. Rec. E879 (August 26, 2022) (statement of Rep. Frank Pallone). 
In the 2015 NSPS, in which the EPA 
determined partial CCS to be the BSER for GHGs from new coal-fired steam generating EGUs, the EPA recognized that the IRC section 45Q tax credit or other tax incentives could factor into the cost of the controls to the sources. Specifically, the EPA calculated the cost of partial CCS on the basis of cost calculations from NETL, which included ‘‘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.’’ 80 FR 64570 (October 23, 2015).
637 Similarly, in the 2015 NSPS, the EPA 
also recognized that revenues from 
utilizing captured CO 2for EOR would 
reduce the cost of CCS to the sources, although the EPA did not account for potential EOR revenues for purposes of determining the BSER. Id. At 64563–64. 
In other rules, the EPA has considered revenues from sale of the by-products of emission controls to affect the costs of the emission controls. For example, in the 2016 Oil and Gas Methane Rule, the EPA determined that certain control requirements would reduce natural gas leaks and therefore result in the collection of recovered natural gas that could be sold; and the EPA further determined that revenues from the sale of the recovered natural gas reduces the cost of controls. See 81 FR 35824 (June 3, 2016). The EPA made the same determination in the 2024 Oil and Gas Methane Rule. See 89 FR 16820, 16865 (May 7, 2024). In a 2011 action concerning a regional haze SIP, the EPA recognized that a NO
Xcontrol would 
alter the chemical composition of fly ash that the source had previously sold, so that it could no longer be sold; and as a result, the EPA further determined that the cost of the NO
Xcontrol should 
include the foregone revenues from the fly ash sales. 76 FR 58570, 58603 (September 21, 2011). In the 2016 emission guidelines for landfill gas from municipal solid waste landfills, the EPA reduced the costs of controls by accounting for revenue from the sale of electricity produced from the landfill gas collected through the controls. 81 FR 59276, 19679 (August 29, 2016). 
The amount of the IRC section 45Q 
tax credit that the EPA is taking into account is $85/metric ton for CO
2that 
is captured and geologically stored. This amount is available to the affected source as long as it meets the prevailing wage and apprenticeship requirements of IRC section 45Q(h)(3)–(4). The 
legislative history to the IRA specifically stated that when the EPA considers CCS as the BSER for GHG emissions from industrial sources in CAA section 111 rulemaking, the EPA should determine the cost of CCS by assuming that the sources would meet those prevailing wage and apprenticeship requirements. 168 Cong. Rec. E879 (August 26, 2022) (statement of Rep. Frank Pallone). If prevailing wage and apprenticeship requirements are not met, the value of the IRC section 45Q tax credit falls to $17/metric ton. The substantially higher credit available provides a considerable incentive to meeting the prevailing wage and apprenticeship requirements. 
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638The EPA used the NETL Baseline Report costs 
directly for the combustion turbine model plant 
BSER analysis. Even though these costs are in 2018 dollars, the adjustment to 2019 dollars (1.018 using the U.S. GDP Implicit Price Deflator) is well within the uncertainty range of the report and the minor adjustment would not impact the EPA’s BSER determination. 639For additional details, see https://
www.epa.gov/power-sector-modeling/ documentation-integrated-planning-model-ipm- base-case-v410. 
640For additional details, see https://
www.epa.gov/system/files/documents/2023-01/ Updated%20Summer%202021%20Reference%20Case%20Incremental%20Documentation%20for%20the%202015%20Ozone%20NAAQS%20Actions_ 0.pdf. 
641The EPA finalized the 2016 NSPS GHGs for 
the Crude Oil and Natural Gas source category at 81 FR 35824 (June 3, 2016). The EPA included cost information in the proposed rulemaking, at 80 FR 56627 (September 18, 2015). 
642Based on the 100-year global warming 
potential for methane of 25 used in the GHGRP (40 CFR 98 Subpart A, table A–1). 643Cost And Performance Baseline for Fossil 
Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity, Rev. 3 (July 2015). Note: The EPA adjusted reported costs to reflect $2022. https://www.netl.doe.gov/projects/files/ CostandPerformanceBaselineforFossilEnergyPlantsVolume1aBitCoalPCandNaturalGastoElectRev3_ 070615.pdf. 
644Cost And Performance Baseline for Fossil 
Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity, Rev. 4A (October 2022). Note: The EPA adjusted reported costs to reflect 
$2022. https://netl.doe.gov/projects/files/ 
CostAndPerformanceBaselineForFossilEnergyPlantsVolume1BituminousCoalAndNaturalGasToElectricity_ 101422.pdf. Therefore, the EPA assumes that 
investors maximize the value of the IRC section 45Q tax credit at $85/metric ton by meeting those requirements. 
(D) Comparison to Other Costs of 
Controls and Other Measures of Cost Reasonableness 
In assessing cost reasonableness for 
the BSER determination for this rule, the EPA looks at a range of cost information. As discussed in Chapter 2 of the RTC, the EPA considered the total annual costs of the rule as compared to past CAA rules for the electricity sector and as compared to the industry’s annual revenues and annual capital expenditures, and considered the effects of this rule on electricity prices. 
For each of the BSER determinations, 
the EPA also considers cost metrics that it has historically considered in assessing costs to compare the costs of GHG control measures to control costs that the EPA has previously determined to be reasonable. This includes comparison to the costs of controls at EGUs for other air pollutants, such as SO
2and NO X, and costs of controls for 
GHGs in other industries. Based on these costs, the EPA has developed two metrics for assessing the cost reasonableness of controls: the increase in cost of electricity due to controls, measured in $/MWh, and the control costs of removing a ton of pollutant, measured in $/ton CO
2e. The costs 
presented in this section of the preamble are in 2019 dollars.
638 
In different rulemakings, the EPA has 
required many coal-fired steam generating units to install and operate flue gas desulfurization (FGD) equipment—that is, wet or dry scrubbers—to reduce their SO
2 
emissions or SCR to reduce their NO X 
emissions. The EPA compares these control costs across technologies—steam generating units and combustion turbines—because these costs are indicative of what is reasonable for the power sector in general. The facts that the EPA required these controls in prior rules, and that many EGUs subsequently installed and operated these controls, provide evidence that these costs are reasonable, and as a result, the cost of these controls provides a benchmark to assess the reasonableness of the costs of the controls in this preamble. In the 2011 CSAPR (76 FR 48208; August 8, 2011), the EPA estimated the annualized 
costs to install and operate wet FGD retrofits on existing coal-fired steam generating units. Using those same cost equations and assumptions (i.e., a 63 
percent annual capacity factor—the average value in 2011) for retrofitting wet FGD on a representative 700 to 300 MW coal-fired steam generating unit results in annualized costs of $14.80 to $18.50/MWh of generation, respectively.
639In the Good Neighbor 
Plan for the 2015 Ozone NAAQS (2023 GNP), 88 FR 36654 (June 5, 2023), the EPA estimated the annualized costs to install and operate SCR retrofits on existing coal-fired steam generating units. Using those same cost equations and assumptions (including a 56 percent annual capacity factor—a representative value in that rulemaking) to retrofit SCR on a representative 700 to 300 MW coal-fired steam generating unit results in annualized costs of $10.60 to $11.80/MWh of generation, respectively.
640 
The EPA also compares costs to the 
costs for GHG controls in rulemakings for other industries. In the 2016 NSPS regulating GHGs for the Crude Oil and Natural Gas source category, the EPA found the costs of reducing methane emissions of $2,447/ton to be reasonable (80 FR 56627; September 18, 2015).
641 
Converted to a ton of CO 2e reduced 
basis, those costs are expressed as $98/ ton of CO
2e reduced.642 
The EPA does not consider either of 
these metrics, $18.50/MWh and $98/ton of CO
2e, to be bright line standards that 
distinguish between levels of control costs that are reasonable and levels that are unreasonable. But they do usefully indicate that control costs that are generally consistent with those levels of control costs should be considered reasonable. The EPA has required controls with comparable costs in prior rules for the electric power industry and the industry has successfully complied with those rules by installing and operating the applicable controls. In the 
case of the $/ton metric, the EPA has required other industries—specifically, 
the oil and gas industry—to reduce their climate pollution at this level of cost- effectiveness. In this rulemaking, the costs of the controls that the EPA identifies as the BSER generally match up well against both of these $/MWh and $/ton metrics for the affected subcategories of sources. And looking broadly at the range of cost information and these cost metrics, the EPA concludes that the costs of these rules are reasonable. 
(E) Comparison to Costs for CCS in Prior 
Rulemakings 
In the CPP and ACE Rule, the EPA 
determined that CCS did not qualify as the BSER due to cost considerations. Two key developments have led the EPA to reevaluate this conclusion: the costs of CCS technology have fallen and the extension and increase in the IRC section 45Q tax credit, as included in the IRA, in effect provide a significant 
stream of revenue for sequestered CO
2 
emissions. The CPP and ACE Rule relied on a 2015 NETL report estimating the cost of CCS. NETL has issued updated reports to incorporate the latest information available, most recently in 2022, which show significant cost reductions. The 2015 report estimated incremental levelized cost of CCS at a new pulverized coal facility relative to a new facility without CCS at $74/MWh (2022$),
643while the 2022 report 
estimated incremental levelized cost at $44/MWh (2022$).
644Additionally, the 
IRA increased the IRC section 45Q tax credit from $50/metric ton to $85/metric ton (and, in the case of EOR or certain industrial uses, from $35/metric ton to $60/metric ton), assuming prevailing wage and apprenticeship conditions are met. The IRA also enhanced the realized value of the tax credit through the elective pay (informally known as direct pay) and transferability monetization options described in section IV.E.1. The combination of lower costs and higher tax credits significantly improves the cost reasonableness of CCS for purposes 
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645DOE/NETL–2016/1796. ‘‘Eliminating the 
Derate of Carbon Capture Retrofits.’’ May 31, 2016. 
https://www.netl.doe.gov/energy-analysis/ details?id=d335ce79-84ee-4a0b-a27b- c1a64edbb866. 646Section XI.A of this preamble provides 
additional information on the NSR program and how it relates to the NSPS and emission guidelines. of determining whether it qualifies as 
the BSER. 
iii. Non-Air Quality Health and 
Environmental Impact and Energy Requirements 
The EPA considered non-GHG 
emissions impacts, the water use impacts, the transport and sequestration of captured CO
2, and energy 
requirements resulting from CCS for steam generating units. As discussed below, where the EPA has found potential for localized adverse consequences related to non-air quality health and environmental impacts or energy requirements, the EPA also finds that protections are in place to mitigate those risks. Because the non-air quality health and environmental impacts are closely related to the energy requirements, we discuss the latter first. 
(A) Energy Requirements 
For a steam generating unit with 90 
percent amine-based CO
2capture, 
parasitic/auxiliary energy demand 
increases and the net power output decreases. In particular, the solvent regeneration process requires heat in the form of steam and CO
2compression 
requires a large amount of electricity. Heat and power for the CO
2capture 
equipment can be provided either by using the steam and electricity produced by the steam generating unit or by an auxiliary cogeneration unit. However, any auxiliary source of heat and power is part of the ‘‘designated facility,’’ along with the steam generating unit. The standards of performance apply to the designated facility. Thus, any CO
2emissions from 
the connected auxiliary equipment need to be captured or they will increase the facility’s emission rate. 
Using integrated heat and power can 
reduce the capacity (i.e., the amount of 
electricity that a unit can distribute to the grid) of an approximately 474 MW- net (501 MW-gross) coal-fired steam generating unit without CCS to approximately 425 MW-net with CCS and contributes to a reduction in net efficiency of 23 percent.
645For retrofits 
of CCS on existing sources, the 
ductwork for flue gas and piping for heat integration to overcome potential spatial constraints are a component of efficiency reduction. The EPA notes that slightly greater efficiency reductions than in the 2016 NETL retrofit report are assumed for the BSER cost analyses, as detailed in the final TSD, GHG Mitigation Measures for Steam 
Generating Units, available in the docket. Despite decreases in efficiency, IRC section 45Q tax credit provides an incentive for increased generation with full operation of CCS because the amount of revenue from the tax credit is based on the amount of captured and 
sequestered CO
2emissions and not the 
amount of electricity generated. In this final action, the Agency considers the energy penalty to not be unreasonable and to be relatively minor compared to the benefits in GHG reduction of CCS. 
(B) Non-GHG Emissions 
As a part of considering the non-air 
quality health and environmental 
impacts of CCS, the EPA considered the potential non-GHG emission impacts of CO
2capture. The EPA recognizes that 
amine-based CO 2capture can, under 
some circumstances, result in the increase in emission of certain co- pollutants at a coal-fired steam generating unit. However, there are protections in place that can mitigate these impacts. For example, as discussed below, CCS retrofit projects with co-pollutant increases may be subject to preconstruction permitting under the New Source Review (NSR) program, which could require the source to adopt emission limitations based on applicable NSR requirements. Sources obtaining major NSR permits would be required to either apply Lowest Achievable Emission Rate (LAER) and fully offset any anticipated increases in criteria pollutant emissions (for their nonattainment pollutants) or apply Best Available Control Technology (BACT) and demonstrate that its emissions of criteria pollutants will not cause or contribute to a violation of applicable National Ambient Air Quality Standards (for their attainment pollutants).
646The EPA 
expects facility owners, states, permitting authorities, and other responsible parties will use these protections to address co-pollutant impacts in situations where individual units use CCS to comply with these emission guidelines. 
The EPA also expects that the 
meaningful engagement requirements discussed in section X.E.1.b.i of this preamble will ensure that all interested stakeholders, including community members who might be adversely impacted by non-GHG pollutants, will have an opportunity to raise this concern with states and permitting authorities. Additionally, state permitting authorities are, in general, 
required to provide notice and an opportunity for public comment on construction projects that require NSR permits. This provides additional opportunities for affected stakeholders to engage in that process, and it is the EPA’s expectation that the responsible authorities will consider these concerns and take full advantage of existing protections. Moreover, the EPA through its regional offices is committed to thoroughly review draft NSR permits associated with CO
2capture projects 
and provide comments as necessary to state permitting authorities to address any concerns or questions with regard to the draft permit’s consideration and treatment of non-GHG pollutants. 
In the following discussion, the EPA 
describes the potential emissions of non-GHG pollutants resulting from installation and operation of CO
2 
capture plants, the protections in place such as the controls and processes for mitigating those emissions, as well as regulations and permitting that may require review and implementation of those controls. The EPA first discusses these issues in relation to criteria air pollutants and precursor pollutants (SO
2, NO X, and PM), and subsequently 
provides details regarding hazardous air pollutants (HAPs) and volatile organic compounds (VOCs). 
Operation of an amine-based CO
2 
capture plant on a coal-fired steam generating unit can impact the emission of criteria pollutants from the facility, including SO
2and PM, as well as 
precursor pollutants, like NO X. Sources 
installing CCS may operate more due to the incentives provided by the IRC section 45Q tax credit, and increased utilization would—all else being equal—result in increases in SO
2, PM, 
and NO X. However, certain impacts are 
mitigated by the flue gas conditioning required by the CO
2capture process and 
by other control equipment that the units already have or may need to install to meet other CAA requirements. Substantial flue gas conditioning, particularly to remove SO
2and PM, is 
critical to limiting solvent degradation and maintaining reliable operation of the capture plant. To achieve the necessary limits on SO
2levels in the 
flue gas for the capture process, steam generating units will need to add an FGD scrubber, if they do not already have one, and will usually need an additional polishing column (i.e., quencher), thereby further reducing the emission of SO
2.A wet FGD column and 
a polishing column will also reduce the emission rate of PM. Additional 
improvements in PM removal may also be necessary to reduce the fouling of 
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647As of September 21, 2023, the Good Neighbor 
Plan ‘‘Group 3’’ ozone-season NO Xcontrol program 
for power plants is being implemented in the 
following states: Illinois, Indiana, Maryland, Michigan, New Jersey, New York, Ohio, Pennsylvania, Virginia, and Wisconsin. Pursuant to court orders staying the Agency’s FIP Disapproval action as to the following states, the EPA is not currently implementing the Good Neighbor Plan ‘‘Group 3’’ ozone-season NO
Xcontrol program for 
power plants in the following states: Alabama, Arkansas, Kentucky, Louisiana, Minnesota, Mississippi, Missouri, Nevada, Oklahoma, Texas, Utah, and West Virginia. 648Sharma, S., Azzi, M., ‘‘A critical review of 
existing strategies for emission control in the monoethanolamine-based carbon capture process and some recommendations for improved strategies,’’ Fuel, 121, 178 (2014). 
649Mertens, J., et al., ‘‘Understanding 
ethanolamine (MEA) and ammonia emissions from amine-based post combustion carbon capture: Lessons learned from field tests,’’ Int’l J. of GHG Control, 13, 72 (2013). 
650U.S. Department of Energy (DOE). Pathways to 
Commercial Liftoff: Carbon Management. https://liftoff.energy.gov/wp-content/uploads/2023/04/ 20230424-Liftoff-Carbon-Management-vPUB_update.pdf. other components (e.g., heat exchangers) 
of the capture process, including 
upgrades to existing PM controls or, where appropriate, the inclusion of various wash stages to limit fly ash carry-over to the CO
2removal system. 
Although PM emissions from the steam generating unit may be reduced, PM 
emissions may occur from cooling towers for those sources using wet cooling for the capture process. For some sources, a WESP may be necessary to limit the amount of aerosols in the flue gas prior to the CO
2capture 
process. Reducing the amount of aerosols to the CO
2absorber will also 
reduce emissions of the solvent out of the top of the absorber. Controls to limit emission of aerosols installed at the outlet of the absorber could be considered, but could lead to higher pressure drops. Thus, emission increases of SO
2and PM would be 
reduced through flue gas conditioning and other system requirements of the CO
2capture process, and NSR 
permitting would serve as an added backstop to review remaining SO
2and 
PM increases for mitigation. 
NO Xemissions can cause solvent 
degradation and nitrosamine formation, depending on the chemical structure of the solvent. Limits on NO
Xlevels of the 
flue gas required to avoid solvent degradation and nitrosamine formation in the CO
2scrubber vary. For most 
units, the requisite limits on NO Xlevels 
to assure that the CO 2capture process 
functions properly may be met by the existing NO
Xcombustion controls. 
Other units may need to install SCR to achieve the required NOx level. Most existing coal-fired steam generating units either already have SCR or will be covered by final Federal Implementation Plan (FIP) requirements regulating interstate transport of NO
X 
(as ozone precursors) from EGUs. See 88 FR 36654 (June 5, 2023).
647For units 
not otherwise required to have SCR, an increase in utilization from a CO
2 
capture retrofit could result in increased NO
Xemissions at the source that, 
depending on the quantity of the emissions increase, may trigger major NSR permitting requirements. Under this scenario, the permitting authority 
may determine that the NSR permit requires the installation of SCR for those units, based on applying the control technology requirements of major NSR. Alternatively, a state could, as part of its state plan, develop enforceable conditions for a source expected to trigger major NSR that would effectively limit the unit’s ability to increase its emissions in amounts that would trigger major NSR. Under this scenario, with no major NSR requirements applying due to the limit on the emissions increase, the permitting authority may conclude for the minor NSR permit that installation of SCR is not required for the units and the source is to minimize its NO
Xemission increases using other 
techniques. Finally, a source with some lesser increase in NO
Xemissions may 
not trigger major NSR to begin with and, as with the previous scenario, the permitting authority would determine the NO
Xcontrol requirements pursuant 
to its minor NSR program requirements. 
Recognizing that potential emission 
increases of SO 2, PM, and NO Xfrom 
operating a CO 2capture process are an 
area of concern for stakeholders, the EPA plans to review and update as needed its guidance on NSR permitting, specifically with respect to BACT determinations for GHG emissions and consideration of co-pollutant increases from sources installing CCS. In its analysis to support this final action, the EPA accounted for controlling these co- pollutant increases by assuming that coal-fired units that install CCS would be required to install SCR and/or FGD if they do not already have those controls installed. The costs of these controls are included in the total program compliance cost estimates through IPM modeling, as well as in the 
BSER cost calculations. 
An amine-based CO
2capture plant 
can also impact emissions of HAP and VOC (as an ozone precursor) from the coal-fired steam generating unit. Degradation of the solvent can produce HAP, and organic HAP and amine solvent emissions from the absorber would contribute to VOC emissions out of the top of the CO
2absorber. A 
conventional multistage water or acid wash and mist eliminator (demister) at the exit of the CO
2scrubber is effective 
at removal of gaseous amine and amine degradation products (e.g., nitrosamine) 
emissions.
648 649 The DOE’s Carbon Management Pathway report notes that 
monitoring and emission controls for such degradation products are currently part of standard operating procedures for amine-based CO
2capture systems.650 
Depending on the solvent properties, different amounts of aldehydes including acetaldehyde and formaldehyde may form through oxidative processes, contributing to total HAP and VOC emissions. While a water wash or acid wash can be effective at limiting emission of amines, a separate system of controls would be required to reduce aldehyde emissions; however, the low temperature and likely high water vapor content of the gas emitted out of absorber may limit the applicability of catalytic or thermal oxidation. Other controls (e.g., electrochemical, ultraviolet) common to water treatment could be considered to reduce the loading of copollutants in the water wash section, although their efficacy is still in development and it is possible that partial treatment could result in the formation of additional degradation products. Apart from these potential controls, any increase in VOC emissions from a CCS retrofit project 
would be mitigated through NSR permitting. As such VOC increases are not expected to be large enough to trigger major NSR requirements, they would likely be reviewed and addressed under a state’s minor NSR program. 
There is one nitrosamine that is a 
listed HAP regulated under CAA section 112. Carbon capture systems that are themselves a major source of HAP should evaluate the applicability of CAA section 112(g) and conduct a case- by-case MACT analysis if required, to establish MACT for any listed HAP, including listed nitrosamines, formaldehyde, and acetaldehyde. Because of the differences in the formation and effectiveness of controls, such a case-by-case MACT analysis should evaluate the performance of controls for nitrosamines and aldehydes separately, as formaldehyde or acetaldehyde may not be a suitable surrogate for amine and nitrosamine emissions. However, measurement of nitrosamine emissions may be challenging when the concentration is low (e.g., less than 1 part per billion, dry 
basis). 
HAP emissions from the CO
2capture 
plant will depend on the flue gas 
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651DCC East PTC Application. https://
ceris.deq.nd.gov/ext/nsite/map/results/detail/- 
8992368000928857057/documents. 65240 CFR 51.165(a)(1)(i) and (ii); 40 CFR 
51.166(b)(5) and (6). 
653The EPA has issued guidance to clarify these 
regulatory criteria of stationary source determination. See https://www.epa.gov/nsr/single- source-determination. 654DOE/NETL–2016/1796. ‘‘Eliminating the 
Derate of Carbon Capture Retrofits.’’ May 31, 2016. https://www.netl.doe.gov/energy-analysis/ details?id=e818549c-a565-4cbc-94db- 442a1c2a70a9. 
655International CCS Knowledge Centre. The 
Shand CCS Feasibility Study Public Report. https:// 
Continued conditions, solvent, size of the source, 
and process design. The air permit application for Project Tundra
651 
includes potential-to-emit (PTE) values for CAA section 112 listed HAP specific to the 530 MW-equivalent CO
2capture 
plant, including emissions of 1.75 tons per year (TPY) of formaldehyde (CASRN 50–00–0), 32.9 TPY of acetaldehyde (CASRN 75–07–0), 0.54 TPY of acetamide (CASRN 60–35–5), 0.018 TPY of ethylenimine (CASRN 151–56–4), 
0.044 TPY of N-nitrosodimethylamine (CASRN 62–75–9), and 0.018 TPY of N- nitrosomorpholine (CASRN 59–89–2). Additional PTE other species that are not CAA section 112 listed HAP were also included, including 0.022 TPY of N-nitrosodiethylamine (CASRN 55–18– 5). PTE values for other CO
2capture 
plants may differ. To comply with North Dakota Department of Environmental Quality (ND–DEQ) Air Toxics Policy, an air toxics assessment was included in the permit application. According to that assessment, the total maximum individual carcinogenic risk was 1.02E– 6 (approximately 1-in-1 million, below the ND–DEQ threshold of 1E–5) primarily driven by N- nitrosodiethylamine and N- nitrosodimethylamine. The hazard index value was 0.022 (below the ND– DEQ threshold of 1), with formaldehyde being the primary driver. Results of air toxics risk assessments for other facilities would depend on the emissions from the facility, controls in place, stack height and flue gas conditions, local ambient conditions, and the relative location of the exposed population. 
Emissions of amines and nitrosamines 
at Project Tundra are controlled by the water wash section of the absorber column. According to the permit to construct issued by ND–DEQ, limits for formaldehyde and acetaldehyde will be established based on testing after initial operation of the CO
2capture plant. The 
permit does not include a mechanism for establishing limits for nitrosamine emissions, as they may be below the limit of detection (less than 1 part per billion, dry basis). 
The EPA received several comments 
related to the potential for non-GHG emissions associated with CCS. Those comments and the EPA’s responses are as follows. 
Comment: Some commenters noted 
that there is a potential for increases in co-pollutants when operating amine- based CO
2capture systems. One 
commenter requested that the EPA proactively regulate potential 
nitrosamine emissions. 
Response: The EPA carefully 
considered these concerns as it finalized its determination of the BSERs for these rules. The EPA takes these concerns seriously, agrees that any impacts to local and downwind communities are important to consider and has done so as part of its analysis discussed at section XII.E. While the EPA acknowledges that, in some circumstances, there is potential for some non-GHG emissions to increase, there are several protections in place to help mitigate these impacts. The EPA believes that these protections, along with the meaningful engagement of potentially affected communities, can facilitate a responsible deployment of this technology that mitigates the risk of any adverse impacts. 
There is one nitrosamine that is a 
listed HAP under CAA section 112 (N- Nitrosodimethylamine; CASRN 62–75– 9). Other nitrosamines would have to be listed before the EPA could establish regulations limiting their emission. Furthermore, carbon capture systems are themselves not a listed source category of HAP, and the listing of a source category under CAA section 112 would first require some number of the sources to exist for the EPA to develop MACT standards. However, if a new CO
2capture facility were to be 
permitted as a separate entity (rather than as part of the EGU) then it may be subject to case-by-case MACT under section 112(g), as detailed in the preceding section of this preamble. 
Comment: Commenters noted that a 
source could attempt to permit CO
2 
facilities as separate entities to avoid triggering NSR for the EGU. 
Response: For the CO
2capture plant 
to be permitted as a separate entity, the source would have to demonstrate to the state permitting authority that the EGU and CO
2capture plant are not a single 
stationary source under the NSR program. In determining what constitutes a stationary source, the EPA’s NSR regulations set forth criteria that are to be used when determining the scope of a ‘‘stationary source.’’
652 
These criteria require the aggregation of different pollutant-emitting activities if 
they (1) belong to the same industrial grouping as defined by SIC codes, (2) are located on contiguous or adjacent properties, and (3) are under common control.
653In the case of an EGU and CO 2capture plant that are collocated, to 
permit them as separate sources they 
should not be under common control or not be defined by the same industrial grouping. 
The EPA would anticipate that, in 
most cases, the operation of the EGU and the CO
2capture plant will 
intrinsically affect one another— typically steam, electricity, and the flue gas of the EGU will be provided to the CO
2capture plant. Conditions of the 
flue gas will affect the operation of the CO
2capture plant, including its 
emissions, and the steam and electrical 
load will affect the operation of the EGU. Moreover, the emissions from the EGU will be routed through the CO
2 
capture system and emitted out of the top of the CO
2absorber. Even if the EGU 
and CO 2capture plant are owned by 
separate entities, the CO 2capture plant 
is likely to be on or directly adjacent to land owned by the owners of the EGU and contractual obligations are likely to exist between the two owners. While each of these individual factors may not ultimately determine the outcome of whether two nominally-separate facilities should be treated as a single stationary source for permitting purposes, the EPA expects that in most cases an EGU and its collocated CO
2 
capture plant would meet each of the aforementioned NSR regulatory criteria necessary to make such a determination. Thus, the EPA generally would not expect an EGU and its CO
2capture plant 
to be permitted as separate stationary sources. 
(C) Water Use 
Water consumption at the plant 
increases when applying carbon 
capture, due to solvent water makeup and cooling demand. Water consumption can increase by 36 percent on a gross basis.
654A separate cooling 
water system dedicated to a CO 2capture 
plant may be necessary. However, the amount of water consumption depends on the design of the cooling system. For example, the cooling system cited in the CCS feasibility study for SaskPower’s Shand Power station would rely entirely on water condensed from the flue gas and thus would not require any increase in external water consumption—all while achieving higher capture rates at lower cost than Boundary Dam Unit 3.
655Regions with limited water supply 
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ccsknowledge.com/pub/Publications/Shand_ CCS_
Feasibility_ Study_ Public_ Report_ Nov2018_ (2021- 
05-12).pdf. 
656NARUC. (2023). Onshore U.S. Carbon Pipeline 
Deployment: Siting, Safety. and Regulation. 
Prepared by Public Sector Consultants for the National Association of Regulatory Utility Commissioners (NARUC). June 2023. https://pubs.naruc.org/pub/F1EECB6B-CD8A-6AD4-B05B- 
E7DA0F12672E. 
657Congressional Research Service. 2022. Carbon 
Dioxide Pipelines: Safety Issues, CRS Reports, June 
3, 2022. https://crsreports.congress.gov/product/ pdf/IN/IN11944. 658DOE/NETL–2016/1796. ‘‘Eliminating the 
Derate of Carbon Capture Retrofits.’’ May 31, 2016. 
https://www.netl.doe.gov/energy-analysis/ details?id=e818549c-a565-4cbc-94db- 442a1c2a70a9. 
659Intergovernmental Panel on Climate Change. 
(2005). Special Report on Carbon Dioxide Capture and Storage. may therefore rely on dry or hybrid 
cooling systems. Therefore, the EPA considers the water use requirements to be manageable and does not expect this consideration to preclude coal-fired power plants generally from being able to install and operate CCS. 
(D) CO
2Capture Plant Siting 
With respect to siting considerations, 
CO 2capture systems have a sizeable 
physical footprint and a consequent 
land-use requirement. One commenter cited their analysis showing that, for a subset of coal-fired sources greater than 300 MW, 98 percent (154 GW of the existing fleet) have adjacent land available within 1 mile of the facility, and 83 percent have adjacent land available within 100 meters of the facility. Furthermore, the cited analysis did not include land available onsite, and it is therefore possible there is even greater land availability for siting capture equipment. Qualitatively, some commenters claimed there is limited land available for siting CO
2capture 
plants adjacent to coal-fired steam generating units. However, those commenters provided no data or analysis to support their assertion. The EPA has reviewed the analysis provided by the first commenter, and the approach, methods, and assumptions are logical. Further, the EPA has reviewed the available information, including the location of coal-fired steam generating units and visual inspection of the associated maps and plots. Although in some cases longer duct runs may be required, this would not preclude coal-fired power plants generally from being able to install and operate CCS. Therefore, the EPA has concluded that siting and land-use requirements for CO
2capture are not 
unreasonable. 
(E) Transport and Geologic 
Sequestration 
As noted in section VII.C.1.a.i(C) of 
this preamble, PHMSA oversight of supercritical CO
2pipeline safety 
protects against environmental release during transport. The vast majority of CO
2pipelines have been operating 
safely for more than 60 years. PHMSA reported a total of 102 CO
2pipeline 
incidents between 2003 and 2022, with one injury (requiring in-patient hospitalization) and zero fatalities.
656In the past 20 years, 500 million metric 
tons of CO 2moved through over 5,000 
miles of CO 2pipelines with zero 
incidents involving fatalities.657 
PHMSA initiated a rulemaking in 2022 to develop and implement new measures to strengthen its safety oversight of supercritical CO
2pipelines. 
Furthermore, UIC Class VI and Class II regulations under the SDWA, in tandem with GHGRP subpart RR and subpart VV requirements, ensure the protection of USDWs and the security of geologic sequestration. The EPA believes these protections constitute an effective framework for addressing potential health and environmental concerns related to CO
2transportation and 
sequestration, and the EPA has taken this regulatory framework into consideration in determining that CCS represents the BSER for long-term steam EGUs. 
(F) Impacts on the Energy Sector 
Additionally, the EPA considered the 
impacts on the power sector, on a 
nationwide and long-term basis, of determining CCS to be the BSER for long-term coal-fired steam generating units. In this final action, the EPA considers that designating CCS as the BSER for these units would have limited and non-adverse impacts on the long- term structure of the power sector or on the reliability of the power sector. Absent the requirements defined in this action, the EPA projects that 11 GW of coal-fired steam generating units would apply CCS by 2035 and an additional 30 GW of coal-fired steam generating units, without controls, would remain in operation in 2040. Designating CCS to be the BSER for existing long-term coal- fired steam generating units may result in more of the coal-fired steam generating unit capacity applying CCS. The time available before the compliance deadline of January 1, 2032, provides for adequate resource planning, including accounting for the downtime necessary to install the CO
2 
capture equipment at long-term coal- fired steam generating units. For the 12- year duration that eligible EGUs earn the IRC section 45Q tax credit, long- term coal-fired steam generating units are anticipated to run at or near base load conditions in order to maximize the amount of tax credit earned through IRC section 45Q. Total generation from coal-fired steam generating units in the medium-term subcategory would gradually decrease over an extended period of time through 2039, subject to the commitments those units have chosen to adopt. Additionally, for the long-term units applying CCS, the EPA has determined that the increase in the 
annualized cost of generation is reasonable. Therefore, the EPA concludes that these elements of BSER can be implemented while maintaining a reliable electric grid. A broader discussion of reliability impacts of these final rules is available in section XII.F of this preamble. 
iv. Extent of Reductions in CO
2 
Emissions 
CCS is an extremely effective 
technology for reducing CO 2emissions. 
As of 2021, coal-fired power plants are 
the largest stationary source of GHG emissions by sector. Furthermore, emission rates (lb CO
2/MWh-gross) from 
coal-fired sources are almost twice those of natural gas-fired combined cycle units, and sources operating in the long- term have the more substantial emissions potential. CCS can be applied to coal-fired steam generating units at the source to reduce the mass of CO
2 
emissions by 90 percent or more. Increased steam and power demand have a small impact on the reduction in emission rate (i.e., lb CO
2/MWh-gross) 
that occurs with 90 percent capture. According to the 2016 NETL Retrofit report, 90 percent capture will result in emission rates that are 88.4 percent lower on a lb/MWh-gross basis and 87.1 percent lower on a lb/MWh-net basis compared to units without capture.
658 
After capture, CO 2can be transported 
and securely sequestered.659Although 
steam generating units with CO 2capture 
will have an incentive to operate at higher utilization because the cost to install the CCS system is largely fixed and the IRC section 45Q tax credit increases based on the amount of CO
2 
captured and sequestered, any increase in utilization will be far outweighed by the substantial reductions in emission rate. 
v. Promotion of the Development and 
Implementation of Technology 
The EPA considered the potential 
impact on technology advancement of designating CCS as the BSER for long- term coal-fired steam generating units, and in this final rule, the EPA considers 
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that designating CCS as the BSER will 
provide for meaningful advancement of CCS technology. As indicated above, the EPA’s IPM modeling indicates that 11 GW of coal-fired power plants install CCS and generate 76 terawatt-hours (TWh) per year in the base case, and that another 8 GW of plants install CCS and generate another 57 TWh per year in the policy case. In this manner, this rule advances CCS technology more widely throughout the coal-fired power sector. As discussed in section VIII.F.4.c.iv(G) of this preamble, this rule advances CCS technology for new combined cycle base load combustion turbines, as well. It is also likely that this rule supports advances in the technology in other industries. 
vi. Comparison With 2015 NSPS For 
Newly Constructed Coal-Fired EGUs 
In the 2015 NSPS, the EPA 
determined that the BSER for newly constructed coal-fired EGUs was based on CCS with 16 to 23 percent capture, based on the type of coal combusted, and consequently, the EPA promulgated standards of performance of 1,400 lb CO
2/MWh-g. 80 FR 64512 (table 1), 
64513 (October 23, 2015). The EPA made those determinations based on the costs of CCS at the time of that rulemaking. In general, those costs were significantly higher than at present, due to recent technology cost declines as well as related policies, including the IRC section 45Q tax credit for CCS, which were not available at that time for purposes of consideration during the development of the NSPS. Id. at 64562 
(table 8). Based on of these higher costs, the EPA determined that 16–23 percent capture qualified as the BSER, rather than a significantly higher percentage of capture. Given the substantial differences in the cost of CCS during the time of the 2015 NSPS and the present time, the capture percentage of the 2015 NSPS necessarily differed from the capture percentage in this final action, and, by the same token, the associated degree of emission limitation and resulting standards of performance necessarily differ as well. If the EPA had strong evidence to indicate that new coal-fired EGUs would be built, it would propose to revise the 2015 NSPS to align the BSER and emissions standards to reflect the new information regarding the costs of CCS. Because there is no evidence to suggest that there are any firm plans to build new coal-fired EGUs in the future, however, it is not at 
present a good use of the EPA’s limited resources to propose to update the new source standard to align with the existing source standard finalized today. While the EPA is not revising the new source standard for new coal-fired EGUs 
in this action, the EPA is retaining the ability to propose review in the future. 
vii. Requirement That Source Must 
Transfer CO
2to an Entity That Reports 
Under the Greenhouse Gas Reporting Program 
The final rule requires that EGUs that 
capture CO
2in order to meet the 
applicable emission standard report in accordance with the GHGRP requirements of 40 CFR part 98, including subpart PP. GHGRP subpart RR and subpart VV requirements provide the monitoring and reporting mechanisms to quantify CO
2storage and 
to identify, quantify, and address potential leakage. Under existing GHGRP regulations, sequestration wells permitted as Class VI under the UIC program are required to report under subpart RR. Facilities with UIC Class II wells that inject CO
2to enhance the 
recovery of oil or natural gas can opt-in 
to reporting under subpart RR by submitting and receiving approval for a monitoring, reporting, and verification (MRV) plan. Subpart VV applies to facilities that conduct enhanced recovery using ISO 27916 to quantify geologic storage unless they have opted to report under subpart RR. For this rule, if injection occurs on site, the EGU must report data accordingly under 40 CFR part 98 subpart RR or subpart VV. If the CO
2is injected off site, the EGU 
must transfer the captured CO 2to a 
facility that reports in accordance with the requirements of 40 CFR part 98, subpart RR or subpart VV. They may also transfer the captured CO
2to a 
facility that has received an innovative technology waiver from the EPA. 
b. Options Not Determined To Be the 
BSER for Long-Term Coal-Fired Steam Generating Units 
In this section, we explain why CCS 
at 90 percent capture best balances the BSER factors and therefore why the EPA has determined it to be the best of the possible options for the BSER. 
i. Partial Capture CCS 
Partial capture for CCS was not 
determined to be BSER because the 
emission reductions are lower and the costs would, in general, be higher. As discussed in section IV.B of this preamble, individual coal-fired power plants are by far the highest-emitting plants in the nation, and the coal-fired power plant sector is higher-emitting than any other stationary source sector. CCS at 90 percent capture removes very high absolute amounts of emissions. Partial capture CCS would fail to capture large quantities of emissions. With respect to costs, designs for 90 percent capture in general take greater advantage of economies of scale. Eligibility for the IRC section 45Q tax credit for existing EGUs requires design capture rates equivalent to 75 percent of a baseline emission rate by mass. Even assuming partial capture rates meet that definition, lower capture rates would receive fewer returns from the IRC section 45Q tax credit (since these are tied to the amount of carbon sequestered, and all else being equal lower capture rates would result in lower amounts of sequestered carbon) and costs would thereby be higher. 
ii. Natural Gas Co-Firing 
(A) Reasons Why Not Selected as BSER 
As discussed in section VII.C.2, the 
EPA is determining 40 percent natural 
gas co-firing to qualify as the BSER for the medium-term subcategory of coal- fired steam generating units. This subcategory consists of units that will permanently cease operation by January 1, 2039. In making this BSER determination, the EPA analyzed the ability of all existing coal-fired units— not only medium-term units—to install and operate 40 percent co-firing. As a result, all of the determinations concerning the criteria for BSER that the EPA made for 40 percent co-firing apply to all existing coal-fired units, including the units in the long-term subcategory. For example, 40 percent co-firing is adequately demonstrated for the long- term subcategory, and has reasonable energy requirements and reasonable non-air quality environmental impacts. It would also be of reasonable cost for the long-term subcategory. Although the capital expenditure for natural gas co- firing is lower than CCS, the variable costs are higher. As a result, the total costs of natural gas co-firing, in general, are higher on a $/ton basis and not substantially lower on a $/MWh basis, than for CCS. Were co-firing the BSER for long-term units, the cost that industry would bear might then be considered similar to the cost for CCS. In addition, the GHG Mitigation Measures TSD shows that all coal-fired units would be able to achieve the requisite infrastructure build-out and obtain sufficient quantities of natural gas to comply with standards of performance based on 40 percent co- firing by January 1, 2030. 
The EPA is not selecting 40 percent 
natural gas co-firing as the BSER for the long-term subcategory, however, because it requires substantially less emission reductions at the unit-level than 90 percent capture CCS. Natural gas co-firing at 40 percent of the heat 
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660IEAGHG Report 2015–06. Integrated Carbon 
Capture and Storage Project at SaskPower’s 
Boundary Dam Power Station. August 2015. https:// 
ieaghg.org/publications/technical-reports/reports- 
list/9-technical-reports/935-2015-06-integrated-ccs- project-at-saskpower-s-boundary-dam-power- station. 661Bottoms, R.R. Process for Separating Acidic 
Gases (1930) United States patent application. 
United States Patent US1783901A; Allen, A.S. and Arthur, M. Method of Separating Carbon Dioxide from a Gas Mixture (1933) United States Patent Application. United States Patent US1934472A. 
662U.S. Department of Transportation, Pipeline 
and Hazardous Material Safety Administration, ‘‘Hazardous Annual Liquid Data.’’ 2022. https://www.phmsa.dot.gov/data-and-statistics/pipeline/ gas-distribution-gas-gathering-gas-transmission- hazardous-liquids. 
663US EPA. GHGRP. https://www.epa.gov/ 
ghgreporting/supply-underground-injection-and- 
geologic-sequestration-carbon-dioxide. 
664Carbon Capture and Storage in the United 
States. CBO. December 13, 2023. https://www.cbo.gov/publication/59345. 
665Dooley, J.J., et al. (2009). ‘‘An Assessment of 
the Commercial Availability of Carbon Dioxide Capture and Storage Technologies as of June 2009.’’ U.S. DOE, Pacific Northwest National Laboratory, under Contract DE–AC05–76RL01830. input to the steam generating unit 
achieves 16 percent reductions in emission rate at the stack, while CCS achieves an 88.4 percent reduction in emission rate. As discussed in section IV.B of this preamble, individual coal- fired power plants are by far the highest- emitting plants in the nation, and the coal-fired power plant sector is higher- emitting than any other stationary source sector. Because the unit-level emission reductions achievable by CCS are substantially greater, and because CCS is of reasonable cost and matches up well against the other BSER criteria, the EPA did not determine natural gas co-firing to be BSER for the long-term subcategory although, under other circumstances, it could be. Determining BSER requires the EPA to select the ‘‘best’’ of the systems of emission reduction that are adequately demonstrated, as described in section V.C.2; in this case, there are two systems of emission reduction that match up well against the BSER criteria, but based on weighing the criteria together, and in light of the substantially greater unit- level emission reductions from CCS, the EPA has determined that CCS is a better system of emission reduction than co- firing for the long-term subcategory. 
The EPA notes that if a state 
demonstrates that a long-term coal-fired steam generating unit cannot install and operate CCS and cannot otherwise reasonably achieve the degree of emission limitation that the EPA has 
determined based on CCS, following the process the EPA has specified in its applicable regulations for consideration of RULOF, the state would evaluate natural gas co-firing as a potential basis for establishing a less stringent standard of performance, as detailed in section X.C.2 of this document. 
iii. Heat Rate Improvements 
Heat rate improvements were not 
considered to be BSER for long-term 
steam generating units because the achievable reductions are very low and may result in a rebound effect whereby total emissions from the source increase, as detailed in section VII.D.4.a of this preamble. 
Comment: One commenter requested 
that HRI be considered as BSER in addition to CCS, so that long-term sources would be required to achieve reductions in emission rate consistent with performing HRI and adding CCS with 90 percent capture to the source. 
Response: As described in section 
VII.D.4.a, the reductions from HRI are very low and many sources have already made HRI, so that additional reductions are not available. It is possible that a source installing CO
2capture will make efficiency improvements as a matter of best practices. For example, Boundary Dam Unit 3 made upgrades to the existing steam generating unit when CCS was installed, including installing a new steam turbine.
660However, the 
reductions from efficiency improvements would not be additive to the reductions from CCS because of the impact of the CO
2capture plant on the 
efficiency of source due to the required steam and electricity load of the capture plant. 
c. Conclusion 
Coal-fired EGUs remain the largest 
stationary source of dangerous CO
2 
emissions. The EPA is finalizing CCS at 
a capture rate of 90 percent as the BSER for long-term coal-fired steam generating units because this system satisfies the criteria for BSER as summarized here. CCS at a capture rate of 90 percent as the BSER for long-term coal-fired steam generating units is adequately demonstrated, as indicated by the facts that it has been operated at scale, is widely applicable to these sources, and that there are vast sequestration opportunities across the continental U.S. Additionally, accounting for recent technology cost declines as well as policies including the tax credit under IRC section 45Q, the costs for CCS are reasonable. Moreover, any adverse non- air quality health and environmental impacts and energy requirements of CCS, including impacts on the power sector on a nationwide basis, are limited and can be effectively avoided or mitigated. In contrast, co-firing 40 percent natural gas would achieve far fewer emission reductions without improving the cost reasonableness of the control strategy. 
These considerations provide the 
basis for finalizing CCS as the best of the systems of emission reduction for long- term coal-fired power plants. In addition, determining CCS as the BSER promotes advancements in control technology for CO
2, which is a relevant 
consideration when establishing BSER under section 111 of the CAA. 
i. Adequately Demonstrated 
CCS with 90 percent capture is 
adequately demonstrated based on the 
information in section VII.C.1.a.i of this preamble. Solvent-based CO
2capture 
was patented nearly 100 years ago in the 1930s661and has been used in a variety 
of industrial applications for decades. 
Thousands of miles of CO 2pipelines 
have been constructed and securely operated in the U.S. for decades.
662And 
tens of millions of tons of CO 2have 
been permanently stored deep underground either for geologic sequestration or in association with EOR.
663There are currently at least 15 
operating CCS projects in the U.S., and another 121 that are under construction or in advanced stages of development.
664This broad application 
of CCS demonstrates the successful operation of all three components of CCS, operating both independently and simultaneously. Various CO
2capture 
methods are used in industrial applications and are tailored to the flue gas conditions of a particular industry (see the final TSD, GHG Mitigation Measures for Steam Generating Units for details). Of those capture technologies, amine solvent-based capture has been demonstrated for removal of CO
2from 
the post-combustion flue gas of fossil fuel-fired EGUs. 
Since 1978, an amine-based system 
has been used to capture approximately 270,000 metric tons of CO
2per year 
from the flue gas of the bituminous coal- fired steam generating units at the 63 MW Argus Cogeneration Plant (Trona, California).
665Amine solvent capture 
has been further demonstrated at coal- fired power plants including AES’s Warrior Run and Shady Point. And since 2014, CCS has been applied at the commercial scale at Boundary Dam Unit 3, a 110 MW lignite coal-fired steam generating unit in Saskatchewan, Canada. 
Impending increases in Canadian 
regulatory CO
2emission requirements 
have prompted optimization of Boundary Dam Unit 3 so that the facility now captures 83 percent of its total CO
2 
emissions. Moreover, from the flue gas 
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666See Essex Chem. Corp. v. Ruckelshaus, 486 
F.2d 427 (D.C. Cir. 1973); Nat’l Asphalt Pavement 
Ass’n v. Train, 539 F.2d 775 (D.C. Cir. 1976). 
667See id. 
668See Sierra Club v. Costle, 657 F.2d 298 (1981). 
669Lignite Energy Council v. EPA, 198 F.3d 930 
(D.C. Cir. 1999). 670See, e.g., Essex Chem. Corp. v. Ruckelshaus, 
486 F.2d 427 (D.C. Cir. 1973); Sierra Club v. Costle, 
657 F.2d 298 (1981). 
671198 F.3d 930 (D.C. Cir. 1999). treated, Boundary Dam Unit 3 
consistently captured 90 percent or more of the CO
2over a 3-year period. 
The adequate demonstration of CCS is further corroborated by the EPAct05- assisted 240MW-equivalent Petra Nova CCS project at the coal-fired W.A. Parish Unit 8, which achieved over 90 percent capture from the treated flue gas during a 3-year period. Additionally, the technical improvements put in practice at Boundary Dam Unit 3 and Petra Nova can be put in place on new capture facilities during initial construction. This includes redundancies and isolations for key equipment, and spray systems to limit fly ash carryover. Projects that have announced plans to install CO
2capture directly include 
these improvements in their design and employ new solvents achieving higher capture rates that are commercially available from technology providers. As a result, these projects target capture efficiencies of at least 95 percent, well above the BSER finalized here. 
Precedent, building upon the 
statutory text and context, has established that the EPA may make a finding of adequate demonstration by drawing upon existing data from individual commercial-scale sources, including testing at these sources,
666 
and that the agency may make projections based on existing data to establish a more stringent standard than has been regularly shown,
667in 
particular in cases when the agency can specifically identify technological improvements that can be expected to achieve the standard in question.
668 
Further, the EPA may extrapolate based on testing at a particular kind of source to conclude that the technology at issue will also be effective at a different, related, source.
669Following this legal 
standard, the available data regarding performance and testing at Boundary Dam, a commercial-scale plant, is enough, by itself, to support the EPA’s adequate demonstration finding for a 90 percent standard. In addition to this, however, in the 9 years since Boundary Dam began operating, operators and the EPA have developed a clear understanding of specific technological improvements which, if implemented, the EPA can reasonably expect to lead to a 90 percent capture rate on a regular and ongoing basis. The D.C. Circuit has established that this information is more than enough to establish that a 90 percent standard is achievable.
670And 
per Lignite Energy Council, the findings 
from Boundary Dam can be extrapolated 
to other, similarly operating power plants, including natural gas plants.
671 
Transport of CO 2and geological 
storage of CO 2have also been 
adequately demonstrated, as detailed in VII.C.1.a.i(B)(7) and VII.C.1.a.i(D)(2). CO
2has been transported through 
pipelines for over 60 years, and in the past 20 years, 500 million metric tons of CO
2moved through over 5,000 miles of 
CO 2pipelines. CO 2pipeline controls 
and PHMSA standards ensure that captured CO
2will be securely conveyed 
to a sequestration site. Due to the proximity of sources to storage, it would be feasible for most sources to build smaller and shorter source-to-sink laterals, rather than rely on a trunkline network buildout. In addition to pipelines, CO
2can also be transported 
via vessel, highway, or rail. Geological storage is proven and broadly available, and of the coal-fired steam generating units with planned operation during or after 2030, 77 percent are within 40 miles of the boundary of a saline reservoir. 
The EPA also considered the 
timelines, materials, and workforce necessary for installing CCS, and determined they are sufficient. 
ii. Cost 
Process improvements have resulted 
in a decrease in the projected costs to 
install CCS on existing coal-fired steam generating units. Additionally, the IRC section 45Q tax credit provides $85 per metric ton ($77 per ton) of CO
2. It is 
reasonable to account for the IRC section 45Q tax credit because the costs that should be accounted for are the costs to the source. For the fleet of coal- fired steam generating units with planned operation during or after 2033, and assuming a 12-year amortization period and 80 percent annual capacity factor and including source specific transport and storage costs, the average total costs of CCS are ¥$5/ton of CO
2 
reduced and ¥$4/MWh. And even for shorter amortization periods, the $/ MWh costs are comparable to or less than the costs for other controls ($10.60–$18.50/MWh) for a substantial number of sources. Notably, the EPA’s IPM model projects that even without this final rule—that is, in the base case, without any CAA section 111 requirements—some units would deploy CCS. Similarly, the IPM model projects that even if this rule 
determined 40 percent co-firing to be the BSER for long-term coal, instead of CCS, some additional units would deploy CCS. Therefore, the costs of CCS with 90 percent capture are reasonable. 
iii. Non-Air Quality Health and 
Environmental Impacts and Energy Requirements 
The CO
2capture plant requires 
substantial pre-treatment of the flue gas to remove SO
2and fly ash (PM) while 
other controls and process designs are necessary to minimize solvent degradation and solvent loss. Although CCS has the potential to result in some increases in non-GHG emissions, a robust regulatory framework, generally implemented at the state level, is in place to mitigate other non-GHG emissions from the CO
2capture plant. 
For transport, pipeline safety is regulated by PHMSA, while UIC Class VI regulations under the SDWA, in tandem with GHGRP subpart RR requirements, ensure the protection of USDWs and the security of geologic sequestration. Therefore, the potential non-air quality health and environmental impacts do not militate against designating CCS as the BSER for long-term steam EGUs. The EPA also considered energy requirements. While the CO
2capture plant requires steam 
and electricity to operate, the incentives provided by the IRC section 45Q tax credit will likely result in increased total generation from the source. Therefore, the energy requirements are not unreasonable, and there would be limited, non-adverse impacts on the broader energy sector. 
2. Medium-Term Coal-Fired Steam 
Generating Units 
The EPA is finalizing its conclusion 
that 40 percent natural gas co-firing on a heat input basis is the BSER for medium-term coal-fired steam generating units. Co-firing 40 percent natural gas, on an annual average heat input basis, results in a 16 percent reduction in CO
2emission rate. The 
technology has been adequately demonstrated, can be implemented at reasonable cost, does not have significant adverse non-air quality health and environmental impacts or energy requirements, including impacts on the energy sector, and achieves meaningful reductions in CO
2 
emissions. Co-firing also advances useful control technology, which provides additional, although not essential, support for treating it as the BSER. 
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672U.S. Environmental Protection Agency. 
National Electric Energy Data System (NEEDS) v7. 
December 2023. https://www.epa.gov/power-sector- modeling/national-electric-energy-data-system- needs. 
67340 CFR 60.22(b)(5), 60.22a(b)(5). 674The EPA recognizes that section 111(d) 
provides that in applying standards of performance, 
a state may take into account, among other factors, the remaining useful life of a facility. The EPA believes that provision is intended to address exceptional circumstances at particular facilities, while the EPA has the responsibility to determine how to address the source category as a whole. See 88 FR 80480, 80511 (November 17, 2023) (‘‘Under CAA 111, EPA must provide BSER and degree of emission limitation determinations that are, to the extent reasonably practicable, applicable to all designated facilities in the source category. In many cases, this requires the EPA to create subcategories of designated facilities, each of which has a BSER 
and degree of emission limitation tailored to its circumstances....  However, as Congress 
recognized, this may not be possible in every instance because, for example, it is not be feasible [sic] for the Agency to know and consider the idiosyncrasies of every designated facility or because the circumstances of individual facilities change after the EPA determined the BSER.’’) (internal citations omitted). That a state may take into account the remaining useful life of an individual source, however, does not bar the EPA from considering operating horizon as a factor in determining whether subcategorization is appropriate. As discussed, the authority to subcategorize is encompassed within the EPA’s authority to identify the BSER. Here, where many units share similar characteristics and have announced intended shorter operating horizons, it is permissible for the EPA to take operating horizon into account in determining the BSER for this subcategory of sources. States may continue to take RULOF factors into account for particular units where the information relevant to those units is fundamentally different than the information the EPA took into account in determining the degree of emission limitation achievable through application of the BSER. Should a court conclude that the EPA does not have the authority to create a subcategory based on the date at which units intend to cease operation, then the EPA believes it would be reasonable for states to consider co-firing as an alternative to CCS as an option for these units through the states’ authority to consider, among other factors, remaining useful life. 
675Steam Electric Reconsideration Rule, 85 FR 
64650, 64679 (October 13, 2020) (distinguishes between EGUs retiring before 2028 and EGUs remaining in operation after that time). a. Rationale for the Medium-Term Coal- 
Fired Steam Generating Unit Subcategory 
For the development of the emission 
guidelines, the EPA first considered CCS as the BSER for existing coal-fired steam generating units. CCS generally achieves significant emission reductions at reasonable cost. Typically, in setting the BSER, the EPA assumes that regulated units will continue to operate indefinitely. However, that assumption is not appropriate for all coal-fired steam generating units. 62 percent of existing coal-fired steam generating units greater than 25 MW have already announced that they will retire or convert from coal to gas by 2039.
672CCS 
is capital cost-intensive, entailing a certain period to amortize the capital costs. Therefore, the EPA evaluated the 
costs of CCS for different amortization periods, as detailed in section VII.C.1.a.ii of the preamble, and determined that CCS was cost reasonable, on average, for sources operating more than 7 years after the compliance date of January 1, 2032. Accordingly, units that cease operating before January 1, 2039, will generally have less time to amortize the capital costs, and the costs for those sources would be higher and thereby less comparable to those the EPA has previously determined to be reasonable. Considering this, and the other factors evaluated in determining BSER, the EPA is not finalizing CCS as BSER for units demonstrating that they plan to permanently cease operation prior to January 1, 2039. 
Instead, the EPA is subcategorizing 
these units into the medium-term subcategory and finalizing a BSER based on 40 percent natural gas co-firing on a heat input basis for these units. Co- firing natural gas at 40 percent has significantly lower capital costs than CCS and can be implemented by January 1, 2030. For sources that expect to continue in operation until January 1, 2039, and that therefore have a 9-year amortization period, the costs of 40 percent co-firing are $73/ton of CO
2 
reduced or $13/MWh of generation, which supports their reasonableness because they are comparable to or less than the costs detailed in section VII.C.1.a.ii(D) of this preamble for other controls on EGUs ($10.60 to $18.50/ MWh) and for GHGs for the Crude Oil and Natural Gas source category in the 2016 NSPS of $98/ton of CO
2ereduced (80 FR 56627; September 18, 2015). Co- 
firing is also cost-reasonable for sources permanently ceasing operations sooner, and that therefore have a shorter amortization period. As discussed in section VII.B.2 of this preamble, with a two-year amortization period, many units can co-fire with meaningful amounts of natural gas at reasonable cost. Of course, even more can co-fire at reasonable costs with amortization periods longer than two years. For example, the EPA has determined that 33 percent of sources with an amortization period of at least three years have costs for 40 percent co-firing below both of the $/ton and $/MWh metrics, and 68 percent of those sources have costs for 20 percent co-firing below both of those metrics. Therefore, recognizing that operating horizon affects the cost reasonableness of controls, the EPA is finalizing a separate subcategory for coal-fired steam generating units operating in the medium-term—those demonstrating that they plan to permanently cease operation after December 31, 2031, and before January 1, 2039—with 40 percent natural gas co-firing as the BSER. 
i. Legal Basis for Establishing the 
Medium-Term Subcategory 
As noted in section V.C.1 of this 
preamble, the EPA has broad authority under CAA section 111(d) to identify subcategories. As also noted in section V.C.1, the EPA’s authority to ‘‘distinguish among classes, types, and sizes within categories,’’ as provided under CAA section 111(b)(2) and as we interpret CAA section 111(d) to provide as well, generally allows the Agency to place types of sources into subcategories when they have characteristics that are relevant to the controls that the EPA may determine to be the BSER for those sources. One element of the BSER is cost reasonableness. See CAA section 111(d)(1) (requiring the EPA, in setting the BSER, to ‘‘tak[e] into account the cost of achieving such reduction’’). As noted in section V, the EPA’s longstanding regulations under CAA section 111(d) explicitly recognize that subcategorizing may be appropriate for sources based on the ‘‘costs of control.’’
673Subcategorizing on the 
basis of operating horizon is consistent 
with a key characteristic of the coal- fired power industry that is relevant for determining the cost reasonableness of control requirements: A large percentage of the sources in the industry have already announced, and more are expected to announce, dates for ceasing operation, and the fact that many coal- fired steam generating units intend to 
cease operation in the near term affects what controls are ‘‘best’’ for different subcategories.
674At the outset, 
installation of emission control technology takes time, sometimes several years. Whether the costs of control are reasonable depends in part on the period of time over which the affected sources can amortize those costs. Sources that have shorter operating horizons will have less time to amortize capital costs. Thus, the annualized cost of controls may thereby be less comparable to the costs the EPA has previously determined to be reasonable.
675 
In addition, subcategorizing by length 
of period of continued operation is similar to two other bases for subcategorization on which the EPA has relied in prior rules, each of which implicates the cost reasonableness of controls: The first is load level, noted in section V.C.1. of this preamble. For 
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676See 79 FR 5031, 5192 (January 30, 2014) 
(explaining that ‘‘[t]he construction permit issued 
by Wyoming requires Naughton Unit 3 to cease burning coal by December 31, 2017, and to be retrofitted to natural gas as its fuel source by June 30, 2018’’ (emphasis added)). 677As described in the proposal, during the early 
engagement process, industry stakeholders requested that the EPA ‘‘[p]rovide approaches that allow for the retirement of units as opposed to investments in new control technologies, which could prolong the lives of higher-emitting EGUs; this will achieve maximum and durable environmental benefits.’’ Industry stakeholders also suggested that the EPA recognize that some units may remain operational for a several-year period but will do so at limited capacity (in part to assure reliability), and then voluntarily cease operations entirely. 88 FR 33245 (May 23, 2023). example, in the 2015 NSPS, the EPA 
divided new natural gas-fired combustion turbines into the subcategories of base load and non-base load. 80 FR 64602 (table 15) (October 23, 2015). The EPA did so because the control technologies that were ‘‘best’’— including consideration of feasibility and cost reasonableness—depended on how much the unit operated. The load level, which relates to the amount of product produced on a yearly or other basis, bears similarity to a limit on a period of continued operation, which concerns the amount of time remaining to produce the product. In both cases, certain technologies may not be cost- reasonable because of the capacity to produce product—i.e., the costs are 
spread over less product produced. Subcategorization on this basis is also supported by how utilities manage their assets over the long term, and was widely supported by industry commenters. 
The second basis for 
subcategorization on which EPA has previously relied is fuel type, as also noted in section V.C.1 of this preamble. The 2015 NSPS provides an example of this type of subcategorization as well. There, the EPA divided new combustion turbines into subcategories on the basis of type of fuel combusted. Id. Subcategorizing on the basis of the type of fuel combusted may be appropriate when different controls have different costs, depending on the type of fuel, so that the cost reasonableness of the control depends on the type of fuel. In that way, it is similar to subcategorizing by operating horizon because in both cases, the subcategory is based upon the cost reasonableness of controls. Subcategorizing by operating horizon is also tantamount to the length of time over which the source will continue to combust the fuel. Subcategorizing on this basis may be appropriate when different controls for a particular fuel have different costs, depending on the length of time when the fuel will continue to be combusted, so that the cost reasonableness of controls depends on that timeframe. Some prior EPA rules for coal-fired sources have made explicit the link between length of time for continued operation and type of fuel combusted by codifying federally enforceable retirement dates as the dates by which the source must ‘‘cease burning coal.’’
676 As noted above, creating a 
subcategory on the basis of operating 
horizon does not preclude a state from considering RULOF in applying a standard of performance to a particular source. The EPA’s authority to set BSER for a source category (including subcategories) and a state’s authority to invoke RULOF for individual sources within a category or subcategory are distinct. The EPA’s statutory obligation is to determine a generally applicable BSER for a source category, and where that source category encompasses different classes, types, or sizes of sources, to set generally applicable BSERs for subcategories accounting for those differences. By contrast, states’ authority to invoke RULOF is premised on the state’s ability to take into account information relevant to individual units that is fundamentally different than the information the EPA took into account in determining BSER generally. As noted, the EPA may subcategorize on the basis of cost of controls, and operating horizon may factor into the cost of controls. Moreover, through section 111(d)(1), Congress also required the EPA to develop regulations that permit states to consider ‘‘among other factors, the remaining useful life’’ of a particular existing source. The EPA has interpreted these other factors to include costs or technical feasibility specific to a particular source, even though these are factors the EPA itself considers in setting the BSER. In other words, the factors the EPA may consider in setting the BSER and the factors the states may consider in applying standards of performance are not distinct. As noted above, the EPA is finalizing these subcategories in response to requests by power sector representatives that this rule accommodate the fact that there is a class of sources that plan to voluntarily cease operations in the near term. Although the EPA has designed the subcategories to accommodate those requests, a particular source may still present source-specific considerations— whether related to its remaining useful life or other factors—that the state may consider relevant for the application of that particular source’s standard of performance, and that the state should address as described in section X.C.2 of this preamble. 
ii. Comments Received on Existing Coal- 
Fired Subcategories 
Comment: The EPA received several 
comments on the proposed 
subcategories for coal-fired steam generating units. Many commenters, including industry commenters, supported these subcategories. Some commenters opposed these proposed 
subcategories. They argued that the subcategories were designed to force coal-fired power plants to retire. 
Response: We disagree with 
comments suggesting that the subcategories for existing coal-fired steam EGUs that the EPA has finalized in this rule were designed to force retirements. The subcategories were not designed for that purpose, and the commenters do not explain their allegations to the contrary. The subcategories were designed, at industry’s request,
677to ensure that 
subcategories of units that can feasibly and cost-reasonably employ emissions reduction technologies—and only those subcategories of units that can do so— are required to reduce their emissions commensurate with those technologies. 
As explained above, in determining the BSER, the EPA generally assumes that a source will operate indefinitely, and calculates expected control costs on that basis. Under that assumption, the BSER for existing fossil-fuel fired EGUs is CCS. Nevertheless, the EPA recognizes that many fossil-fuel fired EGUs have already announced plans to cease operation. In recognition of this unique, distinguishing factor, the EPA determined whether a different BSER would be appropriate for fossil fuel- fired EGUs that do not intend to operate over the long term, and concluded, for the reasons stated above, that natural gas co-firing was appropriate for these sources that intended to cease operation before 2039. This subcategory is not intended to force retirements, and the EPA is not directing any state or any unit as to the choice of when to cease operation. Rather, the EPA has created this subcategory to accommodate these sources’ intended operation plans. In fact, a number of industry commenters specifically requested and supported subcategories based on retirement dates in recognition of the reality that many operators are choosing to retire these units and that whether or not a control technology is feasible and cost- reasonable depends upon how long a unit intends to operate. 
Specifically, as noted in section VII.B 
of this preamble, in this final action, the 
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678U.S. Environmental Protection Agency. 
National Electric Energy Data System (NEEDS) v7. 
December 2023. https://www.epa.gov/power-sector- modeling/national-electric-energy-data-system- needs. 
679See Document ID No. EPA–HQ–OAR–2023– 
0072–0772. 680U.S. Environmental Protection Agency (EPA). 
‘‘Power Sector Emissions Data.’’ Washington, DC: 
Office of Atmospheric Protection, Clean Air Markets Division. Available from EPA’s Air Markets Program Data website: https://campd.epa.gov . medium-term subcategory includes a 
date for permanently ceasing operation, which applies to coal-fired plants demonstrating that they plan to permanently cease operating after December 31, 2031, and before January 1, 2039. The EPA is retaining this subcategory because 55 percent of existing coal-fired steam generating units greater than 25 MW have already announced that they will retire or convert from coal to gas by January 1, 2039.
678Accordingly, the costs of CCS— 
the high capital costs of which require a lengthy amortization period from its January 1, 2032, implementation date— are higher than the traditional metric for cost reasonableness for these sources. As discussed in section VII.C.2 of this preamble, the BSER for these sources is co-firing 40 percent natural gas. This is because co-firing, which has an implementation date of January 1, 2030, has lower capital costs and is therefore cost-reasonable for sources continuing to operate on or after January 1, 2032. It is further noted that this subcategory is elective. Furthermore, states also have the authority to establish a less stringent standard through RULOF in the state plan process, as detailed in section X.C.2 of this preamble. 
In sum, these emission guidelines do 
not require any coal-fired steam EGU to retire, nor are they intended to induce retirements. Rather, these emission guidelines simply set forth presumptive standards that are cost-reasonable and achievable for each subcategory of existing coal-fired steam EGUs. See section VII.E.1 of this preamble (responding to comments that this rule violates the major questions doctrine). 
Comment: The EPA broadly solicited 
comment on the dates and values defining the proposed subcategories for coal-fired steam generating units. Regarding the proposed dates for the subcategories, one industry stakeholder commented that the ‘‘EPA’s proposed retirement dates for applicability of the various subcategories are appropriate 
and broadly consistent with system reliability needs.’’
679More specifically, 
industry commenters requested that the cease-operation-by date for the imminent-term subcategory be changed from January 1, 2032, to January 1, 2033. Industry commenters also stated that the 20 percent utilization limit in the definition of the near-term subcategory was overly restrictive and inconsistent with the emissions stringency of either 
the proposed medium term or imminent term subcategory—commenters requested greater flexibility for the near- term subcategory. Other comments from 
NGOs and other groups suggested various other changes to the subcategory definitions. One commenter requested moving the cease-operation-by date for the medium-term subcategory up to January 1, 2038, while eliminating the imminent-term subcategory and extending the near-term subcategory to January 1, 2038. 
Response: The EPA is not finalizing 
the proposed imminent-term or near- term subcategories. The EPA is finalizing an applicability exemption for sources demonstrating that they plan to permanently cease operation prior to January 1, 2032, as detailed in section VII.B of this preamble. The EPA is finalizing the cease operating by date of January 1, 2039, for medium-term coal- fired steam generating units. These dates are all based on costs of co-firing and CCS, driven by their amortization periods, as discussed in the preceding sections of this preamble. 
b. Rationale for Natural Gas Co-Firing as 
the BSER for Medium-Term Coal-Fired Steam Generating Units 
In this section of the preamble, the 
EPA describes its rationale for natural gas co-firing as the final BSER for medium-term coal-fired steam generating units. 
For a coal-fired steam generating unit, 
the substitution of natural gas for some of the coal, so that the unit fires a combination of coal and natural gas, is known as ‘‘natural gas co-firing.’’ The EPA is finalizing natural gas co-firing at a level of 40 percent of annual heat input as BSER for medium-term coal- fired steam generating units. 
i. Adequately Demonstrated 
The EPA is finalizing its 
determination that natural gas co-firing 
at the level of 40 percent of annual heat input is adequately demonstrated for coal-fired steam generating units. Many existing coal-fired steam generating units already use some amount of natural gas, and several have co-fired at relatively high levels at or above 40 percent of heat input in recent years. 
(A) Boiler Modifications 
Existing coal-fired steam generating 
units can be modified to co-fire natural 
gas in any desired proportion with coal, up to 100 percent natural gas. Generally, the modification of existing boilers to enable or increase natural gas firing typically involves the installation of new gas burners and related boiler modifications, including, for example, 
new fuel supply lines and modifications to existing air ducts. The introduction of natural gas as a fuel can reduce boiler efficiency slightly, due in large part to the relatively high hydrogen content of natural gas. However, since the reduction in coal can result in reduced auxiliary power demand, the overall impact on net heat rate can range from a 2 percent increase to a 2 percent decrease. 
It is common practice for steam 
generating units to have the capability to burn multiple fuels onsite, and of the 565 coal-fired steam generating units operating at the end of 2021, 249 of them reported consuming natural gas as a fuel or startup source. Coal-fired steam generating units often use natural gas or oil as a startup fuel, to warm the units up before running them at full capacity with coal. While startup fuels are generally used at low levels (up to roughly 1 percent of capacity on an annual average basis), some coal-fired steam generating units have co-fired natural gas at considerably higher shares. Based on hourly reported CO
2 
emission rates from the start of 2015 through the end of 2020, 29 coal-fired steam generating units co-fired with natural gas at rates at or above 60 percent of capacity on an hourly basis.
680The capability of those units on 
an hourly basis is indicative of the extent of boiler burner modifications and sizing and capacity of natural gas pipelines to those units, and implies that those units are technically capable of co-firing at least 60 percent natural gas on a heat input basis on average over the course of an extended period (e.g., a year). Additionally, during that same 2015 through 2020 period, 29 coal-fired steam generating units co-fired natural gas at over 40 percent on an annual heat input basis. Because of the number of units that have demonstrated co-firing above 40 percent of heat input, the EPA is finalizing that co-firing at 40 percent is adequately demonstrated. A more detailed discussion of the record of natural gas co-firing, including current trends, at coal-fired steam generating units is included in the final TSD, GHG Mitigation Measures for Steam Generating Units. 
(B) Natural Gas Pipeline Development 
In addition to any potential boiler 
modifications, the supply of natural gas 
is necessary to enable co-firing at existing coal-fired steam boilers. As 
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681In practice, not all sources would necessarily 
be subject to a natural gas co-firing BSER in 
compliance. E.g., some portion of that population 
of sources could install CCS, so the resulting amount of natural gas co-firing would be less. 
682The average time for permitting for a natural 
gas pipeline lateral is 1.5 years, and many sources could be permitted faster (about 1 year) so that it is reasonable to assume that many sources could begin construction by June 2027. The average time for construction of an individual pipeline is about 1 year or less. Considering this, the EPA assumes construction of all of the natural gas pipeline laterals in the analysis occurs over a 2-year period (June 2027 through June 2029), and notes that in practice some of these projects could be constructed outside of this period. 
683Documentation for the Lateral Cost Estimation 
(2024), ICF International. Available in Docket ID EPA–HQ–OAR–2023–0072. discussed in the previous section, many 
plants already have at least some access to natural gas. In order to increase natural gas access beyond current levels, plants may find it necessary to construct natural gas supply pipelines. 
The U.S. natural gas pipeline network 
consists of approximately 3 million 
miles of pipelines that connect natural gas production with consumers of natural gas. To increase natural gas consumption at a coal-fired boiler without sufficient existing natural gas access, it is necessary to connect the facility to the natural gas pipeline transmission network via the construction of a lateral pipeline. The cost of doing so is a function of the total necessary pipeline capacity (which is characterized by the length, size, and number of laterals) and the location of the plant relative to the existing pipeline transmission network. The EPA estimated the costs associated with developing new lateral pipeline capacity sufficient to meet 60 percent of the net summer capacity at each coal- fired steam generating unit that could be included in this subcategory. As discussed in the final TSD, GHG 
Mitigation Measures for Steam Generating Units, the EPA estimates that this lateral capacity would be sufficient to enable each unit to achieve 40 percent natural gas co-firing on an annual average basis. 
The EPA considered the availability 
of the upstream natural gas pipeline capacity to satisfy the assumed co-firing demand implied by these new laterals. This analysis included pipeline development at all EGUs that could be included in this subcategory, including those without announced plans to cease operating before January 1, 2039. The EPA’s assessment reviewed the reasonableness of each assumed new lateral by determining whether the peak gas capacity of that lateral could be satisfied without modification of the transmission pipeline systems to which it is assumed to be connected. This analysis found that most, if not all, 
existing pipeline systems are currently able to meet the peak needs implied by these new laterals in aggregate, assuming that each existing coal-fired unit in the analysis co-fired with natural gas at a level implied by these new laterals, or 60 percent of net summer generating capacity. While this is a reasonable assumption for the analysis to support this mitigation measure in the BSER context, it is also a conservative assumption that overstates the amount of natural gas co-firing 
expected under the final rule.
681 
Most of these individual laterals are 
less than 15 miles in length. The maximum aggregate amount of pipeline capacity, if all coal-fired steam capacity that could be included in the medium- term subcategory (i.e., all capacity that 
has not announced that it plans to retire by 2032) implemented the final BSER by co-firing 40 percent natural gas, would be comparable to pipeline capacity constructed recently. The EPA estimates that this maximum total capacity would be nearly 14.7 billion cubic feet per day, which would require about 3,500 miles of pipeline costing roughly $11.5 billion. Over 2 years,
682this maximum 
total incremental pipeline capacity would amount to less than 1,800 miles per year, with a total annual capacity of roughly 7.35 billion cubic feet per day. This represents an estimated annual investment of approximately $5.75 billion per year in capital expenditures, on average. By comparison, based on data collected by EIA, the total annual mileage of natural gas pipelines constructed over the 2017–2021 period ranged from approximately 1,000 to 2,500 miles per year, with a total annual capacity of 10 to 25 billion cubic feet per day. This represents an estimated annual investment of up to nearly $15 billion. The upper end of these historical annual values is much higher than the maximum annual values that could be expected under this final BSER measure—which, as noted above, represent a conservative estimate that significantly overstates the amount of co-firing that the EPA projects would occur under this final rule. 
These conservatively high estimates 
of pipeline requirements also compare favorably to industry projections of future pipeline capacity additions. Based on a review of a 2018 industry report, titled ‘‘North America Midstream Infrastructure through 2035: Significant Development Continues,’’ investment in midstream infrastructure development 
is expected to range between $10 to $20 billion per year through 2035. Approximately $5 to $10 billion annually is expected to be invested in natural gas pipelines through 2035. This report also projects that an average of over 1,400 miles of new natural gas pipeline will be built through 2035, which is similar to the approximately 1,670 miles that were built on average from 2013 to 2017. These values are consistent with the average annual expenditure of $5.75 billion on less than 1,800 miles per year of new pipeline construction that would be necessary for the entire operational fleet of existing coal-fired steam generating units to co- fire with natural gas. The actual pipeline investment for this subcategory would be substantially lower. 
(C) Compliance Date for Medium-Term 
Coal-Fired Steam Generating Units 
The EPA is finalizing a compliance 
date for medium-term coal-fired steam generating units of January 1, 2030. 
As in the timeline for CCS for the long 
term coal-fired steam generating units described in section VII.C.1.a.i(E), the EPA assumes here that feasibility work occurs during the state plan development period, and that all subsequent work occurs after the state plan is submitted and thereby effective at the state level. The EPA assumes 12 months of feasibility work for the natural gas pipeline lateral and 6 months of feasibility work for boiler modifications (both to occur over June 2024 to June 2025). As with the feasibility analysis for CCS, the feasibility analysis for co-firing will inform the state plan and therefore it is reasonable to assume units will perform it during the state planning window. Feasibility for the pipeline includes a right-of-way and routing analysis. Feasibility for the boiler modifications includes conceptual studies and design basis. 
The timeline for the natural gas 
pipeline permitting and construction is based on a review of recently completed permitting approvals and construction.
683The average time to 
complete permitting and approval is less than 1.5 years, and the average time to complete actual construction is less than 1 year. Of the 31 reviewed pipeline projects, the vast majority (27 projects) took less than a total of 3 years for permitting and construction, and none took more than 3.5 years. Therefore, it is reasonable to assume that permitting and construction would take no more than 3 years for most sources (June 2026 to June 2029), noting that permitting 
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684Natural Gas Co-Firing Memo, Sargent & Lundy 
(2023). Available in Docket ID EPA–HQ–OAR– 
2023–0072. and construction for many sources 
would be faster. 
The timeline for boiler modifications 
based on the baseline duration co-firing conversion project schedule developed by Sargent and Lundy.
684The EPA 
assumes that, with the exception of the feasibility studies discussed above, work on the boiler modifications begins after the state plan submission due date. The EPA also assumes permitting for the boiler modifications is required and takes 12 months (June 2026 to June 2027). In the schedule developed by Sargent and Lundy, commercial arrangements for the boiler modification take about 6 months (June 2026 to December 2026). Detailed engineering and procurement takes about 7 months (December 2026 to July 2027), and begins after commercial arrangements are complete. Site work takes 3 months (July 2027 to October 2027), followed by 4 months of construction (October 2027 to February 2028). Lastly, startup and testing takes about 2 months (June 2029 to August 2029), noting that the EPA assumes this occurs after the natural gas pipeline lateral is constructed. Considering the preceding information, the EPA has determined January 1, 2030 is the compliance date for medium-term coal-fired steam generating units. 
ii. Costs 
The capital costs associated with the 
addition of new gas burners and other 
necessary boiler modifications depend on the extent to which the current boiler is already able to co-fire with some natural gas and on the amount of gas co- firing desired. The EPA estimates that, on average, the total capital cost associated with modifying existing boilers to operate at up to 100 percent of heat input using natural gas is approximately $52/kW. These costs could be higher or lower, depending on the equipment that is already installed and the expected impact on heat rate or steam temperature. 
While fixed O&M (FOM) costs can 
potentially decrease as a result of decreasing the amount of coal consumed, it is common for plants to maintain operation of one coal pulverizer at all times, which is necessary for maintaining several coal burners in continuous service. In this case, coal handling equipment would be required to operate continuously and therefore natural gas co-firing would have limited effect on reducing the coal- related FOM costs. Although, as noted, coal-related FOM costs have the potential to decrease, the EPA does not 
anticipate a significant increase in impact on FOM costs related to co-firing with natural gas. 
In addition to capital and FOM cost 
impacts, any additional natural gas co- firing would result in incremental costs related to the differential in fuel cost, taking into consideration the difference in delivered coal and gas prices, as well as any potential impact on the overall net heat rate. The EPA’s reference case projects that in 2030, the average delivered price of coal will be $1.56/ MMBtu and the average delivered price of natural gas will be $2.95/MMBtu. Thus, assuming the same level of generation and no impact on heat rate, the additional fuel cost would be $1.39/ MMBtu on average in 2030. The total additional fuel cost could increase or decrease depending on the potential impact on net heat rate. An increase in net heat rate, for example, would result in more fuel required to produce a given amount of generation and thus additional cost. In the final TSD, GHG Mitigation Measures for Steam Generating Units, the EPA’s cost estimates assume a 1 percent average increase in net heat rate. 
Finally, for plants without sufficient 
access to natural gas, it is also necessary to construct new natural gas pipelines (‘‘laterals’’). Pipeline costs are typically expressed in terms of dollars per inch of pipeline diameter per mile of pipeline distance (i.e., dollars per inch-mile), 
reflecting the fact that costs increase with larger diameters and longer pipelines. On average, the cost for lateral development within the contiguous U.S. is approximately $280,000 per inch-mile (2019$), which can vary based on site-specific factors. The total pipeline cost for each coal- fired steam generating unit is a function of this cost, as well as a function of the necessary pipeline capacity and the location of the plant relative to the existing pipeline transmission network. The pipeline capacity required depends on the amount of co-firing desired as well as on the desired level of generation—a higher degree of co-firing while operating at full load would require more pipeline capacity than a lower degree of co-firing while operating at partial load. It is reasonable to assume that most plant owners would develop sufficient pipeline capacity to deliver the maximum amount of desired gas use in any moment, enabling higher levels of co-firing during periods of lower fuel price differentials. Once the necessary pipeline capacity is determined, the total lateral cost can be 
estimated by considering the location of each plant relative to the existing natural gas transmission pipelines as well as the available excess capacity of each of those existing pipelines. 
The EPA determined the costs of 40 
percent co-firing based on the fleet of coal-fired steam generating units that existed in 2021 and that do not have known plans to cease operations or convert to gas by 2032, and assuming that each of those units continues to operate at the same level as it operated over 2017–2021. The EPA assessed those costs against the cost reasonableness metrics, as described in section VII.C.1.a.ii(D) of this preamble (i.e., emission control costs on EGUs of 
$10.60 to $18.50/MWh and the costs in the 2016 NSPS regulating GHGs for the Crude Oil and Natural Gas source category of $98/ton of CO
2ereduced (80 
FR 56627; September 18, 2015)). On average, the EPA estimates that the weighted average cost of co-firing with 40 percent natural gas as the BSER on an annual average basis is approximately $73/ton CO
2reduced, or 
$13/MWh. The costs here reflect an amortization period of 9 years. These estimates support a conclusion that co- firing is cost-reasonable for sources that continue to operate up until the January 1, 2039, threshold date for the subcategory. The EPA also evaluated the fleet average costs of natural gas co- firing for shorter amortization periods and has determined that the costs are consistent with the cost reasonableness metrics for the majority of sources that will operate past January 1, 2032, and therefore have an amortization period of at least 2 years and up to 9 years. These estimates and all underlying assumptions are explained in detail in the final TSD, GHG Mitigation Measures for Steam Generating Units. Based on this cost analysis, alongside the EPA’s overall assessment of the costs of this rule, the EPA is finalizing that the costs of natural gas co-firing are reasonable for the medium-term coal-fired steam generating unit subcategory. If a particular source has costs of 40 percent co-firing that are fundamentally different from the cost reasonability metrics, the state may consider this fact under the RULOF provisions, as detailed in section X.C.2 of this preamble. The EPA previously estimated the cost of natural gas co- firing in the Clean Power Plan (CPP). 80 FR 64662 (October 23, 2015). The cost- estimates for co-firing presented in this section are lower than in the CPP, for several reasons. Since then, the expected difference between coal and gas prices has decreased significantly, from over $3/MMBtu to less than $1.50/ MMBtu in this final rule. Additionally, 
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685Pipeline Safety: Safety of Gas Transmission 
Pipelines: Repair Criteria, Integrity Management 
Improvements, Cathodic Protection, Management of Change, and Other Related Amendments (87 FR 52224; August 24, 2022). 
686Pipeline Safety: Safety of Gas Transmission 
Pipelines: MAOP Reconfirmation, Expansion of Assessment Requirements, and Other Related Amendments (84 FR 52180; October 1, 2019). 687Pipeline Safety: Safety of Gas Gathering 
Pipelines: Extension of Reporting Requirements, Regulation of Large, High-Pressure Lines, and Other Related Amendments (86 FR 63266; November 15, 2021). a recent analysis performed by Sargent 
and Lundy for the EPA supports a considerably lower capital cost for modifying existing boilers to co-fire with natural gas. The EPA also recently conducted a highly detailed facility- level analysis of natural gas pipeline costs, the median value of which is slightly lower than the value used by the EPA previously to approximate the cost of co-firing at a representative unit. 
iii. Non-Air Quality Health and 
Environmental Impact and Energy Requirements 
Natural gas co-firing for steam 
generating units is not expected to have any significant adverse consequences related to non-air quality health and environmental impacts or energy requirements. 
(A) Non-GHG Emissions 
Non-GHG emissions are reduced 
when steam generating units co-fire 
with natural gas because less coal is combusted. SO
2, PM 2.5, acid gas, 
mercury and other hazardous air pollutant emissions that result from coal combustion are reduced proportionally to the amount of natural gas consumed, i.e., under this final rule, by 40 percent. 
Natural gas combustion does produce NO
Xemissions, but in lesser amounts 
than from coal-firing. However, the magnitude of this reduction is dependent on the combustion system modifications that are implemented to facilitate natural gas co-firing. 
Sufficient regulations also exist 
related to natural gas pipelines and transport that assure natural gas can be safely transported with minimal risk of environmental release. PHMSA develops and enforces regulations for the safe, reliable, and environmentally sound operation of the nation’s 2.6 million mile pipeline transportation system. Recently, PHMSA finalized a rule that will improve the safety and strengthen the environmental protection of more than 300,000 miles of onshore gas transmission pipelines.
685PHMSA 
also recently promulgated a separate rule covering natural gas transmission,
686as well as a rule that 
significantly expanded the scope of safety and reporting requirements for more than 400,000 miles of previously unregulated gas gathering lines.
687FERC 
is responsible for the regulation of the siting, construction, and/or abandonment of interstate natural gas pipelines, gas storage facilities, and Liquified Natural Gas (LNG) terminals. 
(B) Energy Requirements 
The introduction of natural gas co- 
firing will cause steam boilers to be 
slightly less efficient due to the high hydrogen content of natural gas. Co- firing at levels between 20 percent and 100 percent can be expected to decrease boiler efficiency between 1 percent and 5 percent. However, despite the decrease in boiler efficiency, the overall net output efficiency of a steam generating unit that switches from coal- to natural gas-firing may change only slightly, in either a positive or negative direction. Since co-firing reduces coal consumption, the auxiliary power demand related to coal handling and emissions controls typically decreases as well. While a site-specific analysis would be required to determine the overall net impact of these countervailing factors, generally the effect of co-firing on net unit heat rate can vary within approximately plus or minus 2 percent. 
The EPA previously determined in 
the ACE Rule (84 FR 32545; July 8, 2019) that ‘‘co-firing natural gas in coal- fired utility boilers is not the best or most efficient use of natural gas and [. . .] can lead to less efficient operation of utility boilers.’’ That determination was informed by the more limited supply of natural gas, and the larger amount of coal-fired EGU capacity and generation, in 2019. Since that determination, the expected supply of natural gas has expanded considerably, and the capacity and generation of the existing coal-fired fleet has decreased, reducing the total mass of natural gas that might be required for sources to implement this measure. 
Furthermore, regarding the efficient 
operation of boilers, the ACE determination was based on the observation that ‘‘co-firing can negatively impact a unit’s heat rate (efficiency) due to the high hydrogen content of natural gas and the resulting production of water as a combustion by- product.’’ That finding does not consider the fact that the effect of co- firing on net unit heat rate can vary within approximately plus or minus 2 percent, and therefore the net impact on overall utility boiler efficiency for each 
steam generating unit is uncertain. 
For all of these reasons, the EPA is 
finalizing that natural gas co-firing at medium-term coal-fired steam generating units does not result in any significant adverse consequences related to energy requirements. 
Additionally, the EPA considered 
longer term impacts on the energy sector, and the EPA is finalizing these impacts are reasonable. Designating natural gas co-firing as the BSER for medium-term coal-fired steam generating units would not have significant adverse impacts on the structure of the energy sector. Steam generating units that currently are coal- fired would be able to remain primarily coal-fired. The replacement of some coal with natural gas as fuel in these sources would not have significant adverse effects on the price of natural gas or the price of electricity. 
iv. Extent of Reductions in CO
2 
Emissions 
One of the primary benefits of natural 
gas co-firing is emission reduction. CO 2 
emissions are reduced by approximately 
4 percent for every additional 10 percent of co-firing. When moving from 100 percent coal to 60 percent coal and 40 percent natural gas, CO
2stack 
emissions are reduced by approximately 16 percent. Non-CO
2emissions are 
reduced as well, as noted earlier in this preamble. 
v. Technology Advancement 
Natural gas co-firing is already well- 
established and widely used by coal- 
fired steam boiler generating units. As a result, this final rule is not likely to lead to technological advances or cost reductions in the components of natural gas co-firing, including modifications to boilers and pipeline construction. However, greater use of natural gas co- firing may lead to improvements in the efficiency of conducting natural gas co- 
firing and operating the associated equipment. 
c. Options Not Determined To Be the 
BSER for Medium-Term Coal-Fired Steam Generating Units 
i. CCS 
As discussed earlier in this preamble, 
the compliance date for CCS is January 
1, 2032. Accordingly, sources in the medium-term subcategory—which have elected to commit to permanently cease operations prior to 2039—would have less than 7 years to amortize the capital costs of CCS. As a result, for these sources, the overall costs of CCS would exceed the metrics for cost reasonableness that the EPA is using in 
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688Clean Air Markets Program Data at https://
campd.epa.gov. this rulemaking, which are detailed in 
section VII.C.1.a.ii(D). For this reason, the EPA is not finalizing CCS as the BSER for the medium-term subcategory. 
ii. Heat Rate Improvements 
Heat rate improvements were not 
considered to be BSER for medium-term 
steam generating units because the achievable reductions are low and may result in rebound effect whereby total emissions from the source increase, as detailed in section VII.D.4.a. 
d. Conclusion 
The EPA is finalizing that natural gas 
co-firing at 40 percent of heat input is 
the BSER for medium-term coal-fired steam generating units because natural gas co-firing is adequately demonstrated, as indicated by the facts that it has been operated at scale and is widely applicable to sources. Additionally, the costs for natural gas co-firing are reasonable. Moreover, natural gas co-firing can be expected to reduce emissions of several other air pollutants in addition to GHGs. Any adverse non-air quality health and environmental impacts and energy requirements of natural gas co-firing are limited. In contrast, CCS, although achieving greater emission reductions, would be of higher cost, in general, for the subcategory of medium-term units, and HRI would achieve few reductions and, in fact, may increase emissions. 
3. Degree of Emission Limitation for 
Final Standards 
Under CAA section 111(d), once the 
EPA determines the BSER, it must determine the ‘‘degree of emission limitation’’ achievable by the application of the BSER. States then determine standards of performance and include them in the state plans, based on the specified degree of emission limitation. Final presumptive standards of performance are detailed in section X.C.1.b of this preamble. There is substantial variation in emission rates among coal-fired steam generating units—the range is, approximately, from 1,700 lb CO
2/MWh-gross to 2,500 lb 
CO 2/MWh-gross—which makes it 
challenging to determine a single, uniform emission limit. Accordingly, the EPA is finalizing the degrees of emission limitation by a percentage change in emission rate, as follows. 
a. Long-Term Coal-Fired Steam 
Generating Units 
As discussed earlier in this preamble, 
the EPA is finalizing the BSER for long- term coal-fired steam generating units as ‘‘full-capture’’ CCS, defined as 90 percent capture of the CO
2in the flue gas. The degree of emission limitation 
achievable by applying this BSER can be determined on a rate basis. A capture rate of 90 percent results in reductions in the emission rate of 88.4 percent on a lb CO
2/MWh-gross basis, and this 
reduction in emission rate can be observed over an extended period (e.g., an annual calendar-year basis). Therefore, the EPA is finalizing that the degree of emission limitation for long- term units is an 88.4 percent reduction in emission rate on a lb CO
2/MWh-gross 
basis over an extended period (e.g., an 
annual calendar-year basis). 
b. Medium-Term Coal-Fired Steam 
Generating Units 
As discussed earlier in this preamble, 
the BSER for medium-term coal-fired steam generating units is 40 percent natural gas co-firing. The application of 40 percent natural gas co-firing results in reductions in the emission rate of 16 
percent. Therefore, the degree of emission limitation for these units is a 16 percent reduction in emission rate on a lb CO
2/MWh-gross basis over an 
extended period (e.g., an annual 
calendar-year basis). 
D. Rationale for the BSER for Natural 
Gas-Fired And Oil-Fired Steam Generating Units 
This section of the preamble describes 
the rationale for the final BSERs for existing natural gas- and oil-fired steam generating units based on the criteria described in section V.C of this preamble. 
1. Subcategorization of Natural Gas- and 
Oil-Fired Steam Generating Units 
The EPA is finalizing subcategories 
based on load level (i.e., annual capacity 
factor), specifically, units that are base load, intermediate load, and low load. The EPA is finalizing routine methods of operation and maintenance as BSER for intermediate and base load units. Applying that BSER would not achieve emission reductions but would prevent increases in emission rates. The EPA is finalizing presumptive standards of performance that differ between intermediate and base load units due to their differences in operation, as detailed in section X.C.1.b.iii of this preamble. The EPA proposed a separate subcategory for non-continental oil-fired steam generating units, which operate differently from continental units; however, the EPA is not finalizing emission guidelines for sources outside of the contiguous U.S., as described in section VII.B. At proposal, the EPA solicited comment on a BSER of ‘‘uniform fuels’’ for low load natural gas- and oil-fired steam generating units, and the EPA is finalizing this approach 
for those sources. 
Natural gas- and oil-fired steam 
generating units combust natural gas or distillate fuel oil or residual fuel oil in a boiler to produce steam for a turbine that drives a generator to create electricity. In non-continental areas, existing natural gas- and oil-fired steam generating units may provide base load power, but in the continental U.S., most existing units operate in a load- following manner. There are approximately 200 natural gas-fired steam generating units and fewer than 30 oil-fired steam generating units in operation in the continental U.S. Fuel costs and inefficiency relative to other technologies (e.g., combustion turbines) 
result in operation at lower annual capacity factors for most units. Based on data reported to EIA and the EPA
688for 
the contiguous U.S., for natural gas-fired steam generating units in 2019, the average annual capacity factor was less than 15 percent and 90 percent of units had annual capacity factors less than 35 percent. For oil-fired steam generating units in 2019, no units had annual capacity factors above 8 percent. Additionally, their load-following method of operation results in frequent cycling and a greater proportion of time spent at low hourly capacities, when generation is less efficient. Furthermore, because startup times for most boilers are usually long, natural gas steam generating units may operate in standby mode between periods of peak demand. Operating in standby mode requires combusting fuel to keep the boiler 
warm, and this further reduces the efficiency of natural gas combustion. 
Unlike coal-fired steam generating 
units, the CO
2emission rates of oil- and 
natural gas-fired steam generating units that have similar annual capacity factors do not vary considerably between units. This is partly due to the more uniform qualities (e.g., carbon content) of the 
fuel used. However, the emission rates for units that have different annual capacity factors do vary considerably, as detailed in the final TSD, Natural Gas- and Oil-fired Steam Generating Units. Low annual capacity factor units cycle frequently, have a greater proportion of CO
2emissions that may be attributed to 
startup, and have a greater proportion of generation at inefficient hourly capacities. Intermediate annual capacity factor units operate more often at higher hourly capacities, where CO
2emission 
rates are lower. High annual capacity factor units operate still more at base load conditions, where units are more 
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689See, for example, Document ID No. EPA–HQ– 
OAR–2023–0072–0583. efficient and CO 2emission rates are 
lower. 
Based on these performance 
differences between these load levels, 
the EPA, in general, proposed 
subcategories based on dividing natural gas- and oil-fired steam generating units into three groups each—low load, intermediate load, and base load. 
The EPA is finalizing subcategories 
for oil-fired and natural gas-fired steam generating units, based on load levels. The EPA proposed the following load levels: ‘‘low’’ load, defined by annual capacity factors less than 8 percent; ‘‘intermediate’’ load, defined by annual capacity factors greater than or equal to 8 percent and less than 45 percent; and ‘‘base’’ load, defined by annual capacity factors greater than or equal to 45 percent. 
The EPA is finalizing January 1, 2030, 
as the compliance date for natural gas- and oil-fired steam generating units and this date is consistent with the dates in the fuel type definitions. 
The EPA received comments that 
were generally supportive of the proposed subcategory definitions,
689 
and the EPA is finalizing the subcategory definitions as proposed. 
2. Options Considered for BSER 
The EPA has considered various 
methods for controlling CO
2emissions 
from natural gas- and oil-fired steam 
generating units to determine whether they meet the criteria for BSER. Co- firing natural gas cannot be the BSER for these units because natural gas- and oil- fired steam generating units already fire large proportions of natural gas. Most natural gas-fired steam generating units fire more than 90 percent natural gas on a heat input basis, and any oil-fired steam generating units that would potentially operate above an annual capacity factor of around 15 percent typically combust natural gas as a large proportion of their fuel as well. Nor is CCS a candidate for BSER. The utilization of most gas-fired units, and likely all oil-fired units, is relatively low, and as a result, the amount of CO
2 
available to be captured is low. However, the capture equipment would still need to be sized for the nameplate capacity of the unit. Therefore, the capital and operating costs of CCS would be high relative to the amount of CO
2available to be captured. 
Additionally, again due to lower utilization, the amount of IRC section 45Q tax credits that owner/operators could claim would be low. Because of the relatively high costs and the relatively low cumulative emission 
reduction potential for these natural gas- and oil-fired steam generating units, the EPA is not determining CCS as the BSER for them. 
The EPA has reviewed other possible 
controls but is not finalizing any of them as the BSER for natural gas- and oil-fired units either. Co-firing hydrogen in a boiler is technically possible, but there is limited availability of hydrogen now and in the near future and it should be prioritized for more efficient units. Additionally, for natural gas-fired steam generating units, setting a future standard based on hydrogen would likely have limited GHG reduction benefits given the low utilization of natural gas- and oil-fired steam generating units. Lastly, HRI for these types of units would face many of the same issues as for coal-fired steam generating units; in particular, HRI could result in a rebound effect that would increase emissions. 
However, the EPA recognizes that 
natural gas- and oil-fired steam generating units could possibly, over time, operate more, in response to other changes in the power sector. Additionally, some coal-fired steam generating units have converted to 100 percent natural gas-fired, and it is possible that more may do so in the future. The EPA also received several comments from industry stating plans to do so. Moreover, in part because the fleet continues to age, the plants may operate with degrading emission rates. In light of these possibilities, identifying the BSER and degrees of emission limitation for these sources would be useful to provide clarity and prevent backsliding in GHG performance. Therefore, the EPA is finalizing BSER for intermediate and base load natural gas- and oil-fired steam generating units to be routine methods of operation and maintenance, such that the sources could maintain the emission rates (on a lb/MWh-gross basis) currently maintained by the majority of the fleet across discrete ranges of annual capacity factor. The EPA is finalizing this BSER for intermediate load and base load natural gas- and oil-fired steam generating units, regardless of the operating horizon of the unit. 
A BSER based on routine methods of 
operation and maintenance is 
adequately demonstrated because units already operate with those practices. There are no or negligible additional costs because there is no additional technology that units are required to apply and there is no change in operation or maintenance that units must perform. Similarly, there are no adverse non-air quality health and environmental impacts or adverse 
impacts on energy requirements. Nor do they have adverse impacts on the energy sector from a nationwide or long-term perspective. The EPA’s modeling, which supports this final rule, indicates that by 2040, a number of natural gas-fired steam generating units will have remained in operation since 2030, although at reduced annual capacity factors. There are no CO
2reductions 
that may be achieved at the unit level, but applying routine methods of operation and maintenance as the BSER prevents increases in emission rates. Routine methods of operation and maintenance do not advance useful control technology, but this point is not significant enough to offset their benefits. 
At proposal, the EPA also took 
comment on a potential BSER of uniform fuels for low load natural gas- and oil-fired steam generating units. As noted earlier in this preamble, non-coal 
fossil fuels combusted in utility boilers typically include natural gas, distillate fuel oil (i.e., fuel oil No. 1 and No. 2), 
and residual fuel oil (i.e., fuel oil No. 5 
and No. 6). The EPA previously established heat-input based fuel composition as BSER in the 2015 NSPS (termed ‘‘clean fuels’’ in that rulemaking) for new non-base load natural gas- and multi-fuel-fired stationary combustion turbines (80 FR 64615–17; October 23, 2015), and the EPA is similarly finalizing lower- emitting fuels as BSER for new low load combustion turbines as described in section VIII.F of this preamble. For low load natural gas- and oil-fired steam generating units, the high variability in emission rates associated with the variability of load at the lower-load levels limits the benefits of a BSER based on routine maintenance and operation. That is because the high variability in emission rates would make it challenging to determine an emission rate (i.e., on a lb CO
2/MWh- 
gross basis) that could serve as the presumptive standard of performance that would reflect application of a BSER of routine operation and maintenance. On the other hand, for those units, a BSER of ‘‘uniform fuels’’ and an associated presumptive standard of performance based on a heat input basis, as described in section X.C.1.b.iii of this preamble, is reasonable. Therefore, the EPA is finalizing a BSER of uniform fuels for low load natural gas- and oil-fired steam generating units, with presumptive standards depending on fuel type detailed in section X.C.1.b.iii. 
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69084 FR 32520 (July 8, 2019). 3. Degree of Emission Limitation 
As discussed above, because the BSER 
for base load and intermediate load 
natural gas- and oil-fired steam 
generating units is routine operation and maintenance, which the units are, by definition, already employing, the degree of emission limitation by application of this BSER is no increase in emission rate on a lb CO
2/MWh-gross 
basis over an extended period of time (e.g., a year). 
For low load natural gas- and oil-fired 
steam generating units, the EPA is finalizing a BSER of uniform fuels, with a degree of emission limitation on a heat input basis consistent with a fixed 130 lb CO
2/MMBtu for natural gas-fired 
steam generating units and 170 lb CO 2/ 
MMBtu for oil-fired steam generating units. The degree of emission limitation for natural gas- and oil-fired steam generating units is higher than the corresponding values under 40 CFR part 60, subpart TTTT, because steam generating units may fire fuels with slightly higher carbon contents. 
4. Other Emission Reduction Measures 
Not Considered BSER 
a. Heat Rate Improvements 
Heat rate is a measure of efficiency 
that is commonly used in the power 
sector. The heat rate is the amount of energy input, measured in Btu, required to generate 1 kilowatt-hour (kWh) of electricity. The lower an EGU’s heat rate, the more efficiently it operates. As a result, an EGU with a lower heat rate will consume less fuel and emit lower amounts of CO
2and other air pollutants 
per kWh generated as compared to a less efficient unit. HRI measures include a variety of technology upgrades and operating practices that may achieve CO
2emission rate reductions of 0.1 to 
5 percent for individual EGUs. The EPA considered HRI to be part of the BSER in the CPP and to be the BSER in the ACE Rule. However, the reductions that may be achieved by HRI are small relative to the reductions from natural gas co-firing and CCS. Also, some facilities that apply HRI would, as a result of their increased efficiency, increase their utilization and therefore increase their CO
2emissions (as well as 
emissions of other air pollutants), a phenomenon that the EPA has termed the ‘‘rebound effect.’’ Therefore, the EPA is not finalizing HRI as a part of BSER. 
i. CO
2Reductions From HRI in Prior 
Rulemakings 
In the CPP, the EPA quantified 
emission reductions achievable through 
heat rate improvements on a regional basis by an analysis of historical 
emission rate data, taking into consideration operating load and ambient temperature. The Agency concluded that EGUs can achieve on average a 4.3 percent improvement in the Eastern Interconnection, a 2.1 percent improvement in the Western Interconnection, and a 2.3 percent improvement in the Texas Interconnection. See 80 FR 64789 (October 23, 2015). The Agency then applied all three of the building blocks to 2012 baseline data and quantified, in the form of CO
2emission rates, the 
reductions achievable in Each interconnection in 2030, and then selected the least stringent as a national performance rate. Id. at 64811–19. The 
EPA noted that building block 1 measures could not by themselves constitute the BSER because the quantity of emission reductions achieved would be too small and because of the potential for an increase in emissions due to increased utilization (i.e., the ‘‘rebound effect’’). 
ii. Updated CO
2Reductions From HRI 
The HRI measures include 
improvements to the boiler island (e.g., neural network system, intelligent sootblower system), improvements to the steam turbine (e.g., turbine overhaul 
and upgrade), and other equipment upgrades (e.g., variable frequency 
drives). Some regular practices that may recover degradation in heat rate to recent levels—but that do not result in upgrades in heat rate over recent design levels and are therefore not HRI measures—include practices such as in- kind replacements and regular surface cleaning (e.g., descaling, fouling 
removal). Specific details of the HRI measures are described in the final TSD, GHG Mitigation Measures for Steam Generating Units and an updated 2023 Sargent and Lundy HRI report (Heat Rate Improvement Method Costs and Limitations Memo), available in the docket. Most HRI upgrade measures achieve reductions in heat rate of less than 1 percent. In general, the 2023 Sargent and Lundy HRI report, which updates the 2009 Sargent and Lundy HRI report, shows that HRI achieve less reductions than indicated in the 2009 report, and shows that several HRI either have limited applicability or have already been applied at many units. Steam path overhaul and upgrade may achieve reductions up to 5.15 percent, with the average being around 1.5 
percent. Different combinations of HRI measures do not necessarily result in cumulative reductions in emission rate (e.g., intelligent sootblowing systems 
combined with neural network systems). Some of the HRI measures 
(e.g., variable frequency drives) only 
impact heat rate on a net generation basis by reducing the parasitic load on the unit and would thereby not be observable for emission rates measured on a gross basis. Assuming many of the HRI measures could be applied to the same unit, adding together the upper range of some of the HRI percentages could yield an emission rate reduction of around 5 percent. However, the reductions that the fleet could achieve on average are likely much smaller. As noted, the 2023 Sargent and Lundy HRI report notes that, in many cases, units have already applied HRI upgrades or that those upgrades would not be applicable to all units. The unit level reductions in emission rate from HRI are small relative to CCS or natural gas co- firing. In the CPP and ACE Rule, the EPA viewed CCS and natural gas co- firing as too costly to qualify as the BSER; those costs have fallen since those rules and, as a result, CCS and natural gas co-firing do qualify as the BSER for the long-term and medium- term subcategories, respectively. 
iii. Potential for Rebound in CO
2 
Emissions 
Reductions achieved on a rate basis 
from HRI may not result in overall 
emission reductions and could instead cause a ‘‘rebound effect’’ from increased utilization. A rebound effect would occur where, because of an improvement in its heat rate, a steam generating unit experiences a reduction in variable operating costs that makes the unit more competitive relative to other EGUs and consequently raises the unit’s output. The increase in the unit’s CO
2emissions associated with the 
increase in output would offset the reduction in the unit’s CO
2emissions 
caused by the decrease in its heat rate and rate of CO
2emissions per unit of 
output. The extent of the offset would depend on the extent to which the unit’s generation increased. The CPP did not consider HRI to be BSER on its own, in part because of the potential for a rebound effect. Analysis for the ACE Rule, where HRI was the entire BSER, observed a rebound effect for certain sources in some cases.
690In this action, 
where different subcategories of units 
are to be subject to different BSER measures, steam generating units in a hypothetical subcategory with HRI as BSER could experience a rebound effect. Because of this potential for perverse GHG emission outcomes resulting from deployment of HRI at certain steam generating units, coupled with the 
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691As discussed in section VII.C.1.a.ii.(D), the 
costs of CCS are reasonable based on the EPA’s 
$/MWh and $/ton metrics. As discussed in RTC section 2.16, the total annual costs of this rule are a small fraction of the revenues and capital costs of the electric power industry. relatively minor overall GHG emission 
reductions that would be expected from this measure, the EPA is not finalizing HRI as the BSER for any subcategory of existing coal-fired steam generating units. 
E. Additional Comments Received on 
the Emission Guidelines for Existing Steam Generating Units and Responses 
1. Consistency With West Virginia v. 
EPA and the Major Questions Doctrine 
Comment: Some commenters argued 
that the EPA’s determination that CCS is the BSER for existing coal-fired power plants is invalid under West Virginia v. EPA, 597 U.S. 697 (2022), and the major 
questions doctrine (MQD). Commenters state that for various reasons, coal-fired power plants will not install CCS and instead will be forced to retire their units. They point to the EPA’s IPM modeling which, they say, shows that many coal-fired power plants retire rather than install CCS. They add that, in this way, the rule effectively results in the EPA’s requiring generation- shifting from coal-fired generation to renewable and other generation, and thus is like the Clean Power Plan (CPP). For those reasons, they state that the rule raises a major question, and further that CAA section 111(d) does not contain a clear authorization for this type of rule. 
Response: The EPA discussed West 
Virginia and its articulation of the MQD 
in section V.B.6 of this preamble. 
The EPA disagrees with these 
comments. This rule is fully consistent with the Supreme Court’s interpretation of the EPA’s authority in West Virginia. The EPA’s determination that CCS—a traditional, add-on emissions control— is the BSER is consistent with the plain text of section 111. As explained in detail in section VII.C.1.a, for long-term coal-fired steam generating units, CCS meets all of the BSER factors: it is adequately demonstrated, of reasonable cost, and achieves substantial emissions reductions. That some coal-fired power plants will choose not to install emission controls and will instead retire does not raise major questions concerns. 
In West Virginia, the U.S. Supreme 
Court held that ‘‘generation-shifting’’ as the BSER for coal- and gas-fired units ‘‘effected a fundamental revision of the statute, changing it from one sort of scheme of regulation into an entirely different kind.’’ 597 U.S. at 728 (internal quotation marks, brackets, and citation omitted). The Court explained that prior CAA section 111 rules were premised on ‘‘more traditional air pollution control measures’’ that ‘‘focus on improving the performance of individual sources.’’ Id. at 727 (citing 
‘‘fuel-switching’’ and ‘‘add-on 
controls’’). The Court said that generation-shifting as the BSER was ‘‘unprecedented’’ because it was designed to ‘‘improve the overall power system by lowering the carbon intensity of power generation . . . by forcing a shift throughout the power grid from one type of energy source to another.’’ Id. at 727–28 (internal quotation marks, 
emphasis, and citation omitted). The Court cited statements by the then- Administrator describing the CPP as ‘‘not about pollution control so much as it was an investment opportunity for States, especially investments in renewables and clean energy.’’ Id. at 
728. The Court further concluded that the EPA’s view of its authority was virtually unbounded because the ‘‘EPA decides, for instance, how much of a switch from coal to natural gas is practically feasible by 2020, 2025, and 2030 before the grid collapses, and how high energy prices can go as a result before they become unreasonably exorbitant.’’ Id. at 729. 
Here, the EPA’s determination that 
CCS is the BSER does not affect a fundamental revision of the statute, nor is it unbounded. CCS is not directed at improvement of the overall power system. Rather, CCS is a traditional ‘‘add-on [pollution] control[ ]’’ akin to measures that the EPA identified as BSER in prior CAA section 111 rules. See id. at 727. It ‘‘focus[es] on improving the performance of individual sources’’—it reduces CO
2 
pollution from each individual source— because each affected source is able to apply it to its own facility to reduce its own emissions. Id. at 727. Further, the 
EPA determined that CCS qualifies as the BSER by applying the criteria specified in CAA section 111(a)(1)— including adequate demonstration, costs of control, and emissions reductions. See section VII.C.1.a of this preamble. 
Thus, CCS as the BSER does not ‘‘chang[e]’’ the statute ‘‘from one sort of scheme of regulation into an entirely different kind.’’ Id. at 728 (internal 
quotation marks, brackets, and citation omitted). 
Commenters contend that 
notwithstanding these distinctions, the choice of CCS as the BSER has the effect of shifting generation because modeling projections for the rule show that coal- fired generation will become less competitive, and gas-fired and renewable-generated electricity will be more competitive and dispatched more frequently. That some coal-fired sources may retire rather than reduce their CO
2 
pollution does not mean that the rule 
‘‘represents a transformative expansion [of EPA’s] regulatory authority’’. Id. at 
724. To be sure, this rule’s 
determination that CCS is the BSER imposes compliance costs on coal-fired power plants. That sources will incur costs to control their emissions of dangerous pollution is an unremarkable consequence of regulation, which, as the Supreme Court recognized, ‘‘may end up causing an incidental loss of coal’s market share.’’ Id. at 731 n.4.
691Indeed, 
ensuring that sources internalize the full costs of mitigating their impacts on human health and the environment is a central purpose of traditional environmental regulation. 
In particular, for the power sector, 
grid operators constantly shift generation as they dispatch electricity from sources based upon their costs. The EPA’s IPM modeling, which is based on the costs of the various types of electricity generation, projects these impacts. Viewed as a whole, these projected impacts show that, collectively, coal-fired power plants will likely produce less electricity, and other sources (like gas-fired units and renewable sources) will likely produce more electricity, but this pattern does not constitute a transformative expansion of statutory authority (EPA’s Power Sector Platform 2023 using IPM; final TSD, Power Sector Trends.) 
These projected impacts are best 
understood by comparing the IPM model’s ‘‘base case,’’ i.e., the projected 
electricity generation without any rule in place, to the model’s ‘‘policy case,’’ i.e., the projected electricity generation 
expected to result from this rule. The base case projects that many coal-fired units will retire over the next 20 years (EPA’s Power Sector Platform 2023 using IPM; final TSD, Power Sector Trends). Those projected retirements track trends over the past two decades where coal-fired units have retired in high numbers because gas-fired units and renewable sources have become increasingly able to generate lower-cost electricity. As more gas-fired and renewable generation sources deploy in the future, and as coal-fired units continue to age—which results in decreased efficiency and increased costs—the coal-fired units will become increasingly marginal and continue to retire (EPA’s Power Sector Platform 2023 using IPM; final TSD, Power Sector Trends.) That is true in the absence of this rule. The EPA’s modeling results 
also project that even if the EPA had 
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692Under the rule, sources are required to meet 
their CCS-based standard of performance by January 
1, 2032. IPM groups calendar years into 5-year periods, e.g., the 2035 model year and the 2040 
model year. January 1, 2032, falls into the 2035 model year. 693Sen. Muskie, Sept. 21, 1970, LH 226. 
694S. Rep. No. 91–1196, at 20 (Sept. 17, 1970), 
1970 CAA Legis. Hist. at 420 (discussing section 114 of the Senate Committee bill, which was the basis for CAA section 111(d)). Note that in the 1977 CAA Amendments, the House Committee Report made a similar statement. H.R. Rep. No. 95–294, at 42 (May 12, 1977), 1977 CAA Legis. Hist. at 2509 (discussing a provision in the House Committee bill that became CAA section 122, requiring EPA to determined BSER for long-term sources 
to be 40 percent co-firing, which requires significantly less capital investment, and not 90 percent capture CCS, a comparable number of sources would retire instead of installing controls. These results confirm that the primary cause for the projected retirements is the marginal profitability of the sources. 
Importantly, the base-case projections 
also show that some coal-fired units install CCS and run at high capacity factors, in fact, higher than they would have had they not installed CCS. This is because the IRC section 45Q tax credit significantly reduces the variable cost of operation for qualifying sources. This incentivizes sources to increase generation to maximize the tons of CO
2 
the CCS equipment captures, and thereby increase the amount of the tax credit they receive. In the ‘‘policy case,’’ beginning when the CCS requirement applies in the 2035 model year,
692some 
additional coal-fired units will likely install CCS, and also run at high capacity factors, again, significantly higher than they would have without CCS. Other units may retire rather than install emission controls (EPA’s Power Sector Platform 2023 using IPM; final TSD, Power Sector Trends). On balance, 
the coal-fired units that install CCS collectively generate nearly the same amount of electricity in the 2040 model year as do the group of coal-fired units in the base case. 
The policy case also shows that in the 
2045 model year, by which time the 12- year period for sources to claim the IRC section 45Q tax credit will have expired, most sources that install CCS retire due to the costs of meeting the CCS-based standards without the benefit of the tax credit. However, in fact, these projected outcomes are far from certain as the modeling results generally do not account for numerous potential changes that may occur over the next 20 or more years, any of which may enable these units to continue to operate economically for a longer period. Examples of potential changes include reductions in the operational costs of CCS through technological improvements, or the development of additional potential revenue streams for captured CO
2as the market for 
beneficial uses of CO 2continues to 
develop, among other possible changed economic circumstances (including the 
possible extension of the tax credits). In light of these potential significant 
developments, the EPA is committing to review and, if appropriate, revise the requirements of this rule by January 1, 2041, as described in section VII.F. 
In any event, the modeling projections 
showing that many sources retire instead of installing controls are in line with the trends for these units in the absence of the rule—as the coal-fired fleet ages and lower-cost alternatives become increasingly available, more operators will retire coal-fired units with or without this rule. In 2045, the average age of coal-fired units that have not yet announced retirement dates or coal-to-gas conversion by 2039 will be 61 years old. And, on average, between 2000 and 2022, even in the absence of this rule, coal-fired units generally retired at 53 years old. Thus, taken as a whole, this rule does not dramatically reduce the expected operating horizon of most coal-fired units. Indeed, for units that install CCS, the generous IRC section 45Q tax credit increases the competitiveness of these units, and it allows them to generate more electricity with greater profit than the sources would otherwise generate if they did not install CCS. 
The projected effects of the rule do 
not show the BSER—here, CCS—is akin to generation shifting, or otherwise represents an expansion of EPA authority with vast political or economic significance. As described above at VII.C.1.a.ii, CCS is an affordable emissions control technology. It is also very effective, reducing CO
2 
emissions from coal-fired units by 90 percent, as described in section VII.C.1.a.i. Indeed, as noted, the IRA tax credits make CCS so affordable that coal-fired units that install CCS run at higher capacity factors than they would otherwise. 
Considered as a whole, and in context 
with historical retirement trends, the projected impacts of this rule on coal- fired generating units do not raise MQD concerns. The projected impacts are merely incidental to the CCS control itself—the unremarkable consequence of marginally increasing the cost of doing business in a competitive market. Nor is the rule ‘‘transformative.’’ The rule does not ‘‘announce what the market share of coal, natural gas, wind, and solar must be, and then requiring plants to reduce 
operations or subsidize their competitors to get there.’’ 597 U.S. at 731 n.4. As noted above, coal-fired units that install CCS are projected to generate substantial amounts of electricity. The retirements that are projected to occur are broadly consistent with market trends over the past two decades, which show that coal-fired electricity production is generally less economic and less competitive than other forms of electricity production. That is, the retirements that the model predicts under this rule, and the structure of the industry that results, diverge little from the prior rate of retirements of coal-fired units over the past two decades. They also diverge little from the rate of retirements from sources that have already announced that they will retire, or from the additional retirements that IPM projects will occur in the base case (EPA’s Power Sector Platform 2023 using IPM; final TSD, Power Sector Trends). 
As discussed above, because much of 
the coal-fired fleet is operating on the edge of viability, many sources would retire instead of installing any meaningful CO
2emissions control— 
whether CCS, natural gas co-firing, or otherwise. Under commenters’ view that such retirements create a major question, any form of meaningful 
regulation of these sources would create a major question and effect a fundamental revision of the statute. That cannot possibly be so. Section 111(d)(1) plainly mandates regulation of these units, which are the biggest stationary source of dangerous CO
2 
emissions. 
The legislative history for the CAA 
further makes clear that Congress intended the EPA to promulgate regulations even where emissions controls had economic costs. At the time of the 1970 CAA Amendments, Congress recognized that the threats of air pollution to public health and welfare had grown urgent and severe. Sen. Edmund Muskie (D–ME), manager of the bill and chair of the Public Works Subcommittee on Air and Water Pollution, which drafted the bill, regularly referred to the air pollution problem as a ‘‘crisis.’’ As Sen. Muskie recognized, ‘‘Air pollution control will be cheap only in relation to the costs of lack of control.’’
693The Senate 
Committee Report for the 1970 CAA Amendments specifically discussed the precursor provision to section 111(d) and noted, ‘‘there should be no gaps in control activities pertaining to stationary source emissions that pose any significant danger to public health or welfare.’’
694Accordingly, some of the 
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study and then take action to regulate radioactive 
air pollutants and three other air pollutants). 
695See Sierra Club v. Costle, 657 F.2d 298, 313 
(D.C. Cir. 1981) (upholding NSPS imposing controls on SO
2emissions from coal-fired power plants 
when the ‘‘cost of the new controls . . . is substantial. EPA estimates that utilities will have to spend tens of billions of dollars by 1995 on pollution control under the new NSPS.’’). 
696168 Cong. Rec. E868 (August 23, 2022) 
(statement of Rep. Frank Pallone, Jr.); id. E879 
(August 26, 2022) (statement of Rep. Frank Pallone, Jr.). 697West Virginia v. EPA, 597 U.S, 697, 728 n.3 
(2022). 
698See 597 U.S. at 727. 
699In 1977, Congress clarified that for purposes 
of CAA section 111(a)(1)(A), concerning standards of performance for new and modified ‘‘fossil fuel- fired stationary sources’’ a standard or performance ‘‘shall reflect the degree of emission limitation and the percentage reduction achievable through application of the best technological system of 
continuous emission reduction which (taking into consideration the cost of achieving such emission reduction, any nonair quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated.’’ Clean Air Act 1977 Revisions (emphasis added). 700See H. Rep. No. 94–1175, 94th Cong., 2d Sess. 
(May 15, 1976) Part A, at 159 (listing the various purposes of the amendment to Section 111 adding the term ‘technological’: ‘‘Fourth, by using best control technology on large new fuel-burning stationary sources, these sources could burn higher sulfur fuel than if no technological means of reducing emissions were used. This means an expansion of the energy resources that could be burned in compliance with environmental requirements. Fifth, since large new fuel-burning sources would not rely on naturally low sulfur coal or oil to achieve compliance with new source performance standards, the low sulfur coal or oil that would have been burned in these major new sources could instead be used in older and smaller sources.’’) 
701In 1990, Congress removed this reference to a 
‘‘technological system’’, and the current text reads simply: ‘‘The term ‘‘standard of performance’’ means 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.’’ 42 U.S.C. 7411(a)(1). 
702Standards of Performance for Stationary 
Compression Ignition Internal Combustion Engines, 71 FR 39154 (July 11, 2006). In the preamble to the final rule, the EPA noted that for engines which had not previously used this new ultra-low sulfur fuel, additives would likely need to be added to the fuel to maintain appropriate lubricity. See id. at 39158. 
703Standards of Performance for Greenhouse Gas 
Emissions From New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units, 80 FR 64510, (October 23, 2015). 
704See id. at 64621. EPA’s prior CAA section 111 
rulemakings have imposed stringent requirements, at significant cost, in order to achieve significant emission reductions.
695 
Congress’s enactment of the IRA and 
IIJA further shows its view that reducing air pollution—specifically, in those laws, GHG emissions to address climate change—is a high priority. As discussed in section IV.E.1, that law provided funds for DOE grant and loan programs to support CCS, and extended and increased the IRC section 45Q tax credit for carbon capture. It also adopted the 
Low Emission Electricity Program (LEEP), which allocates funds to the EPA for the express purpose of using CAA regulatory authority to reduce GHG emissions from domestic electricity generation through use of its existing CAA authorities. CAA section 135, added by IRA section 60107. The EPA is promulgating the present rulemaking with those funds. The congressional sponsor of the LEEP made clear that it authorized the type of rulemaking that the EPA is promulgating today: he stated that the EPA may promulgate rulemaking under CAA section 111, based on CCS, to address CO
2emissions from fossil fuel- 
fired power plants, which may be ‘‘impactful’’ by having the ‘‘incidental effect’’ of leading some ‘‘companies . . . to choose to retire such plants.... ’ ’
696 
For these reasons, the rule here is 
consistent with the Supreme Court’s decision in West Virginia. The selection of CCS as the BSER for existing coal- fired units is a traditional, add-on control intended to reduce the emissions performance of individual sources. That some sources may retire instead of controlling their emissions does not otherwise show that the rule runs afoul of the MQD. The modeling projections for this rule show that the anticipated retirements are largely consistent with historical trends, and due to many coal-fired units’ advanced age and lack of competitiveness with lower cost methods of electricity generation. 2. Redefining the Source 
Comment: Some commenters 
contended that the proposed 40 percent 
natural gas co-firing performance standard violates legal precedent that bars the EPA from setting technology- based performance standards that would have the effect of ‘‘redefining the source.’’ They stated that this prohibition against the redefinition of the source bars the EPA from adopting the proposed performance standard for medium-term coal-fired EGUs, which requires such units to operate in a manner for which the unit was never designed to do, namely operate as a hybrid coal/natural gas co-firing generating unit and combusting 40 percent of its fuel input as natural gas (instead of coal) on an annual basis. 
Commenters argued that co-firing 
would constitute forcing one type of source to become an entirely different kind of source, and that the Supreme Court precluded such a requirement in West Virginia v. EPA when it stated in 
footnote 3 of that case that the EPA has ‘‘never ordered anything remotely like’’ a rule that would ‘‘simply require coal plants to become natural gas plants’’ and the Court ‘‘doubt[ed that EPA] could.’’
697 
Response: The EPA disagrees with 
these comments. 
Standards based on co-firing, as 
contemplated in this rule, are based on a ‘‘traditional pollution control measure,’’ in particular, ‘‘fuel switching,’’ as the Supreme Court recognized in West Virginia.
698Rules 
based on switching to a cleaner fuel are authorized under the CAA, an authorization directly acknowledged by Congress. Specifically, as part of the 1977 CAA Amendments, Congress required that the EPA base its standards regulating certain new sources, including power plants, on ‘‘technological’’ controls, rather than simply the ‘‘best system.’’
699Congress 
understood this to mean that new sources would be required to implement add-on controls, rather than merely relying on fuel switching, and noted 
that one of the purposes of this amendment was to allow new sources to burn high sulfur coal while still decreasing emissions, and thus to increase the availability of low sulfur coal for existing sources, which were not subject to the ‘‘technological’’ 
control requirement.
700In 1990, 
however, Congress removed the ‘‘technological’’ language, allowing the EPA to set fuel-switching based standards for both new and existing power plants.
701 
The EPA has a tradition of 
promulgating rules based on fuel switching. For example, the 2006 NSPS for stationary compression ignition internal combustion engines required the use of ultra-low sulfur diesel.
702 
Similarly, in the 2015 NSPS for EGUs,
703the EPA determined that the 
BSER for peaking plants was to burn primarily natural gas, with distillate oil used only as a backup fuel.
704Nor is 
this approach unique to CAA section 111; in the 2016 rule setting section 112 standards for hazardous air pollutant emissions from area sources, for example, the EPA finalized an alternative particulate matter (PM) standard that specified that certain oil- fired boilers would meet the applicable 
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705See National Emission Standards for 
Hazardous Air Pollutants for Area Sources: 
Industrial, Commercial, and Institutional Boilers, 81 FR 63112–01 (September 14, 2016). standard if they combusted only ultra- 
low-sulfur liquid fuel.705 
Moreover, the West Virginia Court’s 
statements in footnote 3 are irrelevant to the question of the validity of a 40 percent co-firing standard. There, the Court was referring to a complete transformation of the coal-fired unit to a 100 percent gas fired unit—a change that would require entirely repowering 
the unit. By contrast, increasing co- firing at existing coal-fired units to 40 percent would require only minor changes to the units’ boilers. In fact, many coal-fired units are already capable of co-firing some amount of gas without any changes at all, and several have fired at 40 percent and above in recent years. Of the 565 coal-fired EGUs operating at the end of 2021, 249 of them reported consuming natural gas as a fuel or startup source, 162 reported more than one month of consumption of natural gas at their boiler, and 29 co- fired at over 40 percent on an annual heat input basis in at least one year while also operating with annual capacity factors greater than 10 percent. For more on this, see section IV.C.2 of this preamble; see also the final TSD, GHG Mitigation Measures for Steam Generating Units. 
F. Commitment To Review and, If 
Appropriate, Revise Emission Guidelines for Coal-Fired Units 
The EPA recognizes that the IRC 45Q 
tax credit is a key component to the cost of CCS, as discussed in section VII.C.1.a.ii(C) of this preamble. The EPA further recognizes that for any affected source, the tax credit is currently available for a 12-year period and not subsequently. The tax credit is generally sufficient to defray the capital costs of CCS and much, if not all, of the operating costs during that 12-year period. Following the 12-year period, affected sources that continue to operate the CCS equipment would have higher costs of generation, due to the CCS operating costs, including parasitic load. Under certain circumstances, these higher costs could push the affected sources lower on the dispatch curve, and thereby lead to reductions in the amount of their generation, i.e., if 
affected sources are not able to replace the revenue from the tax credit with revenue from other sources, or if the price of electricity does not reflect any additional costs needed to minimize GHG emissions. However, the costs of CCS and the 
overall economic viability of operating 
CO
2capture at power plants are 
improving and can be expected to continue to improve in years to come. CO
2that is captured from fossil-fuel 
fired sources is currently beneficially used, including, for example, for enhanced oil recovery and in the food and beverage industry. There is much research into developing beneficial uses for many other industries, including construction, chemical manufacturing, graphite manufacturing. The demand for CO
2is expected to grow considerably 
over the next several decades. As a result, in the decades to come, affected sources may well be able to replace at least some of the revenues from the tax credit with revenues from the sale of CO
2. We discuss these potential 
developments in chapter 2 of the Response to Comments document, available in the rulemaking docket. 
In addition, numerous states have 
imposed requirements to decarbonize generation within their borders. Many utilities have also announced plans to decarbonize their fleet, including building small modular (advanced nuclear) reactors. Given the relatively high capital and fixed costs of small modular reactors, plans for their construction represent an expectation of higher future energy prices. This suggests that, in the decades to come, at least in certain areas of the country, affected sources may be able to maintain a place in the dispatch curve that allows them to continue to generate while they continue to operate CCS, even in the absence of additional revenues for CO
2. 
We discuss these potential developments in the final TSD, Power Sector Trends, available in the rulemaking docket. 
These developments, which may 
occur by the 2040s—the expiration of the 12-year period for the IRC 45Q tax credit, the potential development of the CO
2utilization market, and potential 
market supports for low-GHG generation—may significantly affect the costs to coal-fired steam EGUs of operating their CCS controls. As a result, the EPA will closely monitor these developments. Our efforts will include consulting with other agencies with expertise and information, 
including DOE, which currently has a program, the Carbon Conversion Program, in the Office of Carbon Management, that funds research into CO
2utilization. We regularly consult 
with stakeholders, including industry stakeholders, and will continue to do so. 
In light of these potential significant 
developments and their impacts, potentially positive or negative, on the economics of continued generation by affected sources that have installed CCS, the EPA is committing to review and, if appropriate, revise this rule by January 1, 2041. This commitment is included in the regulations that the EPA is promulgating with this rule. The EPA will conduct this review based on what we learn from monitoring these developments, as noted above. Completing this review and any appropriate revisions by that date will allow time for the states to revise, if necessary, standards applicable to affected sources, and for the EPA to act on those state revisions, by the early to mid-2040s. That is when the 12-year period for the 45Q tax credit is expected to expire for affected sources that comply with the CCS requirement by January 1, 2032, and when other significant developments noted above may be well underway. 
VIII. Requirements for New and 
Reconstructed Stationary Combustion Turbine EGUs and Rationale for Requirements 
A. Overview 
This section discusses the 
requirements for stationary combustion 
turbine EGUs that commence construction or reconstruction after May 23, 2023. The requirements are codified in 40 CFR part 60, subpart TTTTa. The EPA explains in section VIII.B of this document the two basic turbine technologies that are used in the power sector and are covered by 40 CFR part 60, subpart TTTTa. Those are simple cycle combustion turbines and combined cycle combustion turbines. The EPA also explains how these technologies are used in the three subcategories: low load turbines, intermediate load turbines, and base load turbines. Section VIII.C provides an overview of how stationary combustion turbines have been previously regulated. Section VIII.D discusses the EPA’s decision to revisit the standards for new and reconstructed turbines as part of the statutorily required 8-year review of the NSPS. Section VIII.E discusses changes that the EPA is finalizing in both applicability and subcategories in the new 40 CFR part 60, subpart TTTTa, as compared to those codified previously in 40 CFR part 60, subpart TTTT. Most notably, for new and reconstructed natural gas-fired combustion turbines, the EPA is finalizing BSER determinations and standards of performance for the three subcategories mentioned above—low load, intermediate load, and base load. 
Sections VIII.F and VIII.G of this 
document discuss the EPA’s 
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determination of the BSER for each of 
the three subcategories of combustion turbines and the applicable standards of performance, respectively. For low load combustion turbines, the EPA is finalizing a determination that the use of lower-emitting fuels is the appropriate BSER. For intermediate load combustion turbines, the EPA is finalizing a determination that highly efficient simple cycle generation is the appropriate BSER. For base load combustion turbines, the EPA is finalizing a determination that the BSER includes two components that correspond initially to a two-phase standard of performance. The first component of the BSER, with an immediate compliance date (phase 1), is highly efficient generation based on the performance of a highly efficient combined cycle turbine and the second component of the BSER, with a compliance date of January 1, 2032 (phase 2), is based on the use of CCS with a 90 percent capture rate, along with continued use of highly efficient generation. For base load turbines, the standards of performance corresponding to both components of the BSER would apply to all new and reconstructed sources that commence construction or reconstruction after May 23, 2023. The EPA occasionally refers to these standards of performance as the phase 1 or phase 2 standards. 
B. Combustion Turbine Technology 
For purposes of 40 CFR part 60, 
subparts TTTT and TTTTa, stationary 
combustion turbines include both simple cycle and combined cycle EGUs. Simple cycle turbines operate in the Brayton thermodynamic cycle and include three primary components: a multi-stage compressor, a combustion chamber (i.e., combustor), and a turbine. 
The compressor is used to supply large volumes of high-pressure air to the combustion chamber. The combustion chamber converts fuel to heat and expands the now heated, compressed air through the turbine to create shaft work. The shaft work drives an electric generator to produce electricity. Combustion turbines that recover the energy in the high-temperature exhaust—instead of venting it directly to the atmosphere—are combined cycle EGUs and can obtain additional useful electric output. A combined cycle EGU includes an HRSG operating in the Rankine thermodynamic cycle. The HRSG receives the high-temperature 
exhaust and converts the heat to mechanical energy by producing steam that is then fed into a steam turbine that, in turn, drives an electric generator. As the thermal efficiency of a stationary combustion turbine EGU is increased, 
less fuel is burned to produce the same amount of electricity, with a corresponding decrease in fuel costs and lower emissions of CO
2and, generally, 
of other air pollutants. The greater the output of electric energy for a given amount of fuel energy input, the higher the efficiency of the electric generation process. 
Combustion turbines serve various 
roles in the power sector. Some combustion turbines operate at low annual capacity factors and are available to provide temporary power during periods of high load demand. These turbines are often referred to as ‘‘peaking units.’’ Some combustion turbines operate at intermediate annual capacity factors and are often referred to as cycling or load-following units. Other combustion turbines operate at high annual capacity factors to serve base load demand and are often referred to as base load units. In this rulemaking, the EPA refers to these types of combustion turbines as low load, intermediate load, and base load, respectively. 
Low load combustion turbines 
provide reserve capacity, support grid reliability, and generally provide power during periods of peak electric demand. As such, the units may operate at or near their full capacity, but only for short periods, as needed. Because these units only operate occasionally, capital expenses are a major factor in the overall cost of electricity, and often, the lowest capital cost (and generally less efficient) simple cycle EGUs are intended for use only during periods of peak electric demand. Due to their low efficiency, these units require more fuel per MWh of electricity produced and their operating costs tend to be higher. Because of the higher operating costs, they are generally some of the last units in the dispatch order. Important characteristics for low load combustion turbines include their low capital costs, their ability to start quickly and to rapidly ramp up to full load, and their ability to operate at partial loads while maintaining acceptable emission rates and efficiencies. The ability to start quickly and rapidly attain full load is important to maximize revenue during periods of peak electric prices and to meet sudden shifts in demand. In 
contrast, under steady-state conditions, more efficient combined cycle EGUs are dispatched ahead of low load turbines and often operate at higher annual capacity factors. 
Highly efficient simple cycle turbines 
and flexible fast-start combined cycle turbines both offer different advantages and disadvantages when operating at intermediate loads. One of the roles of these intermediate or load following 
EGUs is to provide dispatchable backup power to support variable renewable generating sources (e.g., solar and 
wind). A developer’s decision as to whether to build a simple cycle turbine or a combined cycle turbine to serve intermediate load demand is based on several factors related to the intended operation of the unit. These factors would include how frequently the unit is expected to cycle between starts and stops, the predominant load level at which the unit is expected to operate, and whether this level of operation is expected to remain consistent or is expected to vary over the lifetime of the unit. In areas of the U.S. with vertically integrated electricity markets, utilities determine dispatch orders based generally on economic merit of individual units. Meanwhile, in areas of the U.S. inside organized wholesale electricity markets, owner/operators of individual combustion turbines control whether and how units will operate over time, but they do not necessarily control the precise timing of dispatch for units in any given day or hour. Such short-term dispatch decisions are often made by regional grid operators that determine, on a moment-to-moment basis, which available individual units should operate to balance supply and demand and other requirements in an optimal manner, based on operating costs, price bids, and/or operational characteristics. However, operating permits for simple cycle turbines often contain restrictions on the annual hours of operation that owners/operators incorporate into longer-term operating plans and short-term dispatch decisions. 
Intermediate load combustion 
turbines vary their generation, especially during transition periods between low and high electric demand. Both high-efficiency simple cycle turbines and flexible fast-start combined cycle turbines can fill this cycling role. While the ability to start quickly and quickly ramp up is important, efficiency is also an important characteristic. These combustion turbines generally have higher capital costs than low load combustion turbines but are generally less expensive to operate. 
Base load combustion turbines are 
designed to operate for extended 
periods at high loads with infrequent starts and stops. Quick-start capability and low capital costs are less important than low operating costs. High- efficiency combined cycle turbines typically fill the role of base load combustion turbines. 
The increase in generation from 
variable renewable energy sources during the past decade has impacted the 
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706Dispatchable generating sources are those that 
can be turned on and off and adjusted to provide 
power to the electric grid based on the demand for electricity. Variable (sometimes referred to as intermittent) generating sources are those that supply electricity based on external factors that are not controlled by the owner/operator of the source (e.g., wind and solar sources). 
707The EPA refers to the capability to combust 
250 MMBtu/h of fossil fuel as the ‘‘base load rating criterion.’’ Note that 250 MMBtu/h is equivalent to 73 MW or 260 GJ/h heat input. way in which dispatchable generating 
resources operate.706For example, the 
electric output from wind and solar generating sources fluctuates daily and seasonally due to increases and decreases in the wind speed or solar intensity. Due to this variable nature of wind and solar, dispatchable EGUs, 
including combustion turbines as well as other technologies like energy storage, are used to ensure the reliability of the electric grid. This requires dispatchable power plants to have the ability to quickly start and stop and to rapidly and frequently change load— much more often than was previously needed. These are important characteristics of the combustion turbines that provide firm backup capacity. Combustion turbines are much more flexible than coal-fired utility boilers in this regard and have played an important role during the past decade in ensuring that electric supply and demand are balanced. 
As discussed in section IV.F.2 of this 
preamble, in the final TSD, Power Sector Trends, and in the accompanying RIA, the EPA’s Power Sector Platform 2023 using IPM projects that natural gas-fired combustion turbines will continue to play an important role in meeting electricity demand. However, that role is projected to evolve as additional renewable and non- renewable low-GHG generation and energy storage technologies are added to the grid. Energy storage technologies can store energy during periods when generation from renewable resources is high relative to demand and can provide electricity to the grid during other periods. Energy storage technologies are projected to reduce the need for base load fossil fuel-fired firm dispatchable power plants, and the capacity factors of combined cycle EGUs are forecast to decline by 2040. 
C. Overview of Regulation of Stationary 
Combustion Turbines for GHGs 
As explained earlier in this preamble, 
the EPA originally regulated new and reconstructed stationary combustion turbine EGUs for emissions of GHGs in 2015 under 40 CFR part 60, subpart TTTT. In 40 CFR part 60, subpart TTTT, the EPA created three subcategories: two for natural gas-fired combustion turbines and one for multi-fuel-fired combustion turbines. For natural gas- fired turbines, the EPA created a 
subcategory for base load turbines and a separate subcategory for non-base load turbines. Base load turbines were defined as combustion turbines with electric sales greater than a site-specific electric sales threshold based on the design efficiency of the combustion turbine. Non-base load turbines were defined as combustion turbines with a capacity factor less than or equal to the site-specific electric sales threshold. For base load turbines, the EPA set a standard of 1,000 lb CO
2/MWh-gross 
based on efficient combined cycle turbine technology. For non-base load and multi-fuel-fired turbines, the EPA set a standard based on the use of lower- emitting fuels that varied from 120 lb CO
2/MMBtu to 160 lb CO 2/MMBtu, 
depending upon whether the turbine burned primarily natural gas or other lower-emitting fuels. 
D. Eight-Year Review of NSPS 
CAA section 111(b)(1)(B) requires the 
Administrator to ‘‘at least every 8 years, 
review and, if appropriate, revise [the NSPS] . . . .’’ The provision further 
provides that ‘‘the Administrator need not review any such standard if the Administrator determines that such review is not appropriate in light of readily available information on the efficacy of such [NSPS].’’ 
The EPA promulgated the NSPS for 
GHG emissions for stationary 
combustion turbines in 2015. Announcements and modeling projections show that project developers are building new fossil fuel-fired combustion turbines and have plans to continue building additional capacity. Because the emissions from this added capacity have the potential to be large and these units are likely to have long operating lives (25 years or more), it is important to limit emissions from these new units. Accordingly, in this final rule, the EPA is updating the NSPS for newly constructed and reconstructed fossil fuel-fired stationary combustion turbines. 
E. Applicability Requirements and 
Subcategorization 
This section describes the 
amendments to the specific applicability criteria for non-fossil fuel- fired EGUs, industrial EGUs, CHP EGUs, and combustion turbine EGUs not connected to a natural gas pipeline. The EPA is also making certain changes to the applicability requirements for stationary combustion turbines affected by this final rule as compared to those for sources affected by the 2015 NSPS. The amendments are described below and include the elimination of the multi-fuel-fired subcategory, further 
binning non-base load combustion turbines into low load and intermediate load subcategories and establishing a capacity factor threshold for base load combustion turbines. 
1. Applicability Requirements 
In general, the EPA refers to fossil 
fuel-fired EGUs that would be subject to 
a CAA section 111 NSPS as ‘‘affected’’ EGUs or units. An EGU is any fossil fuel-fired electric utility steam generating unit (i.e., a utility boiler or 
IGCC unit) or stationary combustion turbine (in either simple cycle or combined cycle configuration). To be considered an affected EGU under the 2015 NSPS at 40 CFR part 60, subpart TTTT, the unit must meet the following applicability criteria: The unit must: (1) be capable of combusting more than 250 MMBtu/h (260 gigajoules per hour (GJ/ h)) of heat input of fossil fuel (either alone or in combination with any other 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).
707However, 40 CFR part 60, 
subpart TTTT, includes applicability 
exemptions for certain EGUs, including: (1) non-fossil fuel-fired units subject to a federally enforceable permit that limits the use of fossil fuels to 10 percent or less of their heat input capacity on an annual basis; (2) CHP units that are subject to a federally enforceable permit limiting annual net electric sales to no more than either the unit’s design efficiency multiplied by its potential electric output, or 219,000 MWh, whichever is greater; (3) stationary combustion turbines that are not physically capable of combusting natural gas (e.g., those that are not 
connected to a natural gas pipeline); (4) utility boilers and IGCC units that have always been subject to a federally enforceable permit limiting annual net electric sales to one-third or less of their potential electric output (e.g., limiting 
hours of operation to less than 2,920 hours annually) or limiting annual electric sales to 219,000 MWh or less; (5) municipal waste combustors that are subject to 40 CFR part 60, subpart Eb; (6) commercial or industrial solid waste incineration units subject to 40 CFR part 60, subpart CCCC; and (7) certain projects under development, as discussed in the preamble for the 2015 final NSPS. 
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708Auxiliary equipment such as boilers or 
combustion turbines that provide heat or electricity 
to the primary EGU (including to any control equipment) would still be considered integrated equipment and included as part of the affected facility. a. Revisions to 40 CFR Part 60, Subpart 
TTTT 
The EPA is amending 40 CFR 60.5508 
and 60.5509 to reflect that stationary combustion turbines that commenced construction after January 8, 2014, or reconstruction after June 18, 2014, and before May 24, 2023, and that meet the relevant applicability criteria are subject to 40 CFR part 60, subpart TTTT. For steam generating EGUs and IGCC units, 40 CFR part 60, subpart TTTT, remains applicable for units constructed after January 8, 2014, or reconstructed after June 18, 2014. The EPA is finalizing 40 CFR part 60, subpart TTTTa, to be applicable to stationary combustion turbines that commence construction or reconstruction after May 23, 2023, and that meet the relevant applicability criteria. 
b. Revisions to 40 CFR Part 60, Subpart 
TTTT, That Are Also Included in 40 CFR Part 60, Subpart TTTTa 
The EPA is finalizing that 40 CFR part 
60, subpart TTTT, and 40 CFR part 60, subpart TTTTa, use similar regulatory text except where specifically stated. This section describes amendments included in both subparts. 
i. Applicability to Non-Fossil Fuel-Fired 
EGUs 
The current non-fossil applicability 
exemption in 40 CFR part 60, subpart TTTT, is based strictly on the combustion of non-fossil fuels (e.g., biomass). To be considered a non-fossil fuel-fired EGU, the EGU must be both: (1) Capable of combusting more than 50 percent non-fossil fuel and (2) subject to a federally enforceable permit condition limiting the annual heat input capacity for all fossil fuels combined of 10 percent or less. The current language does not take heat input from non- combustion sources (e.g., solar thermal) 
into account. Certain solar thermal installations have natural gas backup burners larger than 250 MMBtu/h. As currently treated in 40 CFR part 60, subpart TTTT, these solar thermal installations are not eligible to be considered non-fossil units because they are not capable of deriving more than 50 percent of their heat input from the combustion of non-fossil fuels. Therefore, solar thermal installations that include backup burners could meet the applicability criteria of 40 CFR part 60, subpart TTTT, even if the burners are limited to an annual capacity factor of 10 percent or less. These EGUs would readily comply with the standard of performance, but the reporting and recordkeeping would increase costs for these EGUs. The EPA proposed and is finalizing 
several amendments to align the applicability criteria with the original intent to cover only fossil fuel-fired EGUs. These amendments ensure that solar thermal EGUs with natural gas backup burners, like other types of non- fossil fuel-fired units that derive most of their energy from non-fossil fuel sources, are not subject to the requirements of 40 CFR part 60, subpart TTTT or TTTTa. Amending the applicability language to include heat input derived from non-combustion sources allows these facilities to avoid the requirements of 40 CFR part 60, subpart TTTT or TTTTa, by limiting the use of the natural gas burners to less than 10 percent of the capacity factor of the backup burners. Specifically, the EPA is amending the definition of non- fossil fuel-fired EGUs from EGUs capable of ‘‘combusting 50 percent or more non-fossil fuel’’ to EGUs capable of ‘‘deriving 50 percent or more of the 
heat input from non-fossil fuel at the base load rating’’ (emphasis added). The definition of base load rating is also being amended to include the heat input from non-combustion sources (e.g., solar 
thermal). 
Revising ‘‘combusting’’ to ‘‘deriving’’ 
in the amended non-fossil fuel applicability language ensures that 40 CFR part 60, subparts TTTT and TTTTa, cover the fossil fuel-fired EGUs that the original rule was intended to cover, while minimizing unnecessary costs to EGUs fueled primarily by steam generated without combustion (e.g., thermal energy supplied through the use of solar thermal collectors). The corresponding change in the base load rating to include the heat input from non-combustion sources is necessary to determine the relative heat input from fossil fuel and non-fossil fuel sources. 
ii. Industrial EGUs 
(A) Applicability to Industrial EGUs 
In simple terms, the current 
applicability provisions in 40 CFR part 
60, subpart TTTT, require that an EGU be capable of combusting more than 250 MMBtu/h of fossil fuel and be capable of selling 25 MW to a utility distribution system to be subject to 40 CFR part 60, subpart TTTT. These applicability provisions exclude industrial EGUs. However, the definition of an EGU also includes ‘‘integrated equipment that provides electricity or useful thermal output.’’ This language facilitates the integration of non-emitting generation and avoids energy inputs from non- affected facilities being used in the emission calculation without also considering the emissions of those facilities (e.g., an auxiliary boiler 
providing steam to a primary boiler). This language could result in certain large processes being included as part of the EGU and meeting the applicability criteria. For example, the high- temperature exhaust from an industrial process (e.g., calcining kilns, dryer, 
metals processing, or carbon black production facilities) that consumes fossil fuel could be sent to a HRSG to produce electricity. If the industrial process uses more than 250 MMBtu/h heat input and the electric sales exceed the applicability criteria, then the unit could be subject to 40 CFR part 60, subpart TTTT or TTTTa. This is potentially problematic for multiple reasons. First, it is difficult to determine the useful output of the EGU (i.e., HRSG) since part of the useful output is included in the industrial process. In addition, the fossil fuel that is combusted could have a relatively high CO
2emissions rate on a lb/MMBtu 
basis, making it potentially problematic to meet the standard of performance using efficient generation. This could result in the owner/operator reducing the electric output of the industrial facility to avoid the applicability criteria. Finally, the compliance costs associated with 40 CFR part 60, subpart TTTT or TTTTa, could discourage the development of environmentally beneficial projects. 
To avoid these outcomes, the EPA is, 
as proposed, amending the applicability provision that exempts EGUs where greater than 50 percent of the heat input is derived from an industrial process that does not produce any electrical or mechanical output or useful thermal output that is used outside the affected EGU.
708Reducing the output or not 
developing industrial electric generating projects where the majority of the heat input is derived from the industrial process itself would not necessarily result in reductions in GHG emissions from the industrial facility. However, the electricity that would have been produced from the industrial project could still be needed. Therefore, projects of this type provide significant environmental benefit by providing additional useful output with little if any additional environmental impact. Including these types of projects would result in regulatory burden without any associated environmental benefit and could discourage project development, 
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70940 CFR part 60, subpart TTTT, currently lists 
‘‘ASME PTC 22 Gas Turbines,’’ ‘‘ASME PTC 46 
Overall Plant Performance,’’ and ‘‘ISO 2314 Gas turbines—acceptance tests’’ as approved methods to determine the design efficiency. leading to potential overall increases in 
GHG emissions. 
(B) Industrial EGUs Electric Sales 
Threshold Permit Requirement 
The current electric sales applicability 
exemption in 40 CFR part 60, subpart TTTT, for non-CHP steam generating units includes the provision that EGUs have ‘‘always been subject to a federally enforceable permit limiting annual net electric sales to one-third or less of their potential electric output (e.g., limiting 
hours of operation to less than 2,920 hours annually) or limiting annual electric sales to 219,000 MWh or less’’ (emphasis added). The justification for this restriction includes that the 40 CFR part 60, subpart Da, applicability language includes ‘‘constructed for the purpose of . . .’’ and the Agency concluded that the intent was defined by permit conditions (80 FR 64544; October 23, 2015). This applicability criterion is important both for determining applicability with the new source CAA section 111(b) requirements and for determining whether existing steam generating units are subject to the existing source CAA section 111(d) requirements. For steam generating units that commenced construction after September 18, 1978, the applicability of 40 CFR part 60, subpart Da, would be relatively clear as to what criteria pollutant NSPS is applicable to the facility. However, for steam generating units that commenced construction prior to September 18, 1978, or where the owner/operator determined that criteria pollutant NSPS applicability was not critical to the project (e.g., emission controls were sufficient to comply with either the EGU or industrial boiler criteria pollutant NSPS), owners/operators might not have requested that an electric sales permit restriction be included in the operating permit. Under the current applicability language, some onsite EGUs could be covered by the existing source CAA section 111(d) requirements even if they have never sold electricity to the grid. To avoid covering these industrial EGUs, the EPA proposed and is finalizing amendments to the electric sales exemption in 40 CFR part 60, subparts TTTT and TTTTa, to read, ‘‘annual net electric sales have never exceeded one-third of its potential electric output or 219,000 MWh, whichever is greater, and is [the ‘‘always been’’ would be deleted] subject to a federally enforceable permit limiting 
annual net electric sales to one-third or less of their potential electric output (e.g., limiting hours of operation to less 
than 2,920 hours annually) or limiting annual electric sales to 219,000 MWh or less’’ (emphasis added). EGUs that 
reduce current generation will continue to be covered as long as they sold more than one-third of their potential electric output at some time in the past. The revisions make it possible for an owner/ operator of an existing industrial EGU to provide evidence to the Administrator that the facility has never sold electricity in excess of the electricity sales threshold and to modify their permit to limit sales in the future. Without the amendment, owners/ operators of any non-CHP industrial EGU capable of selling 25 MW would be subject to the existing source CAA section 111(d) requirements even if they have never sold any electricity. Therefore, the EPA is eliminating the requirement that existing industrial EGUs must have always been subject to a permit restriction limiting net electric sales. 
iii. Determination of the Design 
Efficiency 
The design efficiency (i.e., the 
efficiency of converting thermal energy to useful energy output) of a combustion turbine is used to determine the electric sales applicability threshold. In 40 CFR part 60, subpart TTTT, the sales criteria are based in part on the individual EGU design efficiency. Three methods for determining the design efficiency are currently provided in 40 CFR part 60, subpart TTTT.
709Since the 2015 NSPS 
was finalized, the EPA has become aware that owners/operators of certain existing EGUs do not have records of the original design efficiency. These units would not be able to readily determine whether they meet the applicability criteria (and would therefore be subject to CAA section 111(d) requirements for existing sources) in the same way that 111(b) sources would be able to determine if the facility meets the applicability criteria. Many of these EGUs are CHP units that are unlikely to meet the 111(b) applicability criteria and would therefore not be subject to any future 111(d) requirements. However, the language in the 2015 NSPS would require them to conduct additional testing to demonstrate this. The requirement would result in burden to the regulated community without any environmental benefit. The electricity generating market has changed, in some cases dramatically, during the lifetime of existing EGUs, especially concerning ownership. As a result of acquisitions and mergers, original EGU design efficiency documentation, as well as performance guarantee results that affirmed the design efficiency, may no longer exist. Moreover, such documentation and results may not be relevant for current EGU efficiencies, as changes to original EGU configurations, upon which the original design efficiencies were based, render those original design efficiencies moot, meaning that there would be little reason to maintain former design efficiency documentation since it would not comport with the efficiency associated with current EGU configurations. As the three specified methods would rely on documentation from the original EGU configuration performance guarantee testing, and results from that documentation may no longer exist or be relevant, it is appropriate to allow other means to demonstrate EGU design efficiency. To reduce potential future compliance burden, the EPA proposed and is finalizing in 40 CFR part 60, subparts TTTT and TTTTa, to allow alternative methods as approved by the Administrator on a case-by-case basis. Owners/operators of EGUs can petition the Administrator in writing to use an alternate method to determine the design efficiency. The Administrator’s discretion is intentionally left broad and can extend to other American Society of Mechanical Engineers (ASME) or International Organization for Standardization (ISO) methods as well as to operating data to demonstrate the design efficiency of the EGU. The EPA also proposed and is finalizing a change to the applicability of paragraph 60.8(b) in table 3 of 40 CFR part 60, subpart TTTT, from ‘‘no’’ to ‘‘yes’’ and that the applicability of paragraph 60.8(b) in table 3 of 40 CFR part 60, subpart TTTTa, is ‘‘yes.’’ This allows the Administrator to approve alternatives to the test methods specified in 40 CFR part 60, subparts TTTT and TTTTa. 
c. Applicability for 40 CFR Part 60, 
Subpart TTTTa 
This section describes applicability 
criteria that are only incorporated into 40 CFR part 60, subpart TTTTa, and that 
differ from the requirements in 40 CFR part 60, subpart TTTT. 
Section 111 of the CAA defines a new 
or modified source for purposes of a given NSPS as any stationary source that commences construction or modification after the publication of the proposed regulation. Thus, the standards of performance apply to EGUs that commence construction or reconstruction after the date of proposal of this rule—May 23, 2023. EGUs that commenced construction after the date 
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71040 CFR 60.2. 
71140 CFR 60.15(a). 
712The EPA refers to the capability to combust 
250 MMBtu/h of fossil fuel as the ‘‘base load rating 
criterion.’’ Note that 250 MMBtu/h is equivalent to 73 MW or 260 GJ/h heat input. 71340 CFR part 60, subpart TTTT, also includes 
coverage for owners/operators of combustion 
turbines in non-contiguous areas. However, owners/ operators of combustion turbines not capable of combusting natural gas (e.g., not connected to a 
natural gas pipeline) are not subject to the rule. This exemption covers many combustion turbines in non-contiguous areas. 714For contractual reasons, many developers of 
CHP units sell the majority of the generated electricity to the electricity distribution grid. Owners/operators of both the CHP unit and thermal host can subtract the site purchased power when determining net electric sales. Third-party developers that do not own the thermal host can also subtract the purchased power of the thermal host when determining net electric sales for applicability purposes. of the proposal for the 2015 NSPS and 
by May 23, 2023, will remain subject to the standards of performance promulgated in the 2015 NSPS. A modification is any physical change in, or change in the method of operation of, an existing source that increases the amount of any air pollutant emitted to which a standard applies.
710The NSPS 
general provisions (40 CFR part 60, subpart A) provide that an existing source is considered a new source if it undertakes a reconstruction.
711 
The EPA is finalizing the same 
applicability requirements in 40 CFR part 60, subpart TTTTa, as the applicability requirements in 40 CFR part 60, subpart TTTT. The stationary combustion turbine must meet the following applicability criteria: The stationary combustion turbine must: (1) be capable of combusting more than 250 MMBtu/h (260 gigajoules per hour (GJ/ h)) of heat input of fossil fuel (either alone or in combination with any other 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).
712In addition, the EPA 
proposed and is finalizing in 40 CFR part 60, subpart TTTTa, to include applicability exemptions for stationary combustion turbines that are: (1) capable of deriving 50 percent or more of the heat input from non-fossil fuel at the base load rating and subject to a federally enforceable permit condition limiting the annual capacity factor for all fossil fuels combined of 10 percent (0.10) or less; (2) combined heat and power units subject to a federally enforceable permit condition limiting annual net electric sales to no more than 219,000 MWh or the product of the design efficiency and the potential electric output, whichever is greater; (3) serving a generator along with other steam generating unit(s), IGCC, or stationary combustion turbine(s) where the effective generation capacity is 25 MW or less; (4) municipal waste combustors that are subject to 40 CFR part 60, subpart Eb; (5) commercial or industrial solid waste incineration units subject to 40 CFR part 60, subpart CCCC; and (6) deriving greater than 50 percent of heat input from an industrial process that does not produce any electrical or mechanical output that is used outside the affected stationary combustion turbine. 
The EPA proposed the same 
requirements to combustion turbines in non-continental areas (i.e., Hawaii, the 
Virgin Islands, Guam, American Samoa, the Commonwealth of Puerto Rico, and the Northern Mariana Islands) and non- contiguous areas (non-continental areas and Alaska) as the EPA did for comparable units in the contiguous 48 states.
713However, the Agency solicited 
comment on whether owners/operators of new and reconstructed combustion turbines in non-continental and non- contiguous areas should be subject to different requirements. Commenters generally commented that due to the difference in non-contiguous areas relative to the lower 48 states, the 
proposed requirements should not apply to owners/operators of new or reconstructed combustion turbines in non-contiguous areas. The Agency has considered these comments and is finalizing that only the initial BSER component will be applicable to owners/operators of combustion turbines located in non-contiguous areas. Therefore, owners/operators of base load combustions turbines would not be subject to the CCS-based numerical standards in 2032 and would continue to comply with the efficiency- based numeric standard. Based on information reported in the 2022 EIA Form EIA–860, there are no planned new combustion turbines in either Alaska or Hawaii. In addition, since 2015 no new combustion turbines have commenced operation in Hawaii. Two new combustion turbine facilities totaling 190 MW have commenced operation in Alaska since 2015. One facility is a combined cycle CHP facility and the other is at an industrial facility and neither facility would likely meet the applicability of 40 CFR part 60, subpart TTTTa. Therefore, not finalizing phase-2 BSER for non-continental and non-contiguous areas will have limited, if any, impacts on emissions or costs. The EPA notes that the Agency has the authority to amend this decision in future rulemakings. 
i. Applicability to CHP Units 
For 40 CFR part 60, subpart TTTT, 
owners/operators of CHP units calculate 
net electric sales and net energy output using an approach that includes ‘‘at least 20.0 percent of the total gross or net energy output consists of electric or direct mechanical output.’’ It is unlikely that a CHP unit with a relatively low electric output (i.e., less than 20.0 
percent) would meet the applicability criteria. However, if a CHP unit with less than 20.0 percent of the total output consisting of electricity were to meet the applicability criteria, the net electric sales and net energy output would be calculated the same as for a traditional non-CHP EGU. Even so, it is not clear that these CHP units would have less environmental benefit per unit of electricity produced than would more traditional CHP units. For 40 CFR part 60, subpart TTTTa, the EPA proposed and is finalizing to eliminate the restriction that CHP units produce at least 20.0 percent electrical or mechanical output to qualify for the CHP-specific method for calculating net electric sales and net energy output. 
In the 2015 NSPS, the EPA did not 
issue standards of performance for certain types of sources—including industrial CHP units and CHPs that are subject to a federally enforceable permit limiting annual net electric sales to no more than the unit’s design efficiency multiplied by its potential electric output, or 219,000 MWh or less, whichever is greater. For CHP units, the approach in 40 CFR part 60, subpart TTTT, for determining net electric sales for applicability purposes allows the owner/operator to subtract the purchased power of the thermal host facility. The intent of the approach is to determine applicability similarly for third-party developers and CHP units owned by the thermal host facility.
714 
However, as written in 40 CFR part 60, subpart TTTT, each third-party CHP unit would subtract the entire electricity use of the thermal host facility when determining its net electric sales. It is clearly not the intent of the provision to allow multiple third-party developers that serve the same thermal host to all subtract the purchased power of the thermal host facility when determining net electric sales. This would result in counting the purchased power multiple times. In addition, it is not the intent of the provision to allow a CHP developer to provide a trivial amount of useful thermal output to multiple thermal hosts and then subtract all the thermal hosts’ purchased power when determining net electric sales for applicability purposes. The EPA 
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715Percent electric sales thresholds, capacity 
factor thresholds, and annual hours of operation 
limitations all categorize combustion turbines based on utilization. 
716While utilization and electric sales are often 
similar, the EPA uses electric sales because the focus of the applicability is facilities that sell electricity to the grid and not industrial facilities where the electricity is generated primarily for use onsite. 
717The EPA used manufacturers’ designations for 
frame and aeroderivative combustion turbines. proposed and is finalizing in 40 CFR 
part 60, subpart TTTTa, to limit to the amount of thermal host purchased power that a third-party CHP developer can subtract for electric sales when determining net electric sales equivalent to the percentage of useful thermal output provided to the host facility by the specific CHP unit. This approach eliminates both circumvention of the intended applicability by sales of trivial amounts of useful thermal output and double counting of thermal host- purchased power. 
Finally, to avoid potential double 
counting of electric sales, the EPA proposed and is finalizing that for CHP units determining net electric sales, purchased power of the host facility be determined based on the percentage of thermal power provided to the host facility by the specific CHP facility. 
ii. Non-Natural Gas Stationary 
Combustion Turbines 
There is currently an exemption in 40 
CFR part 60, subpart TTTT, for stationary combustion turbines that are not physically capable of combusting natural gas (e.g., those that are not 
connected to a natural gas pipeline). While combustion turbines not connected to a natural gas pipeline meet the general applicability of 40 CFR part 60, subpart TTTT, these units are not subject to any of the requirements. The EPA is not including in 40 CFR part 60, 
subpart TTTTa, the exemption for stationary combustion turbines that are not physically capable of combusting natural gas. As described in the standards of performance section, owners/operators of combustion turbines burning fuels with a higher heat input emission rate than natural gas would adjust the natural gas-fired emissions rate by the ratio of the heat input-based emission rates. The overall result is that new stationary combustion turbines combusting fuels with higher GHG emissions rates than natural gas on a lb CO
2/MMBtu basis must maintain 
the same efficiency compared to a natural gas-fired combustion turbine and comply with a standard of performance based on the identified BSER. 
2. Subcategorization 
In this final rule, the EPA is 
continuing to include both simple and 
combined cycle turbines in the definition of a stationary combustion turbine, and like in prior rules for this source category, the Agency is finalizing three subcategories—low load, intermediate load, and base load combustion turbines. These subcategories are determined based on electric sales (i.e., utilization) relative to 
the combustion turbines’ potential electric output to an electric distribution network on both a 12-operating month and 3-year rolling average basis. The applicable subcategory is determined each operating month and a stationary combustion turbine can switch subcategories if the owner/operator changes the way the facility is operated. Subcategorization based on percent electric sales is a proxy for how a combustion turbine operates and for determining the BSER and corresponding emission standards. For example, low load combustion turbines tend to spend a relatively high percentage of operating hours starting and stopping. However, within each subcategory not all combustion turbines operate the same. Some low load combustion turbines operate with less starting and stopping, but in general, combustion turbines tend to operate with fewer starts and stops (i.e., more 
steady-state hours of operation) with increasing percentages of electric sales. The BSER for each subcategory is based on representative operation of the combustion turbines in that subcategory and on what is achievable for the subcategory as a whole. 
Subcategorization by electric sales is 
similar, but not identical, to subcategorizing by heat input-based capacity factors or annual hours of operation limits.
715The EPA has 
determined that, for NSPS purposes, electric sales is appropriate because it reflects operational limitations inherent in the design of certain units, and also that—given these differences—certain emission reduction technologies are more suitable for some units than for others.
716This subcategorization 
approach is also consistent with industry practice. For example, operating permits for simple cycle turbines often include annual operating hour limitations of 1,500 to 4,000 hours annually. When average hourly capacity factors (i.e., duty cycles) are accounted 
for, these hourly restrictions are similar to annual capacity factor restrictions of approximately 15 percent and 40 percent, respectively. The owners or operators of these combustion turbines never intend for them to provide base load power. In contrast, operating permits do not typically restrict the 
number of hours of annual operation for combined cycle turbines, reflecting that these types of combustion turbines are intended to have the ability to provide base load power. 
The EPA evaluated the operation of 
the three general combustion turbine technologies—combined cycle turbines, frame-type simple cycle turbines, and aeroderivative simple cycle turbines— when determining the subcategorization approach in this rulemaking.
717The 
EPA found that, at the same capacity factor, aeroderivative simple cycle turbines have more starts (including fewer operating hours per start) than either frame simple cycle turbines or combined cycle turbines. The maximum number of starts for aeroderivative simple cycle turbines occurs at capacity factors of approximately 30 percent and the maximum number of starts for frame simple cycle turbines and combined cycle turbines both occur at capacity factors of approximately 25 percent. In terms of the median hours of operation per start, the hours per starts increases exponentially with capacity factor for 
each type of combustion turbine. The rate of increase is greatest for combined cycle turbines with the run times per start increasing significantly at capacity factors of 40 and greater. This threshold roughly matches the subcategorization threshold for intermediate load and base load turbines in this final rule. As is discussed later in section VIII.F.3 and VIII.F.4, technology options including those related to efficiency and to post combustion capture are impacted by the way units operate and can be more effective for units with fewer stops and starts. 
a. Legal Basis for Subcategorization 
As noted in section V.C.1 of this 
preamble, CAA section 111(b)(2) 
provides that the EPA ‘‘may distinguish among classes, types, and sizes within categories of new sources for the purpose of establishing . . . standards [of performance].’’ The D.C. Circuit has held that the EPA has broad discretion in determining whether and how to subcategorize under CAA section 111(b)(2). Lignite Energy Council, 198 
F.3d at 933. As also noted in section V.C.1 of this preamble, in prior CAA section 111 rules, the EPA has subcategorized on numerous bases, including, among other things, fuel type and load, i.e., utilization. In particular, 
as noted in section V.C.1 of this preamble, the EPA subcategorized on the basis of utilization—for base load 
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and non-base load subcategories—in the 
2015 NSPS for GHG emissions from combustion turbines, Standards of Performance for Greenhouse Gas Emissions From New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units, 80 FR 64509 (October 23, 2015), and also in the NESHAP for Reciprocating Internal 
Combustion Engines; NSPS for Stationary Internal Combustion Engines, 79 FR 48072–01 (August 15, 2014). 
Subcategorizing combustion turbines 
based on utilization is appropriate because it recognizes the way differently designed combustion turbines actually operate. Project developers do not construct combined cycle combustion turbine system to start and stop often to serve peak demand. Similarly, project developers do not construct and install simple cycle combustion turbines to operate at higher capacity factors to provide base load demand. And intermediate load demand may be served by higher efficiency simple cycle turbine systems or by ‘‘quick start’’ combined cycle units. Thus, there are distinguishing features (i.e., different 
classes, types, and sizes) of turbines that are predominantly used in each of the utilization-based subcategories. Further, the amount of utilization and the mode of operation are relevant for the systems of emission reduction that the EPA may evaluate to be the BSER and therefore for the resulting standards of performance. See section VII.C.2.a.i for more discussion of the legal basis to subcategorize based upon characteristics relevant to the controls the EPA may determine to be the BSER. 
As noted in sections VIII.E.2.b and 
VIII.F of this preamble, combustion turbines that operate at low load have highly variable operation and therefore highly variable emission rates. This variability made it challenging for the EPA to specify a BSER based on efficient design and operation and limits the BSER for purposes of this rulemaking to lower-emitting fuels. The EPA notes that the subcategorization threshold and the standard of performance are related. For example, the Agency could have finalized a lower electric sales threshold for the low load subcategory (e.g., 15 percent) and 
evaluated the emission rates at the 
lower capacity factors. In future rulemaking the Agency could further evaluate the costs and emissions impacts of reducing the threshold for combustion turbines subject to a BSER based on the use of lower emitting fuels. 
Intermediate load combustion 
turbines (i.e., those that operate at loads 
that are somewhat higher than the low load peaking units) are most often designed to be simple cycle units rather 
than combined cycle units. This is because combustion turbines operating in the intermediate load range also start and stop and vary their load frequently (though not as often as low load peaking units). Because of the more frequent starts and stops, simple cycle combustion turbines are more economical for project developers when compared to combined cycle combustion turbines. Utilization of CCS technology is not practicable for those simple cycle units due to the lack of a HRSG. Therefore, the EPA has determined that efficient design and operation is the BSER for intermediate load combustion turbines. 
While use of CCS is practicable for 
combined cycle combustion turbines, it is most appropriate for those units that operate at relatively higher loads (i.e., as 
base load units) that do not frequently start, stop, and change load. Moreover, with current technology, CCS works better on units running at base load levels. 
b. Electric Sales Subcategorization (Low, 
Intermediate, and Base Load Combustion Turbines) 
As noted earlier, in the 2015 NSPS, 
the EPA established separate standards of performance for new and reconstructed natural gas-fired base load and non-base load stationary combustion turbines. The electric sales threshold distinguishing the two subcategories is based on the design efficiency of individual combustion turbines. A combustion turbine qualifies as a non-base load turbine—and is thus subject to a less stringent standard of performance—if it has net electric sales equal to or less than the design efficiency of the turbine (not to exceed 50 percent) multiplied by the potential electric output (80 FR 64601; October 23, 2015). If the net electric sales exceed that level on both a 12-operating month and 3-calendar year basis, then the combustion turbine is in the base load subcategory and is subject to a more stringent standard of performance. Subcategory applicability can change on a month-to-month basis since applicability is determined each 
operating month. For additional discussion on this approach, see the 2015 NSPS (80 FR 64609–12; October 23, 2015). The 2015 NSPS non-base load subcategory is broad and includes combustion turbines that assure grid reliability by providing electricity during periods of peak electric demand. These peaking turbines tend to have low annual capacity factors and sell a small amount of their potential electric output. The non-base load subcategory in the 2015 NSPS also includes 
combustion turbines that operate at intermediate annual capacity factors and are not considered base load EGUs. These intermediate load EGUs provide a variety of services, including providing dispatchable power to support variable generation from renewable sources of electricity. The need for this service has been expanding as the amount of electricity from wind and solar continues to grow. In the 2015 NSPS, the EPA determined the BSER for the non-base load subcategory to be the use of lower-emitting fuels (e.g., natural gas 
and Nos. 1 and 2 fuel oils). In 2015, the EPA explained that efficient generation did not qualify as the BSER due in part to the challenge of determining an achievable output-based CO
2emissions 
rate for all combustion turbines in this subcategory. 
In this action, the EPA proposed and 
is finalizing the subcategories in 40 CFR part 60, subpart TTTTa, that will be applicable to sources that commence construction or reconstruction after May 23, 2023. First, the Agency proposed and is finalizing the definition of design efficiency so that the heat input calculation of an EGU is based on the higher heating value (HHV) of the fuel instead of the lower heating value (LHV), as explained immediately below. This has the effect of lowering the calculated potential electric output and the electric sales threshold. In addition, the EPA proposed and is finalizing division of the non-base load subcategory into separate intermediate and low load subcategories. 
i. Higher Heating Value as the Basis for 
Calculation of the Design Efficiency 
The heat rate is the amount of energy 
used by an EGU to generate 1 kWh of electricity and is often provided in units of Btu/kWh. As the thermal efficiency of a combustion turbine EGU is increased, 
less fuel is burned per kWh generated and there is a corresponding decrease in emissions of CO
2and other air 
pollutants. The electric energy output as a fraction of the fuel energy input expressed as a percentage is a common practice for reporting the unit’s efficiency. The greater the output of electric energy for a given amount of fuel energy input, the higher the efficiency of the electric generation process. Lower heat rates are associated with more efficient power generating plants. 
Efficiency can be calculated using the 
HHV or the LHV of the fuel. The HHV is the heating value directly determined by calorimetric measurement of the fuel in the laboratory. The LHV is calculated using a formula to account for the 
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718The HHV of natural gas is 1.108 times the LHV 
of natural gas. Therefore, the HHV efficiency is 
equal to the LHV efficiency divided by 1.108. For example, an EGU with a LHV efficiency of 59.4 percent is equal to a HHV efficiency of 53.6 percent. The HHV/LHV ratio is dependent on the composition of the natural gas (i.e., the percentage 
of each chemical species (e.g., methane, ethane, 
propane)) within the pipeline and will slightly move the ratio. 
719Natural gas is also sold on a HHV basis. 
720European plants tend to report thermal 
efficiency based on the LHV of the fuel rather than the HHV for both combustion turbines and steam generating EGUs. In the U.S., boiler efficiency is typically reported on a HHV basis. 
721It is important to note that net output values 
reflect the net output delivered to the electric grid and not the net output delivered to the end user. Electricity is lost as it is transmitted from the point of generation to the end user and these ‘‘line losses’’ increase the farther the power is transmitted. 40 CFR part 60, subpart TTTT, provides a way to account for the environmental benefit of reduced line losses by crediting CHP EGUs, which are typically located close to large electric load centers. See 40 CFR 60.5540(a)(5)(i) and the definitions of gross energy output and net energy output in 40 CFR 60.5580. 
722The 7 percent auxiliary load for combined 
cycle turbines with 90 percent CCS is specific to electric output. Additional auxiliary load includes thermal energy that is diverted to the CCS system instead of being used to generate additional electricity. This additional auxiliary thermal energy is accounted for when converting the phase 1 emissions standard to the phase 2 standard. 723While the design efficiency is capped at 50 
percent on a LHV basis, the base load rating (maximum heat input of the combustion turbine) is on a HHV basis. This mixture of LHV and HHV results in the electric sales threshold being 11 percent higher than the design efficiency. The design efficiency of all new combined cycle EGUs exceed 50 percent on a LHV basis. moisture in the combustion gas (i.e., 
subtracting the energy required to vaporize the water in the flue gas) and is a lower value than the HHV. Consequently, the HHV efficiency for a given EGU is always lower than the corresponding LHV efficiency because the reported heat input for the HHV is larger. For U.S. pipeline natural gas, the HHV heating value is approximately 10 percent higher than the corresponding LHV heating value and varies slightly based on the actual constituent composition of the natural gas.
718The 
EPA default is to reference all technologies on a HHV basis,
719and the 
Agency is basing the heat input calculation of an EGU on HHV for purposes of the definition of design efficiency. However, it should be recognized that manufacturers of combustion turbines typically use the LHV to express the efficiency of combustion turbines.
720 
Similarly, the electric energy output 
for an EGU can be expressed as either of two measured values. One value relates to the amount of total electric power generated by the EGU, or gross output. However, a portion of this electricity must be used by the EGU facility to operate the unit, including compressors, pumps, fans, electric motors, and pollution control equipment. This within-facility electrical demand, often referred to as the parasitic load or auxiliary load, reduces the amount of power that can be delivered to the transmission grid for 
distribution and sale to customers. Consequently, electric energy output may also be expressed in terms of net output, which reflects the EGU gross output minus its parasitic load.
721 When using efficiency to compare the 
effectiveness of different combustion 
turbine EGU configurations and the applicable GHG emissions control technologies, it is important to ensure that all efficiencies are calculated using the same type of heating value (i.e., HHV or LHV) and the same basis of electric energy output (i.e., MWh-gross 
or MWh-net). Most emissions data are available on a gross output basis and the EPA is finalizing output-based standards based on gross output. However, to recognize the superior environmental benefit of minimizing auxiliary/parasitic loads, the Agency is 
including optional equivalent standards on a net output basis. To convert from gross to net output-based standards, the EPA used a 2 percent auxiliary load for simple and combined cycle turbines and a 7 percent auxiliary load for combined cycle EGUs using 90 percent CCS.
722 
ii. Lowering the Threshold Between the Base Load and Non-Base Load Subcategories 
The subpart TTTT distinction 
between a base load and non-base load combustion turbine is determined by the unit’s actual electric sales relative to its potential electric sales, assuming the EGU is operated continuously (i.e., percent electric sales). Specifically, stationary combustion turbines are categorized as non-base load and are subsequently subject to a less stringent standard of performance if they have net electric sales equal to or less than their design efficiency (not to exceed 50 percent) multiplied by their potential electric output (80 FR 64601; October 23, 2015). Because the electric sales threshold is based in part on the design efficiency of the EGU, more efficient combustion turbine EGUs can sell a higher percentage of their potential electric output while remaining in the non-base load subcategory. This approach recognizes both the environmental benefit of combustion turbines with higher design efficiencies and provides flexibility to the regulated community. In the 2015 NSPS, it was unclear how often high-efficiency simple cycle EGUs would be called upon to support increased generation from variable renewable generating resources. Therefore, the Agency determined it was appropriate to provide maximum flexibility to the regulated community. To do this, the 
Agency based the numeric value of the design efficiency, which is used to calculate the electric sales threshold, on the LHV efficiency. This had the impact of allowing combustion turbines to sell a greater share of their potential electric output while remaining in the non-base load subcategory. 
The EPA proposed and is finalizing 
that the design efficiency in 40 CFR part 60, subpart TTTTa be based on the HHV efficiency instead of LHV efficiency and 
to not include the 50 percent maximum and 33 percent minimum restrictions. When determining the potential electric output used in calculating the electric sales threshold in 40 CFR part 60, subpart TTTT, design efficiencies of greater than 50 percent are reduced to 50 percent and design efficiencies of less than 33 percent are increased to 33 percent for determining electric sales threshold subcategorization criteria. The 50 percent criterion was established to limit non-base load EGUs from selling greater than 55 percent of their potential electric sales.
723The 33 percent 
criterion was included to be consistent with applicability thresholds in the electric utility criteria pollutant NSPS (40 CFR part 60, subpart Da). 
Neither of those criteria are 
appropriate for 40 CFR part 60, subpart TTTTa, and the EPA proposed and is finalizing a decision that they are not incorporated when determining the electric sales threshold. Instead, as discussed later in the section, the EPA is finalizing a fixed percent electric sales thresholds and the design efficiency does not impact the subcategorization thresholds. However, the design efficiency is still used when determining the potential electric sales and any restriction on using the actual design efficiency of the combustion turbine would have the impact of changing the threshold. If this restriction were maintained, it would reduce the regulatory incentive for manufacturers to invest in programs to develop higher efficiency combustion turbines. 
The EPA also proposed and is 
finalizing a decision to eliminate the 33 percent minimum design efficiency in the calculation of the potential electric output. The EPA is unaware of any new combustion turbines with design efficiencies meeting the general 
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724The EPA solicited comment on basing the 
electric sales threshold on a value calculated using 
0.94 times the design efficiency. 725This discussion assumes that the combined 
cycle turbine incorporates a bypass stack that allows the combustion turbine engine to operate independent of the HRSG/steam turbine. Without a bypass stack the combustion turbine engine could not come to full load as quickly. applicability criteria of less than 33 
percent; and this will likely have no cost or emissions impact. 
The EPA solicited comment on 
whether the intermediate/base load electric sales threshold should be reduced further to a range that would lower the base load electric sales threshold for simple cycle turbines to between 29 to 35 percent (depending on the design efficiency) and to between 40 to 49 percent for combined cycle turbines (depending on the design 
efficiency). The specific approach the EPA solicited comment on was reducing the design efficiency by 6 percent (e.g., multiplying by 0.94) when determining the electric sales threshold. Some commenters supported lowering the proposed electric sales threshold while others supported maintaining the proposed standards. 
After considering comments, in 40 
CFR part 60, subpart TTTTa, the EPA has determined it is appropriate to eliminate the sliding scale electric sales threshold based on the design efficiency and instead base the subcategorization thresholds on fixed electric sales (also referred to sometimes here as capacity factor). In 40 CFR part 60 subpart TTTTa, the EPA is finalizing that the fixed electric sales threshold between intermediate load combustion turbines and base load combustion turbines is 40 percent. The 40 percent electric sales (capacity factor) threshold reflects the maximum capacity factor for intermediate load simple cycle turbines and the minimum prorated efficiency approach for base load combined cycle turbines that the EPA solicited comment on in proposal.
724 
The base load electric sales threshold 
is appropriate for new combustion turbines because, as will be discussed later, the first component of BSER for base load turbines is based on highly efficient combined cycle generation. Combined cycle units are significantly more efficient than simple cycle turbines; and therefore, in general, the EPA should be focusing its determination of the BSER for base load units on that more efficient technology. The electric sales thresholds and the emission standards are related because, at lower capacity factors, combustion turbines tend to have more variable operation (e.g., more starts and stops 
and operation at part load conditions) that reduces the efficiency of the combustion turbine. This is particularly the case for combined cycle turbines because while the turbine engine can come to full load relatively quickly, the 
HRSG and steam turbine cannot, and combined cycle turbines responding to highly variable load will have efficiencies similar to simple cycle turbines.
725This has implications for 
the appropriate control technologies and corresponding emission reduction potential. The EPA determined the final standard of performance based on review of emissions data for recently installed combined cycle combustion turbines with 12-operating month capacity factors of 40 percent or greater. The EPA considered a capacity factor threshold lower than 40 percent. However, expanding the subcategory to include combustion turbines with a 12- operating month electric sales of less than 40 percent would require the EPA to consider the emissions performance of combined cycle turbines operating at lower capacity factors and, while it would expand the number of sources in the base load subcategory, it would also result in a higher (i.e., less stringent) 
numerical emission standard for the sources in the category. 
Direct comparison of the costs of 
combined cycle turbines relative to simple cycle turbines can be challenging because model plant costs are often for combustion turbines of different sizes and do not account for variable operation. For example, combined cycle turbine model plants are generally for an EGU that is several hundred megawatts while simple cycle turbine model plants are generally less than a hundred megawatts. Direct comparison of the LCOE from these model plants is not relevant because the facilities are not comparable. Consider a facility with a block of 10 simple cycle turbines that are each 50 MW (so the overall facility capacity is 500 MW). Each simple cycle turbine operates as an individual unit and provides a different value to the electric grid as compared to a single 500 MW combined cycle turbine. While the minimum load of the combined cycle facility might be 200 MW, the block of 10 simple cycle turbines can provide from approximately 20 MW to 500 MW to the electric grid. 
A more accurate cost comparison 
accounts for economies of scale and estimates the cost of a combined cycle turbine with the same net output as a simple cycle turbine. Comparing the modeled LCOE of these combustion turbines provides a meaningful 
comparison, at least for base load combustion turbines. Without accounting for economies of scale and variable operation, combined cycle turbines can appear to be more cost effective than simple cycle turbines under almost all conditions. In addition, without accounting for economies of scale, large frame simple cycle turbines can appear to be more cost effective than higher efficiency aeroderivative simple cycle turbines, even if operated at a 100 percent capacity factor. These cost models are not intended to make direct comparisons, and the EPA appropriately accounted for economies of scale when estimating the cost of the BSER. Since base load combustion turbines tend to operate under steady state conditions with few starts and stops, startup and shutdown costs and the efficiency impact of operating at variable loads are not important for determining the compliance costs of base load combustion turbines. 
Based on an adjusted model plant 
comparison, combined cycle EGUs have a lower LCOE at capacity factors above approximately 40 percent compared to simple cycle EGUs operating at the same capacity factors. This supports the final base load fixed electric sales threshold of 40 percent for simple cycle turbines because it would be cost-effective for owners/operators of simple cycle turbines to add heat recovery if they elected to operate at higher capacity factors as a base load unit. Furthermore, based on an analysis of monthly emission rates, recently constructed combined cycle EGUs maintain consistent emission rates at capacity factors of less than 55 percent (which is the base load electric sales threshold in subpart TTTT) relative to operation at higher capacity factors. Therefore, the base load subcategory operating range can be expanded in 40 CFR part 60, subpart TTTTa, without impacting the stringency of the numeric standard. However, at capacity factors of less than approximately 40 percent, emission rates of combined cycle EGUs increase relative to their operation at higher capacity factors. It takes much longer for a HRSG to begin producing steam that can be used to generate additional electricity than it takes a combustion engine to reach full power. Under operating conditions with a significant number of starts and stops, typical of some intermediate and especially low load combustion turbines, there may not be enough time for the HRSG to generate steam that can be used for additional electrical generation. To maximize overall efficiency, combined cycle EGUs often use combustion turbine engines that are less efficient than the most 
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726The duty cycle is the average operating 
capacity factor. For example, if an EGU operates at 
75 percent of the fully rated capacity, the duty cycle would be 75 percent regardless of how often the EGU actually operates. The capacity factor is a measure of how much an EGU is operated relative to how much it could potentially have been operated. 727The calculation used to determine the electric 
sales threshold includes both the design efficiency and the base load rating. Since the base load rating stays the same when adjusting the numeric value of the design efficiency for applicability purposes, adjustments to the design efficiency has twice the impact. Specifically, using three-fourths of the efficient simple cycle turbine engines. 
Under operating conditions with frequent starts and stops where the HRSG does not have sufficient time to begin generating additional electricity, a combined cycle EGU may be no more efficient than a highly efficient simple cycle EGU. These distinctions in operation are thus meaningful for determining which emissions control technologies are most appropriate for types of units. Once a combustion turbine unit exceeds approximately 40 percent annual capacity factor, it is economical to add a HRSG which results in the unit becoming both more efficient and less likely to cycle its operation. Such units are, therefore, better suited for more stringent emission control technologies including CCS. 
After the 2015 NSPS was finalized, 
some stakeholders expressed concerns about the approach for distinguishing between base load and non-base load turbines. They posited a scenario in which increased utilization of wind and solar resources, combined with low natural gas prices, would create the need for certain types of simple cycle turbines to operate for longer time periods than had been contemplated when the 2015 NSPS was being developed. Specifically, stakeholders have claimed that in some regional electricity markets with large amounts of variable renewable generation, some of the most efficient new simple cycle turbines—aeroderivative turbines— could be called upon to operate at capacity factors greater than their design efficiency. However, if those new simple cycle turbines were to operate at those higher capacity factors, they would become subject to the more stringent standard of performance for base load turbines. As a result, according to these stakeholders, the new aeroderivative turbines would have to curtail their generation and instead, less-efficient existing turbines would be called upon to run by the regional grid operators, which would result in overall higher emissions. The EPA evaluated the operation of simple cycle turbines in areas of the country with relatively large amounts of variable renewable generation and did not find a strong correlation between the percentage of generation from the renewable sources and the 12-operating month capacity factors of simple cycle turbines. In addition, most of the simple cycle turbines that commenced operation between 2010 and 2016 (the most recent simple cycle turbines not subject to 40 CFR part 60, subpart TTTT) have operated well below the base load electric sales threshold in 40 CFR part 60, subpart TTTT. Therefore, the Agency does not believe that the concerns expressed by stakeholders necessitates any revisions to the regulatory scheme. In fact, as noted above, the EPA is finalizing that the electric sales threshold can be lowered without impairing the availability of simple cycle turbines where needed, including to support the integration of variable generation. The EPA believes that the final threshold is not overly restrictive since a simple cycle turbine could operate on average for more than 9 hours a day in the intermediate load subcategory. 
iii. Low and Intermediate Load 
Subcategories 
This section discusses the EPA’s 
rationale for subcategorizing non-base load combustion turbines into two subcategories—low load and intermediate load. 
(A) Low Load Subcategory 
The EPA proposed and is finalizing in 
40 CFR part 60, subpart TTTTa, a low 
load subcategory to includes combustion turbines that operate only during periods of peak electric demand (i.e., peaking units), which will be 
separate from the intermediate load subcategory. Low load combustion turbines also provide ramping capability and other ancillary services to support grid reliability. The EPA evaluated the operation of recently constructed simple cycle turbines to understand how they operate and to determine at what electric sales level or capacity factor their emissions rate is relatively steady. (Note that for purposes of this discussion, the terms ‘‘electric sales’’ and ‘‘capacity factor’’ are used interchangeably.) Low load combustion turbines generally only operate for short periods of time and potentially at relatively low duty cycles.
726This type 
of operation reduces the efficiency and increases the emissions rate, regardless of the design efficiency of the combustion turbine or how it is maintained. For this reason, it is difficult to establish a reasonable output-based standard of performance for low load combustion turbines. 
To determine the electric sales 
threshold—that is, to distinguish between the intermediate load and low load subcategories—the EPA evaluated capacity factor electric sales thresholds 
of 10 percent, 15 percent, 20 percent, and 25 percent. The EPA proposed to find and is finalizing a conclusion that the 10 percent threshold is problematic for two reasons. First, simple cycle turbines operating at that level or lower have highly variable emission rates, and therefore it is difficult for the EPA to establish a meaningful output-based standard of performance. In addition, only one-third of simple cycle turbines that have commenced operation since 2015 have maintained 12-operating month capacity factors of less than 10 percent. Therefore, setting the threshold at this level would bring most new simple cycle turbines into the intermediate load subcategory, which would subject them to a more stringent emission rate that is only achievable for simple cycle turbines operating at higher capacity factors. This could create a situation where simple cycle turbines might not be able to comply with the intermediate load standard of performance while operating at the low end of the intermediate load capacity factor subcategorization criteria. 
Based on the EPA’s review of hourly 
emissions data, at a capacity factor above 15 percent, GHG emission rates for many simple cycle turbines begin to stabilize. At higher capacity factors, more time is typically spent at steady state operation rather than ramping up and down; and emission rates tend to be lower while in steady-state operation. Of recently constructed simple cycle turbines, half have maintained 12- operating month capacity factors of 15 percent or less, two-thirds have maintained capacity factors of 20 percent or less; and approximately 80 
percent have maintained maximum capacity factors of 25 percent or less. The emission rates clearly stabilize for most simple cycle turbines operating at capacity factors of greater than 20 percent. Based on this information, the EPA proposed the low load electric sales threshold—again, the dividing line to distinguish between the intermediate and low load subcategories—to be 20 percent and solicited comment on a range of 15 to 25 percent. The EPA also solicited comment on whether the low load electric sales threshold should be determined by a site-specific threshold based on three-fourths of the design efficiency of the combustion turbine.
727Under this approach, simple 
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design efficiency reduces the electric sales 
threshold by half. 728Under the proposed subcategorization 
approach, for a combustion turbine to be subcategorized as an intermediate load combustion turbine while operating at capacity factors of greater than 40 percent required the use of a HRSG (e.g., combined cycle turbine technology). 729The EPA did not propose to include, and is 
not finalizing including, integrated renewables as part of the BSER. Commenters opposed a BSER that would include integrated renewables as part of the BSER. Commenters noted that this could result in renewables being installed in suboptimal locations which could result in lower overall GHG reductions. cycle turbines selling less than 18 to 22 
percent of their potential electric output (depending on the design efficiency) would still have been considered low load combustion turbines. This ‘‘sliding scale’’ electric sales threshold approach is like the approach the EPA used in the 2015 NSPS to recognize the environmental benefit of installing the most efficient combustion turbines for low load applications. Using this approach, combined cycle EGUs would have been able to sell between 26 to 31 percent of their potential electric output while still being considered low load combustion turbines. Some commenters supported a lower electric sales threshold while others supported a higher threshold. Based on these comments, the EPA is finalizing the proposed low load electric sales threshold of 20 percent of the potential electric sales. The fixed 20 percent capacity factor threshold represents a level of utilization at which most simple cycle combustion turbines perform at a consistent level of efficiency and GHG emission performance, enabling the EPA to establish a standard of performance that reflects a BSER of efficient operation. The 20 percent capacity factor threshold is also more environmentally protective than the higher thresholds the EPA considered, since owners and operators of combustion turbines operating above a 
20 percent capacity factor would be subject to an output-based emissions standard instead of a heat input-based emissions standard based on the use of lower-emitting fuels. This ensures that owners/operators of intermediate load combined cycle turbines properly maintain and operate their combustion turbines. 
(B) Intermediate Load Subcategory 
The proposed sliding scale 
subcategorization approach essentially 
included two subcategories within the proposed intermediate load subcategory. As proposed, simple cycle turbines would be classified as intermediate load combustion turbines when operated between capacity factors of 20 percent and approximately 40 percent while combined cycle turbines would be classified as intermediate load combustion turbines when operated between capacity factors of 20 percent to approximately 55 percent. Owners/ operators of combined cycle turbines operating at the high end of the intermediate load subcategory would only be subject to an emissions standard based on a BSER of high-efficiency simple cycle turbine technology. The proposed approach provided a regulatory incentive for owners/ operators to purchase the most efficient technologies in exchange for additional compliance flexibility. The use of a prorated efficiency the EPA solicited comment on would have lowered the simple cycle and combined cycle turbine thresholds to approximately 35 percent and 50 percent, respectively. 
In this final rule, the BSER for the 
intermediate load subcategory is consistent with the proposal—high- efficiency simple cycle turbine technology. While not specifically identified in the proposal, the BSER for the base load subcategory is also consistent with the proposal—the use of combined cycle technology.
728 
The 12-operating month electric sales 
(i.e., capacity factor) thresholds for the 
stationary combustion turbine subcategories in this final rule are summarized below in Table 2. 
TABLE 2—S ALES THRESHOLDS FOR  
SUBCATEGORIES OF COMBUSTION  
TURBINE EGU S 
Subcategory 12-Operating month 
electric sales 
threshold 
(percent of potential 
electric sales) 
Low Load ...................... ≤20 
Intermediate Load ......... >20 and ≤40 
Base Load .................... >40 
iv. Integrated Onsite Generation and Energy Storage 
Integrated equipment is currently 
included as part of the affected facility, and the EPA proposed and is finalizing amended regulatory text to clarify that the output from integrated renewables is included as output when determining the NSPS emissions rate. The EPA also proposed that the output from the integrated renewable generation is not included when determining the net electric sales for applicability purposes (i.e., generation from integrated 
renewables would not be considered when determining if a combustion turbine is subcategorized as a low, intermediate, or base load combustion turbine). In the alternative, the EPA solicited comment on whether instead of exempting the generation from the integrated renewables from counting toward electric sales, the potential output from the integrated renewables 
would be included when determining the design efficiency of the facility. Since the design efficiency is used when determining the electric sales threshold this would increase the allowable electric sales for subcategorization purposes. Including the integrated renewables when determining the design efficiency of the affected facility has the impact of increasing the operational flexibility of owners/ operators of combustion turbines. Commenters generally supported maintaining that integrated renewables are part of the affected facility and including the output of the renewables when determining the emissions rate of the affected facility.
729Therefore, the 
Agency is finalizing a decision that the rated output of integrated renewables be included when determining the design efficiency of the affected facility, which is used to determine the potential electric output of the affected facility, and that the output of the integrated renewables be included in determining the emissions rate of the affected facility. However, since the design efficiency is not a factor in determining the subcategory thresholds in 40 CFR part 60, subpart TTTTa, the output of the integrated renewables will not be included for determining the applicable subcategory. If the output from the integrated renewable generation were 
included for subcategorization purposes, this could discourage the use of integrated renewables (or curtailments) because affected facilities could move to a subcategory with a more stringent emissions standard that could cause the owner/operator to be out of compliance. The impact of this approach is that the electric sales threshold of the combustion turbine island itself, not including the integrated renewables, for an owner/ operator of a combustion turbine that includes integrated renewables that increase the potential electric output by 1 percent would be 1 or 2 percent higher for the stationary combustion turbine island not considering the integrated renewables, depending on the design efficiency of the combustion turbine itself, than an identical combustion turbine without integrated renewables. In addition, when the output from the integrated renewables is considered, the output from the integrated renewables 
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730In 40 CFR part 60, subpart TTTT, electricity 
sold by units that are not called upon to operate due 
to a system emergency (e.g., units already operating 
when the system emergency is declared) is counted toward the percentage electric sales threshold. 
731See 80 FR 64612; October 23, 2015. 732Commenters noted that grid operators have 
slightly different terms for grid emergencies, but example descriptions include: EEA 1, all available generation online and non-firm wholesale sales curtailed; EEA 2, load management procedures in effect, all available generation units online, demand-response programs in effect; and EEA 3, firm load interruption is imminent or in progress. lowers the emissions rate of the affected 
facility by approximately 1 percent. 
For integrated energy storage 
technologies, the EPA solicited comment on and is finalizing a decision to include the rated output of the energy storage when determining the design efficiency of the affected facility. Similar to integrated renewables, this increases the flexibility of owner/ operators to sell larger amounts of electricity while remaining in the low, variable, and intermediate load subcategories. While energy storage technologies have high capital costs, operating costs are low and would dispatch prior to the combustion turbine the technology is integrated with. Therefore, simple cycle turbines with integrated energy storage would likely operate at lower capacity factors than an identical simple cycle turbine at the same location. However, while the energy storage might be charged with renewables that would otherwise be curtailed, there is no guarantee that low emitting generation would be used to charge the energy storage. Therefore, the output from the energy storage is not considered in either determining the NSPS emissions rate or as net electric sales for subcategorization applicability purposes. In future rulemaking the Agency could further evaluate the impact of integrated energy storage on the operation of simple cycle turbines to determine if the number of starts and stops are reduced and increases the efficiency of simple cycle turbines relative to simple cycle turbines without integrated energy storage. If this is the case, it could be appropriate to lower the threshold for combustion turbines subject to a lower emitting fuels BSER because emission rates would be stable at lower capacity factors. 
v. Definition of System Emergency 
In 2015, the EPA included a provision 
that electricity sold during hours of 
operation when a unit is called upon due to a system emergency is not counted toward the percentage electric sales subcategorization threshold in 40 CFR part 60, subpart TTTT.
730The 
Agency concluded that this exclusion is necessary to provide flexibility, maintain system reliability, and minimize overall costs to the sector.
731 
The intent is that the local grid operator will determine the EGUs essential to maintaining grid reliability. Subsequent 
to the 2015 NSPS, members of the regulated community informed the EPA 
that additional clarification of a system emergency is needed to determine and document generation during system emergencies. The EPA proposed to include the system emergency approach in 40 CFR part 60, subpart TTTTa, and solicited comment on amending the definition of system emergency to clarify in implementation in 40 CFR part 60, subparts TTTT and TTTTa. Commenters generally agreed with the proposal to allow owners/operators of EGUs called upon during a system emergency to operate without impacting the EGUs’ subcategorization (i.e., electric sales during system emergencies would not be considered when determining net electric sales), and that the Agency should clarify how system emergencies are determined and documented. 
In terms of the definition of the 
system emergency provision, commenters stated that ‘‘abnormal’’ be deleted from the definition, and instead of referencing ‘‘the Regional Transmission Organizations (RTO), Independent System Operators (ISO) or 
control area Administrator,’’ the definition should reference ‘‘the balancing authority or reliability coordinator.’’ This change would align the regulation’s definition with the terms used by NERC. Some commenters also stated that the EPA should specify that electric sales during periods the grid operator declares energy emergency alerts (EEA) levels 1 through 3 be included in the definition of system emergency.
732In addition, some 
commenters stated that the definition should be expanded to include the concept of energy emergencies. Specifically, the definition should also exempt generation during periods when a load-serving entity or balancing authority has exhausted all other resource options and can no longer meet its expected load obligations. Finally, commenters stated that the definition should apply to all EGUs, regardless of if they are already operating when the system emergency is declared. This would avoid regulatory incentive to come offline prior to a potential system emergency to be eligible for the electric sales exemption and would treat all EGUs similarly during system emergencies (i.e., not penalize EGUs 
that are already operating to maintain grid reliability and avoiding the need to declare grid emergencies). 
The Agency is including the system 
emergency concept in 40 CFR part 60, subpart TTTTa, along with a definition that clarifies how to determine generation during periods of system emergencies. The EPA agrees with commenters that the definition of system emergency should be clarified and that it should not be limited to EGUs not operating when the system emergency is declared. Based on information provided by entities with reliability expertise, the EPA has determined that a system emergency should be defined to include EEA levels 2 and 3. These EEA levels generally correspond to time-limited, well- defined, and relatively infrequent situations in which the system is experiencing an energy deficiency. During EEA level 2 and 3 events, all available generation is online and demand-response or other load management procedures are in effect, or firm load interruption is imminent or in progress. The EPA believes it is appropriate to exclude hours of operation during such events in order to ensure that EGUs are not impeded from maintaining or increasing their output as needed to respond to a declared energy emergency. Because these events tend to be short, infrequent, and well- defined, the EPA also believes any incremental GHG emissions associated with operations during these periods would be relatively limited. 
The EPA has determined not to 
include EEA level 1 in the definition of a ‘‘system emergency.’’ The EPA’s understanding is that EEA level 1 events often include situations in which an energy deficiency does not yet exist, and in which balancing authorities are preparing to pursue various options for either bringing additional resources online or managing load. The EPA also understands that EEA level 1 events tend to be more frequently declared, and longer in duration, than level 2 or 3 events. Based on this information, the EPA believes that including EEA level 1 events in the definition of a ‘‘system emergency’’ would carry a greater risk of increasing overall GHG emissions without making a meaningful contribution to supporting reliability. This approach balances the need to have operational flexibility when the grid may be strained to help ensure that all available generating sources are available for grid reliability, while balancing with important considerations about potential GHG emission tradeoffs. The EPA is also amending the definition in 40 CFR part 60, subpart TTTT, to be 
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733For owners/operators of combustion turbines 
the lower emitting fuels requirement is defined to 
include fuels with an emissions rate of 160 lb CO 2/ 
MMBtu or less. For owners/operators of steam generating units or IGCC facilities the EPA is requiring the use of the maximum amount of non- coal fuels available to the affected facility. 734Combustion turbines co-firing natural gas with 
other fuels must determine fuel-based site-specific 
standards at the end of each operating month. The site-specific standards depend on the amount of co- fired natural gas. 80 FR 64616 (October 23, 2015). 735Note that according to 40 CFR part 60, subpart 
TTTT, combustion turbines co-firing 25 percent 
hydrogen by volume could be subcategorized as multi-fuel-fired EGUs because the percent methane by volume could fall below 70 percent, the heating value could fall below 35 MJ/Sm
3, and 10 percent 
of the heat input could be coming from a fuel not meeting the definition of natural gas. consistent with the definition in 40 CFR 
part 60, subpart TTTTa. 
Commenters also added that 
operation during system emergencies should be subject to alternate standards of performance (e.g., owners/operators 
are not required to use the CCS system during system emergencies to increase power output). The EPA agrees with commenters that since system emergencies are defined and historically rare events, an alternate standard of performance should apply during these periods. Carbon capture systems require significant amounts of energy to operate. Allowing owners/operators of EGUs equipped with CCS systems to temporarily reduce the capture rate or cease capture will increase the electricity available to end users during system emergencies. In place of the applicable output-based emissions standard, the owner/operator of an intermediate or base load combustion turbine would be subject to a BSER based on the combustion of lower- emitting fuels during system emergencies.
733The emissions and 
output would not be included when calculating the 12-operating month emissions rate. The EPA considered an alternate emissions standard based on efficient generation but rejected that for multiple reasons. First, since system emergencies are limited in nature the emissions calculation would include a limited number of hours and would not necessarily be representative of an achievable longer-term emissions rate. In addition, EGUs that are designed to operate with CCS will not necessarily operate as efficiently without the CCS system operating compared to a similar EGU without a CCS system. Therefore, the Agency is not able to determine a reasonable efficiency-based alternate emissions standard for periods of system emergencies. Due to both the costs and time associated with starting 
and stopping the CCS system, the Agency has determined it is unlikely that an owner/operator of an affected facility would use it where it is not needed. System emergencies have historically been relatively brief and any hours of operation outside of the system emergencies are included when determining the output-based emissions standard. During short-duration system emergencies, the costs associated with stopping and starting the CCS system could outweigh the increased revenue from the additional electric sales. In 
addition, the time associated with starting and stopping a CCS system would likely result in an EGU operating without the CCS system in operation during periods of non-system emergencies. This would require the owner/operator to overcontrol during other periods of operation to maintain emissions below the applicable standard of performance. Therefore, it is likely an owner/operator would unnecessarily adjust the operation of the CCS system during EEA levels 2 and 3. 
In addition to these measures, DOE 
has authority pursuant to section 202(c) of the Federal Power Act to, on its own motion or by request, order, among other things, the temporary generation of electricity from particular sources in certain emergency conditions, including during events that would result in a shortage of electric energy, when the Secretary of Energy determines that doing so will meet the emergency and serve the public interest. An affected source operating pursuant to such an order is deemed not to be operating in violation of its environmental requirements. Such orders may be issued for 90 days and may be extended in 90-day increments after consultation with the EPA. DOE has historically issued section 202(c) orders at the request of electric generators and grid operators such as RTOs in order to enable the supply of additional generation in times of expected emergency-related generation shortfalls. 
c. Multi-Fuel-Fired Combustion 
Turbines 
In 40 CFR part 60, subpart TTTT, 
multi-fuel-fired combustion turbines are subcategorized as EGUs that combust 10 percent or more of fuels not meeting the definition of natural gas on a 12- operating month rolling average basis. The BSER for this subcategory is the use of lower-emitting fuels with a corresponding heat input-based standard of performance of 120 to 160 lb CO
2/MMBtu, depending on the fuel, 
for newly constructed and reconstructed multi-fuel-fired stationary combustion turbines.
734Lower-emitting fuels for 
these units include natural gas, ethylene, propane, naphtha, jet fuel kerosene, Nos. 1 and 2 fuel oils, biodiesel, and landfill gas. The definition of natural gas in 40 CFR part 60, subpart TTTT, includes fuel that maintains a gaseous state at ISO conditions, is composed of 70 percent by volume or more methane, and has a 
heating value of between 35 and 41 megajoules (MJ) per dry standard cubic meter (dscm) (950 and 1,100 Btu per dry standard cubic foot). Natural gas 
typically contains 95 percent methane and has a heating value of 1,050 Btu/ lb.
735A potential issue with the multi- 
fuel subcategory is that owners/ operators of simple cycle turbines can elect to burn 10 percent non-natural gas fuels, such as Nos. 1 or 2 fuel oil, and thereby remain in that subcategory, regardless of their electric sales. As a result, they would remain subject to the less stringent standard that applies to multi-fuel-fired sources, the lower- emitting fuels standard. This could allow less efficient combustion turbine designs to operate as base load units without having to improve efficiency and could allow EGUs to avoid the need for efficient design or best operating and maintenance practices. These potential circumventions would result in higher GHG emissions. 
To avoid these outcomes, the EPA 
proposed and is finalizing a decision not to include the multi-fuel subcategory for low, intermediate, and base load combustion turbines in 40 CFR part 60, subpart TTTTa. This means that new multi-fuel-fired turbines that commence construction or reconstruction after May 23, 2023, will fall within a particular subcategory depending on their level of electric sales. The EPA also proposed and is finalizing a decision that the performance standards for each subcategory be adjusted appropriately for multi-fuel-fired turbines to reflect the application of the BSER for the subcategories to turbines burning fuels with higher GHG emission rates than natural gas. To be consistent with the definition of lower-emitting fuels in the 2015 NSPS, the maximum allowable heat input-based emissions rate is 160 lb CO
2/MMBtu. For example, a standard of 
performance based on efficient generation would be 33 percent higher for a fuel oil-fired combustion turbine compared to a natural gas-fired combustion turbine. This assures that the BSER, in this case efficient generation, is applied, while at the same time accounting for the use of multiple fuels. 
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736The EPA recognizes that standards of 
performance are technology neutral and that a 
standard based on application of CCS could be achieved by co-firing hydrogen. d. Rural Areas and Small Utility 
Distribution Systems 
As part of the original proposal and 
during the Small Business Advocacy Review (SBAR) outreach the EPA solicited comment on creating a subcategory for rural electric cooperatives and small utility distribution systems (serving 50,000 customers or less). Commenters expressed concerns that a BSER based on either co-firing hydrogen or CCS may present an additional hardship on economically disadvantaged communities and on small entities, and that the EPA should evaluate potential increased energy costs, transmission upgrade costs, and infrastructure encroachment which may directly affect the disproportionately impacted communities. As described in section VIII.F, the BSER for new stationary combustion turbines does not include hydrogen co-firing and CCS qualifies as the BSER for base load combustion turbines on a nationwide basis. Therefore, the EPA has determined that a subcategory for rural cooperatives and/or small utility distribution systems is not appropriate. 
F. Determination of the Best System of 
Emission Reduction (BSER) for New and Reconstructed Stationary Combustion Turbines 
In this section, the EPA describes the 
technologies it proposed as the BSER for each of the subcategories of new and reconstructed combustion turbines that commence construction after May 23, 2023, as well as topics for which the Agency solicited comment. In the following section, the EPA describes the technologies it is determining are the final BSER for each of the three subcategories of affected combustion turbines and explains its basis for selecting those controls, and not others, as the final BSER. The controls that the EPA evaluated included combusting non-hydrogen lower-emitting fuels (e.g., natural gas and distillate oil), using highly efficient generation, using CCS, and co-firing with low-GHG hydrogen. 
For the low load subcategory, the EPA 
proposed the use of lower-emitting fuels as the BSER. This was consistent with the BSER and performance standards established in the 2015 NSPS for the non-base load subcategory as discussed earlier in section VIII.C. 
For the intermediate load subcategory, 
the EPA proposed an approach under which the BSER was made up of two components: (1) highly efficient generation; and (2) co-firing 30 percent (by volume) low-GHG hydrogen. Each component of the BSER represented a different set of controls, and those 
controls formed the basis of corresponding standards of performance that applied in two phases. Specifically, the EPA proposed that affected facilities (i.e., facilities that commence 
construction or reconstruction after May 23, 2023) could apply the first component of the BSER (i.e., highly 
efficient generation) upon initial startup to meet the first phase of the standard of performance. Then, by 2032, the EPA proposed that affected facilities could apply the second component of the BSER (i.e., co-firing 30 percent (by 
volume) low-GHG hydrogen) to meet a second and more stringent standard of performance. The EPA also solicited comment on whether the intermediate load subcategory should apply a third component of the BSER: co-firing 96 percent (by volume) low-GHG hydrogen by 2038. In addition, the EPA solicited comment on whether the low load subcategory should also apply the second component of BSER, co-firing 30 percent (by volume) low-GHG hydrogen, by 2032. The Agency proposed that these latter components of the BSER would continue to include the application of highly efficient generation. 
For the base load subcategory, the 
EPA also proposed a multi-component BSER and multi-phase standard of performance. The EPA proposed that each new base load combustion turbine would be required to meet a phase-1 standard of performance based on the application of the first component of the BSER—highly efficient generation— upon initial startup of the affected source. For the second component of the BSER, the EPA proposed two potential technology pathways for base load combustion turbines with corresponding standards of performance. One proposed technology pathway was 90 percent CCS, which base load combustion turbines would install and begin to operate by 2035 to meet the phase-2 standard of performance. A second proposed technology pathway was co-firing low- GHG hydrogen, which base load combustion turbines would implement in two steps: (1) By co-firing 30 percent (by volume) low-GHG hydrogen to meet the phase-2 standard of performance by 2032, and (2) by co-firing 96 percent (by volume) low-GHG hydrogen to meet a phase 3 standard of performance by 2038. Throughout, the Agency proposed base load turbines, like intermediate load turbines, would remain subject to the first component of the BSER based 
on highly efficient generation. 
The proposed approach reflected the 
EPA’s view that the BSER components for the intermediate load and base load subcategories could achieve deeper reductions in GHG emissions by implementing CCS and co-firing low- GHG hydrogen. This proposed approach also recognized that building the infrastructure required to support widespread use of CCS and low-GHG hydrogen technologies in the power sector will take place on a multi-year time scale. Accordingly, new and reconstructed facilities would be aware of their need to ramp toward more stringent phases of the standards, which would reflect application of the more stringent controls in the BSER. This would occur either by co-firing a lower percentage (by volume) of low-GHG hydrogen by 2032 and a higher percentage (by volume) of low-GHG hydrogen by 2038, or with installation and use of CCS by 2035. The EPA also solicited comment on the potential for an earlier compliance date for the second phase. 
For the base load subcategory, the 
EPA proposed two potential BSER pathways because the Agency believed there was more than one viable technology for these combustion turbines to significantly reduce their CO
2emissions. The Agency also found 
value in receiving comments on, and potentially finalizing, both BSER pathways to enable project developers to elect how they would reduce their CO
2emissions on timeframes that make 
sense for each BSER pathway.736The 
EPA solicited comment on whether the co-firing of low-GHG hydrogen should be considered a compliance pathway for sources to meet a single standard of performance based on the application of CCS rather than a separate BSER pathway. The EPA proposed that there would be earlier opportunities for units to begin co-firing lower amounts of low- GHG hydrogen than to install and begin operating 90 percent CCS systems. However, the Agency proposed that it would likely take longer for those units to increase their co-firing to significant quantities of low-GHG hydrogen. Therefore, in the proposal, the EPA presented the BSER pathways as separate subcategories and solicited comment on the option of finalizing a single standard of performance based on the application of CCS. 
For the low load subcategory, the EPA 
proposed and is finalizing that the BSER is the use of lower-emitting fuels. For the intermediate load subcategory, the EPA proposed and is finalizing that the 
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737The EPA sometimes refers to highly efficient 
generating technology in combination with the best 
operating and maintenance practices as highly efficient generation. The affected sources must meet standards based on this efficient generating 
technology upon the effective date of the final rule. 738Important characteristics for minimizing 
emissions from low load combustion turbines 
include the ability to operate efficiently while operating at part load conditions and the ability to rapidly achieve maximum efficiency to minimize 
periods of operation at lower efficiencies. These characteristics do not necessarily always align with 
higher design efficiencies that are determined under steady-state full-load conditions. BSER is highly efficient generating 
technology—simple cycle technology as well as operating and maintaining it efficiently.
737The EPA is not finalizing 
a second component of the BSER or a phase-2 standard of performance for intermediate load combustion turbines at this time. For the base load subcategory, the EPA proposed and is finalizing that the first component of the BSER is highly efficient generating technology—combined cycle technology as well as operating and maintaining it efficiently. The EPA proposed and is finalizing a second component of the BSER or a phase-2 standard of performance for base load combustion 
turbines—efficient generation in combination with 90 percent CCS. 
The EPA is not finalizing low-GHG 
hydrogen co-firing as the second component of the BSER for the intermediate load or base load combustion turbines at this time. (See section VIII.F.5.b for the EPA’s explanation of this decision.) With respect to the CCS pathway for base load combustion turbines, the EPA is finalizing a second phase of the standards of performance that includes 
a single CCS BSER pathway, which includes the use of highly efficient generation and 90 percent CCS. Owners/ operators of new and reconstructed base 
load combustion turbines will be required to meet the second phase standards of performance for 12- operating month rolling averages that begin on or after January 2032, that reflect application of both the phase-1 and phase-2 components of the BSER. Table 3 of this document summarizes the final BSER for combustion turbine EGUs that commence construction or reconstruction after May 23, 2023. The EPA is finalizing standards of performance based on those BSER for each subcategory, as discussed in section VIII.G. 
TABLE 3—F INAL BSER FORCOMBUSTION TURBINE EGU S 
Subcategory1 Fuel 1st Component BSER 2nd Component BSER 
Low Load ....................................... All Fuels ........... lower-emitting fuels ....................... N/A. 
Intermediate Load ......................... All Fuels ............ Highly Efficient Simple Cycle Gen-
eration.N/A. 
Base Load ..................................... All Fuels ........... Highly Efficient Combined Cycle 
Generation.Highly Efficient Combined Cycle Generation Plus 
90 Percent CCS Beginning in 2032. 
1The low load subcategory is applicable to combustion turbines selling 20 percent or less of their potential electric output, the intermediate 
load subcategory is applicable to combustion turbines selling greater than 20 percent and less than or equal to 40 percent of their potential elec-
tric output, and the base load subcategory is applicable to combustion turbines selling greater than 40 percent of their potential electric output. 
1. BSER for Low Load Subcategory 
This section describes the BSER for 
the low load (i.e., peaking) subcategory 
at this time, which is the use of lower- 
emitting fuels. The Agency proposed and is finalizing a determination that the use of lower-emitting fuels, which the EPA determined to be the BSER for the non-base load subcategory in the 2015 NSPS, is the BSER for this low load subcategory. As explained in section VIII.E.2.b, the EPA is narrowing the definition of the low load subcategory by lowering the electric sales threshold (as compared to the electric sales threshold for non-base load combustion turbines in the 2015 NSPS), so that combustion turbines with higher electric sales would be placed in the intermediate load subcategory and therefore be subject to a more stringent standard based on the more stringent BSER. 
a. Background: The Non-Base Load 
Subcategory in the 2015 NSPS 
The 2015 NSPS defined non-base load 
natural gas-fired EGUs as stationary combustion turbines that (1) burn more than 90 percent natural gas and (2) have net electric sales equal to or less than their design efficiency (not to exceed 50 
percent) multiplied by their potential electric output (80 FR 64601; October 23, 2015). These are calculated on 12- operating month and 3-calendar year rolling average bases. The EPA also determined in the 2015 NSPS that the BSER for newly constructed and reconstructed non-base load natural gas- fired stationary combustion turbines is 
the use of lower-emitting fuels. Id. at 64515. These lower-emitting fuels are primarily natural gas with a small allowance for distillate oil (i.e., Nos. 1 
and 2 fuel oils), which have been widely used in stationary combustion turbine EGUs for decades. 
The EPA also determined in the 2015 
NSPS that the standard of performance for sources in this subcategory is a heat input-based standard of 120 lb CO
2/ 
MMBtu. The EPA established this clean- fuels BSER for this subcategory because of the variability in the operation in non-base load combustion turbines and the challenges involved in determining a uniform output-based standard that all new and reconstructed non-base load units could achieve. 
Specifically, in the 2015 NSPS, the 
EPA recognized that a BSER for the non- base load subcategory based on the use of lower-emitting fuels results in limited 
GHG reductions, but further recognized that an output-based standard of performance could not reasonably be applied to the subcategory. The EPA explained that a combustion turbine operating at a low capacity factor could operate with multiple starts and stops, and that its emission rate would be highly dependent on how it was operated and not its design efficiency. Moreover, combustion turbines with low annual capacity factors typically operated differently from each other, and therefore had different emission rates. The EPA recognized that, as a 
result, at the time it would not be possible to determine a standard of performance that could reasonably apply to all combustion turbines in the subcategory. For that reason, the EPA further recognized, efficient design
738 
and operation would not qualify as the BSER; rather, the BSER should be lower- emitting fuels and the associated standard of performance should be based on heat input. Since the 2015 NSPS, all newly constructed simple cycle turbines have been non-base load units and thus have become subject to this standard of performance. 
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739The BSER for multi-fuel-fired combustion 
turbines subject to 40 CFR part 60, subpart TTTT, 
is also the use of fuels with an emissions rate of 160 lb CO
2/MMBtu or less. The use of these fuels 
will demonstrate compliance with the low load 
subcategory. 
740The EPA is not finalizing a definition of low- 
GHG hydrogen. 741The cost effectiveness calculation is highly 
dependent upon assumptions concerning the 
increase in capital costs, the decrease in heat rate, and the price of natural gas. b. BSER 
Consistent with the rationale of the 
2015 NSPS, the EPA proposed and is 
finalizing that the use of fuels with an emissions rate of less than 160 lb CO
2/ 
MMBtu (i.e., lower-emitting fuels) meets 
the BSER requirements for the low load subcategory at this time. Use of these fuels is technically feasible for combustion turbines. Natural gas comprises the majority of the heat input for simple cycle turbines and is the lowest cost fossil fuel. In the 2015 NSPS, the EPA determined that natural gas comprised 96 percent of the heat input for simple cycle turbines. See 80 FR 64616 (October 23, 2015). Therefore, a BSER based on the use of natural gas and/or distillate oil would have minimal, if any, costs to regulated entities. The use of lower-emitting fuels would not have any significant adverse energy requirements or non-air quality or environmental impacts, as the EPA determined in the 2015 NSPS. Id. at 
64616. In addition, the use of fuels meeting this criterion would result in some emission reductions by limiting the use of fuels with higher carbon content, such as residual oil, as the EPA also explained in the 2015 NSPS. Id. Although the use of fuels meeting this criterion would not advance technology, in light of the other reasons described here, the EPA proposed and is finalizing that the use of natural gas, Nos. 1 and 2 fuel oils, and other fuels
739currently 
specified in 40 CFR part 60, subpart TTTT, qualify as the BSER for new and reconstructed combustion turbine EGUs in the low load subcategory at this time. The EPA also proposed including low- GHG hydrogen on the list of fuels meeting the uniform fuels criteria in 40 CFR part 60, subpart TTTTa. The EPA is finalizing the inclusion of hydrogen, regardless of the production pathway, on the list of fuels meeting the uniform fuels criteria in 40 CFR part 60, subpart TTTTa.
740The addition of hydrogen 
(and fuels derived from hydrogen) to 40 CFR part 60, subpart TTTTa, simplifies the recordkeeping and reporting requirements for low load combustion turbines that elect to burn hydrogen. 
For the reasons discussed in the 2015 
NSPS and noted above, the EPA did not propose that efficient design and operation qualify as the BSER for the low load subcategory. The emissions rate of a low load combustion turbine is highly dependent upon the way the 
specific combustion turbine is operated. For example, a combustion turbine with multiple startups and shutdowns and operation at part loads will have high emissions relative to if it were operated at steady-state high-load conditions. Important characteristics for reducing GHG emissions from low load combustion turbines are the ability to minimize emissions during periods of startup and shutdown and efficient operation at part loads and while changing loads. If the combustion turbine is frequently operated at part- load conditions with frequent starts and stops, a combustion turbine with a high design efficiency, which is determined at full-load steady-state conditions, would not necessarily emit at a lower GHG rate than a combustion turbine with a lower design efficiency. In addition, combustion turbines with higher design efficiencies have higher initial costs compared to combustion turbines with lower design efficiencies. Since the EPA does not have sufficient information at this time to determine emission reduction for the subcategory it is not possible to determine the cost effectiveness of a BSER based on high efficiency simple cycle turbines.
741 
The EPA solicited comment on 
whether, and the extent to which, high- efficiency designs also operate more efficiently at part loads and can start more quickly and reach the desired load more rapidly than combustion turbines with less efficient design efficiencies. In addition, the EPA solicited comment on the cost premium of high-efficiency simple cycle turbines. To the extent the Agency received additional relevant information, the EPA was considering promulgating design standard requirements pursuant to CAA section 111(h). However, the EPA did not receive comments that changed the proposal conclusions. 
The EPA did not propose the use of 
CCS or hydrogen co-firing as the BSER (or as a component of the BSER) for low load combustion turbines. The EPA did not propose that CCS is the BSER for simple cycle turbines based on the Agency’s assessment that currently available post-combustion amine-based carbon capture systems require that the exhaust from a combustion turbine be cooled prior to entering the carbon capture equipment. The most energy efficient way to cool the exhaust gas is to use a HRSG, which is an integral component of a combined cycle turbine system but is not incorporated in a simple cycle unit. For this reason and due to the high costs of CCS for low load combustion turbines, the Agency did not propose and is not finalizing a determination that CCS qualifies as the BSER for this subcategory of sources. 
The EPA did not propose low-GHG 
hydrogen co-firing as the BSER for low load combustion turbines because not all new combustion turbines can necessarily co-fire higher percentages of hydrogen, there are potential infrastructure issues specific to low load combustion turbines, and at the relatively infrequent levels of utilization that characterize the low load subcategory, a low-GHG hydrogen co- firing BSER would not necessarily result in cost-effective GHG reductions for all low load combustion turbines. As discussed later in this section, the Agency is not determining that low- GHG hydrogen co-firing qualifies as the BSER for combustion turbines. In future rulemaking the Agency could further evaluate the costs and emissions performance of other technologies to reduce emissions from low-load units to determine if other technologies qualify as the BSER. 
2. BSER for Intermediate Load 
Subcategory 
This section describes the BSER for 
new and reconstructed combustion turbines in the intermediate load subcategory. For combustion turbines in the intermediate load subcategory, the BSER is the use of high-efficiency simple cycle turbine technology in combination with the best operating and maintenance practices. 
a. Lower-Emitting Fuels 
The EPA did not propose and is not 
finalizing lower-emitting fuels as the 
BSER for intermediate load combustion turbines because, as described earlier in this section, it would achieve few GHG emission reductions compared to highly efficient generation. 
b. Highly Efficient Generation 
This section includes a discussion of 
the various highly efficient generation 
technologies used by owners/operators of combustion turbines. The appropriate technology depends on how the combustion turbine is operated, and the EPA has determined it does not have sufficient information to determine an appropriate output-based emissions standard for low load combustion turbines. At higher capacity factors, emission rates for simple cycle combustion turbines are more consistent, and the EPA has sufficient 
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742‘‘Cost and Performance Baseline for Fossil 
Energy Plants, Volume 5: Natural Gas Electricity 
Generating Units for Flexible Operation.’’ DOE/ NETL–2023/3855. May 5, 2023. 
743Fast start combined cycle turbine do not use 
an auxiliary boiler during hot starts and conventional start combined cycle turbine do not have auxiliary boilers. 744A steam injected combustion turbine would be 
considered a combined cycle combustion turbine (for NSPS purposes) because energy from the turbine engine exhaust is recovered in a HRSG and that energy is used to generate additional electricity. information to determine a BSER other 
than lower-emitting fuels. 
The use of highly efficient generating 
technology in combination with the best operating and maintenance practices has been demonstrated by multiple facilities for decades. Notably, over time, as technologies have improved, what is considered highly efficient has changed as well. Highly efficient generating technology is available and offered by multiple vendors for both simple cycle and combined cycle turbines. Both types of combustion turbines can also employ best operating and maintenance practices, which include routine operating and maintenance practices that minimize fuel use. 
For simple cycle turbines, 
manufacturers continue to improve the efficiency by increasing firing temperature, increasing pressure ratios, using intercooling on the air compressor, and adopting other measures. These improved designs allow for improved operating efficiencies and reduced emission rates. Design efficiencies of simple cycle turbines range from 33 to 40 percent. Best operating practices for simple cycle turbines include proper maintenance of the combustion turbine flow path components and the use of inlet air cooling to reduce efficiency losses during periods of high ambient temperatures. 
For combined cycle turbines, high- 
efficiency technology uses a highly efficient combustion turbine engine matched with a high-efficiency HRSG. The most efficient combined cycle EGUs use HRSG with three different steam pressures and incorporate a steam reheat cycle to maximize the efficiency of the Rankine cycle. It is not necessarily practical for owners/ operators of combined cycle facilities using a turbine engine with an exhaust temperature below 593 °C or a steam 
turbine engine smaller than 60 MW to incorporate a steam reheat cycle. Smaller combustion turbine engines, less than those rated at approximately 2,000 MMBtu/h, tend to have lower exhaust temperatures and are paired with steam turbines of 60 MW or less. These smaller combined cycle units are limited to using a HRSG with three different steam pressures, but without a 
reheat cycle. This increases the heat rate of the combined cycle unit by approximately 2 percent. High efficiency also includes, but is not limited to, the use of the most efficient steam turbine and minimizing energy losses using insulation and blowdown heat recovery. Best operating and maintenance practices include, but are not limited to, minimizing steam leaks, 
minimizing air infiltration, and cleaning and maintaining heat transfer surfaces. 
A potential drawback of combined 
cycle turbines with the highest design efficiencies is that the facility is relatively complicated and startup times can be relatively long. Combustion turbine manufacturers have invested in fast-start technologies that reduce startup times and improve overall efficiencies. According to the NETL Baseline Flexible Operation Report, while the design efficiencies are the same, the capital costs of fast-start combined cycle turbines are 1.6 percent higher than a comparable conventional start combined cycle facility.
742The 
additional costs include design parameters that significantly reduce start times. However, fast-start combined cycle turbines are still significantly less flexible than simple cycle turbines and generally do not serve the same role. The startup time to full load from a hot start takes a simple cycle turbine 5 to 8 minutes, while a combined cycle turbines ranges from 30 minutes for a fast-start combined cycle turbine to 90 minutes for a conventional start combined cycle turbine. The startup time to full load from a cold start takes a simple cycle turbine 10 minutes, while a combined cycle turbines ranges from 120 minutes for a fast-start combined cycle turbine to 250 minutes for a conventional start combined cycle turbine. In addition, fast-start combined cycle turbines require the use of an 
auxiliary boiler during warm and cold starts.
743In addition, minimum run 
times for simple cycle aeroderivative engines and combined cycle EGUs equal one minute and 120 minutes, respectively. Minimum downtime for the same group is five minutes and 60 minutes, respectively. Finally, simple cycle aeroderivative turbines have no limit to the number of starts per year. Combined cycle EGUs are limited in the number of starts, and additional maintenance costs will occur if the hours/start ratio drops below 25. The model combined cycle turbines in the NETL Baseline Flexible Operation Report use a HRSG with three different steam pressures and a reheat cycle. While the use of this type of HRSG increases design efficiencies at steady state conditions, it increases the capital costs and decreases the flexibility (e.g., longer start times) of the combined cycle 
turbine. While less common, combined cycle turbines can be designed with a relatively simple HRSG that produces either a single or two pressures of steam without a reheat cycle. While design efficiencies are lower, the combined cycle turbines are more flexible and have the potential to operate similar to at least a portion of the simple cycle turbines in the intermediate load subcategory and provide the same value to the grid. 
The EPA solicited comment on 
whether additional technologies for new simple and combined cycle EGUs that could reduce emissions beyond what is currently being achieved by the best performing EGUs should be included in the BSER. Specifically, the EPA sought comment on whether pressure gain combustion should be incorporated into a standard of performance based on an efficient generation BSER for both simple and combined cycle turbines. In addition, the EPA sought comment on whether the HRSG for combined cycle turbines should be designed to utilize supercritical steam conditions or to utilize supercritical CO
2as the working 
fluid instead of water; whether useful thermal output could be recovered from a compressor intercooler and boiler blowdown; and whether fuel preheating should be implemented. Commenters generally noted that these technologies are promising, but that because the EPA did not sufficiently evaluate the BSER criteria in the proposal and none of these technologies should be incorporated as part of the BSER. The EPA continues to believe these technologies are promising, but the Agency is not including them as part of the BSER at this time. 
The EPA also solicited comment on 
whether the use of steam injection is applicable to intermediate load combustion turbines. Steam injection is the use of a relatively simple and low- cost HRSG to produce steam, but instead of recovering the energy by expanding the steam through a steam turbine, the steam is injected into the compressor and/or through the fuel nozzles directly into the combustion chamber and the energy is extracted by the combustion turbine engine.
744 
Advantages of steam injection include improved efficiency and increased output of the combustion turbine as well as reduced NO
Xemissions. 
Combustion turbines using steam 
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745Bahrami, S., et al. (2015). Performance 
Comparison between Steam Injected Gas Turbine 
and Combined Cycle during Frequency Drops. Energies 2015, Volume 8. https://doi.org/10.3390/ en8087582. 
746Mitsubishi Power. Smart-AHAT (Advanced 
Humid Air Turbine). https://power.mhi.com/ products/gasturbines/technology/smart-ahat. 747The costing approach used by the EPA 
compares a combined cycle turbine using a smaller turbine engine plus a steam turbine to match the output from a simple cycle turbine. injection have characteristics in- 
between simple cycle and combined cycle combustion turbines. They are more efficient, but more complex and have higher capital costs than simple cycle combustion turbines without steam injection. Conversely, compared to combined cycle EGUs, simple cycle combustion turbines using steam injection are simpler, have shorter construction times, and have lower capital costs, but have lower efficiencies.
745 746 Combustion turbines 
using steam injection can start quickly, have good part-load performance, and can respond to rapid changes in demand, making the technology a potential solution for reducing GHG 
emissions from intermediate load combustion turbines. A potential drawback of steam injection is that the additional pressure drop across the HRSG can reduce the efficiency of the combustion turbine when the facility is running without the steam injection operating. 
The EPA is aware of a limited number 
of combustion turbines that are using steam injection that have maintained 12-operating month emission rates of less than 1,000 lb CO
2/MWh-gross. 
Commenters stated that steam injection does not qualify as the BSER because it has not been adequately demonstrated and the EPA did not include sufficient analysis of the technology in the proposal to determine it as the BSER for intermediate load combustion turbines. The EPA continues to believe the technology is promising and it may be used to comply with the standard of performance, but the Agency is not determining that it is the BSER for intermediate load combustion turbines at this time. In a potential future rulemaking, the Agency could further evaluate the costs and emissions performance of steam injection to determine if the technology qualifies as the BSER. 
i. Adequately Demonstrated 
The EPA proposed and is finalizing 
that highly efficient simple cycle 
designs are adequately demonstrated because highly efficient simple cycle turbines have been demonstrated by multiple facilities for decades, the efficiency improvements of the most efficient designs are incremental in nature and do not change in any significant way how the combustion 
turbine is operated or maintained, and the levels of efficiency that the EPA is proposing have been achieved by many recently constructed combustion turbines. Therefore, efficient generation technology described in this BSER is commercially available and the standards of performance are achievable. 
ii. Costs 
In general, advanced generation 
technologies enhance operational 
efficiency compared to lower efficiency designs. Such technologies present little incremental capital cost compared to other types of technologies that may be considered for new and reconstructed sources. In addition, more efficient designs have lower fuel costs, which offsets at least a portion of the increase in capital costs. 
For the intermediate load subcategory, 
the EPA considers that the costs of high- efficiency simple cycle combustion turbines are reasonable. As described in the subcategory section, the cost of combustion turbine engines is dependent upon many factors, but the EPA estimates that that the capital cost of a high-efficiency simple cycle turbine is 10 percent more than a comparable lower efficiency simple cycle turbine. Assuming all other costs are the same and that the high-efficiency simple cycle turbine uses 8 percent less fuel, high-efficiency simple cycle combustion turbines have a lower LCOE compared to standard efficiency simple cycle combustion turbines at a 12-operating month capacity factor of approximately 31 percent. At a 20 percent and 15 percent capacity factors, the compliance costs are $1.5/MWh and $35/metric ton and $3.0/MWh and $69/metric ton, respectively. The EPA has determined that the incremental costs the use of high efficiency simple cycle turbines as 
the BSER for intermediate load combustion turbines is reasonable. The EPA notes that the approach the Agency used to estimate these costs have a relatively high degree of uncertainty and are likely high given the common use of high efficiency simple cycle turbines without a regulatory driver. 
The EPA considered but is not 
finalizing combined cycle unit design for combustion turbines as the BSER for the intermediate load subcategory because it is unclear if combined cycle turbines could serve the same role as intermediate load simple cycle turbines as a whole. Specifically, the EPA does not have sufficient information to determine that an intermediate load combined cycle turbine can start and stop with enough flexibility to provide the same level of grid support as intermediate load simple cycle turbines as a whole. In addition, the amount of GHG reductions that could be achieved by operating combined cycle EGUs as intermediate load EGUs is unclear. Intermediate load combustion turbines start and stop so frequently that there would often not be sufficient periods of continuous operation where the HRSG would have sufficient time to generate steam to operate the steam turbine enough to significantly lower the emissions rate of the EGU. 
Some commenters agreed with the 
proposed rationale of the EPA, and other commenters disagreed and said that combined cycle turbine technology is cost effective and lower-emitting than simple cycle turbine technology and therefore qualifies as the BSER for intermediate load combustion turbines. Commenters supporting combined cycle technology as the BSER submitted cost information that indicated that combined cycle EGUs have lower capital costs and LCOE than simple cycle turbines. However, the commenters compared capital costs of larger combined cycle turbines to smaller simple cycle turbines and did not account for economies of scale. The EPA has concluded that the appropriate cost comparison is for combustion turbines with the same rated net output.
747Comparing the costs of 
different size EGUs is not appropriate because these EGUs provide different grid services. In addition, the commenters did not account for startup costs and the time required for a steam turbine to begin operating when determining the LCOE. 
The EPA considered the operation of 
simple cycle turbine to determine the potential for simple cycle turbine to add a HRSG while continuing to operate in the same manner, providing the same grid services, as current simple cycle turbines. As noted previously, aeroderivative simple cycle turbines have shorter run times per start than frame type simple cycle turbines at the same capacity factor. At an annual capacity factor of 20 percent, the median run time per start for aeroderivative and frame simple cycle turbines is 12 and 16 hours respectively. At an annual capacity factor of 30 percent, the average run times per start increase to 17 and 26 hours for aeroderivative and frame turbines respectively. The higher operating times of frame type simple cycle turbines, 
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748The emission reduction comparison is done 
assuming the same level of operation. Overall 
emission impacts would be different if the more efficient combustion turbine operates more then the baseline. 749This is a simplified assumption that does not 
take into account changing market conditions that could change the makeup and operation of new combustion turbines. 
750See 80 FR 64510 (October 23, 2015). along with the larger size of frame type 
turbines, indicate that combined cycle technology could be applicable to at least a portion of intermediate load combustion turbines. In future rulemakings addressing GHGs from new as well as existing combustion turbines, the EPA intends to further evaluate the costs and potential emission reductions of the use of faster starting and lower cost HRSG technology for intermediate load combustion turbines to determine if the technology does in fact qualify as the BSER. 
iii. Non-Air Quality Health and 
Environmental Impact and Energy Requirements 
Use of highly efficient generation 
reduces all non-air quality health and environmental impacts and energy requirements assuming it displaces less efficient or higher-emitting generation. Even when operating at the same input- based emissions rate, the more efficient a unit is, the less fuel is required to produce the same level of output; and, as a result, emissions are reduced for all pollutants. The use of highly efficient combustion turbines, compared to the use of less efficient combustion turbines, reduces all pollutants.
748By 
the same token, because improved efficiency allows for more electricity generation from the same amount of fuel, it will not have any adverse effects on energy requirements. 
Designating highly efficient 
generation as part of the BSER for new and reconstructed intermediate load combustion turbines will not have significant impacts on the nationwide supply of electricity, electricity prices, or the structure of the electric power sector. On a nationwide basis, the additional costs of the use of highly efficient generation will be small because the technology does not add significant costs and at least some of those costs are offset by reduced fuel costs. In addition, at least some of these new combustion turbines would be 
expected to incorporate highly efficient generation technology in any event. 
iv. Extent of Reductions in CO
2 
Emissions 
The EPA estimated the potential 
emission reductions associated with a 
standard that reflects the application of highly efficient generation as BSER for the intermediate load subcategory. As discussed in section VIII.G.1, the EPA determined that the standards of performance reflecting this BSER are 1,170 lb CO
2/MWh-gross for 
intermediate load combustion turbines. 
Between 2015 and 2022, 113 simple 
cycle turbines, an average of 16 per year, commenced operation. Of these, 112 reported 12-operating month capacity factors. The EPA estimates that 23 simple cycle turbines operated at 12- operating month capacity factors greater than 20 percent and potentially would be considered intermediate combustion turbines. To estimate reductions, the EPA assumed that the number of simple cycle turbines constructed between 2015 and 2022 and the operation of those combustion turbines would continue on an annual basis.
749For each 
simple cycle turbine that operated at a capacity greater than 20 percent, the EPA determined the percent reduction in emissions, based on the maximum 12-operating months intermediate load emission rate, that would be required to comply with the final NSPS for intermediate load turbines. The EPA then applied that same percent reduction in emissions to the average operating capacity factor to determine the emission reductions from the NSPS. Using this approach, the EPA estimates that the intermediate load standard will impact approximately a quarter of new simple cycle turbines. The EPA divided the total amount of calculated reductions for intermediate load simple cycle turbines built between 2015 and 2022 and divided that value by 7 (the number of years evaluated) to get estimated annual reductions. This approach results in annual reductions of 31,000 tons of CO
2as well as 8 tons of 
NO X. The emission reductions are 
projected to result primarily from building additional higher efficiency aeroderivative simple cycle turbines instead of less efficient frame simple cycle turbines. The reduced emissions come from relatively small reductions in the emission rates of the intermediate load aeroderivative simple cycle turbines. This is a snapshot of projected emission reductions from applying the NSPS retroactively to 2022. If more intermediate load simple cycle turbines are built in the future, the emission reductions would be higher than this estimate. Conversely, if fewer intermediate load simple cycles are built, the emission reductions would be lower than the EPA’s estimate. 
Importantly, the ‘‘highly efficient 
generation’’ which the EPA has determined to be the BSER for new and reconstructed intermediate load 
combustion turbines and to be the first component BSER for base load stationary combustions, is not the same as the ‘‘heat rate improvements’’ (HRI, or ‘‘efficiency improvements’’) that the EPA determined to be the BSER for existing coal-fired steam generating EGUs in the ACE Rule. As noted earlier in this document, the EPA has concluded that the suite of HRI in the ACE Rule is not an appropriate BSER for existing coal-fired EGUs. In the EPA’s technical judgment, the suite of HRI set forth in the ACE Rule would provide negligible CO
2reductions at best and, in 
many cases, may increase CO 2 
emissions because of the ‘‘rebound effect,’’ which is explained and discussed in section VII.D.4.a.iii of this preamble. Increased CO
2emissions from 
the ‘‘rebound effect’’ can occur when a coal-fired EGU improves its efficiency (heat rate), which can move the unit up on the dispatch order—resulting in an EGU operating for more hours during the year than it would have without having done the efficiency improvements. There is also the possibility that a more efficient coal- fired EGU could displace a lower emitting generating source, further exacerbating the problem. 
Conversely, including ‘‘highly 
efficient generation’’ as a component of the BSER for new and reconstructed does not create this risk of displacing a lower-emitting generating source. A new highly efficient stationary combustion turbine may be dispatched more than it would have been if it were not built as a highly efficient turbine, but it is more likely to displace an existing coal-fired EGU or a less efficient existing stationary combustion turbine. It would be unlikely to displace a renewable generating source. 
For base load stationary combustion 
turbines, ‘‘highly efficient generation’’ is 
the first component of the BSER—with 90 percent capture CCS being the second component of the BSER. This is very similar to the Agency’s BSER determination for the NSPS for new fossil fuel-fired steam generating units. In that final rule, the EPA established standards of performance for newly constructed fossil fuel-fired steam generating units based on the performance of a new highly efficient supercritical pulverized coal (SCPC) EGU implementing post-combustion partial CCS technology, which the EPA determined to be the BSER for these sources.
750 
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751Cost And Performance Baseline for Fossil 
Energy Plants Volume 1: Bituminous Coal and 
Natural Gas to Electricity, Rev. 4A (October 2022), https://www.osti.gov/servlets/purl/1893822 . v. Promotion of the Development and 
Implementation of Technology 
The EPA also considered the potential 
impact of selecting highly efficient simple cycle generation technology as the BSER for the intermediate load subcategory in promoting the development and implementation of improved control technology. New highly efficient simple cycle turbines are more efficient than the average new simple cycle turbine and a standard based on the performance of the most efficient, best performing simple cycle turbine will promote penetration of the most efficient units throughout the industry. Accordingly, consideration of this factor supports the EPA’s proposal to determine this technology to be the BSER. 
c. Low-GHG Hydrogen and CCS 
The EPA did not propose and is not 
finalizing either CCS or co-firing low- 
GHG hydrogen as the first component of the BSER for intermediate load combustion turbines, for the reasons given in sections VIII.F.4.c.iii (CCS) and VIII.F.5 (low-GHG hydrogen). 
d. Summary of BSER Determinations 
The EPA is finalizing that highly 
efficient generating technology in 
combination with the best operating and maintenance practices is the BSER for intermediate load combustion turbines. Specifically, the use of highly efficient simple cycle technology in combination with the best operating and maintenance practices is the BSER for intermediate load combustion turbines. 
Highly efficient generation qualifies 
the BSER because it is adequately demonstrated, it can be implemented at reasonable cost, it achieves emission reductions, and it does not have significant adverse non-air quality health or environmental impacts or significant adverse energy requirements. The fact that it promotes greater use of advanced technology provides additional support; however, the EPA considers highly efficient generation to 
the BSER for intermediate load combustion turbines even without taking this factor into account. 
3. BSER for Base Load Subcategory— 
First Component 
This section describes the first 
component of the BSER for newly constructed and reconstructed combustion turbines in the base load subcategory. For combustion turbines in the base load subcategory, the first component of the BSER is the use of high-efficiency combined cycle technology in combination with the best operating and maintenance practices. a. Lower-Emitting Fuels 
The EPA did not propose and is not 
finalizing lower-emitting fuels as the 
BSER for base load combustion turbines because, as described earlier in this section, it would achieve few GHG emission reductions compared to highly efficient generation. 
b. Highly Efficient Generation 
i. Adequately Demonstrated 
The EPA proposed and is finalizing 
that highly efficient combined cycle 
designs are adequately demonstrated because highly efficient combined cycle EGUs have been demonstrated by multiple facilities for decades, and the efficiency improvements of the most efficient designs are incremental in nature and do not change in any significant way how the combustion turbine is operated or maintained. Due to the differences in HRSG efficiencies for smaller combined cycle turbines, the EPA proposed and is finalizing less stringent standards of performance for smaller base load turbines with base load ratings of less than 2,000 MMBtu/ h relative to those for larger base load turbines. The levels of efficiency that the EPA is proposing have been achieved by many recently constructed combustion turbines. Therefore, efficient generation technology described in this BSER is commercially available and the standards of performance are achievable. 
ii. Costs 
For the base load subcategory, the 
EPA considers the cost of high- 
efficiency combined cycle EGUs to be reasonable. While the capital costs of a higher efficiency combined cycle EGUs are 1.9 percent higher than standard efficiency combined cycle EGUs, fuel use is 2.6 percent lower.
751The 
reduction in fuel costs fully offset the capital costs at capacity factors of 40 percent or greater over the expected 30- year life of the facility. Therefore, a BSER based on the use of high- efficiency combined cycle combustion turbines for base load combustion turbines would have minimal, if any, overall compliance costs since the capital costs would be recovered through reduced fuel costs over the expected 30-year life of the facility. iii. Non-Air Quality Health and 
Environmental Impact and Energy Requirements 
Use of highly efficient generation 
reduces all non-air quality health and environmental impacts and energy requirements as compared to use of less efficient generation. Even when operating at the same input-based emissions rate, the more efficient a unit is, the less fuel is required to produce the same level of output; and, as a result, emissions are reduced for all pollutants. The use of highly efficient combustion turbines, compared to the use of less efficient combustion turbines, reduces all pollutants. By the same token, because improved efficiency allows for more electricity generation from the same amount of fuel, it will not have any adverse effects on energy requirements. 
Designating highly efficient 
generation as part of the BSER for new and reconstructed base load combustion turbines will not have significant impacts on the nationwide supply of electricity, electricity prices, or the structure of the electric power sector. On a nationwide basis, the additional costs of the use of highly efficient generation will be small because the technology does not add significant costs and at least some of those costs are offset by reduced fuel costs. In addition, at least some of these new combustion turbines would be expected to incorporate highly efficient generation technology in any event. 
iv. Extent of Reductions in CO
2 
Emissions 
The EPA used a similar approach to 
estimating emission reductions for base 
load combustion turbines as intermediate load combustion turbines, except the Agency reviewed recently constructed combined cycle EGUs. As discussed in section VIII.G.1, the EPA determined that the standard of performance reflecting this BSER is 800 lb CO
2/MWh-gross for base load 
combustion turbines. The Agency assumed all new combined cycle turbines would be impacted by the base load emissions standard. Between the beginning of 2015 and the beginning of 2022, 129 combined cycle turbines, an average of 18 per year, commenced operation. Of those combined cycle turbines, 107 had 12-operating month emissions data. For each of these 107 combined cycle turbines that had a maximum 12-operating month emissions rate greater than 800 lb CO
2/ 
MWh-gross, the EPA determined the reductions that would occur assuming the combined cycle turbine reduced its 
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752See Portland Cement Ass’n v. Ruckelshaus, 
486 F.2d 375, 391 (D.C. Cir. 1973) (citations 
omitted). emissions rate to 800 lb CO 2/MWh-gross 
and continued to operate at its average 
capacity factor. The EPA summed the results and divided by 8 (the number of years evaluated) to estimate the annual GHG reductions that will result from this final rule. The EPA estimates that the base load standard will result in annual reductions of 313,000 tons of CO
2as well as 23 tons of NO X. The 
reductions increase each year and in year 3 the annual reductions would be 939,000 tons of CO
2and 69 tons of NO X. 
v. Promotion of the Development and 
Implementation of Technology 
The EPA also considered the potential 
impact of selecting highly efficient generation technology as the BSER in promoting the development and implementation of improved control technology. The highly efficient combustion turbines are more efficient and lower emitting than the average new combustion turbine generation technology. Determining that highly efficient turbines are a component of the BSER will advance penetration of the best performing combustion turbines throughout the industry—and will incentivize manufacturers to offer improved turbines that meet the final standard of performance associated with application of the BSER. Accordingly, consideration of this factor supports the EPA’s proposal to determine this technology to be the BSER. 
c. Low-GHG Hydrogen and CCS 
The EPA did not propose and is not 
finalizing either CCS or co-firing low- 
GHG hydrogen as the first component of the BSER for base load combustion turbines, for the reasons given in sections VIII.F.4.c.iii (CCS) and VIII.F.5 (low-GHG hydrogen). 
d. Summary of BSER Determinations 
The EPA is finalizing that highly 
efficient generating technology in 
combination with the best operating and maintenance practices is the BSER for first component of the BSER for base load combustion turbines. The phase-1 standards of performance are based on the application of that technology. Specifically, the use of highly efficient combined cycle technology in combination with best operating and maintenance practices is the first component of the BSER for base load combustion turbines. 
Highly efficient generation qualifies 
as the BSER because it is adequately demonstrated, it can be implemented at reasonable cost, it achieves emission reductions, and it does not have significant adverse non-air quality health or environmental impacts or significant adverse energy requirements. 
The fact that it promotes greater use of advanced technology provides additional support; however, the EPA considers highly efficient generation to be a component of the BSER for base load combustion turbines even without taking this factor into account. 
4. BSER for Base Load Subcategory— 
Second Component 
a. Authority To Promulgate a Multi-Part 
BSER and Standard of Performance 
The EPA’s approach of promulgating 
standards of performance that apply in 
multiple phases, based on determining the BSER to be a set of controls with multiple components, is consistent with CAA section 111(b). That provision authorizes the EPA to promulgate ‘‘standards of performance,’’ CAA section 111(b)(1)(B), defined, in the singular, as ‘‘a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the [BSER].’’ CAA section 111(a)(1). CAA section 111(b)(1)(B) further provides, ‘‘[s]tandards of performance . . . shall become effective upon promulgation.’’ In this rulemaking, the EPA is determining that the BSER is a set of controls that, depending on the subcategory, include highly efficient generation plus use of CCS. The EPA is determining that affected sources can apply the first component of the BSER— highly efficient generation—by the effective date of the final rule and can apply both the first and second components of the BSER—highly efficient generation in combination with 90 percent CCS—in 2032. 
Accordingly, the EPA is finalizing 
standards of performance that reflect the application of this multi-component BSER and that take the form of standards of performance that affected sources must comply with in two phases. This multi-phase standard of performance ‘‘become[s] effective upon promulgation.’’ CAA section 111(b)(1)(B). That is, upon promulgation, affected sources become legally subject to the multi-phase standard of performance and must comply with it by its terms. Specifically, affected sources must comply with the first phase standards, which are based on the application of the first component of the BSER, upon initial startup of the facility. They must comply with the second phase standards, which are based on the application of both the first and second components of the BSER, beginning January 2032. D.C. Circuit caselaw supports the 
proposition that CAA section 111 
authorizes the EPA to determine that controls qualify as the BSER—including meeting the ‘‘adequately demonstrated’’ criterion—even if the controls require some amount of ‘‘lead time,’’ which the court has defined as ‘‘the time in which the technology will have to be available.’’
752The caselaw’s 
interpretation of ‘‘adequately demonstrated’’ to accommodate lead time accords with common sense and the practical experience of certain types of controls, discussed below. Consistent with this caselaw, the phased implementation of the standards of performance in this rule ensures that facilities have sufficient lead time for planning and implementation of the use of CCS-based controls necessary to comply with the second phase of the standards, and thereby ensures that the standards are achievable. For further discussion of this point, see section V.C.2.b.iii. 
The EPA has promulgated several 
prior rulemakings under CAA section 111(b) that have similarly provided the 
regulated sector with lead time to accommodate the availability of technology, which also serve as precedent for the two-phase implementation approach proposed in this rule. See 81 FR 59332 (August 29, 2016) (establishing standards for municipal solid waste landfills with 30- month compliance timeframe for installation of control device, with interim milestones); 80 FR 13672, 13676 (March 16, 2015) (establishing stepped compliance approach to wood heaters standards to permit manufacturers lead time to develop, test, field evaluate and certify current technologies to meet Step 2 emission limits); 78 FR 58416, 58420 (September 23, 2013) (establishing multi-phased compliance deadlines for revised storage vessel standards to permit sufficient time for production of necessary supply of control devices and for trained personnel to perform installation); 77 FR 56422, 56450 (September 12, 2012) (establishing standards for petroleum refineries, with 3-year compliance timeframe for installation of control devices); 71 FR 39154, 39158 (July 11, 2006) (establishing standards for stationary compression ignition internal combustion engines, with 2- to 3-year compliance timeframe and up to 6 years for certain emergency fire pump engines); 70 FR 28606, 28617 (March 18, 2005) (establishing two-phase caps for 
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753Cf. New Jersey v. EPA, 517 F.3d 574, 583–584 
(D.C. Cir. 2008) (vacating rule on other grounds). 
754Cf. West Virginia v. EPA, 597 U.S. 697 (2022) 
(vacating rule on other grounds). mercury standards of performance from 
new and existing coal-fired electric utility steam generating units based on timeframe when additional control technologies were projected to be adequately demonstrated).
753Cf. 80 FR 
64662, 64743 (October 23, 2015) (establishing interim compliance period to phase in final power sector GHG standards to allow time for planning 
and investment necessary for implementation activities).
754In each 
action, the standards and compliance timelines were effective upon the final rule, with affected facilities required to comply consistent with the phased compliance deadline specified in each action. 
It should be noted that the multi- 
phased implementation of the standards of performance that the EPA is finalizing in this rule, like the delayed or multi-phased standards in prior rules just described, is distinct from the promulgation of revised standards of performance under the 8-year review provision of CAA section 111(b)(1)(B). As discussed in section VIII.F, the EPA has determined that the proposed BSER—highly efficient generation and use of CCS—meet all of the statutory criteria and are adequately demonstrated for the compliance timeframes being finalized. Thus, the second phase of the standard of performance applies to affected facilities that commence construction after May 23, 2023 (the date of the proposal). In contrast, when the EPA later reviews and (if appropriate) revises a standard of performance under the 8-year review provision, then affected sources that commence construction after the date of that proposal of the revised standard of performance will be subject to that standard, but not sources that commenced construction earlier. 
Similarly, the multi-phased 
implementation of the standard of performance that the EPA is including in this rule is also distinct from the promulgation of emission guidelines for existing sources under CAA section 111(d). Emission guidelines only apply to existing sources, which are defined in CAA section 111(a)(6) as ‘‘any stationary source other than a new source.’’ Because new sources are defined relative to the proposal of standards pursuant to CAA section 111(b)(1)(B), standards of performance adopted pursuant to emission guidelines will only apply to sources constructed before May 23, 2023, the date of the proposed standards of performance for new sources. 
b. BSER for the Intermediate Load 
Subcategory—Second Component 
The EPA proposed that the second 
component of the BSER for intermediate load combustion turbines was co-firing 30 percent low-GHG hydrogen in 2032. As discussed in section VIII.F.5.b, the EPA is not determining that low-GHG hydrogen qualifies as the BSER at this time. Therefore, the Agency is not finalizing a second component of the BSER for intermediate load combustion turbines. 
c. BSER for Base Load Subcategory— 
Second Component 
i. Lower-Emitting Fuels 
The EPA did not propose and is not 
finalizing lower-emitting fuels as the 
second component of the BSER for intermediate or base load combustion turbines because it would achieve few emission reductions, compared to highly efficient generation without or in combination with the use of CCS. 
ii. Highly Efficient Generation 
For the reasons described above, the 
EPA is determining that highly efficient 
generation in combination with best operating and maintenance practices continues to be a component of the BSER that is reflected in the second phase of the standards of performance for base load combustion turbine EGUs. Highly efficient generation reduces fuel use and, therefore, the amount of CO
2 
that must be captured by a CCS system. Since a highly efficient turbine system would produce less flue gas that would need to be treated (compared to a less efficient turbine system), physically smaller carbon capture equipment may be used—potentially reducing capital, fixed, and operating costs. 
iii. Hydrogen Co-Firing 
The EPA proposed a pathway for the 
second component of the BSER for base 
load combustion turbines of co-firing 30 percent low-GHG hydrogen in 2032 increasing to 96 percent low-GHG hydrogen co-firing in 2038. As discussed in section VIII.F.5.b of this preamble, the EPA is not finalizing a determination that low-GHG hydrogen co-firing qualifies as the BSER. Therefore, the Agency is not finalizing a second component low-GHG hydrogen co-firing pathway of the BSER for base load combustion turbines. As the EPA’s standard of performance is technology neutral, however, affected sources may comply with it by co-firing hydrogen. iv. CCS 
(A) Overview 
In this section of the preamble, the 
EPA explains its rationale for finalizing 
that CCS with 90 percent capture is a component of the BSER for new base load combustion turbines. CCS is a control technology that can be applied at the stack of a combustion turbine EGU, achieves substantial reductions in emissions and can capture and permanently sequester at least 90 percent of the CO
2emitted by 
combustion turbines. The technology is adequately demonstrated, given that it has been operated on a large scale and is widely applicable to these sources, and there are vast sequestration opportunities across the continental U.S. Additionally, the costs for CCS are reasonable in light of recent technology cost declines and policies including the tax credit under IRC section 45Q. Moreover, the non-air quality health and environmental impacts of CCS can be mitigated, and the energy requirements of CCS are not unreasonably adverse. The EPA’s weighing of these factors together provides the basis for finalizing 90 percent capture CCS as a component of BSER for these sources. In addition, this BSER determination aligns with the caselaw, discussed in section V.C.2.h of the preamble, stating that CAA section 111 encourages continued advancement in pollution control technology. 
This section incorporates by reference 
the parts of section VII.C.1.a. of this 
preamble that discuss the many aspects of CCS that are common to both steam generating units and to new combustion turbines. This includes the discussion of simultaneous demonstration of CO
2 
capture, transport, and sequestration discussed at VII.C.1.a.i(A); the discussion of CO
2capture technology 
used at coal-fired steam generating units at VII.C.1.a.i(B) (the Agency explains below why that record is also relevant to our BSER analysis for new combustion turbines); the discussion of CO
2transport at VII.C.1.a.i(C); and the 
discussion of geologic storage of CO 2at 
VII.C.1.a.i(D). And the record supporting that transport and sequestration of CO
2from coal-fired 
units is adequately demonstrated and meets the other requirements for BSER applies as well to transport and sequestration of CO
2from combustion 
turbines. 
The primary differences between 
using post-combustion capture from a coal combustion flue gas and a natural gas combustion flue gas are associated with the level of CO
2in the flue gas 
stream and the levels of other pollutants that must be removed. In coal 
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755NETL Carbon Dioxide Capture Approaches. 
https://netl.doe.gov/research/carbon-management/ 
energy-systems/gasification/gasifipedia/capture- approaches. 756Fluor Econamine FG PlusSMbrochure. https:// 
a.fluor.com/f/1014770/x/a744f915e1/econamine-fg- 
plus-brochure.pdf. 
757‘‘Commercially Available CO 2Capture 
Technology’’ Power, (Aug 2009). https://www.powermag.com/commercially-available-co2- capture-technology/. 758Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 
427, 433 (1973). combustion flue gas, the concentration 
of CO 2is typically approximately 13 to 
15 volume percent, while the concentration of CO
2from natural gas- 
fired combined cycle combustion flue gas is approximately 3 to 4 volume percent.
755Capture of CO 2at dilute 
concentrations is more challenging but 
there are commercially available amine- based solvents that can be used with dilute CO
2streams to achieve 90 percent 
capture. In addition, flue gas from a coal-fired steam EGU contains a variety of non-carbonaceous components that must be removed to meet environmental limits (e.g., mercury and other metals, 
particulate matter (fly ash), and acid gases (including sulfur dioxide (SO
2) 
and hydrogen chloride and hydrogen fluoride). When amine-based post- combustion carbon capture is used with a coal-fired EGU, the flue gas stream must be further cleaned, sometimes beyond required environmental standards, to avoid the fouling of downstream process equipment and to prevent degradation of the amine solvent. Absent pretreatment of the coal combustion flue gas, the amines can absorb SO
2and other acid gases to form 
heat stable salts, thereby degrading the performance of the solvent. Amine solvents can also experience catalytic oxidative degradation in the presence of some metal contaminants. Thermal oxidation of the solvent can also occur but can be mitigated by interstage cooling of the absorber column. Natural gas combustion flue gas typically contains very low (if any) levels of SO
2, 
acid gases, fly ash, and metals. Therefore, fouling and solvent degradation are less of a concern for carbon capture from natural gas-fired EGUs. 
New natural gas-fired combustion 
turbine EGUs also have the option of using oxy-combustion technology—such as that currently being demonstrated and developed by NET Power. As discussed earlier, the NET Power system uses oxy-combustion (combustion in pure oxygen) of natural gas and a high- pressure supercritical CO
2working fluid 
(instead of steam) to produce electricity in a combined cycle turbine configuration. The combustion products are water and high-purity, pipeline- ready CO
2which is available for 
sequestration or sale to another industry. The NET Power technology does not involve solvent-based CO
2 
separation and capture since pure CO 2 
is a product of the process. The NET Power technology is not currently 
applicable to coal-fired steam generating utility boilers—though it could be utilized with combustion of gasified coal or other solid fossil fuels (e.g., petroleum coke). 
For new base load combustion 
turbines, the EPA proposed that CCS with a 90 percent capture rate, beginning in 2035, meets the BSER criteria. Some commenters agreed with the EPA that CCS for base load combustion turbines satisfies the BSER criteria. Other commenters claimed that CCS is not a suitable BSER for new base load combustion turbines. The EPA disagrees with these commenters. 
As with existing coal-fired steam 
generating units, CCS applied to new combined cycle combustion turbines has three major components: CO
2 
capture, transportation, and sequestration/storage. CCS with 90 percent capture has been adequately demonstrated for combined cycle combustion turbines for many of the same reasons described in section VII.C.1.a.i. The Bellingham Energy Center, a natural gas-fired combined cycle combustion turbine in south central Massachusetts, successfully applied post-combustion carbon capture using the Fluor Econamine FG Plus
SM 
amine-based solvent from 1991–2005 with 85–95 percent CO
2capture.756The 
plant captured approximately 365 tons 
of CO 2per day from a 40 MW slip 
stream757and was ultimately shut 
down and decommissioned primarily due to rising gas prices. 
As discussed in further detail below, 
additional natural gas-fired combined cycle combustion turbine CCS projects are in the planning stage, which confirms that CCS is becoming accepted across the industry. As discussed above, CCS with 90 percent capture has been demonstrated for coal-fired steam generating units, and that information forms part of the basis for the EPA’s determination that CCS with 90 percent capture has been have adequately demonstrated for these combustion turbines. Statements from vendors and the experience of industrial applications of CCS provide further support that post-combustion CCS with 90 percent capture is adequately demonstrated for these combustion turbines. 
The EPA’s analysis of the 
transportation and sequestration components of CCS for new base load combustion turbines is similar to its 
analysis of those components for existing coal-fired steam generating units and, therefore, for much the same reasons, the EPA is determining that each of those components is adequately demonstrated, and that CCS as a whole—including those components when combined with the 90 percent CO
2capture component—is adequately 
demonstrated. In addition, new sources may consider access to CO
2transport 
and storage sites in determining where to build, and the EPA expects that since this rule was proposed, companies siting new base load combustion turbines have taken into consideration the likelihood of a regulatory regime requiring significant emissions reductions. 
The use of CCS at 90 percent capture 
can be implemented at reasonable cost because it allows affected sources to maximize the benefits of the IRC section 45Q tax credit. Finally, any adverse health and environmental impacts and energy requirements are limited and, in many cases, can be mitigated or avoided. It should also be noted that a determination that CCS is the BSER for these units will promote further use and development of this advanced technology. After balancing these factors, the EPA is determining that utilization of CCS with 90 percent capture for new base load combustion turbine EGUs satisfies the criteria for BSER. 
(B) Adequately Demonstrated 
The legal test for an adequately 
demonstrated system, and an achievable 
standard, has been discussed at length above. (See sections V.C.2.b and VII.C.a.i of this preamble). As previously noted, concepts of adequate demonstration and achievability are closely related: ‘‘[i]t is the system which 
must be adequately demonstrated and the standard which must be 
achievable,’’
758based on application of 
the system. An achievable standard means a standard based on the EPA’s finding that sufficient evidence exists to reasonably determine that the affected sources in the source category can adopt a specific system of emission reduction 
to achieve the specified degree of emission limitation. The foregoing sections have shown that CCS, specifically using amine post- combustion CO
2capture, is adequately 
demonstrated for existing coal units, 
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759The EPA uses the two phrases (i) BSER is CCS 
with 90 percent capture and (ii) CCS with 90 
percent capture is achievable, or similar phrases, interchangeably. 
760Lignite Energy Council v. EPA, 198 F.3d 930 
(D.C. Cir. 1999). 761Many of the challenges faced by Boundary 
Dam Unit 3—which proved to be solvable—were 
caused by the impurities, including fly ash, SO 2, 
and trace contaminants in coal-fired post- combustion flue gas—which do not occur in the natural gas post-combustion flue gas. As a result, for CO
2capture for natural gas combustion, flue gas 
handling is simpler, solvent degradation is easier to prevent, and fewer redundancies may be necessary for various components (e.g., heat exchangers). 762The EPA proposed that because the BSER for 
non-base load combustion turbines was simple cycle technology, CCS was not applicable. 
763U.S. Department of Energy (DOE). Carbon 
Capture Opportunities for Natural Gas Fired Power Systems. https://www.energy.gov/fecm/articles/ 
carbon-capture-opportunities-natural-gas-fired- power-systems. and that a 90 percent capture standard 
is achievable.759 
Pursuant to Lignite Energy Council v. 
EPA, the EPA may extrapolate based on 
data from a particular kind of source to conclude that the technology at issue will also be effective at a similar source.
760This standard is satisfied in 
our case, because of the essential ways in which CO
2capture at coal-fired steam 
generating units is identical to CO 2 
capture at natural gas-fired combined cycle turbines. As detailed in section VII.C.1.a.i(B), amine-based CO
2capture 
removes CO 2from post-combustion flue 
gas by reaction of the CO 2with amine 
solvent. The same technology (i.e., the 
same solvents and processes) that is employed on coal-fired steam generating units—and that is employed to capture CO
2from fossil fuel combustion in other 
industrial processes—can be applied to remove CO
2from the post-combustion 
flue gas of natural gas-fired combined cycle EGUs. In fact, the only differences in application of amine-based CO
2 
capture on a natural gas-fired combined cycle unit relative to a coal-fired steam generating unit are related to the differences in composition of the respective post-combustion flue gases, and as explained below, these differences do not preclude achieving 90 percent capture from a gas-fired turbine. 
First, while coal flue gas contains 
impurities including SO
2, PM, and trace 
minerals that can affect the downstream CO
2process, and thus coal flue gas 
requires substantial pre-treatment, the post-combustion flue gas of natural gas- fired combustion turbines has few, if any, impurities that would impact the downstream CO
2capture plant. Where 
impurities are present, SO 2in particular 
can cause solvent degradation, and coal- fired sources without an FGD would likely need to install one. Filterable PM (fly ash) from coal, if not properly managed, can cause fouling and scale to accumulate on downstream blower fans, heat exchangers, and absorber packing material. Further, additional care in the solvent reclamation is necessary to mitigate solvent degradation that could otherwise occur due to the trace elements that can be present in coal. Because the flue gas from natural gas- fired combustion turbines contains few, if any, impurities that would impact downstream CO
2capture, the flue gas 
from natural gas-fired combined cycle EGUs is easier to work with for CO
2 capture, and many of the challenges that 
were faced by earlier commercial scale demonstrations on coal-fired units can be avoided in the application of CCS at natural gas-fired combustion turbines. 
Second, the CO
2concentration of 
natural gas-fired combined cycle flue gas is lower than that of coal flue gas (approximately 3-to-4 volume percent for natural gas combined cycle EGUs; 13-to-15 volume percent for coal). For solvent-based CO
2capture, CO 2 
concentration is the driving force for mass transfer and the reaction of CO
2 
with the solvent. However, flue gases with lower CO
2concentrations can be 
readily addressed by the correct sizing and design of the capture equipment— and such considerations have been made in evaluating the BSER here and are reflected in the cost analysis in VII.C.1.a.ii(A) of this preamble. Moreover, as is detailed in the following sections of the preamble, amine-based CO
2capture has been shown to be 
effective at removal of CO 2from the flue 
gas of natural gas-fired combined cycle EGUs. In fact, there is not a technical 
limit to removal of CO
2from flue gases 
with low CO 2concentrations—the EPA 
notes that amine solvents have been shown to be able to remove CO
2to 
concentrations that are less than the concentration of CO
2in the atmosphere. 
Considering these factors, the 
evidence that underlies the EPA’s determination that amine post- combustion CO
2capture is adequately 
demonstrated, and that a 90 percent capture standard is achievable, at coal- fired steam generating units, also applies to natural gas-fired combined cycle EGUs. Where differences exist, due to differences in flue gas composition, CCS at natural gas-fired combined cycle combustion turbines will in general face fewer challenges than CCS at coal-fired steam generators.
761Moreover, in addition to 
the evidence outlined above, the following sections provide additional information specific to, including examples of, anime-based capture at natural gas-fired combined cycle EGUs. For these reasons, the EPA has determined that CCS at 90 percent capture is adequately demonstrated for natural gas fired combined cycle EGUs. (1) CO
2Capture for Combined Cycle 
Combustion Turbines 
As discussed in the preceding, new 
stationary combustion turbines can use 
amine-based post-combustion capture. Additionally, new stationary combustion turbines may also utilize oxy-combustion, which uses a purified oxygen stream from an air separation unit (often diluted with recycled CO
2to 
control the flame temperature) to combust the fuel and produce a nearly pure stream of CO
2in the flue gas, as 
opposed to combustion with oxygen in air which contains 80 percent nitrogen. Currently available post-combustion amine-based CO
2capture systems 
require that the flue gas be cooled prior to entering the capture equipment. This holds true for the exhaust from either a coal-fired utility boiler or from a combustion turbine. The most energy efficient way to cool the flue gas stream is to use a HRSG—which, as explained above, is an integral component of a combined cycle turbine system—to generate additional useful output.
762 
CO 2capture has been successfully 
applied to an existing combined cycle turbine and several other projects are in development, as discussed immediately below. 
(a) CCS on Combined Cycle EGUs 
The most prominent example of the 
use of carbon capture technology on a 
natural gas-fired combined cycle turbine EGU was at the 386 MW Bellingham Cogeneration Facility in Bellingham, Massachusetts. The plant used Fluor’s Econamine FG Plus
SMamine-based CO 2 
capture system with a capture capacity of 360 tons of CO
2per day. The system 
was used to produce food-grade CO 2 
and was in continuous commercial operation from 1991 to 2005 (14 years). The capture system was able to continuously capture 85–95 percent of the CO
2that would have otherwise been 
emitted from the flue gas of a 40 MW slip stream.
763The natural gas 
combustion flue gas at the facility contained 3.5 volume percent CO
2and 
13–14 volume percent oxygen. As mentioned earlier, the flue gas from a 
coal combustion flue gas stream has a typical CO
2concentration of 
approximately 15 volume percent and more dilute CO
2stream are more 
challenging to separate and capture. Just before the CO
2capture system was shut 
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764https://boereport.com/2022/08/16/fluor/ . 
765‘‘Technologies for CCS on Natural Gas Power 
Systems’’ Dr. Satish Reddy presentation to USEA, 
April 2014, https://usea.org/sites/default/files/ event-/Reddy%20USEA%20Presentation%202014.pptx. 
766https://www.fluor.com/market-reach/ 
industries/energy-transition/carbon-capture. 
767https://newsroom.fluor.com/news-releases/ 
news-details/2024/Fluors-Econamine-FG-PlusSM- Carbon-Capture-Technology-Selected-to-Reduce- CO2-Emissions-at-Chevron-Facility/default.aspx. 
768https://netl.doe.gov/carbon-capture/power- 
generation. 
769Mitsubishi Heavy Industries, ‘‘Mitsubishi 
Heavy Industries Engineering Successfully Completes Testing of New KS–21
TMSolvent for CO 2 
Capture,’’ https://www.mhi.com/news/211019.html . 
770MHI and MHIENG Awarded FEED Contract. 
https://www.mhi.com/news/22083001.html . 771Buli, N. (2021, May 10). SSE, Equinor plan 
new gas power plant with carbon capture in Scotland. Reuters. https://www.reuters.com/ 
business/sustainable-business/sse-equinor-plan- new-gas-power-plant-with-carbon-capture-scotland- 2021-05-11/. 
772Acorn CCS granted North Sea storage licenses. 
September 18, 2023. https://www.ogj.com/energy- transition/article/14299094/acorn-granted-licenses- for-co2-storage. 
773https://status23.globalccsinstitute.com/ . 
774The NET Power Cycle was formerly referred 
to as the Allam-Fetvedt cycle. https://netpower.com/technology/. 
775Yellen, D. (2020, May 25). Allam Cycle carbon 
capture gas plants: 11 percent more efficient, all CO
2captured. Energy Post. https://energypost.eu/ 
allam-cycle-carbon-capture-gas-plants-11-more- efficient-all-co2-captured/. 
776This allows for capture of over 97 percent of 
the CO 2emissions. www.netpower.com. 780Calpine Sutter Decarbonization Project, May 
17, 2023. https://www.smud.org/en/Corporate/ 
Continued down in 2005 (due to high natural gas 
price), the system had logged more than 120,000 hours of CO
2capture764and 
had a 98.5 percent on-stream (availability) factor.
765 
The Fluor Econamine FG PlusSMis a 
propriety carbon capture solution with more than 30 licensed plants and more than 30 years of operation. This technology uses a proprietary solvent to capture CO
2from post-combustion 
sources. The process is well suited to capture CO
2from large, single-point 
emission sources such as power plants or refineries, including large facilities with CO
2capture capacities greater than 
10,000 tons per day.766On February 6, 
2024, Fluor Corporation announced that Chevron New Energies plans to use the Econamine FG Plus
SMcarbon capture 
technology to reduce CO 2emissions at 
Chevron’s Eastridge Cogeneration combustion turbine facility in Kern County, California. When installed, Fluor’s carbon capture solution is expected to reduce the Eastridge Cogeneration facility’s carbon emissions by approximately 95 percent.
767 
Moreover, recently, CO 2capture 
technology has been operated on NGCC post-combustion flue gas at the Technology Centre Mongstad (TCM) in Norway.
768TCM can treat a 12 MWe 
flue gas stream from a natural gas 
combined cycle cogeneration plant at Mongstad power station. Many different solvents have been operated at TCM including MHI’s KS–21
TMsolvent,769 
achieving capture rates of over 98 percent. 
Additionally, in Scotland, the 
proposed 900 MW Peterhead Power Station combined cycle EGU with CCS is in the planning stages of development. MHI is developing a FEED for the power plant and capture facility.
770It is anticipated that the 
power plant will be operational by the end of the 2020s and will have the potential to capture 90 percent of the CO
2emitting from the combined cycle facility and sequester up to 1.5 million metric tons of CO
2annually. A storage 
site being developed 62 miles off the Scottish North Sea coast will serve as a destination for the captured CO
2.771 772  
Furthermore, the Global CCS Centre is 
tracking other international CCS on combustion turbine projects that are in on-going stages of development.
773 
(b) NET Power Cycle 
In addition, there are several planned 
projects using NET Power’s Allam- Fetvedt Cycle.
774The Allam-Fetvedt 
Cycle is a proprietary process for producing electricity that combusts a fuel with purified oxygen (diluted with recycled CO
2to control flame 
temperature) and uses supercritical CO 2 
as the working fluid instead of water/ steam. This cycle is designed to achieve thermal efficiencies of up to 59 percent.
775Potential advantages of this 
cycle are that it emits no NO Xand 
produces a stream of high-purity CO 2776 
that can be delivered by pipeline to a storage or sequestration site without extensive processing. A 50 MW (thermal) test facility in La Porte, Texas was completed in 2018 and has since accumulated over 1,500 hours of runtime. There are several announced NET Power commercial projects proposing to use the Allam-Fetvedt Cycle. These include the 280 MW Broadwing Clean Energy Complex in Illinois, and several international projects. 
In Scotland, the proposed 900 MW 
Peterhead Power Station combined cycle EGU with CCS is in the planning stages of development. MHI is developing a FEED for the power plant and capture facility.
777It is anticipated 
that the power plant will be operational by the end of the 2020s and will have the potential to capture 90 percent of the CO
2emitting from the combined 
cycle facility and sequester up to 1.5 million metric tons of CO
2annually. A storage site being developed 62 miles off 
the Scottish North Sea coast will serve as a destination for the captured CO
2.778 779  
(c) Coal-Fired Steam Generating Units 
As detailed in section VII.C.1.a, CCS 
has been demonstrated on coal-fired power plants, which provides further support that CCS on base load combined cycle units is adequately demonstrated. Further, 90 percent capture is expected to be, in some ways, more straightforward to achieve for natural gas-fired combined cycle combustion turbines than for coal-fired steam generators. Many of the challenges faced by Boundary Dam Unit 3—which proved to be solvable—were caused by the impurities, including fly ash, SO
2, 
and trace contaminants in coal-fired post-combustion flue gas. Such impurities naturally occur in coal (sulfur and trace contaminants) or are a natural result of combusting coal (fly ash), but not in natural gas, and thus they do not appear in the natural gas post-combustion flue gas. As a result, for CO
2capture for natural gas 
combustion, flue gas handling is simpler, solvent degradation is easier to prevent, and fewer redundancies may be necessary for various components (e.g., heat exchangers). 
(d) Other Industry 
As discussed in section 
VII.C.1.a.i.(A)(1) of this preamble, CCS 
installations in other industries support that capture equipment can achieve 90 percent capture of CO
2from natural gas- 
fired base load combined cycle combustion turbines. 
(e) EPAct05-Assisted CO
2Capture 
Projects at Stationary Combustion 
Turbines 
As for steam generating units, 
EPAct05-assisted CO 2capture projects 
on stationary combustion turbines corroborate that CO
2capture on gas 
combustion turbines is adequately demonstrated. Several CCS projects with at least 90 percent capture at commercial-scale combined cycle turbines are in the planning stages. These projects support that CCS with at least 90 percent capture for these units is the industry standard and support the EPA’s determination that CCS is adequately demonstrated. 
CCS is planned for the existing 550 
MW natural gas-fired combined cycle (two combustion turbines) at the Sutter Energy Center in Yuba City, California.
780The Sutter 
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Environmental-Leadership/2030-Clean-Energy- 
Vision/CEV-Landing-Pages/Calpine-presentation. 
781Carbon Capture Demonstration Projects 
Selections for Award Negotiations. https://www.energy.gov/oced/carbon-capture- demonstration-projects-selections-award- negotiations. 
782Calpine Carbon Capture. https://
calpinecarboncapture.com/wp-content/uploads/ 2023/05/Calpine-Deer-Park-English.pdf. 
783Deer Park Energy Center TCEQ Records Online 
Primary ID 171713. 
784Baytown Energy Center Air Permit TCEQ 
Records Online Primary ID 172517. 785Carbon Capture Demonstration Projects 
Selections for Award Negotiations. https://www.energy.gov/oced/carbon-capture- demonstration-projects-selections-award- negotiations. 
786Competitive Power Ventures (2022). Multi- 
Billion Dollar Combined Cycle Natural Gas Power Station with Carbon Capture Announced in West Virginia. Press Release. September 16, 2022. https:// 
www.cpv.com/2022/09/16/multi-billion-dollar- 
combined-cycle-natural-gas-power-station-with- carbon-capture-announced-in-west-virginia/. 
787General Electric (GE) (2022). U.S. Department 
of Energy Awards $5.7 Million for GE-Led Carbon Capture Technology Integration Project Targeting to Achieve 95% Reduction of Carbon Emissions. Press Release. February 15, 2022. https://www.ge.com/ news/press-releases/us-department-of-energy- awards-57-million-for-ge-led-carbon-capture- technology. 
788Larson, A. (2022). GE-Led Carbon Capture 
Project at Southern Company Site Gets DOE Funding. Power. https://www.powermag.com/ge- 
led-carbon-capture-project-at-southern-company- site-gets-doe-funding/. 
789U.S. Department of Energy (DOE) (2021). DOE 
Invests $45 Million to Decarbonize the Natural Gas Power and Industrial Sectors Using Carbon Capture and Storage. October 6, 2021. https://www.energy.gov/articles/doe-invests-45-million- decarbonize-natural-gas-power-and-industrial- sectors-using-carbon. 
790DOE (2022). Additional Selections for Funding 
Opportunity Announcement 2515. Office of Fossil Energy and Carbon Management. https://www.energy.gov/fecm/additional-selections- funding-opportunity-announcement-2515. 
791DOE (2019). FOA 2058: Front-End Engineering 
Design (FEED) Studies for Carbon Capture Systems on Coal and Natural Gas Power Plants. Office of Fossil Energy and Carbon Management. https://www.energy.gov/fecm/foa-2058-front-end- engineering-design-feed-studies-carbon-capture- systems-coal-and-natural-gas. Decarbonization project will use ION 
Clean Energy’s amine-based solvent technology at a capture rate of 95 percent or more. The project expects to complete a FEED study in 2024 and, prior to being selected by DOE for funding award negotiation, planned commercial operation in 2027. Sutter Decarbonization is one of the projects selected by DOE for funding as part of OCED’s Carbon Capture Demonstration Projects program.
781 
The CO 2capture project at the Deer 
Park Energy Center in Deer Park, Texas will be designed to capture 95 percent or more of the flue gas from the five combustion turbines at the 1,200 MW natural gas-fired combined cycle power plant, using technology from Shell CANSOLV.
782The CO 2capture project 
already has an air permit issued for the project, which includes a reduction in the allowable emission limits for NO
X 
from four of the combustion turbines.783 
The CO 2capture facility will include 
two quencher columns, two absorber columns, and one stripping column. 
The Baytown Energy Center in 
Baytown, Texas is an existing natural gas-fired combined cycle cogeneration facility providing heat and power to a nearby industrial facility, while distributing additional electricity to the grid. CCS using Shell’s CANSOLV solvent is planned for the equivalent of two of the three combustion turbines at the 896 MW natural gas-fired combined cycle power plant, with a capture rate of 95 percent. The CO
2capture facility 
at Baytown Energy Center also has an air permit in place, and the permit application provides some details on the 
process design.
784The CO 2capture 
facility will include two quencher columns, two absorber columns, and one stripping column. To mitigate NO
X 
emissions, the operation of the SCR systems for the combustion turbines will be adjusted to meet lower NO
X 
allowable limits—adjustments may include increasing ammonia flow, more frequent SCR repacking and head cleaning, and, possibly, optimization of the ammonia distribution system. The Baytown CO
2capture project is one of 
the projects selected by DOE for funding as part of OCED’s Carbon Capture Demonstration Projects program.
785 
Captured CO 2will be transported and 
stored at sites along the U.S. Gulf Coast. 
An 1,800 MW natural gas-fired 
combustion turbine that will be constructed in West Virginia and will utilize CCS has been announced. The project is planned to begin operation later this decade.
786 
There are numerous other EPAct05- 
assisted projects related to natural gas- fired combined cycle turbines including the following.
787 788 789 790 791 These 
projects provide corroborating evidence that capture of at least 90 percent is accepted within the industry. 
•General Electric (GE) (Bucks, 
Alabama) was awarded $5,771,670 to retrofit a combined cycle turbine with CCS technology to capture 95 percent of CO
2and is targeting commercial 
deployment by 2030. 
•Wood Environmental & 
Infrastructure Solutions (Blue Bell, Pennsylvania) was awarded $4,000,000 to complete an engineering design study for CO
2capture at the Shell Chemicals 
Complex. The aim is to reduce CO 2 
emissions by 95 percent using post- combustion technology to capture CO
2 from several plants, including an onsite natural gas CHP plant. 
•General Electric Company, GE 
Research (Niskayuna, New York) was awarded $1,499,992 to develop a design to capture 95 percent of CO
2from 
combined cycle turbine flue gas with the potential to reduce electricity costs by at least 15 percent. 
•SRI International (Menlo Park, 
California) was awarded $1,499,759 to design, build, and test a technology that can capture at least 95 percent of CO
2 
while demonstrating a 20 percent cost reduction compared to existing combined cycle turbine carbon capture. 
•CORMETECH, Inc. (Charlotte, 
North Carolina) was awarded $2,500,000 to further develop, optimize, and test a new, lower-cost technology to capture CO
2from combined cycle 
turbine flue gas and improve scalability to large, combined cycle turbines. 
•TDA Research, Inc. (Wheat Ridge, 
Colorado) was awarded $2,500,000 to build and test a post-combustion capture process to improve the performance of combined cycle turbine flue gas CO
2capture. 
•GE Gas Power (Schenectady, New 
York) was awarded $5,771,670 to perform an engineering design study to incorporate a 95 percent CO
2capture 
solution for an existing combined cycle turbine site while providing lower costs and scalability to other sites. 
•Electric Power Research Institute 
(EPRI) (Palo Alto, California) was awarded $5,842,517 to complete a study to retrofit a 700 MWe combined cycle turbine with a carbon capture system to capture 95 percent of CO
2. 
•Gas Technology Institute (Des 
Plaines, Illinois) was awarded $1,000,000 to develop membrane technology capable of capturing more than 97 percent of combined cycle turbine CO
2flue gas and demonstrate 
upwards of 40 percent reduction in costs. 
•RTI International (Research 
Triangle Park, North Carolina) was awarded $1,000,000 to test a novel non- aqueous solvent technology aimed at demonstrating 97 percent capture efficiency from simulated combined cycle turbine flue gas. 
•Tampa Electric Company (Tampa, 
Florida) was awarded $5,588,173 to conduct a study retrofitting Polk Power Station with post-combustion CO
2 
capture technology aiming to achieve a 95 percent capture rate. 
There are also several announced NET 
Power Allam-Fetvedt Cycle based CO
2 
capture projects that are EPAct05- assisted. These include the 280 MW Coyote Clean Power Project on the Southern Ute Indian Reservation in 
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792https://ieaghg.org/ccs-resources/blog/new- 
ieaghg-report-2022-08-start-up-and-shutdown- 
protocol-for-power-stations-with-co2-capture. 
793https://assets.publishing.service.gov.uk/ 
media/5f95432ad3bf7f35f26127d2/start-up-shut- down-times-power-ccus-main-report.pdf. 794Specifically, this includes the information 
concerning Boundary Dam, coupled with engineering analysis concerning key improvements that can be implemented in future CCS deployments during initial design and construction (i.e., all the information in section 
VII.C.1.a.i.(B)(1)(a) and the information concerning Boundary Dam in section VII.C.1.a.i.(B)(1)(b)); (ii) the information concerning other coal-fired demonstrations, including the Argus Cogeneration Plant and AES’s Warrior Run (i.e., all the 
information concerning those sources in section VII.C.1.a.i.(B)(1)(a)); (iii) the information concerning industrial applications of CCS (i.e., all the 
information in section VII.C.1.a.i.(A)(1); and (iv) the information concerning CO
2capture technology 
vendor statements (i.e., all the information in 
VII.C.1.a.i.(B)(3)). Colorado and a 300 MW project located 
near Occidental’s Permian Basin operations close to Odessa, Texas. Commercial operation of the facility near Odessa, Texas is expected in 2028. 
(f) Range of Conditions 
The composition of natural gas 
combined cycle post-combustion flue 
gas is relatively uniform as the level of impurities is, in general, low. There may be some difference in NO
Xemissions, 
but considering the sources are new, it is likely that they will be installed with SCR, resulting in uniform NO
X 
concentrations in the flue gas. The EPA notes that some natural gas combined cycle units applying CO
2capture may 
use exhaust gas recirculation to increase the concentration of CO
2in the flue 
gas—this produces a higher concentration of CO
2in the flue gas. For 
those sources that apply that approach, the CO
2capture system can be scaled 
smaller, reducing overall costs. Considering these factors, the EPA concludes that there are not substantial differences in flue gas conditions for natural gas combined cycle units, and the small differences that could exist would not adversely impact the operation of the CO
2capture equipment. 
As detailed in section VII.C.1.a.i(B)(7), 
single trains of CO 2capture facilities 
have turndown capabilities of 50 percent. Effective turndown to 25 percent of throughputs can be achieved by using 2 trains of capture equipment. CO
2capture rates have also been shown 
to be higher at lower throughputs. Moreover, during off-peak hours when electricity prices are lower, additional lean solvent can be produced and held in reserve, so that during high-demand hours, the auxiliary demands to the capture plant stripping column reboiler be reduced. Considering these factors, the capture rate would not be affected by load following operation, and the operation of the combustion turbine would not be limited by turndown capabilities of the capture equipment. As detailed in preceding sections, simple cycle combustion turbines cycle frequently, and have a number of startups and shutdowns per year. However, combined cycle units cycle 
less frequently and have fewer startups and shutdowns per year. Startups of combined cycle units are faster than coal-fired steam generating units described in section VII.C.1.a.i(B)(7) of the preamble. Cold startups of combined cycle units typically take not more than 3 hours (hot startups are faster), and shutdown takes less than 1 hour. During startup, heat input to the unit is lower to slowly raise the temperature of the HRSG. Importantly, natural gas post- 
combustion flue gas does not require the 
same pretreatment as coal post- combustion flue gas. Therefore, amine solvents are able to capture CO
2as soon 
as the flue gas contacts the lean solvent, and startup does not have to wait for operation of other emission controls. Furthermore, there are several different process strategies that can be employed to enable capture during cold startup.
792 793 These include using an 
additional reserve of lean solvent (solvent without absorbed CO
2), 
dedicated heat storage for reboiler preheating, and fast starting steam cycle technologies or high-pressure bypass extraction. Each of these three options has been modeled to show that 95 percent capture rates can be achieved during startup. The first option simply uses a reserve of lean solvent during startup so that capture can occur without needing to wait for the stripping column reboiler to heat up. For hot starts, the startup time of the NGCC is faster, and since the reboiler is already warm, the capture plant can begin operating faster. Shutdowns are short, and high capture efficiencies can be maintained. 
Considering that startup and 
shutdown for natural gas combined cycle units is fast, startups are relatively few, and simple process strategies can be employed so that high capture efficiencies can be achieved during startup, the EPA has concluded that startup and shutdown do not adversely impact the achievable CO
2capture rate. 
Considering the preceding 
information, the EPA has determined that 90 percent capture is achievable over long periods (i.e., 12-month rolling 
averages) for base load combustion turbines for all relevant flue gas conditions, variable load, and startup and shutdown. 
(g) Summary of Evidence Supporting 
BSER Determination Without EPAct05- Aassisted Projects 
As noted above, under the EPA’s 
interpretation of the EPAct05 provisions, the EPA may not rely on 
capture projects that received assistance under EPAct05 as the sole basis for a determination of adequate demonstration, but the EPA may rely on those projects to support or corroborate other information that supports such a determination. The information described above that supports the EPA’s determination that 90 percent CO
2 
capture from natural gas-fired 
combustion turbines is adequately demonstrated, without consideration of the EPAct05-assisted projects, includes (i) the information concerning coal-fired steam generating units listed in VII.C.1.a.i.(B)(9)
794(other than the 
information concerning EPAct05- assisted coal-fired unit projects and the information concerning natural gas-fired combustion turbines); (ii) the information that a 90 percent capture standard is achievable at coal-fired steam generating units, also applies to natural gas-fired combined cycle EGUs 
(i.e., all the information in 
VIII.F.4.c.iv.(B) (before (1)) and (1) (before (a)); (iii) the information concerning CCS on combined cycle EGUs (i.e., all the information in 
VIII.F.4.c.iv.(B)(1)(a)); and (iv) the information concerning Net Power (i.e., all the information in VIII.F.4.c.iv.(B)(1)(b)). All this information by itself is sufficient to support the EPA’s determination that 90 percent CO
2capture from coal-fired 
steam generating units is adequately demonstrated. Substantial additional information from EPAct05-assisted projects, as described in section VIII.F.4.c.iv.(B)(1)(e), provides additional support and confirms that 90 percent CO
2capture from natural gas- 
fired combustion turbines is adequately demonstrated. 
(2) Transport of CO
2 
In section VII.C.1.a.i.(C) of this 
document, the EPA described its 
rationale for finalizing a determination that CO
2transport by pipelines as a 
component of CCS is adequately demonstrated for use of CCS with existing steam generating EGUs. The Agency’s rationale for finalizing the same determination—that CO
2transport 
by pipelines as a component of CCS is adequately demonstrated for CCS use with new combustion turbine EGUs—is much the same as that described in section VII.C.1.a.i.(C). As discussed in 
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795PHMSA additionally initiated a rulemaking in 
2022 to develop and implement new measures to 
strengthen its safety oversight of CO 2pipelines 
following investigation into a CO 2pipeline failure 
in Satartia, Mississippi in 2020. For more information, see: https://www.phmsa.dot.gov/news/ phmsa-announces-new-safety-measures-protect- americans-carbon-dioxide-pipeline-failures. 796For additional information on CO 2 
transportation and geologic sequestration availability, please see EPA’s final TSD, GHG Mitigation Measures for Steam Generating Units. section VII.C.1.a.i.(C) of this preamble, 
CO 2pipelines are available and their 
network is expanding in the U.S., and the safety of existing and new supercritical CO
2pipelines is 
comprehensively regulated by PHMSA.
795A new combustion turbine 
may also be co-located with a storage site, so that minimal transport of the CO
2is required. 
Pipeline transport of CO 2captured 
from newly constructed or reconstructed natural gas-fired combustion turbine EGUs meets the BSER requirements based on the same evidence, and for the same reasons, as does pipeline transport of CO
2captured 
from existing coal-fired steam generating EGUs, as described in section VII.C.1.a.i.(C) of this preamble. This is because the CO
2that is captured from a 
natural gas-fired turbine, compressed, and delivered into a pipeline is 
indistinguishable from the CO
2that is 
captured from an existing coal-fired steam generating unit. Accordingly, all the evidence and explanation in section VII.C.1.a.i.(C) of this preamble that it is adequately demonstrated, cost-effective, and consistent with the other BSER factors for an existing coal-fired steam generating unit to construct a lateral pipeline from its facility to a sequestration site applies to new natural gas-fired turbines. This includes the history of CO
2pipeline build-out 
(VII.C.1.a.i.(C)(1)), the recent examples of new pipelines (VII.C.1.a.i.(C)(1)(b)), EPAct05-assisted CO
2pipelines for CCS 
(VII.C.1.a.i.(C)(1)(c)), the network of existing and planned CO
2trunklines 
(VII.C.1.a.i.(C)(1)(d)), permitting and rights of way considerations (VII.C.1.a.i.(C)(2)), and considerations of the security of CO
2transport, including 
PHMSA requirements (VII.C.1.a.i.(C)(3)). 
The only difference between pipeline 
transport for the coal-fired steam generation and the gas-fired turbines is that the coal-fired units are already in existence and, as a result, the location and length of their pipelines, as needed to transport their CO
2to nearby 
sequestration, is already known, whereas new gas-fired turbines are not yet sited. We discuss the implications for new gas-fired turbines in the next section. (3) Geologic Sequestration of CO
2 
In section VII.C.1.a.i.(D) of this 
document, the EPA described its 
rationale for finalizing a determination that geologic sequestration (i.e., the 
long-term containment of a CO
2stream 
in subsurface geologic formations) is adequately demonstrated as a component of the use of CCS with existing coal-fired steam generating EGUs. Similar to the previous discussion regarding CO
2transport, the 
Agency’s rationale for finalizing a determination that geologic sequestration is adequately demonstrated as a component of the use of CCS with new combustion turbine EGUs is the same as described in VII.C.1.a.i.(D) for existing coal-fired steam generating EGUs. The storage/ sequestration sites used to store captured CO
2from existing coal-fired 
EGUs could also be used to store captured CO
2from newly constructed or 
reconstructed combustion turbine EGUs. All of the considerations and challenges associated with developing geologic storage sites for existing sources are also considerations and challenges associated with developing such sites for newly constructed or reconstructed sources. 
(a) In General 
Geologic sequestration (i.e., the long- 
term containment of a CO
2stream in 
subsurface geologic formations) is well 
proven. Deep saline formations, which may be evaluated and developed for CO
2sequestration are broadly available 
throughout the U.S. Geologic sequestration requires a demonstrated understanding of the processes that affect the fate of CO
2in the subsurface. 
As discussed in section VII.C.1.a.i.(D) of this preamble, there have been numerous instances of geologic sequestration in the U.S. and overseas, and the U.S. has developed a detailed set of regulatory requirements to ensure the security of sequestered CO
2. This 
regulatory framework includes the UIC well regulations, which are under the authority of the SDWA, and the GHGRP, under the authority of the CAA. 
Geologic settings which may be 
suitable for geologic sequestration of CO
2are widespread and available 
throughout the U.S. Through an availability analysis of sequestration potential in the U.S. based on resources from the DOE, the USGS, and the EPA, the EPA found that there are 43 states with access to, or are within 100 km from, onshore or offshore storage in deep saline formations, unmineable coal seams, and depleted oil and gas reservoirs. All of the evidence and explanation 
that geological sequestration of CO
2is 
adequately demonstrated and meets the other BSER factors that the EPA described with respect to sequestration of CO
2from existing coal-fired steam 
generating units in section VII.C.1.a.i.(D) of this preamble apply with respect to CO
2from new natural gas-fired 
combustion turbines. Sequestration is broadly available (VII.C.1.a.i.(D)(1)(a)). It is adequately demonstrated, with many examples of projects successfully injecting and containing CO
2in the 
subsurface (VII.C.1.a.i.(D)(2)). It provides secure storage, with a detailed set of regulatory requirements to ensure the security of sequestered CO
2, 
including the UIC well regulations pursuant to SDWA authority, and the GHGRP pursuant to CAA authority (VII.C.1.a.i.(D)(4)). The EPA has the experience to properly regulate and review permits for UIC Class VI injection wells, has made considerable improvements to its permitting process to expedite permitting decisions, and has granted several states primacy to issue permits, and is supporting that state permitting (VII.C.1.a.i.(D)(5)). 
(b) New Natural Gas-Fired Combustion 
Turbines 
As discussed in section 
VII.C.1.a.i.(D)(1), deep saline formations that may be considered for use in geologic sequestration (or storage) are common in the continental United States. In addition, there are numerous unmineable coal seams and depleted oil and gas reserves throughout the country that could potentially be utilized as sequestration sites. The DOE estimates that areas of the U.S. with appropriate geology have a sequestration potential of at least 2,400 billion to over 21,000 billion metric tons of CO
2in deep saline 
formations, unmineable coal seams, and oil and gas reservoirs. The EPA’s scoping assessment found that at least 37 states have geologic characteristics that are amenable to deep saline sequestration and identified an additional 6 states are within 100 kilometers of potentially amenable deep saline formations in either onshore or offshore locations. In terms of land area, 80 percent of the continental U.S. is within 100 km of deep saline formations.
796While the EPA’s 
geographic availability analyses focus on deep saline formations, other geologic formations such as unmineable coal seams or depleted oil and gas 
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797In this discussion, the term RTO indicates 
both ISOs and RTOs. 
798https://prairiestateenergycampus.com/about/ 
ownership/. 
799https://www.ipautah.com/participants- 
services-area/. 800Portland General Electric, ‘‘Our Power Plants,’’ 
https://portlandgeneral.com/about/who-we-are/ 
how-we-generate-energy/our-power-plants. 
801See George Plaven, ‘‘PGE power plant rising in 
E. Oregon,’’ The Columbian (October 10, 2015, 5:55 a.m.), https://www.columbian.com/news/2015/oct/ 
10/pge-power-plant-rising-in-e-oregon/. See also Portland General Electric, ‘‘PGE Service Area,’’ https://portlandgeneral.com/about/info/service- area. reservoirs represent potential additional 
CO 2storage options. Therefore, we 
expect that the vast majority of new base load combustion turbine EGUs could be sited within 100 km of a sequestration site. 
While the potential for some type of 
sequestration exists in large swaths of the continental U.S., we recognize that there are a few states that do not have geologic conditions suitable for geologic sequestration within or near their borders. If an area does not have a suitable geologic sequestration site, then a utility or project developer seeking to build a new combustion turbine EGU for base load generation has two options— either (1) the new EGU may be located near the electricity demand and the CO
2 
transported via a CO 2pipeline to a 
geologic sequestration site, or (2) the new EGU may be located closer to a geologic sequestration site and the electricity delivered to customers through transmission lines. Regarding option 1, as discussed in VII.C.1.a.i(C), the EPA believes that both new and existing EGUs are capable of constructing CO
2pipelines as needed. 
With regard to option 2, we expect that this option may be preferred for projects where a CO
2pipeline of substantial 
length would be required to reach the sequestration site. However, we note that for new base load combustion turbine EGUs, project developers have flexibility with regard to siting such that they can balance whether to site a new unit closer to a potential geologic sequestration site or closer to a load area depending on their specific needs. 
Electricity demand in areas that may 
not have geologic sequestration sites may be served by gas-fired EGUs that are built in areas with geologic sequestration, and the generated electricity can be delivered through transmission lines to the load areas through ‘‘gas-by-wire.’’ An analogous approach, known as ‘‘coal-by-wire’’ has long been used in the electricity sector for coal-fired EGUs because siting a coal-fired EGU near a coal mine and transmitting the generated electricity long distances to the load area is sometimes less expensive than siting the coal EGU near the load area and shipping the coal long distances. The same principle may apply to new base load combustion turbine EGUs such that it may be more practicable for an project developer to site a new base load combustion turbine EGU in a location in close proximity to a geologic sequestration site and to deliver the electricity generated through transmission lines to the load area 
rather than siting the new gas-fired combustion turbine EGU near the load area and building a lengthy pipeline to 
the geologic sequestration site. 
Gas-by-wire and coal-by-wire are 
possible due to the electricity grid’s extensive high voltage transmission networks that enable electricity to be transmitted over long distances. See the memorandum, Geographic Availability 
of CCS for New Base Load NGCC Units, which is available in the rulemaking docket for this action. In many of the areas without reasonable access to geologic sequestration, utilities, electric cooperatives, and municipalities have a history of joint ownership of electricity generation outside the region or contracting with electricity generation in outside areas to meet demand. Some of the areas are in Regional Transmission Organizations (RTOs),
797 
which engage in planning as well as balancing supply and demand in real time throughout the RTO’s territory. Accordingly, generating resources in one part of the RTO can serve load in other parts of the RTO, as well as load outside of the RTO. 
In the coal context, there are many 
examples of where coal-fired power generation in one state has been used to supply electricity in other states. For example, the Prairie State Generating Plant, a 2-unit 1,600 MW coal-fired power plant in Illinois that is currently considering retrofitting with CCS, serves load in eight different states from the Midwest to the mid-Atlantic.
798The 
Intermountain Power Project, a coal- fired plant located in Delta, Utah, that is converting to co-fire hydrogen and natural gas, serves customers in both Utah and California.
799Additionally, 
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. Further, Idaho Power, which serves customers in Idaho and eastern Oregon has met demand in part from power generating at coal-fired power plants located in Wyoming and Nevada. This same concept of siting generation in one location to serve demand in another area and using existing transmission infrastructure to do so could similarly be applied to gas-fired combustion turbine power plants, and, in fact, there are examples of gas-fired combustion turbine EGUs serving demand more than 100 km away from where they are sited. For example, Portland General Electric’s Carty Generating Station, a 436–MW NGCC unit located in Boardman, Oregon
800serves demand in 
Portland, Oregon,801which is 
approximately 270 km away from the 
source. 
In the memorandum, Geographic 
Availability of CCS for New Base Load NGCC Units, we explore in detail the potential for gas-by-wire and the ability of demand in areas without geologic sequestration potential to be served by gas generation located in areas that have access to geologic sequestration. As discussed in the memorandum, the vast majority of the United States is within 100 km of an area with geologic sequestration potential. A review of our scoping assessment indicates that there are limited areas of the country that are not within 100 km of a potential deep saline sequestration formation (although some of these areas may be within 100 km of an unmineable coal seam or depleted oil and gas reservoir that could potentially serve as a sequestration site). In many instances, these areas include areas with low population density, areas that are already served by transmission lines that could deliver gas-by-wire, and/or include areas that have made policy or other decisions not to pursue a resource mix that includes new NGCC due to state renewable portfolio standards or for other reasons. 
In many of these areas, utilities, 
electric cooperatives, and municipalities have a history of obtaining electricity from generation in outside areas to meet demand. Some of the relevant areas are in an RTO or ISO, which operate the transmission system and dispatch generation to balance supply and demand regionwide, as well as engage in regionwide planning and cost allocation to facilitate needed transmission development. Accordingly, generating resources in one part of an RTO/ISO, such as through an NGCC plant, can serve loads in other parts of the RTO/ISO, as well as serving load areas outside of the RTO/ISO. As we consider each of these geographic areas in the memorandum, Geographic Availability of CCS for New Base Load NGCC Units, we make key points as to why this final rule does not negatively impact the ability of these regions to access new NGCC generation to the extent that NGCC generation is needed to supply demand and/or those regions 
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802CCS reduced the net output of the NETL F 
class combined cycle EGU from 726 MW to 
645 MW. 
803Although not our primary approach to 
assessing costs in this final rule, for consistency with the proposal’s assumption capacity factor, these calculations use a service life of 30 years, an interest rate of 7.0 percent, a natural gas price of $3.61/MMBtu, and a capacity factor of 65 percent. These costs do not include CO
2transport, storage, 
or monitoring costs. 804Recent DOE analysis has compared the NETL 
costs with more recent FEED study costs and expert interviews and determined they are consistent after accounting for differences in inflation, economic assumptions, and other technology details. Portfolio Insights: Carbon Capture in the Power Sector, DOE. https://www.energy.gov/oced/portfolio-strategy . 
805Energy Procedia. (2014). Impact of exhaust gas 
recirculation on combustion turbines. Energy and economic analysis of the CO
2capture from flue gas 
of combined cycle power plants. https://www.sciencedirect.com/science/article/pii/ S1876610214001234. 806For example, see the article CCUS Market 
Outlook 2023: Announced Capacity Soars by 50%, which states, ‘‘New gas power plants with carbon capture, for example, could be cheaper than unabated power in Germany as early as next year when coupled with the carbon price.’’ https://about.bnef.com/blog/ccus-market-outlook-2023- announced-capacity-soars-by-50/. 
807The DOE has also previously funded FEED 
studies for natural gas-fired combined cycle turbine facilities. These include FEED studies at existing combined cycle turbine facilities at Panda Energy Fund in Texas, Elk Hills Power Plant in Kern County, California, Deer Park Energy Center in Texas, Delta Energy Center in Pittsburg, California, and utilization of a Piperazine Advanced Stripper (PZAS) process for CO
2capture conducted by The 
University of Texas at Austin. 
808Portfolio Insights: Carbon Capture in the 
Power Sector report. DOE. https://www.energy.gov/ oced/portfolio-strategy. 
809Molten carbonate fuel cells are configured for 
emissions capture through a process where the flue gas from an EGU is routed through the molten carbonate fuel cell that concentrates the CO
2as a 
side reaction during the electric generation process want to include new NGCC generation 
in their resource mixes. 
(C) Costs 
The EPA has evaluated the costs of 
CCS for new combined cycle units, 
including the cost of installing and operating CO
2capture equipment as 
well as the costs of transport and storage. The EPA has also compared the costs of CCS for new combined cycle units to other control costs, in part derived from other rulemakings that the EPA has determined to be cost- reasonable, and the costs are comparable. Based on these analyses, the EPA considers the costs of CCS for new combined cycle units to be reasonable. Certain elements of the transport and storage costs are similar for new combustion turbines and existing steam generating units. In this section, the EPA outlines these costs and identifies the considerations specific to new combustion turbines. These costs are significantly reduced by the IRC section 45Q tax credit. 
(1) Capture Costs 
According to the NETL Fossil Energy 
Baseline Report (October 2022 revision), 
before accounting for the IRC section 45Q tax credit for sequestered CO
2, 
using a 90 percent capture amine-based post-combustion CO
2capture system 
increases the capital costs of a new combined cycle EGU by 115 percent on a $/kW basis, increases the heat rate by 13 percent, increases incremental operating costs by 35 percent, and derates the unit (i.e., decreases the 
capacity available to generate useful output) by 11 percent.
802For a base load 
combustion turbine, carbon capture increases the LCOE by 62 percent (an increase of 27 $/MWh) and has an estimated cost of $81/ton ($89/metric 
ton) of onsite CO
2reduction.803The 
NETL costs are based on the use of a second-generation amine-based capture system without exhaust gas recirculation (EGR) and, as discussed below, do not take into account further cost reductions that can be expected to occur from efficiency improvements as post-combustion capture systems are more widely deployed, as well as potential technological 
developments.
804 
The flue gas from natural gas-fired 
combined cycle turbine differs from that of coal-fired EGUs in several ways that impact the cost of CO
2capture. These 
include that the CO 2concentration in 
the flue gas is approximately one-third of that observed at coal-fired EGUs, the volumetric flow rate on a per MW basis is larger, and the oxygen concentration is approximately 3 times that of a coal- fired EGU. While the higher amount of excess oxygen has the potential to reduce the efficiency of amine-based solvents that are susceptible to oxidation, natural gas post-combustion flue gas does not have other impurities (SO
2, PM, trace metals) that are present 
and must be managed in coal flue gas. Other important factors include that the lower concentrations of CO
2reduce the 
efficiency of the capture process and that the larger volumetric flow rates require a larger CO
2absorber, which 
increases the capital cost of the capture 
process. Exhaust gas recirculation (EGR), also referred to as flue gas recirculation (FGR), is a process that addresses all these issues. EGR diverts some of the combustion turbine exhaust gas back into the inlet stream for the combustion turbine. Doing so increases the CO
2concentration and decreases the 
O2concentration in the exhaust stream 
and decreases the flow rate, producing more favorable conditions for CCS. One study found that EGR can decrease the capital costs of a combined cycle EGU with CCS by 6.4 percent, decrease the heat rate by 2.5 percent, decrease the LCOE by 3.4 percent, and decrease the overall CO
2capture costs by 11 percent 
relative to a combined cycle EGU without EGR.
805The EPA notes that the 
NETL costs on which the EPA bases its cost calculations for combined cycle CCS do not assume the use of EGR, but as discussed below, EGR use is plausible and would reduce those costs. 
While the costs considered in the 
preceding are based on the current costs of CCS, the EPA notes that the costs of capture systems can be expected to decrease over the rest of this decade and continue to decrease afterwards.
806As 
part of the plan to reduce the costs of 
CO 2capture, the DOE is funding 
multiple projects to further advance CCS technology from various point sources, including combined cycle turbines, cement manufacturing plants, and iron and steel plants.
807It should be 
noted that some of these projects may be EPAct05-assisted. The general aim is to lower the costs of the technologies, and to increase investor confidence in the commercial scale applications, particularly for newer technologies or proven technologies applied under unique circumstances. In particular, OCED’s Carbon Capture Demonstration Projects are targeted to accelerate continued power sector carbon capture commercialization through reducing costs and reducing uncertainties to project development. These cost and uncertainty reductions arise from reductions in cost of capital, increases in system scale, standardization and reduction in non-recurring engineering costs, maturation of supply chain ecosystem, and improvements in engineering design and materials over time.
808 
Although current post-combustion 
CO 2capture projects have primarily 
been based on amine capture systems, there are multiple alternate capture technologies in development—many of which are funded through industry research programs—that could yield reductions in capital, operating, and auxiliary power requirements and could reduce the cost of capture significantly or improve performance. More specifically, post combustion carbon capture systems generally fall into one of several categories: solvents, sorbents, membranes, cryogenic, and molten carbonate fuel cells
809systems. It is 
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in the fuel cell. FuelCell Energy, Inc. (2018). 
SureSource Capture. https://www.fuelcellenergy.com/recovery-2/suresource- capture/. 
810DOE. Carbon Capture, Transport, & Storage. 
Supply Chain Deep Dive Assessment. February 24, 2022. https://www.energy.gov/sites/default/files/ 
2022-02/Carbon%20Capture%20Supply%20Chain%20Report%20-%20Final.pdf . 
811International Energy Agency (IEA) (2020). 
CCUS in Clean Energy Transitions—A new era for CCUS. https://www.iea.org/reports/ccus-in-clean- energy-transitions/a-new-era-for-ccus. The same is true for CCS on coal-fired EGUs. 
812Technology Readiness and Costs of CCS 
(2021). Global CCS Institute. https://www.globalccsinstitute.com/wp-content/uploads/ 2021/03/Technology-Readiness-and-Costs-for-CCS- 2021-1.pdf. 813https://www.sciencedirect.com/science/ 
article/pii/S1750583607000163. 
814As an additional example for cost reductions 
from learning processes via deployment achieved in 
other complex power generation projects, the most recent sustained deployment of 19 nuclear reactors 
in South Korea from 1989 through 2008 resulted in a 13 percent reduction in capital costs. https://www.sciencedirect.com/science/article/pii/ S0301421516300106. 
815International Energy Agency (IEA) (2020). 
CCUS in Clean Energy Transitions—CCUS technology innovation. https://www.iea.org/reports/ ccus-in-clean-energy-transitions/a-new-era-for-ccus. 
816Energy Information Administration (EIA) 
(2023). Assumptions to the Annual Energy Outlook 
2023: Electricity Market Module. https://www.eia.gov/outlooks/aeo/assumptions/pdf/EMM_Assumptions.pdf. 
817National Renewable Energy Laboratory (NREL) 
(2023). Annual Technology Baseline 2023. https:// 
atb.nrel.gov/electricity/2023/fossil_ energy_
technologies. 818Portfolio Insights: Carbon Capture in the 
Power Sector. DOE. 2024. https://www.energy.gov/ 
oced/portfolio-strategy. 
819https://www.frontiersin.org/articles/10.3389/ 
fenrg.2022.987166/full. 
820https://www.sciencedirect.com/science/ 
article/pii/S1750583607000163. 
821Grant, T., et al. ‘‘Quality Guidelines for Energy 
System Studies; Carbon Dioxide Transport and Storage Costs in NETL Studies.’’ National Energy Technology Laboratory. 2019. https://www.netl.doe.gov/energy-analysis/details?id=3743. 
822National Energy Technology Laboratory 
(NETL), ‘‘FE/NETL CO2 Saline Storage Cost Model (2017),’’ U.S. Department of Energy, DOE/NETL– 2018–1871, 30 September 2017. https://netl.doe.gov/energy-analysis/details?id=2403. expected that as CCS infrastructure 
increases, technologies from each of these categories will become more economically competitive. For example, advancements in solvents that are potentially direct substitutes for current amine-solvents will reduce auxiliary energy requirements and reduce both operating and capital costs, and thereby, increase the economic competitiveness of CCS.
810Planned large-scale projects, 
pilot plants, and research initiatives will also decrease the capital and operating 
costs of future CCS technologies. 
In general, CCS costs have been 
declining as carbon capture technology advances.
811While the cost of capture 
has been largely dependent on the concentration of CO
2in the gas stream, 
advancements in varying individual CCS technologies tend to drive down the cost of capture for other CCS technologies. The increase in CCS investment is already driving down the costs of near-future CCS technologies. The Global CCS Institute has tracked publicly available information on previously studied, executed, and proposed CO
2capture projects.812The 
cost of CO 2capture from low-to-medium 
partial pressure sources such as coal- fired power generation has been trending downward over the past decade, and is projected to fall by 50 percent by 2025 compared to 2010. This is driven by the familiar learning- processes that accompany the deployment of any industrial technology. A review of learning rates (the reduction in cost for a doubling of production or capacity) for various energy related technologies similar to carbon capture (flue gas desulfurization, selective catalytic reduction, combined cycle turbines, pulverized coal boilers, LNG production, oxygen production, and hydrogen production via steam methane reforming) demonstrated learning rates of 5 percent to 27 percent for both capital expenditures and operations and maintenance costs.
813 814  
Studies of the cost of capture and 
compression of CO 2from power stations 
completed 10 years ago averaged around $95/metric ton ($2020). Comparable studies completed in 2018/2019 estimated capture and compression costs could fall to approximately $50/ metric ton CO
2by 2025. Current target 
pricing for announced projects at coal- fired steam generating units is approximately $40/metric ton on average, compared to Boundary Dam whose actual costs were reported to be $105/metric ton, noting that these estimates do not include the impact of the 45Q tax credit as enhanced by the IRA. Additionally, IEA suggests this trend will continue in the future as technology advancements ‘‘spill over’’ into other projects to reduce costs.
815 
Similarly, EIA incorporates a minimum 20 percent reduction in carbon capture and sequestration costs by 2035 in their Annual Energy Outlook 2023 modeling in part to account for the impact of spillover and international learning.
816 
The Annual Technology Baseline published by NREL with input from NETL projects a 10 percent reduction in capital expenditures from 2021 through 2032 in the ‘‘Conservative Technology Innovation Scenario’’ for natural gas carbon capture retrofit projects, under the assumption that only learning processes lead to future cost reductions and that there are no additional improvements from investments in targeted technology research and development.
817In a recent case study 
of the cost and performance of carbon capture retrofits on existing natural gas combined cycle units, based on discussions with external technology providers, engineering consultants, asset developers, and applicants for DOE awards, DOE used a 25 percent capital cost reduction estimate to illustrate the potential future capital costs of an Nth- of-a-Kind facility, as well as 
‘‘conservatively model[ing]’’ operating expense reductions at 1 percent, for a combined overall decrease in the levelized cost of energy of about 10 percent for the Nth-of-a-Kind facility compared to a First-of-a-Kind facility.
818 
DOE further found this illustrative cost reduction estimate from learning through doing to be consistent with other studies that use hybrid engineering-economic and experience- curve approaches to estimate potential decreases in the levelized cost of energy of 10–11 percent for Nth-of-a-Kind plants compared with First-of-a-Kind plants.
819 820 Policies in the IIJA and IRA 
are further increasing investment in CCS technology that can accelerate the pace of innovation and deployment. 
(2) CO
2Transport and Sequestration 
Costs 
NETL’s ‘‘Quality Guidelines for 
Energy System Studies; Carbon Dioxide 
Transport and Sequestration Costs in NETL Studies’’ provides an estimation of transport costs based on the CO
2 
Transport Cost Model.821The CO 2 
Transport Cost Model estimates costs for a single point-to-point pipeline. Estimated costs reflect pipeline capital costs, related capital expenditures, and operations and maintenance costs. 
NETL’s Quality Guidelines also 
provide an estimate of sequestration costs. These costs reflect the cost of site screening and evaluation, permitting and construction costs, the cost of injection wells, the cost of injection equipment, operation and maintenance costs, pore volume acquisition expense, and long-term liability protection. Permitting and construction costs also reflect the regulatory requirements of the UIC Class VI program and GHGRP subpart RR for geologic sequestration of CO
2in deep saline formations. NETL 
calculates these sequestration costs on the basis of generic plant locations in the Midwest, Texas, North Dakota, and Montana, as described in the NETL energy system studies.
822 
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823Department of Energy. Regional Direct Air 
Capture Hubs. (2022). https://www.energy.gov/ 
oced/regional-direct-air-capture-hubs. 
824DOE. Carbon Dioxide Transportation 
Infrastructure. https://www.energy.gov/lpo/carbon- 
dioxide-transportation-infrastructure. 
825Department of Energy. ‘‘Regional Direct Air 
Capture Hubs.’’ (2022). https://www.energy.gov/ 
oced/regional-direct-air-capture-hubs. 
826For more information, see the NETL 
announcement. https://www.netl.doe.gov/node/ 
12405. 827In the proposal, the EPA used a constant 65 
percent capacity factor, representative of the initial capacity factor of recently constructed combined cycle turbines, and effective 30-year 45Q tax credit of $41/ton. For this final rule, the EPA considers the approach of using a higher capacity factor for the first 12 years and a lower one for the last 18 years to reflect more accurately actual operating conditions, and therefore to be a more realistic basis for calculating CCS costs. 
828The EPA’s cost approach for CCS for existing 
coal-fired units also assumed that those units would increase their capacity during the 12-year period when the 45Q tax credit was available. See preamble section VII.C.1.a.ii, and Greenhouse Gas Mitigation Measures for Steam Generating Units TSD section 4.7.5. Because coal-fired power plants are existing plants, the EPA calculated CCS costs by assuming a 12-year amortization period for the CCS equipment, and the EPA did not need to make any assumptions about the operation of the coal-fired unit after the 12-year period. 
829Compliance costs would be lower if higher 
capacity factors were used during the first 12 years of operation. 830The CCS and CO 2TS&M costs are amortized 
over the period the equipment is operated—30 years or 12 years. There are two primary cost drivers for 
a CO 2sequestration project: the rate of 
injection of the CO 2into the reservoir 
and the areal extent of the CO 2plume 
in the reservoir. The rate of injection 
depends, in part, on the thickness of the reservoir and its permeability. Thick, permeable reservoirs provide for better injection and fewer injection wells. The areal extent of the CO
2plume depends 
on the sequestration capacity of the reservoir. Thick, porous reservoirs with a good sequestration coefficient will present a small areal extent for the CO
2 
plume and have lower testing and monitoring costs. NETL’s Quality Guidelines model costs for a given cumulative storage potential.
823 
In addition, provisions in the IIJA and 
IRA are expected to significantly increase the CO
2pipeline infrastructure 
and development of sequestration sites, which, in turn, are expected to result in further cost reductions for the application of CCS at a new combined cycle EGUs. The IIJA establishes a new Carbon Dioxide Transportation Infrastructure Finance and Innovation program to provide direct loans, loan guarantees, and grants to CO
2 
infrastructure projects, such as pipelines, rail transport, ships and barges.
824The IIJA also establishes a 
new Regional Direct Air Capture Hubs program which includes funds to support four large-scale, regional direct air capture hubs and more broadly support projects that could be developed into a regional or inter- regional network to facilitate sequestration or utilization.
825DOE is 
additionally implementing IIJA section 40305 (Carbon Storage Validation and Testing) through its CarbonSAFE initiative, which aims to further development of geographically widespread, commercial-scale, safe storage.
826The IRA increases and 
extends the IRC section 45Q tax credit, discussed next. 
(3) IRC Section 45Q Tax Credit 
For the reasons explained in section 
VII.C.1.a.ii of this preamble, in 
determining the cost of CCS, the EPA is taking into account the tax credit provided under IRC section 45Q, as revised by the IRA. The tax credit is available at $85/metric ton ($77/ton) 
and offsets a significant portion of the capture, transport, and sequestration costs noted above. 
(4) Total Costs of CCS 
In a typical NSPS analysis, the EPA 
amortizes costs over the expected 
operating life of the affected facility and assumes constant revenue and expenses over that period of time. For a new combustion turbine, the expected operating life is 30 years. The EPA has adjusted that analysis in this rule to account for the fact that the IRC section 45Q tax credit is available for only the 12 years after operation is commenced. Since the duration of the tax credit is less than the expected life of a new base load combustion turbine, the EPA conducted the costing analysis by recognizing that the substantial revenue available for sequestering CO
2during 
the first 12 years of operation is expected to result in higher capacity factors for that period, and the potential higher operating costs during the subsequent 18 years when the 45Q tax credit is not available is likely to result in lower capacity factors (see final TSD, Greenhouse Gas Mitigation Measures, Carbon Capture and Storage for Combustion Turbines for more discussion).
827 828  
Specifically, the EPA’s cost analysis 
assumes that the combined cycle turbine operates at a capacity of 80 percent over the initial 12-year period. This capacity level is generally consistent with the IPM model projections of 87 percent (and, in fact, somewhat more conservative). The 80 percent capacity factor assumption is also less than the 85 percent capacity factor assumption in the NETL analysis.
829But notably, the higher 
capacity factors in the IPM analysis and in the NETL analysis suggest that higher capacity factors may be reasonable and as figure 8 in the final TSD, Greenhouse Gas Mitigation Measures, Carbon Capture and Storage for Combustion Turbines demonstrates, would result in 
even lower costs. The analysis further assumes that the turbine operates at a capacity of 31 percent during the remaining 18-year period. As explained in the final TSD, Greenhouse Gas Mitigation Measures Carbon Capture and Storage for Combustion Turbines, to avoid impacting the compliance costs due to changes in the overall capacity factors with the base case, the EPA kept the overall 30-year capacity factor at the historical average of 51 percent. The EPA evaluated several operational scenarios (as described in the TSD). The scenario with an initial 12-year capacity factor of 80 percent and a subsequent 18-year capacity factor of 31 percent (for a 30-year capacity factor of 51 percent) represents the primary policy case. It should be noted that at a 31 percent capacity factor, the combustion turbine would be subcategorized as an intermediate load combustion turbine, and therefore would be subject to a less stringent standard of performance that is based on efficient operation, not on the use of CCS. 
This costing approach results in lower 
compliance costs than assuming a constant capacity factor for the 30-year useful life of the turbine because of increased revenue from generation during the initial 12-year period, increased revenue from the IRC section 45Q tax credits during that period, and lower costs during the last 18 years when the tax credit is not available. As noted, this is a reasonable approach because the economic incentive provided by the tax credit is so significant on a $/ton basis that the EPA expects sources to dispatch at higher levels while the tax credit is in effect. 
The EPA calculated two sets of CCS 
costs: the first assumes that the turbine continues to operate the capture system during the last 18 years, and the second assumes that the turbine does not operate the capture system during the last 18 years.
830Assuming continued 
operation of the capture equipment, the compliance costs are $15/MWh and $46/ton ($51/metric ton) for a 6,100 MMBtu/h H-Class turbine, which has a net output of approximately 990 MW; and $19/MWh and $57/ton ($63/metric ton) for a 4,600 MMBtu/h F-Class turbine, which has a net output of 
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831The output of the H-Class model combined 
cycle EGU without CCS is 992 MW. The auxiliary 
load of CCS reduces the net out to 883 MW. The output of the F-Class model combined cycle EGU without CCS is 726 MW. The auxiliary load of CCS reduces the net out to 645 MW. 
832As we explain in the final TSD, GHG 
Mitigation Measures—Carbon Capture and Storage for Combustion Turbines, sections 2.3–2.5, the 6,100 MMBtu/h H-Class combustion turbine is the median size of recently constructed combined cycle facilities and the 4,600 MMBtu/h F-Class combustion turbine approximates the size of a number of recently constructed combined cycle facilities as well. CCS costs for smaller sources are higher but are not prohibitive. GHG Mitigation Measures—Carbon Capture and Storage for Combustion Turbines TSD, section 2.3, Figures 12a and 13. As noted in RTC section 3.1, we expect costs to decrease due to learning by doing and technological development. In addition, since the incremental generating costs of larger more efficient combined cycle turbines are lower relative to smaller combined cycle turbines, it is more likely that larger more efficient combined cycle turbine will operate as base load combustion turbines. 
833A DOE analysis of a representative NGCC 
plant using CCS in the ERCOT market indicates that operating at high operating capacity could be profitable today with the IRC 45Q tax credits. Portfolio Insights: Carbon Capture in the Power Sector. DOE. https://www.energy.gov/oced/ 
portfolio-strategy. 
834These additional efficiency improvements are 
noted in the final TSD, Efficient Generation: Combustion Turbine Electric Generating Units. 835The compliance costs assume the same 
capacity factors in the base and policy case, that is, without CCS and with CCS. If combined cycle turbine with CCS were to operate at higher capacity factors in the policy case, compliance costs would be reduced. approximately 700 MW.831 832 If the 
capture system is not operated while the 
combustion turbine is subcategorized as an intermediate load combustion turbine, the compliance costs are reduced to $8/MWh and $43/ton ($47/ metric ton) for a 6,100 MMBtu/h H- Class combustion turbine, and $12/ MWh and $60/ton ($66/metric ton) for a 4,600 MMBtu/h F-Class combustion turbine. All of these costs are comparable to the cost metrics that, based on prior rules, the EPA finds to be reasonable in this rulemaking.
833For 
a more detailed discussion of costs, see the TSD—GHG Mitigation Measures— Carbon Capture and Storage for Combustion Turbines, section 2.3, Figure 12a. 
The EPA considers these CCS cost 
estimates to be conservatively high because they do not take into account cost improvements from the potential use of exhaust gas recirculation, which, according to one study, could lower LCOE by 3.4 percent, as described in preamble section VIII.F.4.c.iv.(C)(1). Nor do they consider the potential for additional efficiency improvements for combined cycle units
834or CCS 
technological advances, as discussed in preamble section VIII.F.4.c.iv.(B)(1)(b), VIII.F.4.c.iv.(C)(1), and RTC section 3.1. The EPA considers that at least some of these cost improvements are likely. Accordingly, the EPA also calculated the CCS costs based on an assumed 5 percent reduction in costs, in order to approximate these likely improvements, 
as follows: Assuming continued operation of the capture equipment, the compliance costs are $13/MWh and $40/ton ($44/metric ton) for a 6,100 MMBtu/h H-Class combustion turbine, and $18/MWh and $54/ton ($59/metric ton) for a 4,600 MMBtu/h F- Class combustion turbine. If the capture system is not operated while the combustion turbine is subcategorized as in intermediate load combustion turbine, the compliance costs are reduced to $8/MWh and $39/ton ($43/ metric ton) for a 6,100 MMBtu/h H-Class combustion turbine, and $11/MWh and $56/ton ($61/metric ton) for a 4,600 MMBtu/h F-Class combustion turbine. 
In addition, the EPA considers all 
those costs to be conservative (in favor of higher costs) because they assume that the combustion turbine operator will not receive any revenues from captured CO
2after the 12-year period 
for the tax credit. In fact, it is plausible that there will be sources of revenue, potentially including from the sale of the CO
2for utilization and credits to 
meet state or corporate clean energy goals, as discussed in RTC section 2.2.4.3. 
It should be noted that natural gas- 
fired combustion turbines with CCS may well generate at higher capacity factors after the expiration of the 45Q tax credit than the EPA’s above- described BSER cost analysis assumes. In fact, the EPA’s IPM model projects that the natural gas combined cycle generation that is projected to install CCS in the illustrative final rule scenario operates at an average 73 percent capacity factor, due to existing state regulatory requirements, during the 2045 model year, which is after the expiration of the 45Q tax credit. In addition, as discussed in RTC section 2.2.4.3, it is plausible that following the 12-year period of the tax credit, by the 2040s, cost improvements in CCS operations, more widespread adoption of CO
2emission limitation requirements 
in the electricity sector, and greater demand for CO
2for beneficial uses will 
support continued operation of fossil fuel-fired generation with CCS. Accordingly, the EPA also calculated CCS costs assuming that new F-Class and H-Class combustion turbines with CCS generate at a constant capacity factor of at least 60 percent, and up to 80 percent, during their 30-year useful life. In this calculation, the EPA amortized the costs of CCS over the 30- year useful life of the turbine. The EPA includes these costs in the final TSD, 
GHG Mitigation Measures—Carbon Capture and Storage for Combustion Turbines, section 2.3, Figure 8.
835At the 
lower levels of capacity, costs are higher 
than described above (which assumed 80 percent capacity during the first 12 years), but even at those lower levels, the costs are broadly consistent with the cost-reasonable metrics based on prior rules, particularly when those costs are reduced by an additional 5 percent to account for improved efficiency and other factors, as noted above. Nonetheless, consistent with the EPA’s commitment to review, and if appropriate, revise the emission guidelines for coal-fired steam generating units as discussed in section VII.F, the EPA also intends to evaluate, by 2041, the continued cost- reasonableness of CCS for natural gas- fired combustion turbines in light of these potential significant developments, and will consider at that time whether a future regulatory action may be appropriate. 
(5) Comparison to Other Costs of 
Controls 
The costs for CCS applied to a 
representative new base load stationary combustion turbine EGU are generally lower than the costs of other controls in 
EPA rules for fossil fuel-fired electric generating units, as well as the costs of other controls for greenhouse gases, as described in section VII.C.1.a.ii(D), which supports the EPA’s view that the CCS costs are reasonable. 
(D) Non-Air Quality Health and 
Environmental Impact and Energy Requirements 
In this section of the preamble, the 
EPA considers the non-air quality health and environmental impacts of CCS for new combined cycle turbines and concludes there are limited consequences related to non-air quality health and environmental impact and energy requirements. The EPA first discusses energy requirements, and then considers non-GHG emissions impacts and water use impacts, resulting from the capture, transport, and sequestration of CO
2. 
With respect to energy requirements, 
including a 90 percent or greater carbon capture system in the design of a new combined cycle turbine will increase the unit’s parasitic/auxiliary energy demand and reduce its net power output. A utility that wants to construct a combined cycle turbine to provide 500 MWe-net of power could build a 
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836While the absolute onsite mass emissions 
would not increase from the second component of 
the BSER, the emissions rate on a lb/MWh-net basis would increase by 13 percent. 837Sharma, S., Azzi, M., ‘‘A critical review of 
existing strategies for emission control in the monoethanolamine-based carbon capture process and some recommendations for improved strategies,’’ Fuel, 121, 178 (2014). 
838Mertens, J., et al., ‘‘Understanding 
ethanolamine (MEA) and ammonia emissions from amine-based post combustion carbon capture: Lessons learned from field tests,’’ Int’l J. of GHG Control, 13, 72 (2013). 839In outreach with potentially vulnerable 
communities, residents have voiced two primary concerns. First, there is the concern that their communities have experienced historically disproportionate burdens from the environmental impacts of energy production, and second, that as the sector evolves to use new technologies such as CCS, they may continue to face disproportionate burden. This is discussed further in section XII.E of this preamble. 500 MWe-net plant knowing that it will 
be de-rated by 11 percent (to a 444 MWe-net plant) with the installation and operation of CCS. In the alternative, the project developer could build a larger 563 MWe-net combined cycle turbine knowing that, with the installation of the carbon capture system, the unit will still be able to provide 500 MWe-net of power to the grid. Although the use of CCS imposes additional energy demands on the affected units, those units are able to accommodate those demands by scaling larger, as needed. 
Regardless of whether a unit is scaled 
larger, the installation and operation of CCS itself does not impact the unit’s potential-to-emit any criteria air pollutants. In other words, a new base load stationary combustion turbine EGU constructed using highly efficient generation (the first component of the BSER) would not see an increase in emissions of criteria air pollutants as a direct result of installing and using 90 percent or greater CO
2capture CCS to 
meet the second phase standard of performance.
836 
Scaling a unit larger to provide heat 
and power to the CO 2capture 
equipment would have the potential to increase non-GHG air emissions. However, most pollutants would be mitigated or controlled by equipment needed to meet other CAA requirements. In general, the emission rates and flue gas concentrations of most non-GHG pollutants from the combustion of natural gas in stationary combustion turbines are relatively low compared to the combustion of oil or coal in boilers. As such, it is not necessary to use an FGD to pretreat the flue gas prior to CO
2removal in the CO 2 
scrubber column. The sulfur content of natural gas is low relative to oil or coal and resulting SO
2emissions are 
therefore also relatively low. Similarly, PM emissions from combustion of natural gas in a combustion turbine are relatively low. Furthermore, the high combustion efficiency of combustion turbines results in relatively low HAP emissions. Additionally, combustion turbines at major sources of HAP are subject to the stationary combustion turbine NESHAP, which includes limits for formaldehyde emissions for new sources that may require installation of an oxidation catalyst (87 FR 13183; March 9, 2022). Regarding NO
X 
emissions, in most cases, the combustion turbines in new combined cycle units will be equipped with low- NO
Xburners to control flame 
temperature and reduce NO Xformation. 
Additionally, new combined cycle units are typically subject to major NSR requirements for NO
Xemissions, which 
may require the installation of SCR to comply with a control technology determination by the permitting authority. See section XI.A of this preamble for additional details regarding the NSR program. Although NO
Xconcentrations may be controlled 
by SCR, for some amine solvents NO X 
in the post-combustion flue gas can react in the CO
2absorber to form 
nitrosamines. A conventional multistage water wash or acid wash and a mist eliminator at the exit of the CO
2 
scrubber is effective at removal of gaseous amine and amine degradation products (e.g., nitrosamine) 
emissions.
837 838 Acetaldehyde and 
formaldehyde can form through oxidation of the solvent, however, this can be mitigated by selecting compatible materials to limit catalytic oxidation and interstage cooling in the absorber to limit thermal oxidation. 
The use of water for cooling presents 
an additional issue. Due to their relatively high efficiency, combined cycle EGUs have relatively small cooling requirements compared to other base load EGUs. According to NETL, a combined cycle EGU without CCS requires 190 gallons of cooling water per MWh of electricity. CCS increases the cooling water requirements due both to the decreased efficiency and the cooling requirements for the CCS process to 290 gallons per MWh, an increase of about 50 percent. However, because combined cycle turbines require limited amounts of cooling water, the absolute amount of increase in cooling water required due to use of CCS is relatively small compared to the amount of water used by a coal-fired EGU. A coal-fired EGU without CCS requires 450 gallons or more per MWh and the industry has demonstrated an ability to secure these quantities of water and the EPA has determined that the increased water requirements for CCS can be addressed. In addition, many combined cycle EGUs currently use dry cooling technologies and the use of dry or hybrid cooling technologies for the CO
2capture process would reduce the need for additional cooling water. Therefore, the EPA is finalizing a determination that the challenges of additional cooling requirements from CCS are limited and do not disqualify CCS from being the BSER. 
Stakeholders have shared with the 
EPA concerns about the safety of CCS projects and that historically disadvantaged and overburdened communities may bear a disproportionate environmental burden associated with CCS projects.
839The 
EPA takes these concerns seriously, agrees that any impacts to historically disadvantaged and overburdened communities are important to consider, and has done so as part of its analysis discussed at section XII.E. For the reasons noted above, the EPA does not expect CCS projects to result in uncontrolled or substantial increases in emissions of non-GHG air pollutants from new combustion turbines. Additionally, a robust regulatory framework exists to reduce the risks of localized emissions increases in a manner that is protective of public health, safety, and the environment. These projects will likely be subject to major NSR requirements for their emissions of criteria pollutants, and therefore the sources would be required to (1) control their emissions of attainment pollutants by applying BACT and demonstrate the emissions will not cause or contribute to a NAAQS violation, and (2) control their emissions of nonattainment pollutants by applying LAER and fully offset the emissions by securing emission reductions from other sources in the area. Also, as mentioned in section VII.C.1, carbon capture systems that are themselves a major source of HAP should evaluate the applicability of CAA section 112(g) and conduct a case- by-case MACT analysis if required, to establish MACT for any listed HAP, including listed nitrosamines, formaldehyde, and acetaldehyde. But, as also discussed in section VII.C.1, a conventional multistage water or acid wash and mist eliminator (demister) at the exit of the CO
2scrubber is effective 
at removal of gaseous amine and amine degradation products (e.g., nitrosamine) 
emissions. Additionally, as noted in 
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840https://www.eia.gov/todayinenergy/ 
detail.php?id=55419. 
841https://cubminnesota.org/xcel-is-no-longer- 
pursuing-gas-power-plant-proposes-more- 
renewable-power/. 842Does not include 114 billion kilowatt hours 
from natural gas-fired CHP projected in AEO 2023. section VII.C.1.a.i.(C) of this preamble, 
PHMSA oversight of supercritical CO 2 
pipeline safety protects against environmental release during transport and UIC Class VI regulations under the SDWA, in tandem with GHGRP requirements, ensure the protection of USDWs and the security of geologic sequestration. 
The EPA is committed to working 
with its fellow agencies to foster meaningful engagement with communities and protect communities from pollution. This can be facilitated through the existing detailed regulatory framework for CCS projects and further supported through robust and meaningful public engagement early in the technological deployment process. 
The EPA also expects that the 
meaningful engagement requirements discussed in section X.E.1.b.i of this preamble will ensure that all interested stakeholders, including community members who might be adversely impacted by non-GHG pollutants, will have an opportunity to raise this concern with states and permitting authorities. Additionally, state permitting authorities, and project developers are, in general, required to provide public notice and comment on permits for such projects. This provides additional opportunities for affected stakeholders to engage in that process, and it is the EPA’s expectation that the responsible entities consider these concerns and take full advantage of existing protections. Moreover, the EPA through its regional offices is committed to thoroughly review permits associated with CO
2capture. 
(E) Impacts on the Energy Sector 
The EPA does not believe that 
determining CCS to be BSER for base load combustion turbines will cause reliability concerns, for several independent reasons. First, the EPA is finalizing a determination that the costs 
of CCS are reasonable and comparable to other control requirements the EPA has required the electric power industry to adopt without significant effects on reliability. Second, base load combined cycle turbines are only one of many options that companies have to build new generation. The EPA expects there to be considerable interest in building intermediate load and low load combustion turbines to meet demand for dispatchable generation. Indeed, the portion of the combustion turbine fleet that is operating at base load is declining as shown in the EPA’s reference case modeling (Power Sector Platform 2023 using IPM reference case, see section IV.F of the preamble). In 2023, combined cycle turbines are only expected to represent 14 percent of all new generating capacity built in the U.S. and only a portion of that is natural gas combined cycle capacity.
840Several 
companies have recently announced plans to move away from new combined cycle turbine projects in favor of more non-base load combustion turbines, renewables, and battery storage. For example, Xcel recently announced plans to build new renewable power generation instead of the combined cycle turbine it had initially proposed to replace the retiring Sherco coal-fired plant.
841Finally, while CCS is 
adequately demonstrated and cost- reasonable, this final rulemaking allows companies that want to build a base load combined cycle turbine another compliance option to meet its requirements: building a unit that co- fires low-GHG hydrogen in the appropriate amount to meet the standard of performance. In fact, companies are currently pursuing both of these options—units with CCS as well as units that will co-fire low-GHG hydrogen are both in various stages of development. For these reasons, determining CCS to be the BSER for base load units will not cause reliability concerns. 
(F) Extent of Reductions in CO
2 
Emissions 
Designating CCS as a component of 
the BSER for certain base load 
combustion turbine EGUs prevents large amounts of CO
2emissions. For example, 
a new base load combined cycle EGU without CCS could be expected to emit 45 million tons of CO
2over its 30-year 
operating life, or 1.5 million tons of CO 2 
per year. Use of CCS would avoid the release of nearly 41 million tons of CO
2 
over the operating life of the combined cycle EGU, or 1.37 million tons per year. However, due to the auxiliary/parasitic energy requirements of the carbon capture system, capturing 90 percent of the CO
2does not result in a 
corresponding 90 percent reduction in CO
2emissions. According to the NETL 
baseline report, adding a 90 percent CO 2 
capture system increases the EGU’s gross heat rate by 7 percent and the unit’s net heat rate by 13 percent. Since more fuel would be consumed in the CCS case, the gross and net emissions rates are reduced by 89.3 percent and 88.7 percent respectively. These amounts of CO
2emissions and 
reductions are larger than for any other industrial source, except for coal-fired 
steam generating units. 
(G) Promotion of the Development and 
Implementation of Technology 
The EPA also considered whether 
determining CCS to be a component of the BSER for new base load combustion turbines will advance the technological development of CCS and concluded that this factor further corroborates our BSER 
determination. A standard of performance based on highly efficient generation in combination with the use of CCS—combined with the availability of IRC section 45Q tax credits and investments in supporting CCS infrastructure from the IIJA—should result in more widespread adoption of CCS. In addition, while solvent-based CO
2capture has been adequately 
demonstrated at the commercial scale, a CCS-based standard of performance may incentivize the development and use of better-performing solvents or other components of the capture equipment. 
Furthermore, the experience gained 
by utilizing CCS with stationary combustion turbine EGUs, with their lower CO
2flue gas concentration 
relative to other industrial sources such as coal-fired EGUs, will advance capture technology with other lower CO
2 
concentration sources. The EIA 2023 Annual Energy Outlook projects that almost 862 billion kWh of electricity will be generated from natural gas-fired sources in 2040.
842Much of that 
generation is projected to come from existing combined cycle EGUs and further development of carbon capture technologies could facilitate increased retrofitting of those EGUs. 
(H) Summary of BSER Determination 
As discussed, the EPA is finalizing a 
determination that the second 
component of the BSER for base load stationary combustion turbines is the utilization of CCS at 90 percent capture. The EPA has determined that 90 percent CCS meets the criteria for BSER for new base load combustion turbines. It is an adequately demonstrated technology that can be implemented a reasonable cost. Importantly, use of CCS at 90 percent capture results in significant reductions of CO
2as compared to a base 
load combustion turbine without CCS. In addition, the EPA has considered non-air quality and energy impacts. Considering all these factors together, with particular emphasis on the importance of significantly reducing carbon pollution from these heavily utilized sources, the EPA concludes that 
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843CO 2Capture Project Schedule and Operations 
Memo, Sargent & Lundy (2024). 
844Transport and Storage Timeline Summary, ICF 
(2024). CCS at 90 percent capture is BSER for 
new base load combustion turbines. In addition, selecting CCS at 90 percent capture further promotes the development and implementation of this critical carbon pollution reduction technology, which confirms the appropriateness of determining it to be the BSER. 
The BSER for base load combustion 
turbines contains two components and the EPA is promulgating standards of performance to be implemented in two phases with each phase reflecting the degree of emission reduction achievable through the application of each component of the BSER. The first component of the BSER is most efficient generation—an affected new base load combustion turbine must be constructed (or reconstructed) to meet a phase 1 emission standard that reflects the emission rate of the best performing combustion turbine systems. The phase 1 standard of performance for base load combustion turbines is in effect immediately once the source begins operation. The second component of the BSER, as just discussed, is use of CCS at a 90 percent capture rate. The phase 2 standard of performance for base load combustion turbines reflects the implementation of 90 capture CCS on a highly efficient combined cycle combustion turbine system. The compliance date begins January 1, 2032. 
(I) January 2032 Compliance Date 
The EPA proposed a compliance date 
beginning January 1, 2035, for new and 
reconstructed base load stationary combustion turbines subject to the phase 2 standard of performance based on CCS as the BSER. Some commenters were supportive of the proposed compliance date and some urged the EPA to set an earlier compliance date; the EPA also received comments on the proposed rule that stated that the 
proposed compliance date was not achievable and referenced longer project timelines for CO
2capture. The EPA has 
considered the comments and information available and is finalizing a compliance date of January 1, 2032, for the phase 2 standard of performance for base-load stationary combustion turbines. The EPA is also finalizing a mechanism for a compliance date extension of up to 1 year in cases where a source faces a delay in the installation and startup of controls that are beyond the control of the EGU owner or operator, as detailed in section VIII.N of this preamble. 
In total, the January 1, 2032, 
compliance date allows for more than 7 years for installation of CCS after issuance of this rule for sources that have recently commenced construction. 
This is consistent with the extended 
project schedule in the Sargent & Lundy report. This is also greater than the approximately 6 years from start to finish for Boundary Dam Unit 3 and Petra Nova. 
As discussed in section VII.C.1.a.i(E), 
the timing for installation of CCS on existing coal-fired steam generating units is based on the baseline project schedule for the capture plant developed by Sargent and Lundy (S&L)
843and a review of the available 
information for installation of CO 2 
pipelines and sequestration sites.844The 
representative timeline for CCS for coal- fired steam generating units is detailed in the final TSD, GHG Mitigation Measures for Steam Generating Units, available in the docket, and the anticipated timeline for development of a CCS project for application at a new or reconstructed base load stationary combustion turbine would be similar. The explanations the EPA provided in section VII.C.1.a.i(E) regarding the timeline for long-term coal-fired steam generating units generally apply to new combustion turbines as well. The EPA expects that the owners or operators of affected combustion turbines will be able to complete the design, planning, permitting, engineering, and construction steps for the carbon capture and transport and storage systems in a similar amount of time as projects for coal-fired EGUs. 
While those considerations apply in 
general, the EPA notes that the timeline for the installation of CCS on coal-fired steam generating units accounted for the state plan development process. Because there are not state plans required for new combustion turbines, new sources can commit to beginning substantial work earlier (e.g., FEED 
studies, right-of-way acquisition), immediately after the completion of feasibility work. However, the EPA also recognizes that other elements of a state plan (e.g., RULOF), by which a source 
under specific circumstances could have a later compliance date, are not available to new sources. Therefore, while the timeline for CCS on coal-fired steam generating units is based on the baseline S&L capture plant schedule (about 6.25 years), the EPA bases the timeline for CCS on new combustion turbines on the extended S&L capture plant schedule (7 years). 
As discussed, base load stationary 
combustion turbines that commence construction or reconstruction on or 
after May 23, 2023, are subject to standards of performance that are implemented initially in two phases. New stationary combustion turbines that are designed and constructed for the purpose of operating in the base load subcategory (i.e., at a 12-operating 
month capacity factor of greater than 40 percent) that hypothetically commenced construction on May 23, 2023, could, according to the schedule allowing, conservatively, up to 7 years to develop a CCS project, have a system constructed and on-line by May 23, 2030. However, the EPA is finalizing a compliance date of January 1, 2032, because some base load combined cycle stationary combustion projects that commenced construction between May 23, 2023, and the date of this final rule, may not have included CCS in the original design and planning for the new EGU and, therefore, would be unlikely to be able to have an operational CCS system available by May 23, 2030. 
Further, the EPA notes that a delayed 
compliance date (of January 1, 2035) was proposed for the phase 2 standards of performance due to overlapping demands on the capacity to design, construct, and operate carbon capture systems as well as pipeline systems that would potentially be needed to support CCS projects for existing steam generating units and other industrial sources. As discussed in section VII.C.1.a.i(E), in this action the EPA is finalizing a compliance date of January 1, 2032 for long term coal-fired steam generating EGUs to meet a standard of performance based on 90 percent capture CCS. This compliance date for long-term coal-fired steam generating EGUs places fewer demands on the capacity to design, construct, and operate carbon capture systems and the associated infrastructure for those sources. Therefore, the EPA does not believe that there is a need to extend the compliance date for phase 2 standards for base load combustion turbine EGUs by 5 years beyond that for existing coal- fired steam generating EGUs, as proposed. 
Considering these factors, the EPA is 
therefore finalizing the compliance date of January 1, 2032 for base load combustion turbine EGUs to meet the phase 2 standard of performance. This is the same compliance date applicable to existing long term coal-fired steam generating EGUs that are subject to a standard of performance based on 90 percent capture CCS. The EPA assumes the timelines for development of the 
various components of CCS for an existing coal-fired steam generating 
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EGU, as discussed in section 
VII.C.1.a.i(E), are very similar for those components for a CCS system serving a new or reconstructed base load combustion turbine EGU. 
Some commenters argued that 
because the power sector will require some amount of time before CCS and associated infrastructure may be installed on a widespread basis, CCS cannot be considered adequately demonstrated. This argument is similar to the argument, discussed in section V.C.2.b, that in order to be adequately demonstrated, a technology must be in widespread commercial use. Both arguments are incorrect. Under CAA section 111, for a control technology to qualify as the BSER, the EPA must demonstrate that it is adequately demonstrated for affected sources. The EPA must also show that the industry can deploy the technology at scale in the compliance timeframe. That the EPA has provided lead time in order to ensure adequate time for industry to deploy the technology at scale shows that the EPA is meeting its statutory obligation, not the inverse. Indeed, it is not at all unusual for the EPA to provide lead time for industry to deploy new technology. The EPA’s approach is in line with the statutory text and caselaw encouraging technology-forcing standard-setting cabined by the EPA’s obligation to ensure that its standards are reasonable and achievable. 
CCS is clearly adequately 
demonstrated, and ripe for wider implementation. Nevertheless, the EPA acknowledged in the proposed rule, and reaffirms now, that the power sector will require some amount of lead time before individual plants can install CCS as necessary. Deploying CCS requires the building of capture facilities, pipelines to transport captured CO
2to 
sequestration sites, and the development of sequestration sites. This is true for both existing coal-fired steam generating EGUs, some of which would be required to retrofit with CCS under the emission guidelines included in this final rulemaking, and new gas-fired combustion turbine EGUs, which must incorporate CCS into their construction planning. 
In this final rulemaking, the EPA is 
setting a compliance deadline of January 1, 2032 for the CCS-based standard for 
new base load combustion turbines. The EPA determined, examining the evidence and exercising its appropriate discretion to do so, that this is a reasonable amount of time to allow for CCS buildout at the plant level. As the EPA explained at proposal, D.C. Circuit caselaw supports this approach. There, the EPA cited Portland Cement v. Ruckelshaus, for the proposition that 
‘‘D.C. Circuit caselaw supports the 
proposition that CAA section 111 authorizes the EPA to determine that controls qualify as the BSER—including meeting the ‘adequately demonstrated’ criterion—even if the controls require some amount of ‘lead time,’ which the court has defined as ‘the time in which the technology will have to be available.’ ’’ (footnote omitted). Nothing in the comments alters the EPA’s view of the relevant legal requirements 
related to adequate demonstration or lead time. 
d. BSER for Base Load Subcategory— 
Third Component 
The EPA proposed a third component 
of the BSER of 96 percent (by volume) hydrogen co-firing in 2038 for owners/ operators of base load combustion turbines that elected to comply with the low-GHG hydrogen co-firing pathway. As discussed in the next section, the EPA is not finalizing the proposed BSER pathway of low-GHG hydrogen co-firing at this time. Therefore, the Agency is not finalizing a third component of the BSER for base load combustion turbines. 
5. Technologies Proposed by the EPA 
But Ultimately Not Determined To Be the BSER 
The EPA is not finalizing its proposed 
BSER pathway of low-GHG hydrogen co-firing for new and reconstructed base load and intermediate load combustion turbines as part of this action. In light of public comments and additional analysis, uncertainties regarding projected costs prevent the EPA from determining that low-GHG hydrogen is a component of the BSER at this time. 
The next section provides a summary 
of the proposed requirements for low- GHG hydrogen followed by, in section VIII.F.5.b, an explanation for why the Agency is not finalizing its proposed determination that low-GHG hydrogen co-firing is BSER. In section VIII.F.6, the EPA discusses considerations for the potential use of hydrogen. In section VIII.F.6.a, the Agency explains why it is not limiting the hydrogen that may be co-fired in a new or reconstructed combustion turbine to only low-GHG hydrogen. In section VIII.F.6.b, the Agency discusses its decision to not include a definition of low-GHG hydrogen. 
a. Proposed Low-GHG Hydrogen Co- 
Firing BSER 
The EPA proposed that new and 
reconstructed intermediate load combustion turbines were subject to a second component of the BSER that consisted of co-firing 30 percent (by volume) low-GHG hydrogen by 2032. 
The EPA also proposed that new and reconstructed base load combustion turbines could elect either (i) a second component of BSER that consisted of installing CCS by 2035, or (ii) a second and third component of BSER that consisted of co-firing 30 percent (by volume) low-GHG hydrogen by 2032 and co-firing 96 percent (by volume) low-GHG hydrogen by 2038. 
The EPA solicited comment on 
whether the Agency should finalize both the CCS and low-GHG hydrogen co-firing pathways as separate subcategories with separate standards of performance and on whether the EPA should finalize one pathway with the option of meeting the standard of performance using either system of emission reduction (88 FR 33277, May 23, 2023). The EPA also solicited comment on the option of finalizing a single standard of performance based on the application of CCS for the base load subcategory (88 FR 33283, May 23, 2023). 
b. Explanation for Not Finalizing Low- 
GHG Hydrogen Co-Firing as a BSER 
The EPA is not finalizing a low-GHG 
hydrogen co-firing component of the BSER at this time. The EPA proposed that co-firing low-GHG hydrogen qualified as a BSER pathway because the components of the system met specific criteria, namely that the capability of combustion turbines to co- fire hydrogen was adequately demonstrated and there was a reasonable expectation that the necessary quantities of low-GHG hydrogen would be nationally available by 2032 and 2038 at reasonable cost. Due to concerns raised by commenters, the EPA conducted additional analysis of key components of the low-GHG hydrogen best system and the Agency’s proposed determination that low-GHG 
hydrogen co-firing qualified as the BSER. This additional analysis, discussed further below, indicated that the currently estimated cost of low-GHG hydrogen in 2030 is higher than anticipated at proposal. These higher cost estimates were key factors in the EPA’s decision to revise its 2030 cost estimate for delivered low-GHG hydrogen. 
While the EPA is not finalizing a 
BSER determination with regard to co- firing with low-GHG hydrogen as part of this rulemaking and is therefore not making any determination about whether such a practice is adequately demonstrated, the Agency notes that there are multiple models of combustion turbines available from major manufacturers that have successfully 
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845Electric Power Research Institute (EPRI). 
(November 3, 2023). Impact of IRA’s 45V Clean 
Hydrogen Production Tax Credit. White paper. https://www.epri.com/research/products/ 000000003002028407. 846The delivered price includes the cost to 
produce, transport, and store hydrogen. 
847U.S. Department of Energy (DOE) (March 
2023). Pathways to Commercial Liftoff: Clean 
Hydrogen. https://liftoff.energy.gov/wp-content/ 
uploads/2023/05/20230523-Pathways-to- Commercial-Liftoff-Clean-Hydrogen.pdf. 848Heid, B.; Sator, A.; Waardenburg, M.; and 
Wilthaner, M. (25 Oct 2022). Five charts on 
hydrogen’s role in a net-zero future. McKinsey & Company. https://www.mckinsey.com/capabilities/ 
sustainability/our-insights/five-charts-on- hydrogens-role-in-a-net-zero-future. 
849Schelling, K. (9 Aug 2023). Green Hydrogen to 
Undercut Gray Sibling by End of Decade. BloombergNEF. https://about.bnef.com/blog/green- 
hydrogen-to-undercut-gray-sibling-by-end-of- decade/. 
850Larsen, J.; King, B.; Kolus, H.; Dasari, N.; 
Bower, G.; and Jones, W. (12 Aug 2022). A Turning 
Point for US Climate Progress: Assessing the Climate and Clean Energy Provisions in the Inflation Reduction Act. Rhodium Group. https://rhg.com/research/climate-clean-energy-inflation- reduction-act/. 
851U.S. Department of Energy (DOE). (February 
22, 2024). Summary of Electrolyzer Cost Data Synthesized from Applications to the DOE Clean Hydrogen Hubs Program. DOE Hydrogen Program, Office of Clean Energy Demonstrations Program Record. https://www.hydrogen.energy.gov/docs/ 
hydrogenprogramlibraries/pdfs/24002-summary- electrolyzer-cost-data.pdf. 
852Martin, P. (December 18, 2023). What gives 
Bill Gates-backed start-up Electric Hydrogen the edge over other electrolyzer makers? Hydrogen demonstrated the ability to combust 
hydrogen. Manufacturers have stated that they expect to have additional models of combustion turbines available that will be capable of firing 100 percent hydrogen while limiting emissions of other pollutants (e.g., NO
X). The EPA 
further discusses considerations around the technical feasibility of hydrogen co- firing in new and reconstructed combustion turbines, and what they mean for the potential use of hydrogen co-firing as a compliance strategy, in section VIII.F.6 of this preamble. 
While the EPA believes that hydrogen 
co-firing is technically feasible based on combustion turbine technology, information about how the low-GHG hydrogen production industry will develop in the future is not sufficiently certain for the EPA to be able to determine that adequate quantities will be available. That is, there remain, at the time of this final rulemaking, uncertainties pertaining to how the future nationwide availability of low- GHG hydrogen will develop. Relatedly, estimates of its future costs are more uncertain than anticipated at proposal. For low-GHG hydrogen to meet the BSER criteria as proposed, the EPA would have to be able to determine that significant quantities of low-GHG hydrogen will be available at reasonable costs such that affected sources in the power sector nationwide could rely on it for use by 2032 and 2038. While some analyses
845show that this will likely be 
the case, the full set of information necessary to support such a determination is not available at this time. However, the EPA believes this may change as the low-GHG hydrogen industry continues to develop. The Agency plans to monitor the development of the industry; if appropriate, the EPA will reevaluate its findings and establish standards of performance that achieve additional emission reductions. Furthermore, as noted above, the EPA considers the co- firing of hydrogen to be technically feasible in multiple models of available combustion turbines. 
As noted above, the EPA has revised 
its cost analysis of low-GHG hydrogen and determined that, due to the present uncertainty, estimated future hydrogen costs are higher than at proposal. The higher estimated cost of low-GHG hydrogen relative to proposal is the key factor in the EPA’s decision to not finalize low-GHG hydrogen co-firing as a BSER pathway for new and reconstructed base load and intermediate load combustion turbines at this time. 
In the proposal, the EPA modeled 
low-GHG hydrogen as a fuel available at a fixed delivered
846price of $1/kg (or 
$7.40/MMBtu) in the baseline. This cost decreased to $0.50/kg (or $3.70/MMBtu) in the Integrated Proposal case when the second phase of the new combustion turbine standard began in 2032. This fuel was assumed to be ‘‘clean’’ and eligible for the highest subsidy under the IRC section 45V hydrogen production tax credit and would comply with the proposed requirement to use low-GHG hydrogen (88 FR 33314, May 23, 2023). The EPA’s revised modeling of the power sector for the final rule used a price of $1.15/kg for delivered low-GHG hydrogen in both the final baseline and policy cases. For additional discussion of the EPA’s revised modeling of the power sector and increased cost estimate for low- GHG hydrogen, see the final RIA included in the docket for this rulemaking. 
The U.S. Department of Energy’s 2022 
report, Pathways to Commercial Liftoff: 
Clean Hydrogen, informed the EPA’s revised low-GHG hydrogen cost analysis. According to the DOE report, the cost to produce, transport, store, and deliver low-GHG or ‘‘clean’’ hydrogen is expected to be between $0.70/kg and $1.15/kg by 2030 with the IRA’s $3/kg maximum IRC section 45V production tax credit included.
847The report also 
points out that the power sector is competing with other industrial sectors—such as transportation, ammonia and chemical production, oil refining, and steel manufacturing—in 
terms of potential downstream applications of clean hydrogen for the purpose of reducing GHG emissions. The DOE report also estimates that $0.40/kg to $0.50/kg is the price the power sector would be willing to pay for clean hydrogen. 
Some analyses of future hydrogen 
costs provide estimates that are higher than those of the DOE. For example, public commenters estimated the cost of delivered ‘‘clean’’ hydrogen to be less than $3/kg by 2030 before declining to $2/kg by 2035. These estimates of delivered hydrogen costs include the IRC section 45V hydrogen production tax credits contained in the IRA, but they do not reflect regulations proposed by the U.S. Department of the Treasury 
pertaining to clean hydrogen production tax and energy credits, which proposed certain eligibility parameters (88 FR 89220, December 26, 2023). Until Treasury’s regulations on the IRC section 45V hydrogen production tax credit are final, some analysts only estimate future production costs of hydrogen, not delivered costs, and do not include any projected potential impacts of the IRA incentives. For example, both McKinsey and BloombergNEF project the unsubsidized production cost of clean hydrogen to be approximately $2/kg by 2030, which could lead to negative to zero prices for some subsidized hydrogen after considering transportation and storage.
848 849 One of the highest 
estimates for the unsubsidized production cost of clean hydrogen is from the Rhodium Group, which estimates the price to be from $3.39/kg to $4.92/kg in 2030.
850Again, it should 
be noted these estimates do not include additional costs for transportation and storage. The increased cost projections for low-GHG hydrogen production are partly due to higher costs for capital equipment, such as electrolyzers. The DOE published a Program Record
851 
detailing higher costs than previously estimated by levering data from the regional clean hydrogen hubs and other literature. Costs increases are predominantly driven by inflation, supply chain cost increases, and higher estimated installation costs. However, there is a significant range in electrolyzer costs; some companies cite costs that are significantly lower ($750- $900/kW installed cost)
852than that 
published in the Program Record. 
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Insight. https://www.hydrogeninsight.com/ 
electrolysers/what-gives-bill-gates-backed-start-up- 
electric-hydrogen-the-edge-over-other-electrolyser- makers-/2-1-1572694. 
853In June 2022, the U.S. Department of Energy 
(DOE) Loans Program Office issued a $504.4 million loan guarantee to finance the Advanced Clean Energy Storage (ACES) project in Delta, Utah. ACES expects to utilize a 220 MW bank of electrolyzers and curtailed renewable energy to produce clean hydrogen that will be stored in salt caverns. The hydrogen will fuel an 840 MW combined cycle combustion turbine at the Intermountain Power Project facility. https://www.energy.gov/lpo/ advanced-clean-energy-storage. 
85488 FR 33240, 33315 (May 23, 2023). 855U.S. Department of the Treasury. (October 5, 
2022). Treasury Seeks Public Input on 
Implementing the Inflation Reduction Act’s Clean Energy Tax Incentives. Press release. https://home.treasury.gov/news/press-releases/jy0993. 6. Considerations for the Potential Use 
of Hydrogen 
The ability of combustion turbines to 
co-fire hydrogen can effectively reduce stack GHG emissions. Hydrogen also offers unique solutions for decarbonization because of its potential to provide dispatchable, clean energy with long-term storage and seasonal capabilities. For example, hydrogen is an energy carrier that can provide long- term storage of low-GHG energy that can be co-fired in combustion turbines and used to balance load with the increasing volumes of variable generation. These services support the reliability of the power system while facilitating the integration of variable zero-emitting energy resources and supporting decarbonization of the electric grid. One technology with the potential to reduce curtailment is energy storage, and some power producers envision a role for 
hydrogen to supplement natural gas as a fuel to support the balancing and reliability of an increasingly decarbonized electric grid. 
Hydrogen is a zero-GHG emitting fuel 
when combusted, so that co-firing it in a combustion turbine in place of natural gas reduces GHG emissions at the stack. For this reason, certain owners/ operators of combustion turbines in the power sector may elect to co-fire hydrogen in the coming years to reduce onsite GHG emissions.
853Co-firing low- 
emitting fuels—sometimes referred to as clean fuels—is a traditional type of emissions control. However, the EPA recognizes that even though the combustion of hydrogen is zero-GHG 
emitting, its production can entail a 
range of GHG emissions, from low to high, depending on the method. These differences in GHG emissions from the different methods of hydrogen production are well-recognized in the energy sector (88 FR 33306, May 23, 2023), and, in fact, hydrogen is generally characterized by its production method and the attendant level of GHG emissions. 
While the focus of this rule is the 
reduction of stack GHG emissions from combustion turbines, the EPA also recognizes that, to ensure overall GHG 
benefits, it is important any hydrogen used in the power sector be low-GHG hydrogen. Thus, even though the EPA is not finalizing the use of low-GHG hydrogen as a component of the BSER for base load or intermediate load combustion turbines, it maintains that the type of hydrogen used (i.e., the 
method by which the hydrogen was produced) should be a primary consideration for any source that decides to co-fire hydrogen. Again, the Agency reiterates its concern that sources in the power sector that choose to co-fire hydrogen to reduce their GHG emission rate should co-fire only low- GHG hydrogen to achieve overall GHG reductions and important climate benefits. 
In the proposal, the EPA solicited 
comment on whether it is necessary to require low-GHG hydrogen. Similarly, the EPA also solicited comment as to whether the low-GHG hydrogen requirement could be treated as severable from the remainder of the standard such that the standard could function without this requirement. The EPA also solicited comment on a host of recordkeeping and reporting topics. These pertained to the complexities of tracking the sources of quantities of produced low-GHG hydrogen and the public interest in such data. 
a. Explanation for Not Requiring 
Hydrogen Used for Compliance To Be Low-GHG Hydrogen 
The EPA proposed that the type of 
hydrogen co-fired must be limited to low-GHG hydrogen, and not include other types of hydrogen.
854This 
requirement was proposed to prevent the anomalous outcome of a GHG control strategy contributing to an increase in overall GHG emissions; the provision that only low-GHG hydrogen could be used for compliance mirrored the EPA’s proposal that low-GHG hydrogen, in particular, could qualify as a component of the BSER. For the 
reasons explained below, the EPA is not finalizing a requirement that any hydrogen that sources choose to co-fire must be low-GHG hydrogen. However, the Agency continues to stress, notwithstanding the lack of requirement under this rule, the importance of ensuring that any hydrogen used in combustion turbines is low-GHG hydrogen. The EPA’s choice to not finalize a low-GHG requirement at this time is based in large part on knowledge of current and future efforts that will reinforce the availability and role of low-GHG hydrogen in the national economy and, more specifically, in the 
power sector. As discussed further below, this decision is against the backdrop of ongoing developments in the public and private sectors, Treasury’s regulations implementing a tax credit for the production of clean hydrogen, multiple Federal government grant and assistance programs, and the EPA’s investigation into methods to control emissions of air pollutants from hydrogen production. 
The EPA’s decision to not require that 
any hydrogen used for compliance be low-GHG hydrogen was based primarily on the current market and policy developments regarding hydrogen production at this particular point in time, including the clean hydrogen production tax credits. There are currently multiple private and public efforts to develop, inter alia, greenhouse gas accounting practices, verification protocols, reporting conventions, and other elements that will help determine how low-GHG hydrogen is measured, tracked, and verified over the next several years. For example, Treasury is expected to finalize parameters for evaluating overall emissions associated with hydrogen production pathways as it prepares to implement IRC section 45V.
855The overall objective of 
Treasury’s parameters is to recognize that different methods of hydrogen production generate different amounts of GHG emissions while encouraging lower-emitting production methods through the multi-tier hydrogen production tax credit (IRC section 45V) (see 88 FR 89220, December 26, 2023). In light of these nascent but fast-moving efforts, the EPA does not believe it is reasonable or helpful to prescribe its own definitions, protocols, and requirements for low-GHG hydrogen at this point in time. 
Furthermore, the Agency anticipates 
that combustion turbines will, despite not being required to do so, use low- GHG hydrogen (to the extent they are co-firing hydrogen as a compliance strategy). Depending on market development in the coming decade, it is reasonable to expect that any hydrogen used in the power sector would generally be low-GHG hydrogen, even without a specific BSER pathway or low-GHG-only requirement included in this final NSPS. For example, several utilities with dedicated access to affordable low-GHG hydrogen are actively developing co-firing projects with the goal of reducing their GHG 
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856Mitsubishi Power. (2020). Intermountain 
Power Agency Orders MHPS JAC Gas Turbine 
Technology for Renewable-Hydrogen Energy Hub. https://power.mhi.com/regions/amer/news/ 200310.html. 
857Intermountain Power Agency (2022). https://
www.ipautah.com/ipp-renewed/. 
858Los Angeles Department of Water & Power 
(2023). Initial Study: Scattergood Generating Station Units 1 and 2 Green Hydrogen-Ready Modernization Project. https://ceqanet.opr.ca.gov/ 2023050366. 
859https://clkrep.lacity.org/onlinedocs/2023/23- 
0039_ rpt_DWP_ 02-03-2023.pdf. 
860Hering, G. (2021). First major US hydrogen- 
burning power plant nears completion in Ohio. S&P Global Market Intelligence. https://www.spglobal.com/platts/en/market-insights/latest- news/electric-power/081221-first-major-us- hydrogen-burning-power-plant-nears-completion- in-ohio. 861U.S. Department of Energy (DOE). (September 
22, 2022). Clean Hydrogen Production Standard. Hydrogen and Fuel Cell Technologies Office. https://www.energy.gov/eere/fuelcells/articles/ clean-hydrogen-production-standard. 
862These tax credits include IRC section 45V (tax 
credit for production of hydrogen through low- or zero-emitting processes), IRC section 48 (tax credit for investment in energy storage property, including hydrogen production), IRC section 45Q (tax credit for CO
2sequestration from industrial processes, 
including hydrogen production); and the use of hydrogen in transportation applications, IRC section 45Z (clean fuel production tax credit), IRC section 40B (sustainable aviation fuel credit). emissions. The infrastructure funding 
and tax incentives included in the IIJA and the IRA are also driving the development of the low-GHG hydrogen supply chain. These rapid changes in the hydrogen marketplace not only counsel against the EPA’s locking in its own requirements at this time; they also provide confidence that greater quantities of low-GHG hydrogen will be available moving forward, even if the precise timing and quantity cannot currently be accurately forecast. The EPA also provides information further below about its intentions to open a non-regulatory docket to engage stakeholders on potential future rulemakings for thermochemical-based hydrogen production facilities to address issues pertaining to GHG, criteria, and HAP emissions. 
i. Hydrogen Production and Associated 
GHGs 
Hydrogen is used in industrial 
processes; in recent years, applications of hydrogen co-firing have also expanded to include stationary combustion turbines used to generate electricity. Several commenters responded to the proposal by stating that to fully evaluate the potential GHG emission reductions from co-firing low- GHG hydrogen in a combustion turbine EGU, it is important to consider the different processes for producing hydrogen and the GHG emissions associated with each process. The EPA agrees that the method of hydrogen production is critical to consider when assessing whether hydrogen co-firing actually reduces overall GHG emissions. As stated previously, the varying levels of CO
2emissions associated with 
different hydrogen production processes 
are well-recognized, and stakeholders routinely refer to hydrogen on the basis of the different production processes and their different GHG profiles. 
ii. Technological and Market 
Transformation of Low-GHG Hydrogen Resources 
In the proposal, the EPA highlighted 
ongoing efforts—independent of any BSER pathway, requirement, or performance standard—of combustion turbine manufacturers and industry stakeholders to research, develop, and deploy hydrogen co-firing technologies (88 FR 33307, May 23, 2023). Their co- firing demonstrations are producing results, such as increasing the percentages (by volume) of hydrogen that a turbine can combust while answering questions regarding safety, performance, reliability, durability, and the emission of other pollutants (e.g., NO
X). Such efforts by industry to invest in the development of hydrogen co- 
firing, and specifically in projects designed to co-fire low-GHG hydrogen, in particular, give the EPA confidence that any hydrogen that sources do choose to co-fire for compliance under this rule will be low-GHG hydrogen. As these efforts progress, a sharper understanding of costs will come into focus while significant Federal funding—through grants, financial assistance programs, and tax incentives included in the IIJA and the IRA discussed below—is intended to support the continued development of a nationwide clean hydrogen supply chain. 
For the most part, companies that 
have announced that they are exploring the use of hydrogen co-firing have stated that they intend to use low-GHG hydrogen in the future as greater quantities of the fuel become available at lower, stabilized prices. Many utilities and merchant generators own and are developing low-GHG electricity generating sources as well as combustion turbines, with the intent to produce low-GHG hydrogen for sale and to use a portion of it to fuel their stationary combustion turbines.
856 857  
This emerging trend lends support to the view that, while acknowledging the uncertainty of the ultimate timing of implementation, there is growing interest in hydrogen co-firing in the power sector and stakeholders are developing these resources with the intent to increase access to low-GHG hydrogen as they increase hydrogen 
utilization in their co-firing applications. Additional information provided by commenters and analysis by the EPA identified several new combustion turbine projects planning to co-fire low-GHG hydrogen, even though these low-GHG methods of hydrogen production are not currently readily available on a nationwide basis.
858 859 860  iii. Infrastructure Funding and Tax 
Incentives Included in the IIJA and IRA 
In both the IIJA and the IRA, Congress 
provided extensive support for the development of hydrogen produced through low-GHG methods. This support includes investment in infrastructure through the IIJA, and the provision of tax credits in the IRA to incentivize the manufacture of hydrogen through low GHG-emitting methods over the coming decades. For example, the IIJA included the H2Hubs program, the Clean Hydrogen Manufacturing and Recycling Program, the Clean Hydrogen Electrolysis Program, and a non- regulatory Clean Hydrogen Production Standard (CHPS).
861In the IRA, 
Congress enacted or expanded tax credits to encourage the production and use of low-GHG hydrogen.
862In 
addition, as discussed in the proposal, IRA section 60107 added new CAA section 135, or the Low Emission Electricity Program (LEEP). This provision provides $1 million for the EPA to assess the GHG emissions reductions from changes in domestic electricity generation and use anticipated to occur annually through fiscal year 2031; and further provides 
$18 million for the EPA to promulgate additional CAA rules to ensure GHG emissions reductions that go beyond the reductions expected in that assessment. CAA section 135(a)(5)–(6). 
Given the incentives provided in both 
the IRA and IIJA for low-GHG hydrogen production and the current trajectory of hydrogen use in the power sector, by 2032, the start date for compliance with the proposed second phase of the NSPS, low-GHG hydrogen may be more widely available and possibly the most common source of hydrogen available for electricity production. It is also possible that the cost of delivered low- GHG hydrogen will continue to decline toward the DOE’s Hydrogen Shot target. These expectations are based on a combination of economies of scale as low-GHG production methods expand, the increasing availability of low-cost input electricity—largely powered by zero- or low-emitting energy sources— 
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863Petition for Rulemaking to List and Establish 
National Emission Standards for Hydrogen 
Production Facilities under the Clean Air Act Sections 111 and 112. The petition can be accessed at https://www.edf.org/sites/default/files/2023-09/ 
Petition%20for%20Rulemaking%20- %20Hydrogen%20Production%20Facilities%20- %20CAA%20111%20and%20112%20- %20EDF%20et%20al.pdf. 
864Id. and learning by doing as more 
combustion turbine projects are developed. The EPA recognizes that the pace and scale of government programs and private research suggest that the Agency will gain significant experience and knowledge on this topic in the future. 
iv. EPA Non-Regulatory Docket and 
Stakeholder Engagement on Potential Regulatory Approaches for Emissions From Thermochemical Hydrogen Production 
In addition to the ongoing industry 
development of and Congressional support for low-GHG hydrogen, the EPA is also taking steps consistent with the importance of mitigating GHG emissions associated with hydrogen production. On September 15, 2023, the EPA received a petition from the Environmental Defense Fund (EDF) along with 13 other health, environmental, and community groups, to regulate fossil and other thermochemical methods of hydrogen production given the current emissions from these facilities and the anticipated growth in the sector spurred by IRA incentives. The petition notes that facilities producing hydrogen for sale produced about 10 MMT of hydrogen and emitted more than 40 MMT of CO
2e 
in 2020.863Regulatory safeguards are 
advocated by petitioners to help ensure that the anticipated growth in this sector does not result in an unbounded increase in emissions of GHGs, criteria, and hazardous air pollutants (HAP). The petition requests that the EPA list hydrogen production facilities as significant sources of pollution under CAA sections 111 and 112, and that the EPA develop both standards of performance for new and modified hydrogen production facilities as well as emission guidelines for existing facilities. The development of emission standards for HAP, including but not limited to methanol, was also requested by petitioners. Petitioners assert that emissions of CO
2, NO X, and PM should 
be addressed under the EPA’s section 111 authorities, and HAP should be addressed by EPA regulations under section 112.
864The EPA is reviewing 
the petition. As a predicate to potential future rulemakings, the Agency is developing a set of framing questions 
and opening a non-regulatory docket to solicit public comment on potential approaches for regulation of GHGs and criteria pollutants under CAA section 111 and an exploration of the appropriateness of regulating HAP emissions under CAA section 112 and on potential section 114 reporting requirements to address this growing industry. 
b. Definition of Low-GHG Hydrogen 
The EPA proposed to define low-GHG 
hydrogen as hydrogen produced with 
emissions of less than 0.45 kg CO
2e/kg 
H2, from well-to-gate, which aligned 
with the highest of the four tiers of tax credits available for hydrogen production, IRC section 45V(b)(2)(D). At that GHG emission rate or less, hydrogen producers are eligible for a tax credit of $3/kg. With these provisions, Congress indicated its judgement as to what GHG levels could be attained by the lowest-GHG hydrogen production, and its intention to incentivize production of that type of hydrogen. Congress’s views informed the EPA’s proposal to define low-GHG hydrogen for purposes of making the BSER for this CAA section 111 rulemaking consistent with IRC section 45V(b)(2)(D). 
The EPA solicited comment broadly 
on its proposed definition for low-GHG hydrogen, and on alternative approaches, to help develop reporting and recordkeeping requirements that would have ensured that co-firing low- GHG hydrogen minimized GHG emissions, and that combustion turbines subject to this standard utilized only low-GHG hydrogen. The EPA also solicited comment on whether it was 
necessary to provide a definition of low- GHG hydrogen in this final rule. 
The EPA is not finalizing a definition 
of low-GHG hydrogen in this action. Because the Agency is not finalizing co- firing with low-GHG hydrogen as a component of the BSER for certain combustion turbines and is not finalizing a requirement that any hydrogen co-fired for compliance by low-GHG hydrogen, there is no reason to finalize a definition of low-GHG hydrogen at this time. 
7. Other Options for BSER 
The EPA considered several other 
systems of emission reduction as 
candidates for the BSER for combustion turbines but is not determining them to be the BSER. They include partial capture CCS, CHP and the hybrid power plant, as discussed below. a. Partial Capture CCS 
Partial capture for CCS was not 
determined to be BSER because the 
emission reductions are lower and the costs would, in general, be higher. As discussed in section IV, individual natural gas-fired combined cycle combustion turbines are the second highest-emitting individual plants in the nation, and the natural gas-fired power plant sector is higher-emitting than all other sectors. CCS at 90 percent capture removes very high absolute amounts of emissions. Partial capture CCS would fail to capture large quantities of emissions. With respect to costs, designs for 90 percent capture in general take greater advantage of economy of scale. Eligibility for the IRC section 45Q tax credit for existing EGUs requires design capture rates equivalent to 75 percent of a baseline emission rate by mass. Sources with partial capture rates that do not meet that requirement would not be eligible for the tax credit and as a result, for them, the CCS requirement would be too expensive to qualify for as the BSER. Even assuming partial capture rates meet that definition, lower capture rates would receive fewer returns from the IRC section 45Q tax credit (since these are tied to the amount of carbon sequestered, and all else equal lower capture rates would result in lower amounts of sequestered carbon) and costs would thereby be higher. 
b. Combined Heat and Power (CHP) 
CHP, also known as cogeneration, is 
the simultaneous production of 
electricity and/or mechanical energy and useful thermal output from a single fuel. CHP requires less fuel to produce a given energy output, and because less fuel is burned to produce each unit of energy output, CHP has lower-emission rates and can be more economic than separate electric and thermal generation. However, a critical requirement for a CHP facility is that it primarily generates thermal output and generates electricity as a byproduct and must therefore be physically close to a thermal host that can consistently accept the useful thermal output. It can be particularly difficult to locate a thermal host with sufficiently large thermal demands such that the useful thermal output would impact the emissions rate. The refining, chemical manufacturing, pulp and paper, food processing, and district energy systems tend to have large thermal demands. However, the thermal demand at these facilities is generally only sufficient to support a smaller EGU, approximately a maximum of several hundred MW. This 
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865EIA, Annual Energy Outlook 2018, February 6, 
2018. https://www.eia.gov/outlooks/aeo/. 
866B. Alqahtani and D. Patin ˜o-Echeverri, Duke 
University, Nicholas School of the Environment, 
‘‘Integrated Solar Combined Cycle Power Plants: Paving the Way for Thermal Solar,’’ Applied Energy 169:927–936 (2016). would limit the geographically available 
locations where new generation could be constructed in addition to limiting its size. Furthermore, even if a sufficiently large thermal host were in close proximity, the owner/operator of the EGU would be required to rely on the continued operation of the thermal host for the life of the EGU. If the thermal host were to shut down, the EGU could be unable to comply with the standard of performance. This reality would likely result in difficulty in securing funding for the construction of the EGU and could also lead the thermal host to demand discount pricing for the delivered useful thermal output. For these reasons, the EPA did not propose CHP as the BSER. 
c. Hybrid Power Plant 
Hybrid power plants combine two or 
more forms of energy input into a single 
facility with an integrated mix of complementary generation methods. While there are multiple types of hybrid power plants, the most relevant type for this proposal is the integration of solar energy (e.g., concentrating solar 
thermal) with a fossil fuel-fired EGU. Both coal-fired and combined cycle turbine EGUs have operated using the integration of concentrating solar thermal energy for use in boiler feed water heating, preheating makeup water, and/or producing steam for use in the steam turbine or to power the boiler feed pumps. 
One of the benefits of integrating solar 
thermal with a fossil fuel-fired EGU is the lower capital and operation and maintenance (O&M) costs of the solar thermal technology. This is due to the ability to use equipment (e.g., HRSG, 
steam turbine, condenser, etc.) already included at the fossil fuel-fired EGU. Another advantage is the improved electrical generation efficiency of the non-emitting generation. For example, solar thermal often produces steam at relatively low temperatures and pressures, and the conversion of the thermal energy in the steam to electricity is relatively low efficiency. In a hybrid power plant, the lower quality steam is heated to higher temperatures and pressures in the boiler (or HRSG) 
prior to expansion in the steam turbine, where it produces electricity. Upgrading the relatively low-grade steam produced by the solar thermal facility in the boiler improves the relative conversion efficiencies of the solar thermal to electricity process. The primary incremental costs of the non-emitting generation in a hybrid power plant are the costs of the mirrors, additional piping, and a steam turbine that is 10 to 20 percent larger than that in a comparable fossil-only EGU to 
accommodate the additional steam load during sunny hours. A drawback of integrating solar thermal is that the larger steam turbine will operate at part loads and reduced efficiency when no steam is provided from the solar thermal panels (i.e., the night and cloudy 
weather). This limits the amount of solar thermal that can be integrated into the steam cycle at a fossil fuel-fired EGU. 
In the 2018 Annual Energy 
Outlook,
865the levelized cost of 
concentrated solar power (CSP) without transmission costs or tax credits is $161/ MWh. Integrating solar thermal into a fossil fuel-fired EGU reduces the capital cost and O&M expenses of the CSP portion by 25 and 67 percent compared to a stand-alone CSP EGU respectively.
866This results in an 
effective LCOE for the integrated CSP of $104/MWh. Assuming the integrated CSP is sized to provide 10 percent of the maximum steam turbine output and the relative capacity factors of a combined cycle turbine and the CSP (those capacity factors are 65 and 25 percent, respectively) the overall annual generation due to the concentrating solar thermal would be 3 percent of the hybrid EGU output. This would result in a 3 percent reduction in the overall CO
2emissions and a 1 percent increase 
in the LCOE, without accounting for any reduction in the steam turbine efficiency. However, these costs do not account for potential reductions in the steam turbine efficiency due to being oversized relative to a non-hybrid EGU. A 2011 technical report by the National Renewable Energy Laboratory (NREL) cited analyses indicating that solar augmentation of fossil power stations is not cost-effective, although likely less expensive and containing less project risk than a stand-alone solar thermal plant. Similarly, while commenters stated that solar augmentation has been successfully integrated at coal-fired 
plants to improve overall unit efficiency, commenters did not provide any new information on costs or indicate that such augmentation is cost- effective. 
In addition, solar thermal facilities 
require locations with abundant sunshine and significant land area in order to collect the thermal energy. Existing concentrated solar power projects in the U.S. are primarily located in California, Arizona, and Nevada with 
smaller projects in Florida, Hawaii, Utah, and Colorado. NREL’s 2011 technical report on the solar-augment potential of fossil-fired power plants examined regions of the U.S. with ‘‘good solar resource as defined by their direct normal insolation (DNI)’’ and identified sixteen states as meeting that criterion: Alabama, Arizona, California, Colorado, Florida, Georgia, Louisiana, Mississippi, Nevada, New Mexico, North Carolina, Oklahoma, South Carolina, Tennessee, Texas, and Utah. The technical report explained that annual average DNI has a significant effect on the performance of a solar-augmented fossil plant, with higher average DNI translating into the ability of a hybrid power plant to produce more steam for augmenting the plant. The technical report used a points-based system and assigned the most points for high solar resource values. An examination of a NREL- generated DNI map of the U.S. reveals that states with the highest DNI values are located in the southwestern U.S., with only portions of Arizona, California, Nevada, New Mexico, and Texas (plus Hawaii) having solar resources that would have been assigned the highest points by the NREL technical report (7 kWh/m2/day or greater). 
Commenters supported not 
incorporating hybrid power plants as part of the BSER, and the EPA is not including hybrid power plants as part of the BSER because of gaps in the EPA’s knowledge about costs, and concerns about the cost-effectiveness of the technology, as noted above. 
G. Standards of Performance 
Once the EPA has determined that a 
particular system or technology 
represents BSER, the CAA authorizes the Administrator to establish standards of performance for new units that reflect the degree of emission limitation achievable through the application of that BSER. As noted above, the EPA is finalizing a two-phase set of standards of performance, which reflect a two- component BSER, for base load combustion turbines. Under this approach, for the first phase of the 
standards, which applies as of the effective date the final rule, the BSER is highly efficient generation and best operating and maintenance practices. During this phase, owners/operators of EGUs will be subject to a numeric standard of performance that is representative of the performance of the best performing EGUs in the subcategory. For the second phase of the standards, beginning in 2035, the BSER for base load turbines includes 90 
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867As proposed, a new small natural gas-fired 
base load EGU would determine the facility 
emissions rate by taking the difference in the base load rating and 250 MMBtu/h, multiplying that number by 0.0743 lb CO
2/(MW * MMBtu), and 
subtracting that number from 900 lb CO 2/MWh- 
gross. The emissions rate for a natural gas-fired base load combustion turbine with a base load rating of 1,000 MMBtu/h is 900 lb CO
2/MWh-gross minus 
750 MMBtu/h (1,000 MMBtu/h–250 MMBtu/h) times 0.0743 lb CO
2/(MW * MMBtu), which results 
in an emissions rate of 844 lb CO 2/MWh-gross. 868The heat input-based emission rates of natural 
gas and distillate oil are 117 and 163 lb CO 2/ 
MMBtu, respectively. The ratio of the heat input- based emission rates (1.39) is multiplied by the natural gas-fired standard of performance (770 lb CO
2/MWh) to get the applicable emissions rate 
(1,070 lb CO 2/MWh). 869As the efficiency of the combustion turbine 
engine is reduced at higher ambient temperatures 
relatively more heat is in the exhaust entering the HRSG. This can increase the output from the steam turbine. percent capture CCS. The affected EGUs 
will be subject to an emissions rate that reflects continued use of highly efficient generation and best operating and maintenance practices, coupled with CCS. In addition, the EPA is finalizing a single component BSER, applicable from May 23, 2023, for low and intermediate load combustion turbines. 
1. Phase-1 Standards 
The first component of the BSER is 
the use of highly efficient combined 
cycle technology for base load EGUs in combination with the best operating and maintenance practices, the use of highly efficient simple cycle technology in combination with the best operating and maintenance practices for intermediate load EGUs, and the use of lower- emitting fuels for low load EGUs. 
The EPA proposed that for base load 
combustion turbines, the first- component BSER supports a standard of 
770 lb CO
2/MWh-gross for large natural 
gas-fired EGUs, i.e., those with a base 
load rating heat input greater than 2,000 MMBtu/h; 900 lb CO
2/MWh-gross for 
small natural gas-fired EGUs, i.e., those 
with a base load rating of 250 MMBtu/ h; and between 900 and 770 lb CO
2/ 
MWh-gross, based on the base load rating of the EGU, for natural gas-fired EGUs with base load ratings between 250 MMBtu/h and 2,000 MMBtu/h.
867 
The EPA proposed that the most efficient available simple cycle technology—which qualifies as the BSER for intermediate load combustion turbines—supports a standard of 1,150 lb CO
2/MWh-gross for natural gas-fired 
EGUs. For new and reconstructed low load combustion turbines, the EPA proposed to find that the use of lower- emitting fuels—which qualifies as the BSER—supports a standard that ranges from 120 lb CO
2/MMBtu to 160 lb CO 2/ 
MMBtu depending on the fuel burned. The EPA proposed these standards to apply at all times and compliance to be determined on a 12-operating month rolling average basis. 
The EPA proposed that these 
standards of performance are achievable specifically for natural gas-fired base load and intermediate load combustion turbine EGUs. However, combustion turbine EGUs burn a variety of fuels, including fuel oil during natural gas 
curtailments. Owners/operators of combustion turbines burning fuels other than natural gas would not necessarily be able to comply with the proposed standards for base load and intermediate load natural gas-fired combustion turbines using highly efficient generation. Therefore, the Agency proposed that owners/operators of combustion turbines burning fuels other than natural gas may elect to use the ratio of the heat input-based emissions rate of the specific fuel(s) burned to the heat input-based emissions rate of natural gas to determine a source- specific standard of performance for the operating period. For example, the NSPS emissions rate for a large base load combustion turbine burning 100 percent distillate oil during the 12- operating month period would be 1,070 lb CO
2/MWh-gross.868 
Some commenters stated that the 
proposed base load emissions standard based on highly efficient generation is not adequately demonstrated, and that site conditions and certain operating parameters are outside of the control of the owner/operator. These commenters explained that the emissions rate of a combustion turbine is dependent on external and site-specific factors, rather than the design efficiency. Factors such as warmer climates, elevation, water conservation measures (e.g., the use of 
dry cooling), and automatic generation control negatively impacted efficiency. They emphasized that operating units at partial loads would be necessary for maintaining grid reliability, especially as more renewables are incorporated, and the proposed limit is only achievable under ideal operating conditions. Commenters noted that the emission standards should account for start and stop cycles, back-up fuel use, degradation, and compliance tolerance. Commenters stated that the lack of 
flexibility would force units to operate at nameplate capacity, even when it was unnecessary and could result in increased emissions. In addition, some commenters stated that duct burners could be an alternative to simple cycle turbines for peaking generation, even though they were less efficient than combined cycle turbines without duct burners. They recommended the Agency consider excluding emissions and heat input from duct burners from the emissions standard. Furthermore, commenters noted multiple units that 
the EPA used in the analysis to support the proposed base load standards were permitted near or above 800 lb CO
2/ 
MWh. Commenters stated that the original equipment manufacturer would not be able to provide a warranty that the proposed 12-month rolling emissions rate is achievable due to the varying operating conditions. Commenters recommended the EPA raise the emissions standard to 850 or 900 lb CO
2/MWh-gross for large base 
load combustion turbines. In addition, commenters suggested that the EPA incorporate scaling for smaller units to 1,100 lb CO
2/MWh-gross, and the 
beginning of the sliding scale should be at least 2,500 MMBtu/h. 
a. Base Load Phase-1 Emission 
Standards 
Considering the public comments, the 
EPA re-evaluated the phase-1 standard of performance for base load combustion turbines. To determine the impact of duty cycle and temperature, the EPA binned hourly data by load and season. This allowed the Agency to isolate the impact of ambient temperature and duty cycle separately. The EPA evaluated the impact of ambient temperature by comparing the average emissions for all hours between 70 to 80 percent load during different seasons. For the combined cycle turbines evaluated, the difference between the summer and winter average emission rates was minimal, typically in the single digits and less than a 1 percent difference in emission rates. Since the seasonal temperature differences are much larger than regional variations, the EPA determined that regional ambient temperature has minimal impact on the emissions rate of combined cycle EGUs. Owners/ operators of combined cycle EGUs are either using inlet cooling effectively to manage the efficiency losses of the combustion turbine engine or increased generation from the Rankine cycle portion (i.e., HRSG and steam turbine) 
of the combined cycle turbine is offsetting efficiency losses in the combustion turbine engine.
869In 
addition, the variation in emissions rate by load (described below) is much larger than temperature and therefore the operating load is a more important factor than ambient temperature impacting CO
2emission rates. 
Based on the emissions data 
submitted to the EPA, combined cycle 
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870Generating electricity closer to electricity 
demand can reduce stress on the electric grid, 
reducing line losses and freeing up transmission capacity to support additional generation from variable renewable sources. Further, combined cycle EGUs located in urban areas could be designed as CHP EGUs, which have potential environmental and economic benefits. 
871Power sector modeling projects that combined 
cycle EGUs will operate at lower capacity factors in the future. Combined cycle EGUs with lower base load efficiencies but higher part load efficiencies could have lower overall emission rates. 
872According to the data in Gas Turbine World 
2021, while there is a design efficiency advantage of going from a 1-on-1 configuration to a 2-on-1 configuration (assuming the same turbine engine), there is no efficiency advantage of 3-on-1 configurations compared to 2-on-1 configurations. CO 2emission are lowest at between 
approximately 80 to 90 percent load. 
Emission rates are relatively stable at higher loads and down to approximately 70 percent load—typically 1 or 2 percent higher than the lowest emissions rate. Emissions can increase dramatically at lower loads and could impact the ability of an owner/operator to comply with the base load standard. The EPA considered two approaches to address potential compliance issues for owners/operators of base load combustion turbines operating at lower duty cycles. The first approach was to calculate emission rates using only hourly data when the combined cycle turbine was operating at an hourly load of 70 percent or higher. However, this has minimal impact on the calculated base load emissions rate. This is because of 2 reasons. First, the majority of operating hours for base load combustion turbines are at 70 percent load or higher. In addition, the 12- operating month averages are determined by the overall sum of the CO
2emissions divided by the overall 
output during the 12-operating month period and not the average of the individual hourly rates. The impact of this approach is that low load hours have smaller impacts on the 12- operating month average relative to high load hours. Therefore, the EPA determined that using only higher load hours to determine the base load emission rates would not address potential issues for owners/operators of base load combustion turbines operating at relative low duty cycles (i.e., low 
hourly capacity factors). 
The second approach the EPA 
considered, and is finalizing, is estimating the emissions rate of combined cycle turbines at the lower end of the base load threshold—where more hours of low load operation could potentially be included in the 12- operating month average—and establishing a standard of performance that is achievable at lower percent of potential electric sales for the base load subcategory. To determine what emission rates are currently achieved by existing high-efficiency combined cycle EGUs, the EPA reviewed 12-operating month generation and CO
2emissions 
data from 2015 through 2023 for all combined cycle turbines that submitted continuous emissions monitoring system (CEMS) data to the EPA’s emissions collection and monitoring plan system (ECMPS). The data were sorted by the lowest maximum 12- operating month emissions rate for each unit to identify long-term emission rates on a lb CO
2/MWh-gross basis that have been demonstrated by the existing 
combined cycle EGU fleets. Since an NSPS is a never-to-exceed standard, the EPA proposed and is finalizing a conclusion that use of long-term data are more appropriate than shorter term data in determining an achievable standard. These long-term averages account for degradation and variable operating conditions, and the EGUs should be able to maintain their current emission rates, as long as the units are properly maintained. While annual emission rates indicate a particular standard is achievable for certain EGUs in the short term, they are not necessarily representative of emission rates that can be maintained over an extended period using highly efficient generating technology in combination with best operating and maintenance practices. 
To determine the 12-operating month 
average emissions rate that is achievable by application of the BSER, the EPA proposed and is finalizing an approach to calculating 12-month CO
2emission 
rates by dividing the sum of the CO 2 
emissions by the sum of the gross electrical energy output over the same period. The EPA did this separately for combined cycle EGUs and simple cycle EGUs to determine the emissions rate for the base load and intermediate load subcategories, respectively. Commenters generally supported the 12-month rolling average for emission standard compliance. 
The average maximum 12-operating 
month base load emissions rate for large combined cycle turbines that began operation since 2015 is 810 lb CO
2/ 
MWh-gross. The range of the maximum 12-operating month emissions rate for individual units is 720 to 920 lb CO
2/ 
MWh-gross. The lowest emissions rate was achieved by an individual unit at the Okeechobee Clean Energy Center. This facility is a large 3-on-1 combined cycle EGU that commenced operation in 2019 and uses a recirculating cooling tower for the steam cycle. Each turbine is rated at 380 MW and the three HRSGs feed a single steam turbine of 550 MW. The EPA did not propose to use the emissions rate of this EGU to determine the standard of performance for multiple reasons. The Okeechobee Clean Energy Center uses a 3-on-1 multi-shaft configuration but, many combined cycle EGUs use a 1-on-1 configuration. Combined cycle EGUs using a 1-on-1 configuration can be designed such that both the combustion turbine and steam turbine are arranged on one shaft and drive the same generator. This configuration has 
potential capital cost and maintenance costs savings and a smaller plant footprint that can be particularly 
important for combustion turbines enclosed in a building. In addition, a single shaft configuration has higher net efficiencies when operated at part load than a multi-shaft configuration. Basing the standard of performance strictly on the performance of multi-shaft combined cycle EGUs could limit the ability of owners/operators to construct new combined cycle EGUs in space- constrained areas (typically urban areas
870) and combined cycle EGUs 
with the best performance when operated as intermediate load EGUs.
871 
Either of these outcomes could result in greater overall emissions from the power sector. An advantage of multi- shaft configurations is that the turbine engine can be installed initially and run as a simple cycle EGU, with the HRSG and steam turbines added at a later date, all of which allows for more flexibility for the regulated community. In addition, a single large steam turbine in a 2–1 or 3–1 configuration can generate electricity more efficiently than multiple smaller steam turbines, 
increasing the overall efficiency of comparably sized combined cycle EGUs. According to Gas Turbine World 2021, multi-shaft combined cycle EGUs have design efficiencies that are 0.7 percent higher than single shaft combined cycle EGUs using the same turbine engine.
872 
The efficiency of the Rankine cycle 
(i.e., HRSG plus the steam turbine) is 
determined in part by the ability to cool the working fluid (e.g., steam) after it 
has been expanded through the turbine. All else equal, the lower the temperature that can be achieved, the more efficient the Rankine cycle. The Okeechobee Clean Energy Center used a recirculating cooling system, which can achieve lower temperatures than EGUs using dry cooling systems and therefore would be more efficient and have a lower emissions rate. However dry cooling systems have lower water requirements and therefore could be the preferred technology in arid regions or 
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873A similar normalization approach was used by 
the EPA in previous EGU GHG NSPS rulemakings 
to benchmark the performance of coal-fired EGUs when determining an achievable efficiency-based standard of performance. 874The most efficient combined cycle turbines 
tend to operate strictly as base load combustion 
turbines, well above the base load subcategorization threshold. 
875The Dresden Energy Facility is listed as being 
located in Muskingum County, Ohio, as being owned by the Appalachian Power Company, as having commenced commercial operation in late 2011. The facility ID (ORISPL) is 55350 1A and 1B. 876The Holland Park Energy Center is a CHP 
system that uses hot water in the cooling system for a snow melt system that uses a warm water piping system to heat the downtown sidewalks to clear the snow during the winter. Since this useful thermal output is low temperature, it likely only results in a small reduction of the electrical efficiency of the EGU. If the useful thermal output were accounted for, the emissions rate of the Holland Energy Park would be lower. The facility ID (ORISPL) is 59093 10 and 11. 
877If the combustion turbine engine exhaust 
temperature is 500 °C or greater, a HRSG using 3 pressure steam without a reheat cycle could potentially provide an even greater increase in efficiency (relative to a HRSG using 2 pressure steam without a reheat cycle). 
878To estimate an achievable emissions rate for 
an efficient combined cycle EGU at 250 MMBtu/h 
Continued in areas where water requirements 
could have significant ecological impacts. Therefore, the EPA proposed and is finalizing that the efficient generation standard for base load EGUs should account for the use of cooling technologies with reduced water requirements. 
Finally, the Okeechobee Clean Energy 
Center operates primarily at high duty cycles where efficiency is the highest and since it is a relatively new facility efficiency degradation might not be accounted for in the emissions analysis. Therefore, the EPA is not determining that the performance of the Okeechobee Clean Energy Facility is appropriate for a nationwide standard. 
The proposed emissions rate of 770 lb 
CO
2/MWh-gross has been demonstrated 
by approximately 15 percent of recently constructed large combined cycle EGUs. As noted in the proposal, these combustion turbines include combined cycle EGUs using 1-on-1 configurations, dry cooling, and combustion turbines on the lower end of the large base load subcategory. In addition, this emissions rate has been demonstrated by using combustion turbines from multiple manufacturers and from one facility that commenced operation in 2011— demonstrating the long-term achievability of the proposed emissions standard. However, as noted by commenters the majority of recently constructed combined cycle turbines are not achieving an emissions rate of 770 lb CO
2/MWh-gross and combustion 
turbine manufacturers might not be willing to guarantee this emissions level in operating making it challenging to build a new combined cycle EGU. 
To account for differences in the 
performance of the best performing combustion turbines and design options that result in less efficient operation, the EPA normalized the reported emission rates for combined cycle EGUs.
873 
Specifically, for the reported emissions rates of combined cycle turbines with cooling towers was increased by 1.0 percent to account for potential new units using dry cooling. Similarly, the emissions rate of 2–1 and 3–1 combined cycle turbines were increased by 1.4 percent to account for potential new units using a 1–1 configuration. In addition, for the best performing combined cycle turbines, the EPA plotted the 12-operating month emissions rate against the 12-operating month heat input-based capacity factor. Based on this data, the EPA used the trend in increasing emission rates at 
lower 12-operating month capacity factors to estimate the emissions rate at capacity factors at which an individual facility has never operated. This approach allowed the EPA to estimate the emissions rate at a 40 percent 12- operating month capacity factor for the best performing combined cycle turbines. This allows the estimation of the emissions rate at the lower end of the base load subcategory using higher capacity factor data.
874The EPA did not 
correct the achievable emissions rate for combined cycle turbines where the relationship indicated emission rates declined at lower 12-operating month capacity factors. 
As noted in the proposal, one of the 
best performing large combined cycle EGUs that has maintained a 12- operating-month base load emissions rate of 770 lb CO
2/MWh-gross is the 
Dresden plant, located in Ohio.875This 
2-on-1 combined cycle facility uses a recirculating cooling tower. The turbine engines are rated at 2,250 MMBtu/h, which demonstrates that the standard of performance for large base load combustion turbines is achievable at a 
heat input rating of 2,000 MMBtu/h. As noted, a 2-on-1 configuration and a cooling tower are more efficient than a 1-on-1 configuration and dry cooling. Normalizing for these factors and accounting for operation at a 12- operating month capacity factor of 40 percent increases the achievable demonstrated emissions rate to 800 lb CO
2/MWh-gross. However, the Dresden 
Energy Facility does not use the most efficient combined cycle design currently available. Multiple more efficient designs have been developed since the Dresden Energy Facility commenced operation a decade ago that more than offset these efficiency losses. Therefore, the EPA has determined that the Dresden combined cycle EGU demonstrates that an emissions rate of 800 lb CO
2/MWh-gross is achievable for 
all new large combined cycle EGUs with an acceptable compliance margin. Therefore, the EPA is finalizing a phase 1 standard of performance of 800 lb CO
2/MWh-gross for large base load 
combustion turbines (i.e., those with a 
base load rating heat input greater than 2,000 MMBtu/h) based on the BSER of highly efficient combined cycle 
technology. 
With respect to small combined cycle 
combustion turbines, the best 
performing unit identified by the EPA is the Holland Energy Park facility in Holland, Michigan, which commenced operation in 2017 and uses a 2-on-1 configuration and a cooling tower.
876 
The 50 MW turbine engines have individual heat input ratings of 590 MMBtu/h and serve a single 45 MW steam turbine. The facility has maintained a 12-operating month, 99 percent confidence emissions rate of 870 lb CO
2/MWh-gross. The emissions 
standard for a base load combustion turbine of this size is 880 lb CO
2/MWh- 
gross. The normalized emissions rate accounting for the use of recirculating cooling towers, a 2–1 configuration, and operation at a 40 percent capacity factor is 900 lb CO
2/MWh-gross. While this is 
higher than the final emissions standard in this rule, there are efficient generation technologies that are not being used at the Holland Energy Park. For example, a commercially available HRSG that uses supercritical CO
2 
instead of steam as the working fluid is available. This HRSG would be significantly more efficient than the HRSG that uses dual pressure steam, which is common for small combined cycle EGUs.
877When these efficiency 
improvements are accounted for, a similar combined cycle EGU would be able to maintain an emissions rate of 880 lb CO
2/MWh-gross. In addition, the 
normalization approach assumes a worst-case scenario. Hybrid cooling technologies are available and offer performance similar to that of wet cooling towers. This long-term data accounts for degradation and variable operating conditions and demonstrates that a base load combustion turbine EGU with a turbine rated at 590 MMBtu/h should be able to maintain an emissions rate of 880 lb CO
2/MWh- 
gross.878Therefore, estimating that 
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the EPA assumed a linear relationship for combined 
cycle efficiency with turbine engines with base load ratings of less than 2,000 MMBtu/h. 879The 89 percent reduction from CCS accounts 
for the increased auxiliary load of a 90 percent post combustion amine-based capture system. Due to rounding, the proposed numeric standards of performance do not necessarily match the standards that would be determined by applying the percent reduction to the phase-1 standards. emission rates will be slightly higher for 
smaller combustion turbines, the EPA is finalizing a phase 1 standard of performance of 900 lb CO
2/MWh-gross 
for small base load combustion turbines (i.e., those with a base load rating of 250 
MMBtu/h) based on the BSER of highly efficient combined cycle technology. 
b. Intermediate Load Emission 
Standards 
For the intermediate load standards of 
performance, some commenters stated that an emissions standard of 1,150 lb CO
2/MWh-gross is only achievable for 
simple cycle except under ideal operating conditions. Since the emissions standard is not achievable in practice, these commenters stated that the majority of new simple cycle turbines would be prevented from operating as variable or intermediate load units. Similar to comments on the base load emissions standard, commenters stated the standard of performance should account for ambient conditions, operation at part load, automatic generation control, and variable loads. If the intermediate load standard is not achievable in practice, it could result in the operation of less efficient generation in other operating modes and an increase in overall GHG emissions. They also explained this could force simple cycle turbines to always operate at nameplate capacity, even when it was not necessary, which would also lead to increased emissions. These commenters requested that the EPA raise the variable and intermediate load emissions standard to 1,250 to 1,300 lb CO
2/MWh-gross. 
Considering the public comments, the 
EPA re-evaluated the standard of performance for intermediate load combustion turbines using the same approach as for combined cycle turbines, except using the performance of simple cycle EGUs. The average maximum 12-operating operating month intermediate load emissions rate for simple cycle turbines that began operation since 2015 is 1,210 lb CO
2/ 
MWh-gross. The range of the maximum 12-operating month emissions rate for individual units is 1,080 to 1,470 lb CO
2/MWh-gross. The lowest emissions 
rate was achieved by an individual unit at the Scattergood Generating Station. This facility includes 2 large aeroderivative simple cycle turbines (General Electric LMS 100) that commenced operation in 2015. Each turbine is rated at approximately 100 MW and use water injection to reduce NO
Xemissions. The EPA did not 
propose and is not finalizing to use the emissions rate of this EGU to determine the standard of performance for multiple reasons. Simple cycle turbine efficiency tends to increase with size and the simple cycle turbines at the Scattergood Facility are the largest aeroderivative turbines available. Establishing a standard of performance based on emission rates that only large aeroderivative turbines could achieve would limit the ability to develop new firm combustion turbine based generating capacity in smaller than 100 MW increments. This could result in the local electric grid operating in a less overall efficient manner, increasing overall GHG emissions. In addition, the largest available aeroderivative simple cycle turbines can use either water injection or dry low NO
Xcombustion to 
reduce emissions of NO X. For this 
particular design, the use of water injection has higher design efficiencies than the dry low NO
Xoption. Water 
injection has similar ecological impacts as water used for cooling towers, the EPA has determined in this case it is important to preserve the option for new intermediate load combustion turbines to use dry low NO
Xcombustion. 
The proposed emissions rate of 1,150 
lb CO 2/MWh-gross was achieved by 20 
percent of recently constructed intermediate load simple cycle turbines. However, only two-thirds of LMS 100 simple cycle turbines installed to date have maintained an intermediate load emissions rate of 1,150 lb CO
2/MWh- 
gross. In addition, only one-third of the Siemens STG–A65 simple cycle turbines and only 10 percent of General Electric LM6000 simple cycle combustion turbine have maintained this emissions rate. Both of these are common aeroderivative turbines and since they do require an intercooler have potential space consideration advantages compared to the LMS100. Finalizing the proposed emissions standard could restrict new intermediate load simple cycle turbine to the use of intercooling, limiting application to locations that can support a cooling tower. An intermediate load emissions rate of 1,170 lb CO
2/MWh- 
gross has been achieved by three- quarters of both the LMS100 and STG– A65 installations and 20 percent of LM6000 installations. In addition, this emissions rate has been demonstrated by a frame simple turbine. The EPA notes that the more efficient versions of the combustion turbines—water injection in the case of the LMS 100 and DLN in the case of the STG–A65—have higher design efficiencies and higher compliance levels than the version with 
the alternate NO
Xcontrol technology. 
This standard of performance has been demonstrated by 40 percent of recently installed intermediate load simple cycle turbines and the Agency has determined that with proper maintenance is achievable with combustion turbines from multiple manufacturers, with and without intercooling, and is finalizing a standard of 1,170 lb CO
2/MWh-gross for 
intermediate load combustion turbines. The EPA considered, but rejected, finalizing an emissions standard of 1,190 lb CO
2/MWh-gross. This standard 
of performance has been achieved by essentially all LMS 100 and SGT–A65 intermediate load simple cycle turbines and 70 percent of recently installed intermediate load simple cycle turbines but would not require the most efficient available versions of new intermediate load simple cycle turbines and does not represent the BSER. 
2. Phase-2 Standards 
The EPA proposed that 90 percent 
CCS (as part of the CCS pathway) 
qualifies as the second component of the BSER for base load combustion turbines. For the base load combustion 
turbines, the EPA reduced the emissions rate by 89 percent to determine the CCS based phase-2 standards.
879The CCS 
percent reduction is based on a CCS system capturing 90 percent of the emitting CO
2being operational anytime 
the combustion turbine is operating. Similar to the phase-1 emission standards, the EPA proposed and is finalizing a decision that standard of performance for base load combustion turbines be adjusted based on the uncontrolled emission rates of the fuels relative to natural gas. For 100 percent distillate oil-fired combustion turbines, the emission rates would be 120 lb CO
2/ 
MWh-gross. 
The EPA solicited comment on the 
range of reduction in emission rate of 75 to 90 percent. In addition, the EPA solicited comment on whether carbon capture equipment has lower availability/reliability than the combustion turbine or the CCS equipment takes longer to startup than the combustion turbine itself there would be periods of operation where the CO
2emissions would not be controlled 
by the carbon capture equipment. For the same reasons as for coal-fired EGUs, the EPA has determined 90 percent CCS 
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880https://www.gevernova.com/content/dam/ 
gepower-new/global/en_ US/downloads/gas-new- 
site/resources/advanced-gas-path-brochure.pdf. 
881https://www.siemens-energy.com/global/en/ 
home/stories/trianel-power-plant-upgrades.html. 
882https://s7d2.scene7.com/is/content/ 
Caterpillar/CM20191213-93d46-8e41d. 
883‘‘GTI’’ (2019). Innovative Steam Technologies. 
https://otsg.com/industries/powergen/gti/ . 
884Ibid. 885https://www.nsenergybusiness.com/news/ 
newsempire-district-starts-riverton-plants- 
combined-cycle-expansion-231013/. 
886https://news.delaware.gov/2013/07/26/ 
repowered-nrg-energy-center-dover-unveiled-gov- markell-congressional-delegation-dnrec-sec-omara- other-officials-join-with-nrg-to-announce-cleaner-natural-gas-facility/. 
887https://www.calpine.com/los-esteros-critical- 
energy-facility. 
888https://www.middleriverpower.com/#portfolio . 
889‘‘Cost and Performance of Retrofitting NGCC 
Units for Caron Capture—Revision 3.’’ DOE/NETL– 2023/3845. March 17, 2023. 
89040 CFR 60.15(b)(2). has been demonstrated and appropriate 
for base load combustion turbines, see section VII.C. 
H. Reconstructed Stationary 
Combustion Turbines 
All the major manufacturers of 
combustion turbines sell upgrade packages that increase both the output and efficiency of existing combustion turbines. An owner/operator of a 
reconstructed combustion turbine would be able to use one of these upgrade packages to comply with the intermediate load emission standards in this final rule. Some examples of these upgrades include GE’s Advanced Gas Path, Siemens’ Hot Start on the Fly, and Solar Turbines’ Gas Compressor Restaging. The Advanced Gas Path option includes retrofitting existing turbine components with improved materials to increase durability, air sealing, and overall efficiency.
880Hot 
Start on the Fly upgrades include implementing new software to allow for the gas and steam turbine to start-up simultaneously, which greatly improves start times, and in some cases could do so by up to 20 minutes.
881Compressor 
restaging involves analyzing the current operation of an existing combustion turbine and adjusting its gas compressor characteristics including transmission, injection, and gathering, to operate in the most efficient manner given the other operating conditions of the turbine.
882In addition, steam injection 
is a retrofittable technology that is estimated to be available for a total cost of all the equipment needed for steam injection of $250/kW.
883Due to the 
differences in materials used and necessary additional infrastructure, a steam injection system can be up to 60 percent smaller than a similar HRSG, which is valuable for retrofit purposes.
884 
For owners/operators of base load 
combustion turbines, however, HRSG have been added to multiple existing simple cycle turbines to convert to combined cycle technology. There have been multiple examples of this kind of conversion from simple cycle to combined cycle. One such example is Unit 12 at Riverton Power Plant in Riverton, Kansas, which was originally built in 2007 as a 143 MW simple cycle combustion turbine. In 2013, an HRSG 
and additional equipment was added to convert Unit 12 to a combined cycle combustion turbine.
885Another is 
Energy Center Dover, located in Dover, Delaware, which in addition to a coal- fired steam turbine, originally had two 44 MW simple cycle combustion turbines. Also in 2013, the unit added an HRSG to one of the existing simple cycle combustion turbines, connected the existing steam generator to it, and retired the remaining coal-related equipment to convert that combustion turbine to a combined cycle one.
886 
Some other examples include the Los Esteros Critical Energy Facility in San Jose, California, which converted from a four-turbine simple cycle peaking facility to a combined-cycle one in 2013, and the Tracy Combined Cycle Power Plant.
887The Tracy facility, located in 
Tracy, California, was built in 2003 with two simple cycle combustion turbines and in 2012 was converted to combined cycle with the addition of a steam turbine.
888 
In the previous sections, the EPA 
explained the background of and requirements for new and reconstructed stationary combustion turbines and evaluated various control technology configurations to determine the BSER. Because the BSER is the same for new and reconstructed stationary combustion turbines, the Agency used the same emissions analysis for both new and reconstructed stationary combustion turbines. For each of the subcategories, the EPA proposed and is finalizing a conclusion that the BSER results in the same standard of performance for new stationary combustion turbines and reconstructed stationary combustion turbines. For CCS, consistent with the NETL Combined Cycle CCS Retrofit Report, the EPA approximated the cost to add CCS to a reconstructed combustion 
turbine by increasing the capital costs of the carbon capture equipment by 9 percent relative to the costs of adding CCS to a newly constructed combustion turbine and decreasing the net efficiency by 0.3 percent.
889Using the 
same costing assumptions for newly constructed combined cycle turbines, 
the compliance costs for reconstructed combined cycle turbines are approximately 10 percent higher than for comparable newly constructed combined cycle turbine. Assuming continued operation of the capture equipment, the compliance costs are $17/MWh and $51/ton ($56/metric ton) for a 6,100 MMBtu/h H-Class combustion turbine, and $21/MWh and $63/ton ($69/metric ton) for a 4,600 MMBtu/h F-Class combustion turbine. If the capture system is not operated while the combustion turbine is subcategorized as in intermediate load combustion turbine, the compliance costs are reduced to $10/MWh and $50/ ton ($55/metric ton) for a 6,100 MMBtu/ h H-Class combustion turbine, and $13/ MWh and $67/ton ($73/metric ton) for a 4,600 MMBtu/h F-Class combustion turbine. 
A reconstructed stationary 
combustion turbine is not required to meet the standards if doing so is deemed to be ‘‘technologically and economically’’ infeasible.
890This 
provision requires a case-by-case reconstruction determination in the light of considerations of economic and technological feasibility. However, this case-by-case determination considers the identified BSER, as well as technologies the EPA considered, but rejected, as BSER for a nationwide rule. One or more of these technologies could be technically feasible and of 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. 
I. Modified Stationary Combustion 
Turbines 
CAA section 111(a)(4) defines a 
‘‘modification’’ as ‘‘any physical change in, or change in the method of operation of, a stationary source’’ that either ‘‘increases the amount of any air pollutant emitted by such source or . . . results in the emission of any air pollutant not previously emitted.’’ Certain types of physical or operational changes are exempt from consideration as a modification. Those are described in 40 CFR 60.2, 60.14(e). 
In the 2015 NSPS, the EPA did not 
finalize standards of performance for stationary combustion turbines that conduct modifications; instead, the EPA concluded that it was prudent to delay 
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891An F factor is the ratio of the gas volume of 
the products of combustion to the heat content of 
the fuel. issuing standards until the Agency 
could gather more information (80 FR 64515; October 23, 2015). There were several reasons for this determination: few sources had undertaken NSPS modifications in the past, the EPA had little information concerning them, and available information indicated that few owners/operators of existing combustion turbines would undertake NSPS modifications in the future; and since the Agency eliminated proposed subcategories for small EGUs in the 2015 NSPS, questions were raised as to whether smaller existing combustion turbines that undertake a modification could meet the final performance standard of 1,000 lb CO
2/MWh-gross. 
It continues to be the case that the 
EPA is aware of no evidence indicating that owners/operators of combustion turbines intend to undertake actions that could qualify as NSPS modifications in the future. The EPA did not propose or solicit comment on standards of performance for modifications of combustion turbines and is not establishing any in this final rule. 
J. Startup, Shutdown, and Malfunction 
In its 2008 decision in Sierra Club v. 
EPA, 551 F.3d 1019 (D.C. Cir. 2008), the 
D.C. Circuit vacated portions of two 
provisions in the EPA’s CAA section 112 regulations governing the emissions of HAP during periods of 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 the SSM exemption violates the requirement under section 302(k) of the CAA that some CAA section 112 standard apply continuously. The EPA has determined the reasoning in the court’s decision in Sierra Club v. EPA 
applies equally to CAA section 111 because the definition of emission or standard in CAA section 302(k), and the embedded requirement for continuous standards, also applies to the NSPS. Consistent with Sierra Club v. EPA, the 
EPA is finalizing standards in this rule that apply at all times. The NSPS general provisions in 40 CFR 60.11(c) currently exclude opacity requirements during periods of startup, shutdown, 
and malfunction and the provision in 40 CFR 60.8(c) contains an exemption from non-opacity standards. These general provision requirements would automatically apply to the standards set in an NSPS, unless the regulation specifically overrides these general provisions. The NSPS subpart TTTT (40 CFR part 60, subpart TTTT) does not contain an opacity standard, thus, the requirements at 40 CFR 60.11(c) are not applicable. The NSPS subpart TTTT also overrides 40 CFR 60.8(c) in table 3 and requires that sources comply with the standard(s) at all times. In reviewing NSPS subpart TTTT and proposing the new NSPS subpart TTTTa, the EPA proposed to retain in subpart TTTTa the requirements that sources comply with the standard(s) at all times in table 3 of the new subpart TTTTa to override the general provisions for SSM exemption related provisions. The EPA proposed and is finalizing that all standards in subpart TTTTa apply at all times. 
In developing the standards in this 
rule, the EPA has taken into account startup and shutdown periods and, for the reasons explained in this section of the preamble, is not establishing alternate standards for those periods. The EPA analysis of achievable standards of performance used CEMS data that includes all period of operation. Since periods of startup, shutdown, and malfunction were not excluded from the analysis, the EPA is not establishing alternate standard for those periods of operation. 
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 CAA section 111 standards. Nothing in CAA section 111 or in caselaw 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 standards of performance, nothing in CAA section 111 requires the Agency to consider malfunctions as part of that analysis. The EPA is not required to treat a malfunction 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. The EPA’s approach to malfunctions in the analogous circumstances (setting ‘‘achievable’’ standards under CAA section 112) has been upheld as reasonable by the D.C. Circuit in U.S. Sugar Corp. v. EPA, 830 F.3d 579, 606– 
610 (2016). 
K. Testing and Monitoring Requirements 
Because the NSPS reflects the 
application of the best system of 
emission reduction under conditions of proper operation and maintenance, in doing the NSPS review, the EPA also evaluates and determines the proper testing, monitoring, recordkeeping and reporting requirements needed to ensure compliance with the NSPS. This section includes a discussion on the current testing and monitoring requirements of the NSPS and any additions the EPA is including in 40 CFR part 60, subpart TTTTa. 
1. General Requirements 
The EPA proposed to allow three 
approaches for determining CO
2 
emissions: a CO 2CEMS and stack gas 
flow monitor; hourly heat input, fuel 
characteristics, and F factors891for 
EGUs firing oil or gas; or Tier 3 calculations using fuel use and carbon content. The first two approaches are in use for measuring CO
2by units affected 
by the Acid Rain program (40 CFR part 75), to which most, if not all, of the EGUs affected by NSPS subpart TTTT are already subject, while the last approach is in use for stationary fuel combustion sources reporting to the GHGRP (40 CFR part 98, subpart C). 
The EPA believes continuing the use 
of approaches already in use by other programs represents a cost-effective means of obtaining quality assured data requisite for determining carbon dioxide mass emissions. MPS reporting software required by this subpart for reporting emissions to the EPA expects hourly or daily CO
2emission values and has 
thousands of electronic checks to validate data using the Acid Rain program requirements (40 CFR part 75). ECMPS does not currently accommodate or validate data under GHGRP’s Tier 3 approach. Because most, if not all, of the EGUs that will be affected by this final rule are already affected by Acid Rain program monitoring requirements, the cost and burden for EGU owners or operators are already accounted for by other rulemakings. Therefore, this aspect of the final rule is designed to have minimal, if any, cost or burden associated with CO
2testing and 
monitoring. In addition, there are no changes to measurement and testing requirements for determining electrical output, both gross and net, as well as 
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892EPA. (2024). Rulemaking Notices for GHG 
Reporting. https://www.epa.gov/ghgreporting/ 
rulemaking-notices-ghg-reporting. 
893International Standards Organization (ISO) 
standard designated as CSA Group (CSA)/American 
National Standards Institute (ANSI) ISO 27916:2019, Carbon Dioxide Capture, 
Transportation and Geological Storage—Carbon Dioxide Storage Using Enhanced Oil Recovery (CO
2- 
EOR) (referred to as ‘‘CSA/ANSI ISO 27916:2019’’). 
894As described in 87 FR 36920 (June 21, 2022), 
both subpart RR and subpart VV (CSA/ANSI ISO 27916:2019) require an assessment and monitoring of potential leakage pathways; quantification of inputs, losses, and storage through a mass balance approach; and documentation of steps and approaches used to establish these quantities. Primary differences relate to the terms in their respective mass balance equations, how each defines leakage, and when facilities may discontinue reporting. thermal output, to existing 
requirements. 
However, the EPA requested comment 
on whether continuous CO 2CEMS and 
stack gas flow measurements should be the sole means of compliance for this rule. Such a switch would increase costs for those EGU owners or operators who are currently relying on the oil- or gas- fired calculation-based approaches. By way of reference, the annualized cost associated with adoption and use of continuous CO
2and flow measurements 
where none now exist is estimated to be about $52,000. To the extent that the rule were to mandate continuous CO
2 
and stack gas flow measurements in accordance with what is currently allowed as one option and that an EGU lacked this instrumentation, its owner or operator would need to incur this annual cost to obtain such information and to keep the instrumentation calibrated. Commenters encouraged the EPA to maintain the flexibility for EGUs to use hourly heat input measurements, fuel characteristics, and F factors as is allowed under the Acid Rain program. Commenters argued that in addition to the incremental costs, some facilities have space constraints that could make the addition of stack gas flow monitors difficult or impractical. In this final rule, the EPA allows the use of hourly heat input, fuel characteristics, and F factors as an alternative to CO
2CEMS 
and stack gas flow monitors for EGUs that burn oil or gas. 
One commenter argued that the part 
75 data requirements, which are required for several emission trading programs including the Acid Rain program, are punitive and that the data are biased high. Other commenters argued that the part 75 CO
2data are 
biased low. EPA disagrees that the data requirements are punitive. Most, if not all, of the EGUs subject to this subpart are already reporting the data under the Acid Rain program. Oil- and gas-fired EGUs that are not subject to the Acid Rain program but are subject to a Cross- State Air Pollution Rule program are already reporting most of the necessary data elements (e.g., hourly heat input 
and F factors) for SO
2and/or NO X 
emissions. The additional data and effort necessary to calculate CO
2 
emissions is minor. The EPA also disagrees that the data are biased significantly high or low. Each CO
2 
CEMS and stack gas flow monitor must undergo regular quality assurance and quality control activities including periodic relative accuracy test audits where the EGU’s monitoring system is compared to an independent monitoring 
system. In a May 2022 study conducted by the EPA, the average difference between the EGU’s monitoring system 
and the independent monitoring system was approximately 2 percent for CO
2 
concentration and slightly greater than 2 percent for stack gas flow. 
2. Requirements for Sources 
Implementing CCS 
The CCS process is also subject to 
monitoring and reporting requirements under the EPA’s GHGRP (40 CFR part 98). The GHGRP requires reporting of facility-level GHG data and other relevant information from large sources and suppliers in the U.S. The ‘‘suppliers of carbon dioxide’’ source category of the GHGRP (GHGRP subpart PP) requires those affected facilities with production process units that capture a CO
2stream for purposes of supplying 
CO 2for commercial applications or that 
capture and maintain custody of a CO 2 
stream in order to sequester or otherwise inject it underground to report the mass of CO
2captured and 
supplied. Facilities that inject a CO 2 
stream underground for long-term containment in subsurface geologic formations report quantities of CO
2 
sequestered under the ‘‘geologic sequestration of carbon dioxide’’ source category of the GHGRP (GHGRP subpart RR). In April 2024, to complement GHGRP subpart RR, the EPA finalized the ‘‘geologic sequestration of carbon dioxide with enhanced oil recovery (EOR) using ISO 27916’’ source category of the GHGRP (GHGRP subpart VV) to provide an alternative method of reporting geologic sequestration in association with EOR.
892 893 894  
CCS as the BSER, as detailed in 
section VIII.F.4.c.iv of this preamble, is determined to be adequately demonstrated based solely on geologic sequestration that is not associated with EOR. However, EGUs also have the compliance option to send CO
2to EOR 
facilities that report under GHGRP subpart RR or GHGRP subpart VV. The EPA is requiring that any affected unit that employs CCS technology that captures enough CO
2to meet the 
proposed standard and injects the captured CO
2underground must report 
under GHGRP subpart RR or GHGRP subpart VV. If the emitting EGU sends the captured CO
2offsite, it must transfer 
the CO 2to a facility that reports in 
accordance with GHGRP subpart RR or GHGRP subpart VV. This does not change any of the requirements to obtain or comply with a UIC permit for facilities that are subject to the EPA’s UIC program under the Safe Drinking Water Act. 
The EPA also notes that compliance 
with the standard is determined exclusively by the tons of CO
2captured 
by the emitting EGU. The tons of CO 2 
sequestered by the geologic sequestration site are not part of that calculation, though the EPA anticipates that the quantity of CO
2sequestered will 
be substantially similar to the quantity captured. However, to verify that the CO
2captured at the emitting EGU is 
sent to a geologic sequestration site, the Agency is leveraging regulatory reporting requirements under the GHGRP. The EPA also emphasizes that this final rule does not involve regulation of downstream recipients of captured CO
2. That is, the regulatory 
standard applies exclusively to the emitting EGU, not to any downstream user or recipient of the captured CO
2. 
The requirement that the emitting EGU transfer the captured CO
2to an entity 
subject to the GHGRP requirements is thus exclusively an element of enforcement of the EGU standard. This avoids duplicative monitoring, reporting, and verification requirements between this rule and the GHGRP, while also ensuring that the facility injecting and sequestering the CO
2(which may 
not necessarily be the EGU) maintains responsibility for these requirements. Similarly, the existing regulatory requirements applicable to geologic sequestration are not part of this final rule. 
L. Recordkeeping and Reporting 
Requirements 
The current rule (subpart TTTT of 40 
CFR part 60) requires EGU owners or 
operators to prepare reports in accordance with the Acid Rain Program’s ECMPS. Such reports are to be submitted quarterly. The EPA believes all EGU owners and operators have extensive experience in using the ECMPS and use of a familiar system ensures quick and effective rollout of the program in this final rule. Because all EGUs are expected to be covered by and included in the ECMPS, minimal, if any, costs for reporting are expected for 
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this final rule. In the unlikely event that 
a specific EGU is not already covered by and included in the ECMPS, the estimated annual per unit cost would be about $8,500. 
The current rule’s recordkeeping 
requirements at 40 CFR part 60.5560 rely on a combination of general provision requirements (see 40 CFR 60.7(b) and (f)), requirements at subpart F of 40 CFR part 75, and an explicit list of items, including data and calculations; the EPA is retaining those existing subpart TTTT of 40 CFR part 60 requirements in the new NSPS subpart TTTTa of 40 CFR part 60. The annual cost of those recordkeeping requirements will be the same amount as is required for subpart TTTT of 40 CFR part 60 recordkeeping. As the recordkeeping in subpart TTTT of 40 CFR part 60 will be replaced by similar recordkeeping in subpart TTTTa of 40 CFR part 60, this annual cost for recordkeeping will be maintained. 
M. Compliance Dates 
Owners/operators of affected sources 
that commenced construction or 
reconstruction after May 23, 2023, must meet the requirements of 40 CFR part 60, subpart TTTTa, upon startup of the new or reconstructed affected facility or the effective date of the final rule, whichever is later. This compliance schedule is consistent with the requirements in section 111 of the CAA. 
N. Compliance Date Extension 
Several industry commenters noted 
the potential for delay in installation 
and utilization of emission controls— especially CCS—due to supply chain constraints, permitting challenges, environmental assessments, or delays in development of necessary infrastructure, among other reasons. Commenters requested that the EPA include a mechanism to extend the compliance date for affected EGUs that are installing emission controls. These commenters explained that an extension mechanism could provide greater regulatory certainty for owners and operators. 
After considering these comments, the 
EPA believes that it is reasonable to provide a consistent and transparent means of allowing a limited extension of the Phase 2 compliance deadline where an affected new or reconstructed base load stationary combustion EGU has demonstrated such an extension is needed for installation and utilization of controls. This mechanism is intended to address unavoidable delays in implementation—not to provide more time to assess the NSPS compliance strategy for the affected EGU. As indicated, the EPA is finalizing a 
provision that will allow the owner/ 
operators of new or reconstructed base load stationary combustion turbine EGUs to request a limited Phase 2 compliance extension based on a case- by-case demonstration of necessity. Under these provisions, the owner or operator of an affected source may apply for a Phase 2 compliance date extension of up to 1 year to comply with the applicable emissions control requirements, which if approved by the EPA, would require compliance with Phase 2 standards of performance no later than January 1, 2033. This mechanism is only available for situations in which an affected source encounters a delay in installation or startup of a control technology that makes it impossible to commence compliance with Phase 2 standards of performance by January 1, 2032 (i.e., the 
Phase 2 compliance date specified in section VIII.F.4 of this preamble). 
The EPA will grant a request for a 
Phase 2 compliance extension of up to 1 year only where a source demonstrates that it has taken all steps possible to install and start up the necessary controls and still cannot comply with the Phase 2 standards of performance by the January 1, 2032 compliance date due to circumstances entirely beyond its control. Any request for a Phase 2 compliance extension must be received by the EPA at least 180 days before the January 1, 2032 Phase 2 compliance date. The owner/operator of the requesting source must provide documentation of the circumstances that precipitated the delay (or an anticipated delay) and demonstrate that those circumstances are entirely beyond the control of the owner/operator and that the owner/operator has no ability to remedy the delay. These circumstances may include, but are not limited to, delays related to permitting, delays in delivery or construction of parts necessary for installation or implementation of the control technology, or development of necessary infrastructure (e.g., CO
2 
pipelines). 
The request must include 
documentation that demonstrates that the necessary controls cannot be installed or started up by the January 1, 2032 Phase 2 compliance date. This may include information and documentation obtained from a control technology vendor or engineering firm demonstrating that the necessary controls cannot be installed or started up by the applicable Phase 2 compliance date, documentation of any 
permit delays, or documentation of delays in construction or permitting of infrastructure (e.g., CO
2pipelines) that 
is necessary for implementation of the 
control technology. The owner/operator of an affected new stationary combustion turbine EGU remains subject to the January 1, 2032 Phase 2 compliance date unless and until the Administrator grants a compliance extension. 
As discussed in sections VII.C.1.a.i.(E) 
and VII.C.2.b.i(C), the EPA has determined compliance timelines for these new sources that are consistent with achieving emission reductions as expeditiously as practicable given the time it takes to install and startup the BSER technologies for compliance with the Phase 2 standards of performance. The Phase 2 compliance dates are designed to accommodate the process steps and timeframes that the EPA reasonably anticipates will apply to affected EGUs. This extension mechanism acknowledges that circumstances entirely outside the control of the owners or operators of affected EGUs may extend the timeframe for installation or startup of control technologies beyond the timeframe that the EPA has determined is reasonable as a general matter. Thus, so long as this extension mechanism is limited to circumstances that cannot be reasonably controlled or remedied by the owners or operators of the affected EGUs and that make it impossible to achieve compliance with Phase 2 standards of performance by the January 1, 2032 compliance date, its use is consistent with achieving compliance as expeditiously as practicable. 
The EPA believes that a 1-year 
extension on top of the lead time already provided by the 2032 compliance date should be sufficient to address any compliance delays and to allow all base load units to timely install CSS. New or reconstructed base load stationary combustion turbines that are granted a 1-year Phase 2 compliance date extension and still are not able to install or startup the control technologies necessary to meet the Phase 2 standard of performance by the extended Phase 2 compliance date of January 1, 2033 may adjust their operation to the intermediate load subcategory (i.e., 12-operating-month 
capacity factor between 20–40 percent). 
Such sources must then comply with applicable standards of performance for the intermediate load stationary combustion turbine subcategory until the necessary controls are installed and operational such that the source can comply with the Phase 2 standard of performance. 
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89580 FR 64510 (October 23, 2015). 
896As part of the interagency review process, an 
error in the partial CCS costing report that the EPA 
used to update the costs of partial CCS between the 2018 Proposal and 2020 OMB Review Package was identified. The error included in the original 2020 OMB Review Package had the impact of increasing the cost of partial CCS. The corrected report resulted in partial CCS costs that were similar to those included in the 2018 Proposal. 
897State of California v. EPA (D.C. Cir. 21–1035), 
Document No. 1893155 (April 5, 2021). IX. Requirements for New, Modified, 
and Reconstructed Fossil Fuel-Fired Steam Generating Units 
A. 2018 NSPS Proposal Withdrawal 1. Background 
As discussed in section V.B, the EPA 
promulgated NSPS for GHG emissions 
from fossil fuel-fired steam generating units in 2015 (‘‘2015 NSPS’’).
895The 
2015 NSPS finalized partial CCS as the BSER and finalized standards of performance to limit emissions of GHG manifested as CO
2from newly 
constructed, modified, and reconstructed fossil fuel-fired EGUs (i.e., utility boilers and integrated gasification combined cycle (IGCC) units). In the same document, the Agency also finalized CO
2emission standards for 
newly constructed and reconstructed stationary combustion turbine EGUs. 80 FR 64510 (October 23, 2015). These final standards were codified in 40 CFR part 60, subpart TTTT. 
On December 20, 2018, the EPA 
published a proposal to revise certain parts of the 2015 Rule, titled ‘‘Review of Standards of Performance for Greenhouse Gas Emissions From New, Modified, and Reconstructed Stationary 
Sources: Electric Utility Generating Units.’’ 83 FR 65424 (December 20, 2018) (‘‘2018 Proposal’’). In Fall 2020, after reviewing comments on the 2018 Proposal, the EPA developed a draft final rule and sent that package to the Office of Management and Budget (OMB) for interagency review under Executive Order 12866 (‘‘2020 OMB Review Package’’). The 2020 OMB Review Package, if finalized, would have amended the BSER for new coal- fired EGUs and required a pollutant- specific significant contribution finding (SCF) prior to regulating a source category. The review of the BSER portion of the package was delayed
896 
and the pollutant-specific SCF portion of the 2020 OMB Review Package was finalized on January 13, 2021 in a final rule, titled ‘‘Pollutant-Specific Contribution Finding for Greenhouse Gas Emissions from New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units, and Process for Determining Significance of Other New Source Performance Standards Source Categories.’’ 86 FR 2542 (January 13, 2021) (‘‘SCF Rule’’). 
However, the D.C. Circuit vacated the SCF Rule on April 5, 2021.
897The BSER 
analysis and that portion of the 2018 Proposal have not been finalized and are being withdrawn in this final action. The 2018 Proposal stated that the Agency was proposing to find that partial CCS is not the BSER on grounds that it is too costly and that the 2015 Rule did not show that the technology had sufficient geographic scope to qualify as the BSER for newly constructed coal-fired EGUs. The EPA instead proposed that the BSER for newly constructed coal-fired EGUs would be the most efficient available steam cycle (i.e., supercritical steam 
conditions for large units and subcritical steam conditions for small units) in combination with the best operating practices instead of partial CCS. In addition, for newly constructed coal- fired EGUs firing moisture-rich fuels (i.e., lignite), the BSER would also 
include pre-combustion fuel drying using waste heat from the process. The 2018 Proposal also would have revised the standards of performance for reconstructed EGUs, the maximally stringent standards for coal-fired EGUs undergoing large modifications (i.e., modifications resulting in an increase in hourly CO
2emissions of more than 10 
percent), and for base load and non-base load operating conditions that reflected 
the Agency’s revised BSER determination. The 2018 Proposal did not revise the BSER for any other sources as determined in the 2015 Rule. It also included minor amendments to the applicability criteria for combined heat and power (CHP) and non-fossil EGUs and other miscellaneous technical changes in the regulatory requirements. 
2. Withdrawal of the 2018 Proposal 
In this action, under CAA section 
111(b), the Agency is withdrawing the 
2018 Proposal and the proposed determination that the BSER for coal- fired steam generating units should be highly efficient generation technology combined with best operating practices. The EPA no longer believes there is a basis for finding that highly efficient generation technology combined with best operating practices are the BSER for coal-fired steam generating units. As described at length in this preamble, CCS technology is adequately demonstrated for coal-fired steam generating units and so it is not appropriate to impose the less effective emission control of highly efficient generation combined with best operating practices for new sources in this source category. Moreover, the EPA is presently considering whether to revise the 2015 Rule to take into account improvements in CCS technology and the existing tax credits under the IRA. For a more in-depth, technical discussion of the rationale underlying this action, please refer to the technical memorandum in the docket titled, 2018 Proposal Withdrawal. 
B. Additional Amendments 
The EPA proposed and is finalizing 
multiple less significant amendments. 
These amendments are either strictly editorial and will not change any of the requirements of 40 CFR part 60, subpart TTTT, or will add additional compliance flexibility. The amendments are also incorporated into the final subpart TTTTa. For additional information on these amendments, see the redline strikeout version of the rule showing the amendments in the docket for this action. 
First, the EPA proposed and is 
finalizing editorial amendments to define acronyms the first time they are used in the regulatory text. Second, the EPA proposed and is finalizing adding International System of Units (SI) equivalent for owners/operators of stationary combustion turbines complying with a heat input-based standard. Third, the EPA proposed and is finalizing correcting errors in the current 40 CFR part 60, subpart TTTT, regulatory text referring to part 63 instead of part 60. Fourth, as a practical matter owners/operators of stationary combustion turbines subject to the heat input-based standard of performance need to maintain records of electric sales to demonstrate that they are not subject to the output-based standard of performance. Therefore, the EPA proposed and is finalizing adding a specific requirement that owner/ operators maintain records of electric sales to demonstrate they did not sell electricity above the threshold that would trigger the output-based standard. Next, the EPA proposed and is finalizing updating the ANSI, ASME, and ASTM International (ASTM) test methods to include more recent versions of the test methods. Finally, the EPA proposed and is finalizing adding additional compliance flexibilities for EGUs either serving a common electric generator or using a common stack. 
C. Eight-year Review of NSPS for Fossil 
Fuel-Fired Steam Generating Units 
1. Modifications 
In the 2015 NSPS, the EPA issued 
final standards for a steam generating 
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89880 FR 64514 (October 23, 2015). 
899Id. at 64597–98. 900Id. at 64598. 901DOE Funding Opportunity Announcement, 
‘‘DOE Invests More Than $444 Million for 
CarbonSAFE Project,’’ (November 15, 2023), https:// 
netl.doe.gov/node/13090; University of Alaska unit that implements a ‘‘large 
modification,’’ defined as a physical change, or change in the method of operation, that results in an increase in hourly CO
2emissions of more than 10 
percent when compared to the source’s highest hourly emissions in the previous 5 years. Such a modified steam generating unit is required to meet a unit-specific CO
2emission limit 
determined by that unit’s best demonstrated historical performance (in the years from 2002 to the time of the modification). The 2015 NSPS did not include standards for a steam generating unit that implements a ‘‘small modification,’’ defined as a change that results in an increase in hourly CO
2 
emissions of less than or equal to 10 percent when compared to the source’s highest hourly emissions in the previous 5 years.
898 
In the 2015 NSPS, the EPA explained 
its basis for promulgating this rule as follows. The EPA has historically been notified of only a limited number of NSPS modifications involving fossil fuel-fired steam generating units and therefore predicted that very few of these units would trigger the modification provisions and be subject to the proposed standards. Given the limited information that we have about past modifications, the Agency has concluded that it lacks sufficient information to establish standards of performance for all types of modifications at steam generating units at this time. Instead, the EPA has determined that it is appropriate to establish standards of performance at this time for larger modifications, such as major facility upgrades involving, for example, the refurbishing or replacement of steam turbines and other equipment upgrades that result in substantial increases in a unit’s hourly CO
2emissions rate. The Agency has 
determined, based on its review of public comments and other publicly available information, that it has adequate information regarding the types of modifications that could result in large increases in hourly CO
2 
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.
899 
The EPA did not reopen any aspect of these determinations concerning modifications in the 2015 NSPS, except, as noted below, for the BSER and associated requirements for large 
modifications. 
Because the EPA has not promulgated 
a NSPS for small modifications, any existing steam generating unit that undertakes a change that increases its hourly CO
2emissions rate by 10 percent 
or less will continue to be treated as an existing source that is subject to the CAA section 111(d) requirements being finalized today. 
With respect to large modifications, 
the EPA explained in the 2015 NSPS that they are rare, but there is record evidence indicating that they may occur.
900Because the EPA is finalizing 
requirements for existing coal-fired steam generating units that are, on their face, more stringent than the requirements for large modifications, the EPA believes it is appropriate to review and revise the latter requirements to minimize the anomalous incentive that an existing source could have to undertake a large modification for the purpose of avoiding the more stringent requirements that it would be subject to if it remained an existing source. Accordingly, the EPA proposed and is finalizing amending the BSER for large modifications for coal- fired steam generating units to mirror the BSER for the subcategory of long- term coal-fired steam generating units that is, the use of CCS with 90 percent capture of CO
2. The EPA believes that 
it is reasonable to assume that any existing source that invests in a physical change or change in the method of operation that would qualify as a large modification expects to continue to operate past 2039. Accordingly, the EPA has determined that CCS with 90 percent capture qualifies as the BSER for such a source for the same reasons that it qualifies as the BSER for existing sources that plan to operate past December 31, 2039. The EPA discusses these reasons in section VII.C.1.a of this preamble. The EPA has determined that CCS with 90 percent capture qualifies as the BSER for large modifications, and not the controls determined to be the BSER in the 2015 NSPS, due to the 
recent reductions in the cost of CCS. 
By the same token, the EPA is 
finalizing that the degree of emission limitation associated with CCS with 90 percent capture is an 88.4 percent reduction in emission rate (lb CO
2/ 
MWh-gross basis), the same as finalized for existing sources with CCS with 90 percent capture. See section VII.C.3.a of this preamble. Based on this degree of emission limitation, the EPA proposed and is finalizing that the standard of performance for steam generating units that undertake large modifications after May 23, 2023, is a unit-specific emission limit determined by an 88.4 percent reduction in the unit’s best historical annual CO
2emission rate 
(from 2002 to the date of the modification). The EPA proposed and is finalizing that an owner/operator of a modified steam generating unit comply with the emissions rate upon startup of the modified affected facility or the effective date of the final rule, whichever is later. The EPA proposed and is finalizing the same testing, monitoring, and reporting requirements as are currently in 40 CFR part 60, subpart TTTT. 
The EPA did not propose, and is not 
finalizing, any review or revision of the 2015 standard for large modifications of oil- or gas-fired steam generating units because the we are not aware of any existing oil- or gas-fired steam generating EGUs that have undertaken such modifications or have plans to do so, and, unlike an existing coal-fired steam generating EGUs, existing oil- or gas-fired steam units have no incentive to undertake such a modification to avoid the requirements we are including in this final rule for existing oil- or gas- fired steam generating units. 
2. New Construction and Reconstruction 
The EPA promulgated NSPS for GHG 
emissions from fossil fuel-fired steam 
generating units in 2015. In the proposal, the EPA proposed that it did not need to review the 2015 NSPS because at that time, the EPA did not have information indicating that any such units will be constructed or reconstructed. However, the EPA has recently become aware that a new coal- fired power plant is under consideration in Alaska. In November 2023, DOE announced a $9 million cooperative agreement for the Alaska Railbelt Carbon Capture and Storage (ARCCS) project, to be led by researchers at the University of Alaska Fairbanks. The ARCCS project would study the viability of a carbon storage complex in Southcentral Alaska, likely at the mostly-depleted Beluga River gas field west of Anchorage’’ in the Cook Inlet Basin, which could store captured CO
2. 
According to reports, the privately owned Flatlands Energy Corp. is considering constructing a 400 MW coal- and biomass-fired power plant in the Susitna River valley region, which, if built, would be one of the sources of captured CO
2.901 
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Fairbanks, Institute of Northern Engineering, ‘‘Cook 
Inlet Region Low Carbon Power Generation With Carbon Capture, Transport, and Storage Feasibility Study,’’ https://ine.uaf.edu/media/391133/cook- 
inlet-low-carbon-power-feasibility-study-uaf- pcorfinal.pdf; Herz, Nathaniel, ‘‘Could a new Alaska coal power plant be climate friendly? An $11 million study aims to find out,’’ Northern Journal (December 29, 2923), republished in Anchorage Daily News, https://www.adn.com/ business-economy/energy/2023/12/29/could-a-new- alaska-coal-power-plant-be-climate-friendly-an-11- million-study-aims-to-find-out/. 
902https://www.gpb.org/news/2010/07/26/judge- 
rejects-coal-plant-permits. 
903https://www.southernenvironment.org/press- 
release/court-rules-ga-failed-to-set-safe-limits-on- pollutants-from-coal-plant/. 
904https://permitsearch.gaepd.org/ 
permit.aspx?id=PDF-OP-22139. 
905https://www.southernenvironment.org/wp- 
content/uploads/legacy/words_ docs/EPD_ Plant_
Washington_ Denial_ Letter.pdf. 90640 CFR 60.20a–60.29a. 
90788 FR 80480 (November 17, 2023). At the time 
of promulgation of these emission guidelines, the November 2023 updates to the CAA section 111(d) implementing regulations are subject to litigation in the D.C. Circuit Court of Appeals. West Virginia v. EPA, D.C. Circuit No. 24–1009. The outcome of that 
litigation will not affect any of the distinct requirements being finalized in these emission guidelines, which are not directly dependent on those procedural requirements. Moreover, regardless of the outcome of that litigation, the necessary regulatory framework will exist for states to develop and submit state plans that include standards of performance for affected EGUs pursuant to these emission guidelines and prior implementing regulations. In light of this development, the EPA 
is not finalizing its proposal not to 
review the 2015 NSPS. Instead, the EPA will continue to consider whether to review the 2015 NSPS and will monitor the development of this potential new construction project in Alaska as well as any other potential projects to newly construct or reconstruct a coal-fired power plant. If the EPA does decide to review the 2015 NSPS, it would propose to revise them for coal-fired steam generating units. 
D. Projects Under Development 
During the 2015 NSPS rulemaking, 
the EPA identified the Plant Washington 
project in Georgia and the Holcomb 2 project in Kansas as EGU ‘‘projects under development’’ based on representations by developers that the projects had commenced construction prior to the proposal of the 2015 NSPS and, thus, would not be new sources subject to the final NSPS (80 FR 64542– 43; October 23, 2015). The EPA did not set a performance standard at the time but committed to doing so if new information about the projects became available. These projects were never constructed and are no longer expected to be constructed. 
The Plant Washington project was to 
be an 850 MW supercritical coal-fired EGU. The Environmental Protection Division (EPD) of the Georgia Department of Natural Resources issued air and water permits for the project in 2010 and issued amended permits in 2014.
902 903 904 In 2016, developers filed 
a request with the EPD to extend the construction commencement deadline specified in the amended permit, but the director of the EPD denied the request, effectively canceling the approval of the construction permit and revoking the plant’s amended air quality permit.
905 The Holcomb 2 project was intended 
to be a single 895 MW coal-fired EGU and received permits in 2009 (after earlier proposals sought approval for development of more than one unit). In 2020, after developers announced they would no longer pursue the Holcomb 2 expansion project, the air permits were allowed to expire, effectively canceling the project. 
For these reasons, the EPA proposed 
and is finalizing a decision to remove these projects under the applicability exclusions in subpart TTTT. 
X. State Plans for Emission Guidelines 
for Existing Fossil Fuel-Fired EGUs 
A. Overview 
This section provides information 
related to state plan development, 
including methodologies for establishing presumptively approvable standards of performance for affected EGUs, flexibilities for complying with standards of performance, and components that must be included in state plans as well as the process for submission. This section also addresses significant comments on and any changes to the proposed emission guidelines regarding state plans that the EPA is finalizing in this action. 
State plan submissions under these 
emission guidelines are governed by the requirements of 40 CFR part 60, subpart Ba (subpart Ba).
906The EPA finalized 
revisions to certain aspects of 40 CFR part 60, subpart Ba, in November 2023, Adoption and Submittal of State Plans for Designated Facilities: Implementing Regulations Under Clean Air Act Section 111(d) (final subpart Ba).
907 
Unless expressly amended or superseded in these emission guidelines, the provisions of subpart Ba apply. This section explicitly addresses any instances where the EPA is adding to, superseding, or otherwise varying the requirements of subpart Ba for the purposes of these particular emission guidelines. 
As noted in the preamble of the 
proposed action, under the Tribal Authority Rule (TAR) adopted by the 
EPA, Tribes may seek authority to implement a plan under CAA section 111(d) in a manner similar to that of a state. See 40 CFR part 49, subpart A. Tribes may, but are not required to, seek approval for treatment in a manner similar to that of a state for purposes of developing a Tribal Implementation Plan (TIP) implementing the emission guidelines. If a Tribe obtains approval and submits a TIP, the EPA will generally use similar criteria and follow similar procedures as those described for state plans when evaluating the TIP submission and will approve the TIP if appropriate. The EPA is committed to working with eligible Tribes to help them seek authorization and develop plans if they choose. Tribes that choose to develop plans will generally have the same flexibilities available to states in this process. 
In section X.B of this document, the 
EPA describes the foundational requirement that state plans achieve an equivalent level of emission reduction to the degree of emission limitation achievable through application of the BSER as determined by the EPA. Section X.C describes the presumptive methodology for calculating the standards of performance for affected EGUs based on subcategory assignment, as well as requirements related to invoking RULOF to apply a less stringent standard of performance than results from the EPA’s presumptive methodology. Section X.C also describes requirements for increments of progress for affected EGUs in certain subcategories and for establishing milestones and reporting obligations for affected EGUs that plan to permanently cease operations, as well as testing and monitoring requirements. In section X.D, the EPA describes how states are permitted to include flexibilities such as emission trading and averaging as compliance measures for affected EGUs in their state plans. Finally, section X.E describes what must be included in state plans, including plan components specific to these emission guidelines and requirements for conducting meaningful engagement, as well as the timing of state plan submission and EPA review of state plans and plan revisions. 
In this section of the preamble, the 
term ‘‘affected EGU’’ means any existing 
fossil fuel-fired steam generating unit that meets the applicability criteria described in section VII.B of this preamble. Affected EGUs are covered by the emission guidelines being finalized in this action under 40 CFR part 60 subpart UUUUb. 
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908See, e.g., West Virginia v. EPA, 597 U.S. 697, 
720 (2022) (‘‘In devising emissions limits for power 
plants, EPA first ‘determines’ the ‘best system of emission reduction’ that—taking into account cost, health, and other factors—it finds ‘has been adequately demonstrated.’ The Agency then quantifies ‘the degree of emission limitation achievable’ if that best system were applied to the covered source.’’) (internal citations omitted). 
909See 40 CFR 60.22a(b)(5). 
91040 CFR 60.24a(c). 
911As explained in section X.C.2 of this 
preamble, states may invoke RULOF to apply a less stringent standard of performance to a particular affected EGU when the state demonstrates that the EGU cannot reasonably achieve the degree of emission limitation determined by the EPA. In this case, the state plan may not necessarily achieve the same stringency as each source achieving the EPA’s presumptive standards of performance because affected EGUs for which RULOF has been invoked 
would have standards of performance less stringent than the EPA’s presumptive standards. B. Requirement for State Plans To 
Maintain Stringency of the EPA’s BSER Determination 
As explained in section V.C of this 
preamble, CAA section 111(d)(1) requires the EPA to establish requirements for state plans that, in turn, must include standards of performance for existing sources. Under CAA section 111(a)(1), a standard of performance is ‘‘a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the best system of emission reduction which . . . the Administrator determines has been adequately demonstrated.’’ That is, the EPA has the responsibility to determine the BSER for a given category or subcategory of sources and to determine the degree of emission limitation achievable through application of the BSER to affected sources.
908The level of 
emission reductions required of existing sources under CAA section 111 is 
reflected in the EPA’s presumptive standards of performance,
909which 
achieve emission reductions under these emission guidelines through requiring cleaner performance by affected sources. 
States use the EPA’s presumptive 
standards of performance to establish requirements for affected sources in their state plans. In general, the standards of performance that states establish for affected sources must be no less stringent than the presumptive standards of performance in the applicable emission guidelines.
910Thus, 
in order for the EPA to find a state plan ‘‘satisfactory,’’ that plan must address each affected EGU within the state and must achieve at least the level of emission reduction that would result if each affected EGU was achieving its presumptive standard of performance, after accounting for any application of RULOF.
911That is, while states have the discretion to establish the applicable 
standards of performance for affected EGUs in their state plans, the structure and purpose of CAA section 111 and the EPA’s regulations require that those plans achieve an equivalent level of emission reductions as applying the EPA’s presumptive standards of performance to each of those sources (again, after accounting for any application of RULOF). Section X.C of this preamble addresses how states maintain the level of emission reduction when establishing standards of performance, and section X.D of this preamble addresses how states maintain the level of emission reduction when incorporating compliance flexibilities. 
Additionally, consistent with the 
understanding that the purpose of CAA section 111 is for affected sources to reduce their emissions through cleaner operation, the Agency is also clarifying that emissions reductions from sources not affected by the final emission 
guidelines may not be counted towards compliance with either a source-specific or aggregate standard of performance. In other words, state plans may not 
account for emission reductions at non- affected fossil fuel-fired EGUs, emission reductions due to the operation or installation of other electricity- generating resources not subject to these emission guidelines for the purposes of demonstrating compliance with affected EGUs’ standards of performance. 
C. Establishing Standards of 
Performance 
This section addresses several topics 
related to standards of performance in state plans. First, this section describes affected EGUs’ eligibility for the subcategories in the final emission guidelines and how to calculate presumptive standards of performance, including calculating unit-specific baseline emission performance. Second, it summarizes compliance date information as well as how states can provide for a compliance date extension mechanism in their state plans. Third, this section describes how states may consider RULOF to apply a less stringent standard of performance or a longer compliance schedule to a particular affected EGU. Fourth, it explains how states must establish certain increments of progress for affected EGUs installing control technology to comply with standards of performance, as well as milestones and reporting obligations for affected EGUs demonstrating that they plan to permanently cease operations. And, finally, this section describes emission 
testing and monitoring requirements. 
Affected EGUs that meet the 
applicability requirements discussed in section VII.B must be addressed in the state plan. For each affected EGU within the state, the state plan must include a standard of performance and compliance schedule. That is, each individual unit must have its own, source-specific standard of performance and compliance schedule. Coal-fired affected EGUs must have increments of progress in the state plan and, if they plan to permanently cease operation and to rely on such cessation of operation for purposes of these emission guidelines, an enforceable commitment and reporting obligations and milestones. State plans must also specify the test methods and procedure for determining compliance with the standards of performance. 
While a presumptive methodology for 
standards of performance and other requirements were proposed for existing combustion turbine EGUs, the EPA is not finalizing emission guidelines for such EGUs at this time; therefore, the following discussion will not address the proposed combustion turbine EGU requirements or comments pertaining to these proposed requirements. In addition, the EPA is not finalizing the imminent- and near-term coal-fired subcategories for coal-fired steam generating units; therefore, the following discussion will not address these proposed subcategories or comments pertaining to these proposed subcategories. Similarly, the EPA is not finalizing emission guidelines for states and territories in non-contiguous areas, and is therefore not finalizing the proposed subcategories for non- continental oil-fired steam generating units or associated requirements nor 
addressing comments pertaining to these subcategories in this section. 
1. Application of Presumptive 
Standards 
This section of the preamble describes 
the EPA’s approach to providing presumptive standards of performance for each of the subcategories of affected EGUs under these emission guidelines, including establishing baseline emission performance. As explained in section X.B of this preamble, CAA section 111(a)(1) requires that standards of performance reflect the degree of emission limitation achievable through application of the BSER, as determined by the EPA. For each subcategory of affected EGUs, the EPA has determined a BSER and degree of emission limitation and is providing, in these emission guidelines, a methodology for 
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912Should a state decide to establish a standard 
of performance for an affected EGU using a 
methodology other than that provided by the EPA in these emission guidelines, the state would have to demonstrate that the resulting standard of performance achieves equivalent emission reductions as application of the EPA’s presumptive standard of performance. 
91388 FR 80529–31 (November 17, 2023). establishing presumptively approvable 
standards of performance (also referred to as ‘‘presumptive standards of performance’’ or ‘‘presumptive standards’’). Appropriate use of these methodologies will result in standards of performance that achieve the requisite degree of emission limitation and therefore meet the statutory requirements of section 111(a)(1) and the corresponding regulatory requirement that standards of performance must generally be no less stringent that the corresponding emission guidelines.
91240 CFR 
60.24a(c). 
Thus, a state, when establishing 
standards of performance for affected EGUs in its plan, must identify each affected EGU in the state and specify into which subcategory each affected EGU falls. The state would then use the corresponding methodology for the given subcategory to establish the presumptively approvable standard of performance for each affected EGU. 
As discussed in section X.C.2 of this 
preamble, states may apply less stringent standards of performance to particular affected EGUs in certain circumstances based on consideration of RULOF. States also have the authority to deviate from the methodology provided in these emission guidelines for presumptively approvable standards in order to apply a more stringent standard of performance (e.g., a state decides that 
an affected EGU in the medium-term coal-fired subcategory should comply with a standard of performance corresponding to co-firing 50 percent natural gas instead of 40 percent). Application of a standard of performance that is more stringent than provided by the EPA’s presumptive methodology does not require application of the RULOF provisions.
913 
a. Establishing Baseline Emission Performance for Presumptive Standards 
For each subcategory, the 
methodology to calculate a standard of performance entails establishing a baseline of CO
2emissions and 
corresponding electricity generation or heat input for an affected EGU and then applying the degree of emission limitation achievable through the application of the BSER (as established in section VII.C of this preamble). The methodology for establishing baseline 
emission performance for an affected EGU will result in a value that is unique to each affected EGU. To establish baseline emission performance for an affected EGU in all the subcategories except the low load natural gas- and oil- fired subcategories, the EPA is finalizing a determination that a state will use the CO
2mass emissions and corresponding 
electricity generation data for a given affected EGU from any continuous 8- quarter period from 40 CFR part 75 reporting within the 5-year period immediately prior to the date the final rule is published in the Federal Register. For affected EGUs in either the low load natural gas-fired subcategory or the low load oil-fired subcategory, the EPA is finalizing a determination that a state will use the CO
2mass emissions 
and corresponding heat input for a 
given affected EGU from any continuous 8-quarter period from 40 CFR part 75 reporting within the 5-year period immediately prior to the date the final rule is published in the Federal Register. This period is based on the NSR program’s definition of ‘‘baseline actual emissions’’ for existing electric steam generating units. See 40 CFR 52.21(b)(48)(i). Eight quarters of 40 CFR part 75 data corresponds to a 2-year period, but the EPA is finalizing this continuous 8-quarter period as it corresponds to quarterly reporting according to 40 CFR part 75. Functionally, the EPA expects states to utilize the most representative continuous 8-quarter period of data from the 5-year period immediately preceding the date the final rule is published in the Federal Register. For the 8 quarters of data, a state would divide the total CO
2emissions (in the 
form of pounds) over that continuous time period by either the total gross electricity generation (in the form of MWh) or, for affected EGUs in either the low load natural gas-fired subcategory or the low load oil-fired subcategory, the total heat input (in the form of MMBtu) over that same time period to calculate baseline CO
2emission performance in 
either lb of CO 2per MWh or lb of CO 2 
per MMBtu. As an example, a state establishing baseline emission performance for an affected EGU in the medium-term coal-fired subcategory in the year 2023 would start by evaluating the CO
2emissions and electricity 
generation data for the affected EGU for 2018 through 2022 and choose a continuous 8-quarter period that it deems to be the most appropriate representation of the operation of that affected EGU. While the EPA will evaluate the choice of baseline periods chosen by states when reviewing state 
plan submissions, the EPA intends to defer to a state’s reasonable exercise of discretion as to which 8-quarter period is representative. 
The EPA is finalizing the use of 8 
quarters during the 5-year period prior to the date the final rule is published in the Federal Register as the relevant 
period for the baseline methodology for several reasons. First, each affected EGU has unique operational characteristics that affect the emission performance of the EGU (load, geographic location, hours of operation, coal rank, unit size, etc.), and the EPA believes each affected EGU’s emission performance baseline should be representative of the source- specific conditions of the affected EGU and how it has typically operated. Additionally, allowing a state to choose (likely in consultation with the owners or operators of affected EGUs) the 8- quarter period for assessing baseline performance can avoid situations in which a prolonged period of atypical operating conditions would otherwise skew the emissions baseline. Relatedly, the EPA believes that, by using total mass CO
2emissions and total electric 
generation or heat input for an affected EGU over an 8-quarter period, any relatively short-term variability of data due to seasonal operations or periods of startup and shutdown, or other anomalous conditions, will be averaged into the calculated level of baseline emission performance. The baseline- setting approach also aligns with the reporting and compliance requirements in the final emission guidelines. Using total mass CO
2emissions and total 
electric generation or heat input provides a simple and streamlined approach for calculating baseline emission performance without the need to sort and filter non-representative data; any minor amount of non- representative data will be subsumed and accounted for through implicit averaging over the course of the 8- quarter period. Moreover, by not sorting or filtering the data, this approach reduces the need for discretion in assessing whether the data is appropriate to use. Commenters generally supported the proposed methodology for setting a baseline, particularly saying that they prefer not to have to sort or filter any data. 
The EPA believes that using this 
baseline-setting approach as the basis for establishing presumptively approvable standards of performance will provide certainty for states, as well as transparency and a streamlined process for state plan development. 
While this approach is specifically designed to be flexible enough to 
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91440 CFR 60.26a. 
915If the state plan incorporates compliance 
flexibilities like emission averaging and trading, an 
affected EGU must demonstrate compliance consistent with the expression of the respective flexibility. See section X.D of this preamble for more information. accommodate unit-specific 
circumstances, states retain the ability to deviate from this methodology. The EPA believes that the instances in which a state may need to use an alternate baseline-setting methodology will be limited to anticipated changes in operation, (i.e., circumstances in which 
historical emission performance is not representative of future emission performance). States that wish to vary the baseline calculation for an affected EGU based on anticipated changes in operation of that EGU, when those changes result in a less stringent standard of performance, must use the RULOF mechanism, which is designed to address such contingencies. 
Comment: Commenters sought 
clarification as to whether the methodology referred to the previous 5 calendar years or the 5-year period ending on the most recent quarter reported under 40 CFR part 75 prior to publication of the final emission guidelines. 
Response: The EPA clarifies that the 
methodology refers to the 5-year period ending on the most recent quarter reported under 40 CFR part 75 prior to publication of the final emission guidelines in the Federal Register. 
b. Presumptive Standards for Fossil 
Fuel-Fired Steam Generating Units 
As described in section VII of this 
preamble, the EPA is finalizing separate subcategories of existing fossil fuel-fired steam generating units based on fuel type (i.e., coal-fired, natural gas-fired, or 
oil-fired). Fuel type is based on the status of the source on January 1, 2030, and annual fuel use reporting is required after that date as a part of compliance. The EPA is further creating a subcategory for coal-fired steam generating units operating in the medium term, and further subcategorizing natural gas- and oil- fired steam generating units by load level. 
Consistent with CAA section 
111(d)(1)’s requirement that state plans provide for the implementation and enforcement of standards of performance, for affected EGUs in the medium-term subcategory, states must include sources’ enforceable commitments to cease operating before January 1, 2039, in their plans. The state plan must specify the calendar date by which the affected EGU plans to cease operation; to be included in a state plan, a commitment to cease operations by such a date must be enforceable by the state, whether through state rule, agreed order, permit, or other legal instrument.
914Upon EPA approval of 
the state plan, that commitment will 
become federally- and citizen- enforceable. 
For affected oil- and natural gas-fired 
steam generating units, subcategories are defined by load level and the type of fuel fired. There are three subcategories for natural gas- and oil- fired steam generating units (base load, intermediate load, and low load). Because subcategory applicability is determined retrospectively, as opposed to prospectively, and because the standards of performance for oil- and natural gas-fired affected EGUs are based on BSERs that do not require add- on controls, it is not necessary to require these sources to take enforceable utilization commitments limiting them to just one subcategory in order to implement and enforce their standards. For steam generating units that meet the definition of natural gas- or oil-fired, and that either retain the capability to fire coal after the date this final rule is published in the Federal Register, that fired any coal during the 5-year period prior to that date, or that will fire any coal after that date and before January 1, 2030, the plan must include a requirement to remove the capability to fire coal before January 1, 2030. 
The EPA is finalizing a requirement 
that compliance be demonstrated annually. For affected EGUs in all subcategories except the low load natural gas- and oil-fired subcategory, an affected EGU must demonstrate compliance based on the lb CO
2/MWh 
emission rate derived by dividing the total reported CO
2mass emissions by 
the total reported electric generation during the compliance period (corresponding to 1 calendar year), which is consistent with the expression of the degree of emission limitation for each subcategory in sections VII.C.3 and VII.D.3. For affected EGUs in the low load natural gas- and oil-fired subcategory, an affected EGU must demonstrate compliance based on the lb 
CO
2/MMBtu emission rate derived by 
dividing the total reported CO 2mass 
emissions by the total reported heat input during the compliance period (again, corresponding to 1 calendar year), consistent with the expression of the degree of emission limitation for the subcategory in section VII.D.3.
915In 
other words, for units with a compliance date of January 1, 2030, the first compliance period will be January 
1, 2030, through December 31, 2030. For units with a compliance date of January 1, 2032, the first compliance period will be January 1, 2032, through December 31, 2032. The compliance demonstration must occur by March 1 of the following year (i.e., for the 2030 
compliance period, by March 1, 2031). 
In addition, the EPA is finalizing a 
requirement that standards of performance must be established as either a rate or, for affected EGUs in certain subcategories, a mass of emissions. If a state chooses to allow mass-based compliance for certain affected EGUs it must first calculate the rate-based emission limitation that corresponds to the presumptive standard of performance, and then explain how it translated that rate-based emission limitation into the mass that constitutes an affected EGU’s standard of performance. See section X.D of this preamble for more information on demonstrating compliance where states are incorporating compliance flexibilities. 
i. Long-Term Coal-Fired Steam 
Generating Units 
This section describes the EPA’s 
methodology for establishing presumptively approvable standards of performance for long-term coal-fired steam generating units. Affected coal- fired steam generating units that do not meet the specifications of the medium- term coal-fired EGU subcategory are necessarily long-term units, and have a BSER of CCS with 90 percent capture and a degree of emission limitation of 90 percent capture of the mass of CO
2 
in the flue gas (i.e., the mass of CO 2after 
the boiler but before the capture equipment) over an extended period of time and an 88.4 percent reduction in emission rate on a lb CO
2/MWh-gross 
basis over an extended period of time 
(i.e., an annual calendar-year basis). The 
EPA is finalizing a determination that where states use the methodology described here to establish standards of performance for affected EGUs in this subcategory, those established standards will be presumptively approvable when included in a state plan submission. 
Establishing a standard of 
performance for an affected coal-fired EGU in this subcategory consists of two steps: establishing a source-specific level of baseline emission performance (as described in section X.C.1.a of this preamble); and applying the degree of emission limitation, based on the application of the BSER, to that level of baseline emission performance. Implementation of CCS with a capture rate of 90 precent translates to a degree 
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of emission limitation comprising of an 
88.4 percent reduction in CO 2emission 
rate compared to the baseline level of emission performance. Using the complement of 88.4 percent (i.e., 11.6 
percent) and multiplying it by the baseline level of emission performance results in the presumptively approvable standard of performance. For example, if a long-term coal-fired EGU’s level of baseline emission performance is 2,000 lbs CO
2per MWh, it will have a 
presumptively approvable standard of performance of 232 lbs CO
2per MWh 
(2,000 lbs CO 2per MWh multiplied by 
0.116). 
The EPA is also finalizing a 
requirement that affected coal-fired EGUs in the long-term subcategory comply with federally enforceable increments of progress, which are described in section X.C.3 of this preamble. 
ii. Medium-Term Coal-Fired Steam 
Generating Units 
This section describes the EPA’s 
methodology for establishing presumptively approvable standards of performance for medium-term coal-fired steam generating units. Affected coal- fired steam generating units that plan to commit to permanently cease operations before January 1, 2039, have a BSER of 40 percent natural gas co-firing on a heat input basis. The EPA is finalizing a determination that where states use the methodology described here to establish standards of performance for an affected EGU in this subcategory, those established standards of performance would be presumptively approvable when included in a state plan submission. 
Establishing a standard of 
performance for an affected EGU in this subcategory consists of two steps: establishing a source-specific level of baseline emission performance (as described in section X.C.1.a); and 
applying the degree of emission limitation, based on the application of the BSER, to that level of baseline emission performance. Implementation of natural gas co-firing at a level of 40 percent of total annual heat input translates to a level of stringency of a 16 percent reduction in emission rate on a lb CO
2/MWh-gross basis over an 
extended period of time (i.e., an annual 
calendar-year basis) compared to the baseline level of emission performance. Using the complement of 16 percent (i.e., 84 percent) and multiplying it by 
the baseline level of emission performance results in the presumptively approvable standard of performance for the affected EGU. For example, if a medium-term coal-fired EGU’s level of baseline emission 
performance is 2,000 lbs CO
2per MWh, 
it will have a presumptively approvable standard of performance of 1,680 CO
2 
lbs per MWh (2,000 lbs CO 2per MWh 
multiplied by 0.84). 
For medium-term coal-fired steam 
generating units that have an amount of co-firing that is reflected in the baseline operation, the EPA is finalizing a requirement that states account for such preexisting co-firing in adjusting the degree of emission limitation. If, for example, an EGU co-fires natural gas at a level of 10 percent of the total annual heat input during the applicable 8- quarter baseline period, the corresponding degree of emission limitation would be adjusted to a 12 percent reduction in CO
2emission rate 
on a lb CO 2/MWh-gross basis compared 
to the baseline level of emission performance (i.e., an additional 30 
percent of natural gas by heat input) to reflect the preexisting level of natural gas co-firing. This results in a standard of performance based on the degree of emission limitation achieving an additional 30 percent co-firing beyond the 10 percent that is accounted for in the baseline. The EPA believes this approach is a more straightforward mathematical adjustment than adjusting the baseline to appropriately reflect a preexisting level of co-firing. 
The standard of performance for the 
medium-term coal-fired subcategory is based on the degree of emission limitation that is achievable through application of the BSER to the affected EGUs in the subcategory and consists exclusively of the rate-based emission limitation. However, the BSER determination for this subcategory is predicated on the assumption that affected EGUs within it will permanently cease operations prior to January 1, 2039. If a state decides to place an affected EGU in the medium- term coal-fired subcategory, the state plan must include that EGU’s commitment to permanently cease operating as an enforceable requirement. The state plan must also include provisions that provide for the implementation and enforcement of this commitment, including requirements for monitoring, reporting, and recordkeeping. 
Affected coal-fired EGUs that are 
relying on commitments to cease 
operating must comply with the milestones and reporting requirements as specified under these emission guidelines. The EPA intends these milestones to assist affected EGUs in ensuring they are completing the necessary steps to comply with their state plan requirements and to help ensure that any issues with 
implementation are identified in a timely and efficient manner. These milestones are described in detail in section X.C.4 of this preamble. Affected EGUs in this subcategory would also be required to comply with the federally enforceable increments of progress described in section X.C.3 of this preamble. 
iii. Natural Gas-Fired Steam Generating 
Units and Oil-Fired Steam Generating Units 
This section describes the EPA’s final 
methodology for presumptively approvable standards of performance for the following subcategories of affected natural gas-fired and oil-fired steam generating units: low load natural gas- fired steam generating units, intermediate load natural gas-fired steam generating units, base load natural gas-fired steam generating units, low load oil-fired steam generating units, intermediate load oil-fired steam generating units, and base load oil-fired steam generating units. The final definitions of these subcategories are discussed in section VII.D.1 of this preamble. The final presumptive standards of performance are based on degrees of emission limitation that units are currently achieving, consistent with the proposed BSER of routine methods of operation and maintenance, which amounts to a proposed degree of emission limitation of no increase in emission rate. 
For natural gas-fired steam generating 
units, the EPA proposed fixed presumptive standards of 1,500 lb CO
2/ 
MWh-gross for intermediate load units (solicited comment on values between 1,400 and 1,600 lb/MWh-gross) and 1,300 lb CO
2/MWh-gross for base load 
units (solicited comment on values between 1,250 and 1,400 lb CO
2/MWh- 
gross). For oil-fired steam generating 
units, the EPA proposed fixed presumptive standards of 1,500 lb CO
2/ 
MWh-gross for intermediate load units (solicited comment on values between 1,400 and 2,000 lb/MWh-gross) and 1,300 lb CO
2/MWh-gross for base load 
units (solicited comment on values between 1,250 and 1,800 lb CO
2/MWh- 
gross). 
The EPA is finalizing presumptive 
standards of performance for affected natural gas-fired and oil-fired steam generating units in lieu of methodologies that states would use to establish presumptive standards of performance. This is largely because of the low variability in emissions data at intermediate and base load for these units and relatively consistent performance between these units at 
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916See Document ID No. EPA–HQ–OAR–2023– 
0072–0806. those load levels, as discussed in 
section VII.D of this preamble and detailed in the final TSD, Natural Gas- and Oil-fired Steam Generating Units, which supports the establishment of a generally applicable standard of performance. 
For intermediate load natural gas- 
fired units (annual capacity factors greater than or equal to 8 percent and less than 45 percent), annual emission rates are less than 1,600 lb CO
2/MWh- 
gross for more than 95 percent of units. Therefore, the EPA is finalizing the presumptive standard of performance of an annual calendar-year emission rate of 1,600 lb CO
2/MWh-gross for these units. 
For base load natural gas-fired units 
(annual capacity factors greater than or equal to 45 percent), annual emission rates are less than 1,400 lb CO
2/MWh- 
gross for more than 95 percent of units. Therefore, the EPA is finalizing the presumptive standard of performance of an annual calendar-year emission rate of 1,400 lb CO
2/MWh-gross for these units. 
In the continental U.S., there are few 
if any oil-fired steam generating units that operate with intermediate or high utilization. Liquid-oil-fired steam generating units with 24-month capacity factors less than 8 percent do qualify for a work practice standard in lieu of emission requirements under the MATS (40 CFR part 63, subpart UUUUU). If oil-fired units operated at higher annual capacity factors, it is likely they would do so with substantial amounts of natural gas-firing and have emission rates that are similar to steam generating units that fire only natural gas at those levels of utilization. There are a few natural gas-fired steam generating units that are near the threshold for qualifying 
as oil-fired units (i.e., firing more than 
15 percent oil in a given year) but that on average fire more than 90 percent of their heat input from natural gas. Therefore, the EPA is finalizing the same presumptive standards of performance for oil-fired steam generating units as for natural gas-fired units (1,400 lb CO
2/MWh-gross for base 
load units and 1,600 lb CO 2/MWh-gross 
for intermediate load units). 
Lastly, the EPA is finalizing uniform 
fuels as the BSER for low load natural gas and oil-fired steam generating units. The EPA is finalizing degrees of emission limitation defined by 130 lb CO
2/MMBtu for low load natural gas- 
fired steam generating units and 170 lb CO
2/MMBtu for low load oil-fired steam 
generating units, and presumptively approvable standards consistent with those values. 
Comment: One commenter stated that 
the EPA should instead allow states to define standards using a source’s baseline emission rate, with some 
additional flexibilities to account for changes in load.
916The commenter also 
requested that, if the EPA were to finalize presumptive standards, then the higher values that the EPA solicited comment on for natural gas-fired units should be finalized. The commenter similarly requested that, if the EPA were to finalize presumptive standards, then the higher values that the EPA solicited comment on for oil-fired units should be finalized—however, the commenter also noted that its two sources that are currently oil-firing operate below an 8 percent annual capacity factor and would therefore not be subject to the intermediate load or base load presumptive standard. 
Response: The EPA is finalizing 
presumptive standards for natural gas- 
fired steam generating units of 1,400 lb CO
2/MWh-gross for base load units and 
1,600 lb CO 2/MWh-gross for 
intermediate load units. The EPA is finalizing the same standards for oil- fired steam generating units for the reasons discussed in the preceding text. Few, if any, oil-fired units operate as intermediate load or base load units, as acknowledged by the commenter. Those oil-fired units that have operated near the threshold for intermediate load have typically fired a large proportion of natural gas and operated at emission rates consistent with the final presumptive standards. 
c. Compliance Dates 
This section summarizes information 
on the compliance dates, or the first 
date on which the standard of performance applies, that the EPA is finalizing for each subcategory. As discussed in section X.C.1.b, compliance is required to be demonstrated on an annual (i.e., calendar year) basis. 
The EPA proposed a compliance date 
of January 1, 2030, for all affected steam generating units. As discussed in section VII.C.1.a.i(E) of this preamble, the EPA received comments that this compliance date was not achievable for sources in the long-term coal-fired EGU subcategory that would be installing CCS. In response to those comments, the EPA reevaluated the information and timeline for CCS installation and is finalizing a compliance date of January 1, 2032, for the long-term coal-fired subcategory. The Agency is finalizing a compliance date of January 1, 2030, for units in the medium-term coal-fired subcategory as well as for natural gas- and oil-fired steaming generating units. The EPA refers to January 1, 2030, 
and January 1, 2032, as ‘‘compliance 
dates,’’ ‘‘final compliance dates,’’ and ‘‘initial compliance dates’’ in various parts of this preamble. In each case, the EPA means that this is the date on which affected EGUs must start monitoring and reporting their emissions and other relevant data for purposes of demonstrating compliance with their standards of performance under these emission guidelines. Affected EGUs demonstrate compliance on a calendar year basis, i.e., the 
compliance period for affected EGUs is 1 calendar year. Therefore, affected EGUs will not have to demonstrate that they are achieving their standards of performance on January 1, 2030, or January 1, 2032, as that demonstration is made only at the end of the compliance period, i.e., at the end of the 
calendar year. But, again, these are the dates on which affected EGUs in the relevant subcategories must start monitoring and reporting for purposes of their future compliance demonstrations with their standards of performance. 
d. Compliance Date Extension 
Mechanism 
The EPA is finalizing provisions that 
allow states to include a mechanism to extend the compliance date for certain affected EGUs in their state plans. This mechanism is only available for situations in which an affected EGU encounters a delay in installation of a control technology that makes it impossible to commence compliance by the date specified in section X.C.1.c of this preamble. The owner or operator must provide documentation of the circumstances that precipitated the delay (or the anticipated delay) and demonstrate that those circumstances were or are entirely beyond the owner or operator’s control and that the owner or operator has no ability to remedy the delay. These circumstances may include, but are not limited to, permitting-related delays or delays in delivery or construction of parts necessary for installation or implementation of the control 
technology. 
The EPA received extensive comment 
requesting a mechanism to extend the compliance date for affected EGUs installing a control technology to address situations in which the owner or operator of the affected EGU encounters a delay outside of their control. Several industry commenters noted the potential for such delays due to, among other reasons, supply chain constraints, permitting processes, and/ or environmental assessments as well as 
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delays in deployment of supporting 
infrastructure like pipelines. These commenters explained that an extension mechanism could provide greater regulatory certainty for owners and operators. In light of this feedback and acknowledgment that there may be circumstances outside of owners/ operators’ control that impact their ability to meet the compliance dates in these emission guidelines, the EPA believes that it is reasonable to provide a consistent and transparent means of allowing a limited extension of the compliance deadline where an affected EGU has demonstrated such an extension is needed for installation of controls. This mechanism is intended to address delays in implementation—not to provide more time to assess the compliance strategy (i.e., the type of 
technology or subcategory assignment) for the affected EGU, as some commenters suggested; those decisions are to be made at the time of state plan approval. 
The compliance date extension 
mechanism is consistent with both CAA section 111 and these emission guidelines. Consistent with the statutory purpose of remedying dangerous air pollution, state plans must generally provide for compliance with standards of performance as expeditiously as practicable but no later than specified in the emission guidelines. 40 CFR 60.24a(c). As discussed in sections VII.C.1.a.i.(E) and VII.C.2.b.i(C), the EPA has determined compliance timelines in these emission guidelines consistent with achieving emission reductions as expeditiously as practicable given the time it takes to install the BSER technologies for the respective subcategories. The compliance dates are designed to accommodate the process steps and timeframes that the EPA reasonably anticipates will apply to affected EGUs. This extension mechanism acknowledges that circumstances entirely outside the control of the owners or operators of affected EGUs may extend the timeframe for installation of control technologies beyond what the EPA reasonably expects for the subcategories as a general matter. Thus, so long as this extension mechanism is limited to circumstances that cannot be reasonably controlled or remedied by states or affected EGUs and that make it impossible to achieve compliance by the dates specified in these emission guidelines, its use is consistent with achieving compliance as expeditiously as practicable. 
The EPA is establishing parameters, 
described in this subsection, for the 
features of this mechanism (e.g., documentation, time limitation). Within these parameters, states should consider state-specific circumstances related to the implementation and enforcement of this mechanism in their state plans. Importantly, in order to provide compliance date extensions that do not require a state plan revision available to affected EGUs, states must include the mechanism in their proposed state plans that are provided for public comment and meaningful engagement (as well as in the final state plan submitted to the EPA), and the circumstances for and consequences of using this mechanism must be clearly spelled out and bounded. States are not required to include this mechanism in their state plans; absent its inclusion, states must submit a state plan revision in order to extend a compliance schedule that has been approved into a plan. 
First, state plans must provide that a 
compliance date extension through this mechanism is available only for affected EGUs that are installing add-on controls. Affected EGUs that intend to comply without installing additional control technologies—including, but not limited to, oil and gas-fired steam generating EGUs—should not experience the types of installation or implementation delays that this mechanism is intended to address. Second, state plan mechanisms must provide that to receive a compliance date extension, the owner or operator of an affected EGU is required to demonstrate to the state air pollution control agency, and provide supporting documentation to establish, the basis for and plans to address the delay. For each affected EGU, this demonstration must include (1) confirmation that the affected EGU has met the relevant increments of progress up to the point of the delay, including any permits obtained and/or contracts entered into for the installation of control technology, (2) documentation, such as invoices or correspondence with permitting authorities, vendors, etc., of the circumstances of the delay and that the delay is due to the action, or lack thereof, of a third party (e.g., supplier or 
permitting authority), and that the owner or operator of the affected EGU has itself acted consistent with achieving timely compliance (e.g., in 
applying for permits with all necessary information or contracting in sufficient time to perform in accordance with required schedules), and (3) plans for addressing the circumstances and remedying the delay as expeditiously as practicable, including updated dates for the final increment of progress corresponding to the compliance date as well as any other increments that are outstanding at the time of the 
demonstration. These requirements for documentation are intended to ensure, inter alia, that the owner or operator has made all reasonable efforts to achieve timely compliance and that the circumstances for granting an extension are not speculative but are rather based on delays the affected EGU is currently experiencing or is reasonably certain to experience. 
The extended compliance date must 
be as expeditiously as practicable and the maximum time allowed for this extension is 1 year beyond the compliance date specified for the affected EGU by the state plan. Several commenters suggested that a 1-year extension was appropriate. If the delay is anticipated to be longer than 1 year, states can provide for the use of this mechanism for up to 1 year but should also initiate a state plan revision if necessary to provide an updated compliance date through consideration of RULOF, subject to EPA approval of the plan revision. 
The state air pollution control agency 
is charged with approving or disapproving a compliance date extension request based on its written determination that the affected EGU has or has not made each of the necessary demonstrations and provided all of the necessary documentation. All documentation for the extension request must be submitted by the owner or operator of the affected EGU to the state air pollution control agency no later than 6 months prior to the compliance date provided in these emission guidelines. The owner or operator of the affected EGU must also notify the relevant EPA Regional Administrator of their compliance date extension request at the time of the submission of the request. The owner or operator of the affected EGU must also post their application for the compliance date extension request to the Carbon Pollution Standards for EGUs website, as discussed in section X.E.1.b.ii of this preamble, when they submit the request to the state air pollution control agency. The state air pollution control agency must notify the relevant EPA Regional Administrator of any determination on an extension request and the new compliance date for any affected EGU(s) with an approved extension at the time of the determination on the extension request. The owner or operator of the affected EGU must also post the state’s determination on the compliance extension request to the Carbon Pollution Standards for EGUs website, as discussed in section X.E.1.b.ii of this 
preamble, upon receipt of the determination, and, if the request is 
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917West Virginia v. EPA, 597 U.S. 697, 720 (2022) 
(‘‘In devising emissions limits for power plants, 
EPA first ‘determines’ the ‘best system of emission reduction’ that—taking into account cost, health, and other factors—it finds ‘has been adequately demonstrated.’ The Agency then quantifies ‘the degree of emission limitation achievable’ if that best system were applied to the covered source.’’) (internal citations omitted). 
918See, e.g., 88 FR 80512 (November 17, 2023). approved, update information on the 
website related to the compliance date and increments of progress dates within 30 days of the receipt of the state’s approval. 
2. Remaining Useful Life and Other 
Factors 
Under CAA section 111(d), the EPA is 
required to promulgate regulations under which states submit plans that ‘‘establish[] standards of performance for any existing source’’ and ‘‘provide for the implementation and enforcement of such standards of performance.’’ While states establish the standards of performance, there is a fundamental obligation under CAA section 111(d) that such standards reflect the degree of emission limitation achievable through the application of the BSER, as determined by the EPA.
917The EPA 
identifies this degree of emission limitation as part of its emission guideline. 40 CFR 60.22a(b)(5). Thus, as described in section X.C.2 of this preamble, the EPA is providing methodologies for states to follow in determining and applying presumptively approvable standards of performance to affected EGUs in each of the subcategories covered by these emission guidelines. In general, the standards of performance that states establish for designated facilities must be no less stringent than the presumptively approvable standards of performance specified in these emission guidelines. 40 CFR 60.24a(c). 
However, CAA section 111(d)(1) also 
requires that the EPA’s regulations permit the states, in applying a standard of performance to any particular designated facility, to ‘‘take into consideration, among other factors, the remaining useful life of the existing source to which the standard applies.’’ The EPA’s implementing regulations under 40 CFR 60.24a allow a state to consider a particular designated facility’s remaining useful life and other factors (‘‘RULOF’’) in applying to that facility a standard of performance that is less stringent than the presumptive level of stringency in the applicable emission guideline, or a compliance schedule that is longer than prescribed by that emission guideline. 
In the proposal, the EPA indicated 
that it had recently proposed, in a separate rulemaking, to clarify the 
general implementing regulations governing the application of RULOF. The Agency further explained that the revised RULOF regulations, as finalized in that separate rulemaking, would apply to these emission guidelines. The revisions to the implementing regulations’ RULOF provisions were finalized in November 2023, with some changes in response to public comments relative to proposal. As provided by 40 CFR 60.20a(a) and (a)(1) and indicated in the proposal, the RULOF provisions in 40 CFR 60.24a, as revised in the November 2023 final rule, will govern the use of RULOF to provide less stringent standards of performance or longer compliance schedules under these emission guidelines. The EPA is not superseding any provision of the RULOF regulations at 40 CFR 60.24a in these emission guidelines. 
As explained in the preamble to the 
final rule, Adoption and Submittal of State Plans for Designated Facilities: Implementing Regulations Under Clear Air Act Section 111(d), the EPA has interpreted the RULOF provision of CAA section 111(d)(1) as allowing states to apply a standard of performance that is less stringent than the degree of emission limitation in the applicable emission guideline, or a longer compliance schedule, to a particular facility based on that facility’s remaining useful life and other factors. The use of RULOF to deviate from an emission guideline is available only when there are fundamental differences between the circumstances of a particular facility and the information the EPA considered in determining the degree of emission limitation or the compliance schedule, and those fundamental differences make it unreasonable for the facility to achieve the degree of emission limitation or meet the compliance schedule in the emission guideline. This ‘‘fundamentally different’’ standard is consistent with the statutory purpose of reducing dangerous air pollution under CAA section 111; the statutory framework under which, to achieve that purpose, the EPA is directed to determine the degree of emission under CAA section 111(a)(1); and the understanding that RULOF is intended as a limited variance from the EPA’s determination to address unusual 
circumstances at particular facilities.
918 
The relevant consideration for states 
contemplating the use of RULOF to apply a less stringent standard of performance is whether a designated facility can reasonably achieve the degree of emission limitation in the 
applicable emission guideline, not whether it can implement the system of emission reduction the EPA determined is the BSER. That is, if a designated facility cannot implement the BSER but can reasonably achieve the specified degree of emission limitation using a different system of emission reduction, the state cannot use RULOF to apply a less stringent standard of performance to that facility. 
If a state has demonstrated, pursuant 
to 40 CFR 60.24a(e), that a particular facility cannot reasonably achieve the degree of emission limitation or compliance schedule determined by the EPA in these emission guidelines, the state may then apply a less stringent standard of performance or longer compliance schedule. The process for doing so is laid out in 40 CFR 60.24a(f). Critically, standards of performance and compliance schedules pursuant to RULOF must be no less stringent, or no longer, than is necessary to address the fundamental difference between the information the EPA considered and the particular facility that was the basis for invoking RULOF under 40 CFR 60.24a(e). In determining a less stringent standard of performance, the state must, to the extent necessary, evaluate the systems of emission reduction identified in the emission guidelines using the factors and evaluation metrics the EPA considered in assessing those systems, including technical feasibility, the amount of emission reductions, the cost of achieving such reductions, any non- air quality health and environmental impacts, and energy requirements. States may also consider, as justified, other factors specific to the facility that were the basis for invoking RULOF under 40 CFR 60.24a(e), as well as additional systems of emission reduction. 
The RULOF provision at 40 CFR 
60.24a(g) states that, where the basis of a less stringent standard of performance is an operating condition within the control of a designated facility, the state plan must include such operating condition as an enforceable requirement. The state plan must also include requirements, such as for monitoring, reporting, and recordkeeping, for the implementation 
and enforcement of the condition. This is relevant in the case of, for example, less stringent standards of performance that are based on a particular designated facility’s remaining useful life or utilization. 
Finally, the general implementing 
regulations provide that states may always adopt and enforce, as part of their state plans, standards of 
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919The other RULOF provisions that the EPA 
proposed as additions to 40 CFR 60.24a but did not 
finalize are related to setting imminent and outermost dates for the consideration of remaining useful life and consideration of RULOF to apply more stringent standards of performance. See 88 FR 80480, 80525, 80529 (November 17, 2023). 
92088 FR 80528 (November 17, 2023). 921See id. at 80527. performance that are more stringent 
than the degree of emission limitation determined by the EPA and compliance schedules that require final compliance more quickly than specified in the applicable emission guidelines. 40 CFR 60.24a(i). States do not have to use the RULOF provisions in 40 CFR 60.24a(e)– (h) to apply a more stringent standard of performance or faster compliance schedule. 
The EPA notes that there were a 
number of RULOF provisions proposed as additions to the general implementation regulations in subpart Ba and discussed in the proposed emission guidances that the EPA did not finalize as part of that separate rulemaking. Any proposed RULOF requirements that were not finalized in 40 CFR 60.24a are likewise not being finalized in this action and do not apply as requirements under these emission guidelines. However, two considerations in particular remain relevant to states’ development of plans despite not being finalized as requirements: consideration of communities most impacted by and vulnerable to the health and environmental impacts of an affected 
EGU that is invoking RULOF, and the need to engage in reasoned decision making that is supported by information and a rationale that is included in the state plan.
919 
As explained in the preamble to the 
November 2023 final rule revising subpart Ba, consideration of health and environmental impacts is inherent in consideration of two factors, the non-air quality health and environmental impacts and amount of emission reduction, that the EPA considers under CAA section 111(a)(1). Therefore, a state considering whether a variance from the EPA’s degree of emission limitation is appropriate will necessarily consider the potential impacts and benefits of control to communities impacted by an affected EGU that is potentially receiving a less stringent standard of performance.
920Additionally, as 
discussed in section X.E.1.b.i of this preamble, the general implementing regulations for CAA section 111(d) in subpart Ba require states to submit, with their state plans or plan revisions, documentation that they have conducted meaningful engagement with pertinent stakeholders and/or their representative in the plan (or plan 
revision) development process. 40 CFR 60.23a(i). The application of a less stringent standard of performance or longer compliance schedule pursuant to RULOF can impact the effects a state plan has on pertinent stakeholders, which include, but are not limited to, industry, small businesses, and communities most affected by and/or vulnerable to the impacts of a state plan or plan revision. See 40 CFR 60.21a(l). Therefore, the potential application of less stringent standards of performance or longer compliance schedule should be part of a state’s meaningful engagement on a state plan or plan revision. 
Similarly, the EPA emphasized in the 
preamble to the November 2023 final rule revising subpart Ba that states carry the burden of making any demonstrations in support of less- stringent standards of performance pursuant to RULOF in developing their plans. As a general matter, states always bear the responsibility of reasonably documenting and justifying the standards of performance in their plans. In order to find a standard of performance satisfactory, the EPA must be able to ascertain, based on the information and analysis included in the state plan submission, that the standard meets the statutory and regulatory requirements.
921 
Comment: Multiple commenters 
expressed support for the EPA’s proposed approach to RULOF, including its framework for ensuring that less stringent standards of performance and longer compliance schedules are limited to unique circumstances that reflect fundamental differences from the circumstances that the EPA considered, and that such standards do not undermine the overall effectiveness of the emission guidelines. These commenters also noted that the proposed RULOF approach is consistent with CAA section 111(d). However, other commenters argued that the EPA lacks authority to put restrictions on how states consider RULOF to apply less stringent standards of performance or longer compliance schedules. Some commenters stated that the EPA’s framework for the consideration of RULOF runs counter to section 111’s framework of cooperative federalism and that the EPA has a limited role of determining BSER for the source 
category while the statute reserves significant authority for the states to establish and implement standards of performance. One commenter elaborated that the broad discretion given to states to establish standards of 
performance gives the EPA only a limited role in reviewing states’ RULOF demonstrations. 
Response: The provisions that will 
govern states’ use of RULOF under these emission guidelines are contained in the part 40, subpart Ba CAA section 111(d) implementing regulations. Following proposal of these emission guidelines, the EPA finalized revisions to the subpart Ba RULOF provisions in a separate rulemaking. Any comments on these generally applicable provisions, including the EPA’s authority to promulgate and implement them and consistency with the cooperative federalism framework of CAA section 111(d), are outside the scope of this action. The EPA has, however, considered and responded to comments that concern the application of these generally applicable RULOF provisions under these particular emission guidelines. 
Comment: Several commenters spoke 
to the role of RULOF given the structure of the proposed subcategories for coal- fired steam generating affected EGUs. Some commenters supported the EPA’s statement that, given the four proposed subcategories based on affected EGUs’ intended operating horizons, the Agency did not anticipate that states would be likely to need to invoke RULOF based on a particular affected EGU’s remaining useful life. In contrast, other commenters stated that the EPA was attempting to unlawfully preempt state consideration of RULOF. Some noted that, regardless of the approach to subcategorization, a particular source may still present source-specific considerations that a state may consider relevant when applying a standard of performance. One commenter referred to RULOF as a way for states to ‘‘modify’’ subcategories to address the circumstances of particular affected EGUs. 
Response: As explained in section 
VII.C of this preamble, the structure of the subcategories for coal-fired steam generating affected EGUs under these final emission guidelines differs from the four subcategories that the EPA proposed. The EPA is finalizing just two subcategories for coal-fired EGUs: the long-term subcategory and the medium- term subcategory. Under these 
circumstances, the justification for the EPA’s statement at proposal that it is unlikely that states would need to invoke RULOF based on a coal-fired steam generating affected EGU’s remaining useful life no longer applies. Consistent with 40 CFR 60.24a(e) and the Agency’s explanation in the proposal, states have the ability to 
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922See 88 FR 33383 (invoking RULOF based on 
a particular coal-fired EGU’s remaining useful life 
‘‘is not prohibited under these emission guidelines’’). 923The EPA also considered expanded use and 
development of technology in determining the BSER for each subcategory. However, as this consideration is not necessarily relevant at the scale of a particular source for which a less stringent standard of performance is being considered, it is not addressed here. consider, inter alia, a particular source’s 
remaining useful life when applying a 
standard of performance to that source.
922 
Moreover, the EPA is clarifying that 
RULOF may be used to particularize the compliance obligations for an affected EGU when a state demonstrates that it is unreasonable for that EGU to achieve the applicable degree of emission limitation or compliance schedule determined by the EPA. Invocation of RULOF does not have the effect of modifying the subcategory structure or creating a new subcategory for a particular affected EGU. That EGU remains in the applicable subcategory. As explained elsewhere in this section of the preamble, the particularized compliance obligations must differ as little as possible from the presumptive standard of performance and compliance schedule for the subcategory into which the affected EGU falls under these emission guidelines. 
Comment: One commenter requested 
that the EPA identify situations in which it is reasonable to deviate from the presumptive standards of performance in the emission guidelines and include presumptively approvable approaches for states to use when invoking RULOF. The commenter noted that this would reduce the regulatory burden on states developing and submitting plans. Another commenter, however, stated that the EPA should not provide any presumptively approvable standard, criteria, or analytic approach for states seeking to use RULOF. This commenter explained that the premise of source-specific variances under RULOF is that they reflect circumstances that are unique to a particular unit and fundamental differences from the general case, and that it would be inappropriate to offer a generic rubric for approving variances separate from the particularized facts of each case. 
Response: The EPA is not identifying 
circumstances in which it would be reasonable to deviate from its determinations or providing presumptively approvable approaches to invoking RULOF in these emission guidelines. For this source category— fossil-fuel fired steam generating EGUs—in particular, the circumstances and characteristics of affected EGUs and the control strategies the EPA has identified as BSER are extremely context- and source-specific. In order to invoke RULOF for a particular affected 
EGU, a state must demonstrate that it is unreasonable for that EGU to reasonably achieve the applicable degree of emission limitation or compliance schedule. Given the diversity of sizes, ages, locations, process designs, operating conditions, etc., of affected 
EGUs, it is highly unlikely that the circumstances that result in one affected EGU being unable to reasonably achieve the applicable presumptive standard or compliance schedule would apply to any other affected EGU. Further, the RULOF provisions of subpart Ba provide clarity for and guidance to states as to what constitutes a satisfactory less-stringent standard of performance under these emission guidelines. 
While the EPA is not providing 
presumptively approvable circumstances or analyses for RULOF in these emission guidelines, it is providing information and analysis that states can leverage in making any determinations pursuant to the RULOF provisions. As explained elsewhere in this section of the preamble, the EPA expects that states will be able to particularize the information it is providing in section VII of this preamble and the final Technical Support Documents for the circumstances of any affected EGUs for which they are considering RULOF, thereby decreasing the analytical burdens. 
Comment: Several commenters stated 
that the proposed emission guidelines did not provide adequate time for RULOF analyses. 
Response: As noted above, the EPA 
expects states to leverage the information it is providing in section VII of this preamble and the final Technical Support Documents in conducting any RULOF analyses under these emission guidelines. In particular, the Agency believes states will be able to use the information it is providing on available control technologies for affected EGUs, technical considerations, and costs given different amortization periods and particularize it for the purpose of conducting any analyses pursuant to 40 CFR 60.24a(e) and (f). Additionally, as discussed in section X.C.2.b of this preamble, the regulatory provisions for RULOF under subpart Ba provide a framework for determining less 
stringent standards of performance that have the practical effect of minimizing states’ analytical burdens. Given the EPA’s consideration of affected EGU’s circumstances and operational characteristics in designing these emission guidelines, the Agency does not anticipate that states will be in the position of conducting numerous RULOF analyses as part of their state 
planning processes. The EPA therefore believes that states will have sufficient time to consider RULOF and conduct any RULOF analyses under these emission guidelines. 
a. Threshold Requirements for 
Considering RULOF 
The general implementing regulations 
of 40 CFR part 60, subpart Ba, provide that a state may apply a less stringent standard of performance or longer compliance schedule than otherwise required under the applicable emission guidelines based on consideration of a particular source’s remaining useful life and other factors. To do so, the state must demonstrate for each designated facility (or class of such facilities) that the facility cannot reasonably achieve the degree of emission limitation determined by the EPA (i.e., the 
presumptively approvable standard of performance) based on: (1) Unreasonable cost resulting from plant age, location, or basic process design, (2) physical impossibility or technical infeasibility of installing the necessary control equipment, or (3) other factors specific to the facility. In order to 
determine that one or more of these circumstances has been met, the state must demonstrate that there are fundamental differences between the information specific to a facility (or class of such facilities) and the information the EPA considered in the applicable emission guidelines that make achieving the degree of emission limitation or compliance schedule in those guidelines unreasonable for the facility. 
For each subcategory of affected EGUs 
in these emission guidelines, the EPA determined the degree of emission limitation achievable through application of the BSER by considering information relevant to each of the factors in CAA section 111(a)(1): whether a system of emission reduction is adequately demonstrated for the subcategory, the costs of a system of emission reduction, the non-air quality health and environmental impacts and energy requirements associated with a system of emission reduction, and the extent of emission reductions from a system.
923As noted above, the relevant 
consideration for invoking RULOF is whether an affected EGU can reasonably achieve the presumptive standard of 
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924The EPA reiterates that states are not 
precluded from considering information and factors 
other than costs under 40 CFR 60.24a(e)(ii) and (iii). performance for the applicable 
subcategory, as opposed to whether it can implement the BSER. In determining the BSER the EPA found that certain costs, impacts, and energy requirements were, on balance, reasonable for affected EGUs; it is therefore reasonable to assume that the same costs, impacts, and energy requirements would be equally reasonable in the context of other systems of reduction, as well. Therefore, the information the EPA considered in relation to each of these factors is the baseline for consideration of RULOF regardless of the system of emission reduction being considered. 
The EPA is providing presumptive 
standards of performance in these emission guidelines in the form of rate- based emission limitations. Thus, the focus for states considering whether a particular affected EGU has met the threshold for a less stringent standard of performance pursuant to RULOF is whether that affected EGU can reasonably achieve the applicable rate- based presumptive standard of performance in these emission guidelines. 
Within each of the statutory factors it 
considered in determining the BSER, the Agency considered information using one or more evaluation metrics. For example, for both the long-term and medium-term coal-fired steam generating EGUs the EPA considered cost in terms of dollars/ton CO
2reduced 
and increases in levelized costs expressed as dollars per MWh electricity generation. Under the non-air quality health and environmental impacts and energy requirements factor, the EPA considered non-greenhouse gas emissions and energy requirements in terms of parasitic load and boiler efficiency, in addition to evaluation metrics specific to the systems being evaluated for each subcategory. For the full range of factors, evaluation metrics, and information the EPA considered with regard to the long-term and medium-term coal-fired steam generating EGU subcategories, see section VII.D.1 and VII.D.2 of this preamble. 
Although the considerations for 
invoking RULOF described in 40 CFR 60.24a(e) are broader than just unreasonable cost of control, much of 
the information the EPA considered in determining the BSER, and therefore many of the circumstances states might consider in determining whether to invoke RULOF, are reflected in the cost consideration. Where possible, states should reflect source-specific considerations in terms of cost, as it is an objective and replicable metric for comparison to both the EPA’s 
information and across affected EGUs and states.
924For example, 
consideration of pipeline length needed for a particular affected EGU is best reflected through consideration of the cost of that pipeline. In particular, consideration of the remaining useful life of a particular affected EGU should be considered with regard to its impact on costs. In determining the BSER, the EPA considers costs and specifically annualized costs associated with payment of the total capital investment associated with the BSER. An affected EGU’s remaining useful life and associated length of the capital recovery period can have a significant impact on annualized costs. States invoking RULOF based on an affected EGU’s 
remaining useful life should demonstrate that the annualized costs of applying the degree of emission limitation achievable through application of the BSER for a source with a short remaining useful life are fundamentally different from the costs that the EPA found were reasonable. For purposes of determining the annualized costs for an affected EGU with a shorter remaining useful life, the EPA considers the amortization period to begin at the compliance date for the applicable subcategory. 
States considering the use of RULOF 
to provide a less stringent standard of performance for a particular EGU must demonstrate that the information relevant to that EGU is fundamentally different from the information the EPA considered. For example, in determining the degree of emission limitation achievable through the application of co-firing for medium-term coal-fired steam generating EGUs, the EPA found that costs of $71/ton CO
2 
reduced and $13/MWh are reasonable. A state seeking to invoke RULOF for an affected coal-fired steam generating EGU based on unreasonable cost of control resulting from plant age, location, or basic process design would therefore, pursuant to 40 CFR 60.24a(e), demonstrate that the costs of achieving the applicable degree of emission limitation for that particular affected EGU are fundamentally different from $71/ton CO
2reduced and/or $13/MWh. 
Any costs that the EPA has 
determined are reasonable for any BSER for affected EGUs under these emission guidelines would not be an appropriate basis for invoking RULOF. Additionally, costs that are not fundamentally different from costs that the EPA has determined are or could be reasonable 
for sources would also not be an appropriate basis for invoking RULOF. Thus, costs that are not fundamentally different from, e.g., $18.50/MWh (the 
cost for installation of wet-FGD on a 300 MW coal-fired steam generating unit, used for cost comparison in section VIII.D.1.a.ii of this preamble) would not be an appropriate basis for invoking RULOF under these emission guidelines. On the other hand, costs that constitute outliers, e.g., that are greater 
than the 95th percentile of costs on a fleetwide basis (assuming a normal distribution) would likely represent a valid demonstration of a fundamental difference and could be the basis of invoking RULOF. 
Importantly, the costs evaluated in 
BSER determinations are, in general, based on average values across the fleet of steam generating units. Those BSER cost analysis values represent the average of a distribution of costs including costs that are above or below the average representative value. On that basis, implicit in the determination that those average representative values are reasonable is the determination that a significant portion of the unit-specific costs around those average representative values are also reasonable, including some portion of those unit-specific costs that are above but not significantly different than the average representative values. That is, the cost values the EPA considered in determining the BSER should not be considered bright-line upper thresholds between reasonable and unreasonable costs. Moreover, the examples in this discussion are provided merely for illustrative purposes; because each RULOF demonstration must be evaluated based on the facts and circumstances relevant to a particular affected EGU, the EPA is not setting any generally applicable thresholds or providing presumptively approvable approaches for determining what constitutes a fundamental difference in cost or any other consideration under these emission guidelines. The Agency will assess each use of RULOF in a state plan against the applicable regulatory requirements; however, the EPA is providing examples in this preamble in response to comments requesting that it provide further clarity and guidance on what constitutes a satisfactory use of RULOF. 
Under 40 CFR 60.24a(e)(1)(iii), states 
may also consider ‘‘other factors specific to the facility.’’ Such ‘‘other factors’’ may include both factors (categories of information) that the EPA did not 
consider in determining the degree of emission limitation achievable through 
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92588 FR 80517 (November 17, 2023). application of the BSER and additional 
evaluation metrics (ways of considering a category of information) that the EPA did not consider in its analysis. To invoke RULOF based on consideration of ‘‘other factors,’’ a state must demonstrate that a factor makes it unreasonable for the affected EGU to achieve the applicable degree of emission limitation in these emission guidelines. 
The general implementing regulations 
of subpart Ba provide that states may invoke RULOF for a class of facilities. In the preamble to the subpart Ba final rule, the EPA explained that ‘‘invoking RULOF and providing a less-stringent standard [of] performance or longer compliance schedule for a class of facilities is only appropriate where all the facilities in that class are similarly situated in all meaningful ways. That is, they must not only share the circumstance that is the basis for invoking RULOF, they must also share all other characteristics that are relevant to determining whether they can reasonably achieve the degree of emission limitation determined by the EPA in the applicable EG. For example, it would not be reasonable to create a class of facilities for the purpose of RULOF on the basis that the facilities do not have space to install the EPA’s BSER control technology if some of them are able to install a different control technology to achieve the degree of emission limitation in the EG.’’
925 
Given that individual fossil fuel-fired steam generating EGUs are very unlikely to be similarly situated with regard to all of the characteristics relevant to determining the reasonableness of meeting a degree of emission limitation, the EPA believes it would not likely be reasonable for a state to invoke RULOF for a class of facilities under these emission guidelines. That is, because there are relatively few affected EGUs in 
each subcategory and because each EGU is likely to have a distinct combination of size, operating process, footprint, geographic location, etc., it is highly 
unlikely that the same threshold analysis would apply to two or more units. 
i. Invoking RULOF for Long-Term Coal- 
Fired Steam Generating EGUs 
In determining the BSER for the long- 
term coal-fired steam generating EGUs, the EPA considered several evaluation metrics specific to CCS. However, affected EGUs are not required to implement CCS to comply with their standards of performance. To the extent a state is considering whether it is reasonable for a particular affected EGU 
in this subcategory to achieve the degree of emission limitation using CCS as the control strategy, the state would consider whether that affected EGU’s circumstances are fundamentally different from the evaluation metrics and information the EPA considered in these emission guidelines. If a state is considering whether it is reasonable for an affected EGU to achieve the degree of emission limitation for long-term coal- fired steam generating EGUs through some other control strategy, certain of the evaluation metrics and information the EPA considered, such as overall costs and energy requirements, would be relevant while other metrics or information may or may not be. 
As discussed above, the EPA 
considered costs in terms of $/ton CO
2 
reduced and $/MWh. The Agency broke down its cost consideration for CCS into capture costs and CO
2transport and 
sequestration costs, as discussed in sections VIII.D.1.a.ii.(A) and (B) of this preamble. The EPA also considered the availability of the IRC section 45Q tax credit in evaluating the cost of CCS for affected EGUs, and finally, evaluated the impacts of two different capacity factor assumptions on costs. Similarly, the Agency considered a number of evaluation metrics specific to CCS under the non-air quality health and environmental impacts and energy requirements factors, in addition to considering non-greenhouse gas emissions and parasitic/auxiliary energy demand increases and the net power output decreases. In particular, the EPA considered water use, CO
2capture plant 
siting, transport and geologic sequestration, and impacts on the energy sector in terms of long-term structure and reliability of the power sector. A state may also consider other factors and circumstances that the EPA did not consider in its evaluation of CCS, to the extent such factors or circumstances are relevant to the reasonableness of achieving the associated degree of emission limitation. 
As detailed in section VII.D.1.a.i of 
this preamble, the EPA has determined that CCS is adequately demonstrated for long-term coal-fired steam generating EGUs. The Agency evaluated the components of CCS both individually and in concurrent, simultaneous operation. If a state believes a particular affected EGU cannot reasonably implement CCS based on physical impossibility or technical infeasibility, the state must demonstrate that the circumstances of that individual EGU are fundamentally different from the 
information on CCS that the EPA considered in these emission guidelines. ii. Invoking RULOF for Medium-Term Coal-Fired Steam Generating EGUs 
As for the long-term coal-fired steam 
generating EGU subcategory, the EPA also considered evaluation metrics and information specific to the BSER, natural gas co-firing, for the medium- term subcategory. Again, similar to the long-term subcategory, certain generally applicable metrics and information that the EPA considered, e.g., overall costs 
and energy requirements, will be relevant regardless of the control strategy a state is considering for an affected EGU in the medium-term subcategory. To the extent a state is considering whether it is reasonable for a particular affected EGU to reasonably achieve the presumptive standard of performance using natural gas co-firing as a control, the state should evaluate whether there is a fundamental difference between the circumstances of that EGU and the information the EPA considered. In considering costs for natural gas co-firing, the Agency took into account costs associated with adding new gas burners and other boiler modifications, fuel cost, and new natural gas pipelines. In considering non-air quality health and environmental impacts and energy requirements, the EPA addressed losses in boiler efficiency due to co-firing, as well as non-greenhouse gas emissions and impact on the structure of the energy sector. States may also consider other factors and circumstances that are relevant to determining the reasonableness of achieving the applicable degree of emission limitation. 
iii. Invoking RULOF To Apply a Longer 
Compliance Schedule 
Under 40 CFR 60.24a(c), ‘‘final 
compliance,’’ i.e., compliance with the 
applicable standard of performance, ‘‘shall be required as expeditiously as practicable but no later than the compliance times specified’’ in the applicable emission guidelines, unless a state has demonstrated that a particular designated facility cannot reasonably comply with the specific compliance time per the RULOF provision at 40 CFR 60.24a(e). The EPA, in these emission guidelines, has detailed the amount of time needed for states and affected EGUs in the long-term and medium- term coal-fired steam generating EGU subcategories to comply with standards of performance using CCS and natural gas co-firing, respectively, in sections VII.C.1 and VII.C.2 of this preamble. These compliance times are based on information available for and applicable to the subcategories as a whole. The 
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926See 88 FR 80509–17 (November 17, 2023). 
927See id. at 80526–27. 
92840 CFR 60.20a(a). 929‘‘Other factors’’ may include facility-specific 
circumstances and factors that the EPA did not 
anticipate and consider in the applicable emission guideline that make achieving the EPA’s degree of emission limitation unreasonable for that facility. 88 FR 80480, 80521 (November 17, 2023). Agency anticipates that some affected 
EGUs will be able to comply more expeditiously than on these generally applicable timelines. Similarly, there may be circumstances in which a particular EGU cannot reasonably comply with its standard of performance by the compliance date specified in these emission guidelines. In order to provide a longer compliance schedule, the state must demonstrate that there is a fundamental difference between the information the EPA considered for the subcategory as a whole and the circumstances of a particular EGU. These circumstances should not be speculative; the state must substantiate the need for a longer compliance schedule with documentation supporting that need and justifying why a certain component or components of implementation will take longer than the EPA considered in these emission guidelines. If a state anticipates that a process or activity will take longer than is typical for similarly situated EGUs within and outside the state or longer than it has historically, the state should provide an explanation of why it expects this to be the case as well as evidence corroborating the reasons and need for additional time. Consistent with 40 CFR 60.24a(c) and (e), states should not use the RULOF provision to provide a longer compliance schedule unless there is a demonstrated, documented reason at the time of state plan submission that a particular source will not be able to achieve compliance by the date specified in these emission guidelines. The EPA notes that it is providing a number of flexibilities in these final emission guidelines for states and sources if they find, subsequent to state plan submission, that additional time is necessary for compliance; states should consider these flexibilities in conjunction with the potential use of RULOF to provide a longer compliance schedule. A source-specific compliance date pursuant to RULOF must be no later than necessary to address the fundamental difference; that is, it must be as close to the compliance schedule provided in these emission guidelines as reasonably possible. Considerations specific to providing a longer compliance schedule to address reliability are addressed in section X.C.2.e.i of this preamble. 
Comment: Several commenters stated 
that the EPA must respect the broad authority granted to states under the CAA and that while the EPA’s information on various factors is helpful to states, states may readily deviate from the emission guidelines in order to account for source- and state-specific 
characteristics. The commenters argued that the EPA’s general implementing regulations at 40 CFR 60.24a(c) recognize that states may consider factors that make application of a less stringent standard of performance or longer compliance time significantly more reasonable, and commenters stated that those factors should include, inter alia, cost, feasibility, infrastructure 
development, NSR implications, fluctuations in performance depending on load, state energy policy, and potential reliability issues. The commenters stated that states have the authority to account for consideration of other factors in various ways and that the EPA must defer to state choices, provided those choices are reasonable and consistent with the statute. 
Response: Comments on states’ use of 
RULOF vis-a `-vis the EPA’s 
determinations pursuant to CAA section 111(a)(1) in the applicable emission guidelines are outside the scope of this rulemaking.
926Similarly, comments on 
the EPA’s authority to review states’ use of RULOF in state plans and the scope of that review are outside the scope of this rulemaking.
927The EPA is also 
clarifying that, while the commenters are correct that the general implementing regulations at 40 CFR 60.24a(c) recognize that states may invoke RULOF to provide a less stringent standard of performance or longer compliance schedule, they also provide that, unless the threshold for the use of RULOF in 40 CFR 60.24a(e) has been met, ‘‘standards of 
performance shall be no less stringent than the corresponding emission guideline(s) . . . and final compliance shall be required as expeditiously as practicable but no later than the compliance times specified’’ in the emission guidelines. The threshold for invoking RULOF is when a state demonstrates that a particular affected EGU cannot reasonably achieve the degree of emission limitation determined by the EPA, based on one or more of the circumstances at 40 CFR 60.24a(e)(i)–(iii), because there are fundamental differences between the information the EPA considered in the emission guidelines and the information specific to the affected EGU. The ‘‘significantly more reasonable’’ standard does not apply to RULOF determinations under these emission guidelines.
928 
The EPA agrees that states have 
authority to consider ‘‘other circumstances specific to the facility.’’ 
States are uniquely situated to have knowledge about unit-specific considerations. If a unit-specific factor or circumstance is fundamentally different from the information the EPA considered and that difference makes it unreasonable for the affected EGU to achieve that degree of emission limitation or compliance schedule,
929it 
is grounds for applying a less stringent standard of performance or longer compliance schedule. The EPA will review states’ RULOF analyses and determinations for consistency with the applicable regulatory requirements at 40 CFR 60.24a(e)–(h). 
Comment: Multiple commenters 
weighed in on the subject of cost metrics. Two commenters stated that the EPA should not require states to consider costs using the same metrics that it considered in the emission guidelines. These commenters explained that the unique circumstances of each unit mean that different metrics may be appropriate and should be allowed as long as the state plan provides a justification. Other commenters, however, supported the proposed requirement for states to consider costs using the same metrics as the EPA. Similarly, commenters differed on the example in the proposed rule preamble that costs that are greater than the 95th percentile of costs on a fleetwide basis would likely be fundamentally different from the fleetwide costs that the EPA considered in these emission guidelines. While one commenter believed that the 95th percentile may not be an appropriate threshold in all circumstances and should not be treated as an absolute, another commenter argued that the EPA should formalize the 95th percentile threshold as a requirement for states seeking to invoke RULOF based on unreasonable cost. 
Response: The EPA believes that, in 
order to evaluate whether there is a fundamental difference between the cost information the EPA considered in these emission guidelines and the cost information for a particular affected EGU, it is necessary for states to evaluate costs using the same metrics that the EPA considered. However, states are not precluded from considering additional cost metrics alongside the two metrics used in these emission guidelines: $/ton of CO
2 
reduced and $/MWh of electricity 
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930See 88 FR 33384 (May 23, 2023). generated. States should justify why any 
additional cost metrics are relevant to determining whether a particular affected EGU can reasonably achieve the applicable degree of emission limitation. 
The EPA did not state that a cost that 
is greater than the 95th percentile of fleetwide costs would necessarily justify invocation of RULOF. Nor did the EPA intend to suggest that such costs are the only way states can demonstrate that the costs for a particular affected EGU are fundamentally different. While it may be an appropriate benchmark in some cases, there are other ways for states to demonstrate that the cost for a particular affected EGU is an outlier. That is, the EPA is not requiring that the unit- specific costs be above the 95th percentile in order to demonstrate that they are fundamentally different from the costs the Agency considered in these emission guidelines. As discussed elsewhere in this section of the preamble, the diversity in circumstances of individual affected EGUs under these emission guidelines makes it infeasible for the EPA to a priori define a bright line for what constitutes reasonable versus unreasonable costs for individual units in these emission guidelines. 
Comment: One commenter noted that 
the EPA should only approve the use of RULOF to provide a longer compliance schedule where there is clearly documented evidence (e.g., receipts, 
invoices, actual site work) that a source is making best endeavors to achieve 
compliance as expeditiously as possible. 
Response: The EPA believes this kind 
of evidence is strong support for providing a longer compliance schedule. The Agency further believes that states should show that the need to provide a longer compliance schedule is notwithstanding best efforts on the parts of all relevant parties to achieve timely compliance. The EPA is not, however, precluding the possibility that states could reasonably justify a longer compliance schedule based on other types of information or evidence. 
b. Calculation of a Standard of 
Performance That Accounts for RULOF 
If a state has demonstrated that a 
particular affected EGU is unable to reasonably achieve the applicable degree of emission limitation or compliance schedule under these emission guidelines per 40 CFR 60.24a(e), it may then apply a less stringent standard of performance or longer compliance schedule according to the process laid out in 40 CFR 60.24a(f). Pursuant to that process, the state must determine the standard of performance or compliance schedule that, respectively, is no less stringent or 
no longer than necessary to address the fundamental difference that was the basis for invoking RULOF. That is, the standard of performance or compliance schedule must be as close to the EPA’s degree of emission limitation or compliance schedule as reasonably possible for that particular EGU. 
The EPA notes that the proposed 
emission guidelines would have included requirements for how states determine less stringent standards of performance, including what systems of emission reduction states must evaluate and the order in which they must be evaluated. These proposed requirements were intended to ensure that states reasonably consider the controls that may qualify as a source-specific BSER.
930However, the final RULOF 
provisions in subpart Ba for determining less stringent standards of performance differ from the proposed subpart Ba provisions in a way that obviates the need for the separate requirements proposed in these emission guidelines. First, as opposed to determining a source-specific BSER for sources that have met the threshold requirements for RULOF, states determine the standard of performance that is no less stringent than the EPA’s degree of emission limitation than necessary to address the fundamental difference. Second, the process for determining such a standard of performance that the EPA finalized at 40 CFR 60.24a(f)(1) involves evaluating, to the extent necessary, the systems of emission reduction that the EPA identified in the applicable emission guidelines using the factors and evaluation metrics that the Agency considered in assessing those systems. Because the final RULOF provisions of subpart Ba create essentially the same process as the provisions the EPA proposed for determining a less stringent standard of performance under these emission guidelines, the EPA has determined it is not necessary to finalize those provisions here. 
The EPA anticipates that states 
invoking RULOF for affected EGUs will 
do so because an EGU is in one of two circumstances: it is implementing the control strategy the EPA determined is the BSER but cannot achieve the degree of emission limitation in the emission guideline using that control (or any other system of emission reduction); or it is not implementing the BSER and cannot reasonably achieve the degree of emission limitation using any system of emission reduction. 
If an affected EGU will be 
implementing the BSER but cannot meet the degree of emission limitation due to 
fundamental differences between the circumstances of that particular EGU and the circumstances the EPA considered in the emission guidelines, it may not be necessary for the state to evaluate other systems of emission reduction to determine the less stringent standard of performance. In this instance, the state and affected EGU would determine the degree of emission limitation the EGU can reasonably achieve, consistent with the requirement that it be no less stringent than necessary. That degree of emission limitation would be the basis for the less stringent standard of performance. For example, assume an affected EGU in the long-term coal-fired steam generating EGU subcategory is intending to install CCS and the state has demonstrated that it is not reasonably possible for the capture equipment at that particular EGU to achieve 90 percent capture of the mass of CO
2in the flue gas 
(corresponding to an 88.4 percent reduction in emission rate), but it can reasonably achieve 85 percent capture. If the source cannot reasonably achieve an 88.4 percent reduction in emission rate using any other system of emission reduction, the state may apply a less stringent standard of performance that corresponds to 85 percent capture without needing to evaluate further systems of emission reduction. 
In other cases, however, an affected 
EGU may not be implementing the BSER and may not be able to reasonably achieve the applicable degree of emission limitation (i.e., the 
presumptive standard of performance) using any control strategy. In such situations, the state must determine the standard of performance that is no less stringent than necessary by evaluating the systems of emission reduction the EPA considered in these emission guidelines, using the factors and evaluation metrics the EPA considered in assessing those systems. States may also consider additional systems of emission reduction that the EPA did not identify but that the state believes are available and may be reasonable for a particular affected EGU. 
The requirement at 40 CFR 
60.24a(f)(1) provides that a state must evaluate these systems of emission reduction to the extent necessary to 
determine the standard of performance that is as close as reasonably possible to the presumptive standard of performance under these emission guidelines. It will most likely not be necessary for a state to consider all of the systems that the EPA identified for 
a given affected EGU. For example, if the state has already determined it is not 
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931See, e.g., sections VII.C.1–4 of this preamble, 
the final TSD, GHG Mitigation Measures for Steam 
Generation Units, the CO 2Capture Project Schedule 
and Operations Memo, Documentation for the Lateral Cost Estimation, Transport and Storage Timeline Summary, and the Heat Rate Improvement Method Costs and Limitations Memo. 932The presumptive standards of performance for 
coal-fired steam-generating affected EGUs and base 
load and intermediate load natural gas- and oil-fired steam generating affected EGUs are in units of lb CO
2/MWh; thus, any standards of performance 
pursuant to consideration of RULOF must be determined in these units, as well. The presumptive standard of performance for low-load natural gas- 
fired and oil-fired affected EGUs are in units of lb CO
2/MMBtu. While the EPA does not expect that 
states will use the RULOF provisions to provide less stringent standards of performance for these sources because their BSER is based on uniform fuels, should a state do so, the standard of performance would be determined in units of lb CO
2/MMBtu. 93340 CFR 60.24a(f) requires that a standard of 
performance pursuant to consideration of RULOF 
be no less stringent than necessary to address the fundamental difference identified under 40 CFR 60.24a(e). If a particular affected EGU can install and operate CCS but only at such a low CO
2capture 
rate that it could reasonably achieve greater 
stringency based on natural gas co-firing, the state would apply a standard of performance based on natural gas co-firing. reasonably possible for an affected EGU 
to implement one of these control strategies, at any stringency, as part of its demonstration under 40 CFR 60.24a(e) that a less stringent standard of performance is warranted, the state does not need to evaluate that system again. Similarly, if a state starts by evaluating the system that achieves the greatest emission reductions and determines the affected EGU can implement that system, it is most likely not necessary for the state to consider the other systems on the list in order to determine that the resulting standard of performance is no less stringent than necessary. The Agency anticipates that states will leverage the information the EPA has provided regarding systems of emission reduction in these emission guidelines, as well as the wealth of other technical, cost, and related information on various control systems in the record for this final action, in conducting their evaluations under 40 CFR 60.24a(f). In many cases, it will be possible for states to use information the EPA has provided as a starting point and particularize it for the circumstances of an individual affected EGU.
931 
For systems of emission reduction 
that have a range of potential stringencies, states should start by evaluating the most stringent iteration that is potentially feasible for the particular affected EGU. If that level of stringency is not reasonable, the state should also evaluate other stringencies as may be needed to determine the standard of performance that is no less 
stringent than the applicable degree of emission limitation in these emission guidelines than necessary. 
In evaluating the systems of emission 
reduction identified in these emissions guidelines, states must also consider the factors and evaluation metrics that the EPA considered in assessing those systems, including technical feasibility, the amount of emission reductions, any non-air quality health and environmental impacts, and energy requirements. 40 CFR 60.24a(f)(1). They may also consider, in evaluating systems of emission reduction, other factors specific to the facility that constitute a fundamental difference between the information the EPA considered and the circumstances of the particular affected EGU and that were the basis of invoking RULOF for that particular EGU. For example, if a state 
determined that it is physically impossible or technically infeasible and/or unreasonably costly for a long- term coal-fired affected EGU to construct a CO
2pipeline because the 
EGU is located on a remote island, the state could consider that information in evaluating additional systems of emission reduction, as well. 
The general implementing regulations 
at 40 CFR 60.24a(f)(2) provide that any less stringent standards of performance that a state applies pursuant to RULOF must be in the form required by the applicable emission guideline. The presumptive standards of performance the EPA is providing in these emission guidelines are rate-based emission limitations. In order to ensure that a source-specific standard of performance is no less stringent than the EPA’s presumptive standard than necessary, the source-specific standard pursuant to RULOF must be determined and expressed in the form of a rate-based emission limitation. That is, the systems of emission reduction that states evaluate pursuant to 40 CFR 60.24a(f)(1) must be systems for reducing a source’s emission rate and the state must apply a standard of performance expressed as an emission rate, in lb CO
2/MWh,932 
that is no less stringent than necessary. As discussed in section X.D.1.b of this preamble, the EPA is not providing that affected EGUs with standards of performance pursuant to consideration of RULOF can use mass-based or rate- based compliance flexibilities under these emission guidelines. 
The general implementing regulations 
also provide that any compliance schedule extending more than twenty months past the state plan submission deadline must include legally enforceable increments of progress. 40 CFR 60.24a(d). Due to the timelines the EPA is finalizing under these emission guidelines, any affected EGU with compliance obligations pursuant to consideration of RULOF will have a compliance schedule that triggers the need for increments of progress in state plans. Because compliance obligations pursuant to RULOF are, by their nature, source-specific, the EPA is not providing particular increments of progress for sources for which RULOF has been invoked in these emission guidelines. Therefore, states must provide increments of progress for RULOF sources in their state plans that comply with the generally applicable requirements in 40 CFR 60.24a(d) and 40 CFR 60.21a(h). 
Additionally, 40 CFR 60.24a(h) 
requires that a less stringent standard of performance must meet all other applicable requirements of both the general implementing regulations and these emission guidelines. 
i. Determining a Less-Stringent Standard 
of Performance for Long-Term Coal Fired Steam Generating EGUs 
The EPA identified four potential 
systems of emission reduction for long- term coal-fired steam generating EGUs: CCS with 90 percent CO
2capture, CCS 
with partial CO 2capture/lower capture 
rates, natural gas co-firing, and HRI. If a state has demonstrated, pursuant to 40 CFR 60.24a(e), that a particular affected coal-fired EGU in the long-term subcategory can install and operate CCS but cannot reasonably achieve an 88.4 percent degree of emission limitation using CCS or any other systems of emission reduction, under the process laid out in 60.24a(f)(1) the state would proceed to evaluate CCS with lower rates of CO
2capture. The state would 
identify the most stringent degree of emission limitation the affected EGU can reasonably achieve using CCS and that degree of emission limitation would become the basis for the source’s less stringent standard of performance.
933 
If a state has demonstrated, pursuant 
to 40 CFR 60.24a(e), that a particular affected coal-fired EGU cannot reasonably install and operate CCS as a control strategy and cannot otherwise achieve the presumptive standard of performance, the state would proceed to evaluate natural gas co-firing and HRI as potential control strategies. Because 40 CFR 60.24a(f)(1) requires that a standard of performance be no less stringent than necessary to address the fundamental differences that were the basis for invoking RULOF, states would start by evaluating natural gas co-firing at 40 percent. If the affected EGU cannot 
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934See 40 CFR 60.24a(c). reasonably co-fire at 40 percent, the 
state would proceed to evaluate lower levels of natural gas co-firing unless it has demonstrated that the EGU cannot reasonably co-fire any amount of natural gas. If that is the case, the state would then evaluate HRI as a control strategy. The EPA notes that states may also consider additional systems of emission reduction that may be available and reasonable for particular EGUs. 
ii. Determining a Less-Stringent 
Standard of Performance for Medium- Term Coal Fired Steam Generating EGUs 
The EPA identified three potential 
systems of emission reduction for affected coal-fired steam generating EGUs in the medium-term subcategory: CCS, natural gas co-firing, and HRI. The EPA explained in section VII.D.2.b.i of this preamble that the cost effectiveness of CCS is less favorable for medium- term steam generating EGUs based on the short periods they have to amortize capital costs and utilize the IRC section 45Q tax credit. The EPA therefore believes that it would be reasonable for states determining a less stringent standard of performance for an affected EGU in the medium-term subcategory to forgo evaluating CCS as a potential control strategy. States would therefore start by evaluating lower levels of natural gas co-firing, unless a state has 
demonstrated pursuant to 40 CFR 60.24a(e) that the particular EGU cannot reasonably install and implement natural gas co-firing as a system of emission reduction. If that is the case, the state would evaluate HRI as the basis for a standard of performance that is no less stringent than necessary. 
The EPA expects that any coal-fired 
steam generating EGU to which a less stringent standard of performance is being applied will be able to reasonably implement some system of emission reduction; at a minimum, the Agency believes that all sources could institute approaches to maintain their historical heat rates. 
iii. Determining a Longer Compliance 
Schedule 
Pursuant to 40 CFR 60.24a(f)(1), a 
longer compliance schedule pursuant to consideration of RULOF must be no longer than necessary to address the fundamental difference identified pursuant to 40 CFR 60.24a(e). For states that are providing extensions to the schedules in the EPA’s emission guidelines, implementation of this requirement is straightforward. States should provide any information and analyses discussed in other sections of this preamble as relevant to justifying the need for, and length of, any 
compliance schedule extensions under the RULOF provisions. For states that are applying less stringent standards of performance that are based on a system of emission reduction other than the BSER for that subcategory, states should apply a compliance schedule consistent with installation and implementation of that system that is as expeditious as practicable.
934 
Comment: One commenter asserted 
that the 2023 proposed rule indicated that states invoking RULOF would be required to evaluate certain controls, in a certain order, as appropriate for subcategories of affected EGUs. The commenter stated that the EPA must defer to states’ consideration of other systems of emission reduction that the EPA has determined are not the BSER, including the manner in which the states choose to consider those systems. 
Response: The EPA is not finalizing 
the proposed requirements in these emission guidelines that would have specified the systems of emission reduction that states must consider when invoking RULOF and the order in which they consider them. The EPA is instead providing that states’ analyses and determinations of less stringent standards of performance pursuant to RULOF must be conducted in accordance with the generally applicable requirements of the part 60, subpart Ba implementing regulations; specifically, 40 CFR 60.24a(f). While the requirements under this regulation for determining less stringent standards of performance pursuant to RULOF are similar to the requirements proposed 
under these emission guidelines, they are also, as described above, more flexible because they provide (1) that states must consider other systems of emission reduction to the extent necessary to determine the standard of 
performance that is no less stringent than the EPA’s degree of emission limitation than necessary, and (2) that states may consider other systems of emission reduction, in addition to those the EPA identified in the applicable emission guidelines. 
c. Contingency Requirements 
Per the general implementing 
regulations at 40 CFR 60.24a(g), if a state 
invokes RULOF based on an operating condition within the control of an affected EGU, such as remaining useful life or a specific level of utilization, the state plan must include such operating condition or conditions as an enforceable requirement. The state plan must also include provisions that provide for the implementation and 
enforcement of the operating conditions, including requirements for monitoring, reporting, and recordkeeping. The EPA notes that there may be circumstances in which an affected EGU’s circumstances change after a state has submitted its state plan; states may always submit plan revisions if needed to alter an enforceable requirement therein. 
Comment: One commenter stated that 
if a state does not accept the presumptive standards of performance for a facility, it must establish federally enforceable retirement dates and operating conditions for that facility. The commenter asserted that the CAA does not authorize the EPA to constrain states’ discretion by requiring them to impose such restrictions as the price for exercising the RULOF authority granted by Congress. The commenter suggested that the EPA eliminate the requirement to include enforceable retirement dates and restrictions on operations in 
conjunction with a RULOF determination and stated that states should retain discretion to decide whether and when, based on RULOF, it is necessary to impose such restrictions on sources. 
Response: The EPA clarifies that 
states are in no way required to impose enforceable retirement dates or operating restrictions on affected EGUs under these emission guidelines. It is entirely within a state’s control to decide whether such a requirement is appropriate for a source. If a state determines that it is, in fact, appropriate to codify an affected EGU’s intention to cease operating or limit its operations as an enforceable requirement, the state may use such considerations as the basis for applying, as warranted, a less stringent standard of performance to that source. This allowance is provided under the subpart Ba general implementing regulations, 40 CFR 60.24a(g). 
d. More Stringent Standards of 
Performance in State Plans 
States always have the authority and 
ability to include more stringent standards of performance and faster compliance schedules as federally enforceable requirements in their state plans. They do not need to use the RULOF provisions to do so. See 40 CFR 60.24a(i). 
e. Interaction of RULOF and Other State 
Plan Flexibilities and Mechanisms 
The EPA discusses the ability of 
affected EGUs with standards of performance determined pursuant to 40 CFR 60.24a(f) to use compliance 
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935See, e.g., the North American Electric 
Reliability Corporation’s ‘‘Probabilistic Assessment: 
Technical Guideline Document,’’ August 2016. https://www.nerc.com/comm/RSTC/PAWG/proba _
technical_ guideline_ document_ 08082014.pdf. 
936The North American Electric Reliability 
Corporation (NERC)’s currently enforceable definition of ‘‘Planning Authority’’ is, ‘‘[t]he responsible entity that coordinates and integrates transmission Facilities and service plans, resource plans, and Protection Systems.’’ Glossary of Terms Used in NERC Reliability Standards, Updated April 1, 2024. https://www.nerc.com/pa/Stand/ Glossary%20of%20Terms/Glossary_ of_Terms.pdf. flexibilities under these emission 
guidelines in section X.D of this preamble. 
i. Use of RULOF To Address Reliability 
The EPA, in determining the degree of 
emission limitation achievable through 
application of the BSER for coal-fired steam generating EGUs, analyzed potential impacts of the BSERs on resource adequacy in addition to considering multiple studies on how reliability could be impacted by these emission guidelines. In doing so, the Agency considered potential large-scale (regional and national) and long-term impacts on the reliability of the electricity system under CAA section 111(a)(1)’s ‘‘energy requirements’’ factor. In evaluating CCS as a control strategy for long-term coal-fired steam generating EGUs, the Agency determined that CCS as the BSER would have limited and non-adverse impacts on the long-term structure of the power sector or on reliability of the power sector. See section VII.C.1.a.iii.(F) and final TSD, Resource Adequacy Analysis. Additionally, the EPA has made several adjustments to the final emission guidelines relative to proposal that should have the effect of alleviating any reliability concerns, including changing the scope of units covered by these actions and removing certain subcategories, including one that would have included an annual capacity factor limitation. See section XII.F of this preamble for further discussion. 
While the EPA has determined that 
the structure and requirements of these emission guidelines will not negatively impact large-scale and long-term reliability, it also acknowledges the more locationally specific, source-by- source decisions that go into maintaining grid reliability. For example, there may be circumstances in which a balancing authority may need to have a particular unit available at a certain time in order to ensure reliability of the larger system. As noted above, the structure and various mechanisms of these emission guidelines allow states and reliability authorities to plan for compliance in a manner that preserves grid operators’ 
abilities to maintain electric reliability. Specifically, coal-fired EGUs that are planning to cease operation do not have control requirements under these emission guidelines, the removal of the imminent-term and near-term subcategories means that states and reliability authorities have greater flexibility in the earlier years of implementation, and the EPA is providing two dedicated reliability mechanisms. Given these adjustments, the Agency believes there will remain very few, if any, circumstances in which states will need to provide particularized compliance obligations for an affected EGU based on a need to address reliability. However, there may be isolated instances in which a particular affected EGU cannot reasonably comply with the applicable requirements due to a source-specific reliability issue. Such unit-specific reliability considerations may constitute an ‘‘[o]ther circumstance[] specific to the facility’’ that makes it unreasonable for a particular EGU to achieve the degree of emission limitation or compliance schedule the EPA has provided in these emission guidelines. 40 CFR 60.24a(e)(1)(iii). The EPA is therefore confirming that states may use the RULOF provisions in 40 CFR 60.24a to apply a less stringent standard of performance or longer compliance schedule to a particular affected EGU based on reliability considerations. The EPA emphasizes that the RULOF provisions should not be used to provide a less stringent standard of performance if the applicable degree of emission limitation for an affected EGU is reasonably achievable. To do so would be inconsistent with CAA sections 111(d) and 111(a)(1). Thus, to the extent states and affected EGUs find it necessary to use RULOF to particularize these emission guidelines’ requirements for a specific unit based on reliability concerns, such adjustments should take the form of longer compliance schedules. 
In order to meet the threshold for 
applying a less stringent standard of performance or longer compliance schedule based on unit-specific reliability considerations under 40 CFR 60.24a(e), a state must demonstrate a fundamental difference between the information the EPA considered on reliability and the circumstances of the specific unit. This demonstration would be made by showing that requiring a particular affected EGU to comply with its presumptive standard of performance under the specified compliance timeframe would compromise reliability, e.g., by necessitating that the 
affected EGU be taken offline for a specific period of time during which a resource adequacy shortfall with adverse impacts would result. In order to make this demonstration, states must provide an analysis of the reliability risk if the particular affected EGU were required to comply with its applicable presumptive standard of performance by the compliance date, clearly demonstrating that the EGU is reliability critical such that requiring it to comply would trigger non-compliance with at 
least one of the mandatory reliability standards approved by FERC or cause the loss of load expectation to increase beyond the level targeted by regional system planners as part of their established procedures for that particular region. Specifically, this requires a clear demonstration that each unit for which use of RULOF is being considered would be needed to maintain the targeted level of resource adequacy.
935The analysis must also 
include a projection of the period of time for which the particular affected EGU is expected to be reliability critical. States must also provide an analysis by the relevant reliability Planning 
Authority
936that corroborates the 
asserted reliability risk and confirms that one or both of the circumstances would result from requiring the particular affected EGU to comply with its applicable requirements, and also confirms the period of time for which the EGU is projected to be reliability critical. The state plan must also include a certification from the Planning Authority that the claims are accurate and that the identified reliability problem both exists and requires the specific relief requested. 
To substantiate a reliability risk that 
stems from resource adequacy in particular, the analyses must also demonstrate that the specific affected EGU has been designated by the relevant Planning Authority as needed for resource adequacy and thus reliability, and that requiring that affected EGU to comply with the requirements in these emission guidelines would interfere with its ability to serve this function as intended by the Planning Authority. However, the EPA reiterates that the structure of the subcategories for coal-fired steam generating affected EGUs in these final emission guidelines differs from the proposal in ways that should provide states and affected EGUs wider latitude to make the operational decisions needed to ensure resource adequacy. Thus, again, the Agency expects that the circumstances in which states need to rely on consideration of RULOF to 
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937The mechanism described in section X.C.1.d 
of this preamble is not restricted to circumstances 
in which a state needs to provide an affected EGU with additional time to comply with its standard of performance specifically for reliability or resource adequacy, but it can be used for this purpose. The reliability mechanism described in section XII.F.3.b is specific to reliability and can be used to extend the date by which a source plans to cease operating by up to 1 year. particularize an affected EGU’s 
compliance obligation will be rare. 
The EPA will review these analyses 
and documentation as part of its evaluation of standards of performance and compliance schedules that states apply based on consideration of reliability under the RULOF provisions. 
As described in sections X.C.1.d and 
XII.F.3.b of this preamble, the EPA is providing two flexible mechanisms that states may incorporate in their plans that, if utilized, would provide a temporary delay of affected EGU’s compliance obligations if there is a demonstrated reliability need.
937The 
EPA anticipates that states discovering, after a state plan has been submitted and approved, that a particular affected EGU needs additional time to meet its compliance obligation as a result of a reliability or resource adequacy issue will avail themselves of these flexibilities. If a state anticipates that the reliability or resource adequacy issue will persist beyond the 1-year extension provided by these flexible mechanisms, the EPA expects that states will also initiate a state plan revision. In such a state plan revision, the state must make the demonstration and provides the analysis described above in order to use to adjust an affected EGU’s compliance obligations to address the reliability or resource adequacy issue at that time. 
The EPA intends to continue 
engagement on the topic of electric system reliability, resource adequacy, and linkages to various EPA regulatory efforts to ensure proper communication with key stakeholders and Federal counterparts including DOE and FERC. Additionally, the Agency intends to coordinate with its Federal partners with expertise in reliability when evaluating RULOF demonstrations that invoke this consideration. There are also opportunities to potentially provide information and technical support on implementation of these emission guidelines and critical reliability considerations that will benefit states, affected sources, system planners, and reliability authorities. Specifically, the DOE–EPA MOU on Electric System Reliability provides a framework for ongoing engagement, and the EPA intends to work with DOE to ensure that reliability stakeholders have additional and ongoing opportunities to engage 
EPA on this important topic. 
Comment: The EPA received multiple 
comments on the use of the RULOF provisions to address reliability. Several commenters emphasized that states need the ability to adjust affected EGUs’ compliance obligations for reasons linked to reliability. They elaborated that an independent system operator/ regional transmission organization determination that an affected EGU is needed for reliability would be anchored in a RULOF analysis that considers forces that may drive the unit’s premature retirement. Some commenters indicated that use of RULOF to address such units would allow those units to continue to operate for the required period of time, applying routine methods of operation, to address grid reliability. They similarly noted that sources that have foreseeable retirement glidepaths but are key resources could be offered a BSER that promotes the EPA’s carbon reduction goals but falls outside of the Agency’s one-size-fits-all BSER approach. 
Another commenter suggested that 
states should be able to modify a subcategory in their plans to address a reliability issue, and provided the example of allowing a unit that is planning to retire at the end of 2032 but that is needed for reliability purposes at greater than 20 percent capacity factor to subcategorize as an imminent-term unit despite operating past the end date for the imminent-term subcategory. The commenter suggested that such a modification could be justified under both the remaining useful life consideration and the energy requirements consideration of RULOF. Other commenters similarly requested that the EPA clarify that the RULOF provisions can be used to accommodate the changes in the power sector, e.g., the 
build-out of transmission and distribution infrastructure, that are ongoing and that may impact the anticipated operating horizons of some affected EGUs. 
Response: As explained above, the 
EPA has analyzed the potential impacts of these emission guidelines and determined that they would have limited and non-adverse impacts on large-scale and long-term reliability and resource adequacy. However, the EPA 
acknowledges that there may be reliability-related considerations that apply at the level of a particular EGU that the Agency could not have known or foreseen and did not consider in its broader assessment. As described above, states may use the RULOF provision to address reliability or resource adequacy if they demonstrate, based on the analysis and consultation with planning authorities described in this section of this preamble, that there is a fundamental difference between the information the EPA considered in these emission guidelines and the circumstances and information relevant to a particular affected EGU that makes it unreasonable for that EGU to comply with its presumptive standard of performance by the applicable compliance date. 
The EPA stresses that a generic or 
unsubstantiated reliability or resource adequacy concern is not sufficient to substantiate a fundamental difference or unreasonableness of complying with applicable requirements. Simply asserting that grid reliability or resource adequacy is a concern for a state and thus an affected EGU needs a less stringent standard of performance or longer compliance schedule would not be sufficient. Rather, a state would have to demonstrate, via the certification and analysis described above, that the relevant planning authority has designated a particular affected EGU as reliability or resource adequacy critical and that requiring that EGU to comply with its standard of performance by the applicable compliance date would interfere with the maintenance of reliability or resource adequacy as intended by that planning authority. 
A standard of performance or 
compliance schedule that has been particularized for an affected EGU based on consideration of reliability or resource adequacy must, pursuant to 40 CFR 60.24a(f), be no less stringent than necessary to address the fundamental difference identified pursuant to 40 CFR 60.24a(e), which in this case would be unit-specific grid reliability or resource adequacy needs. A less stringent standard of performance does not necessarily correspond to a standard of performance based on routine methods of operation and maintenance. 
The EPA notes that states do not need 
to use the RULOF provisions to justify the date on which a particular affected EGU plans to cease operation. RULOF only comes into play if there is a fundamental difference between the information the EPA considered and the information specific to an affected EGU with a shorter remaining useful life that makes achieving the EPA’s presumptive standard of performance unreasonable,, e.g., the amortized cost of control. If a 
state elects to rely on an affected EGU’s operating conditions, such as a plan to permanently cease operation, as the basis for applying a less stringent standard of performance, those conditions must be included as an 
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enforceable commitment in the state 
plan. 
As explained elsewhere in this 
section of the preamble, the effect of RULOF is not to modify subcategories under these emission guidelines but rather to particularize the compliance obligations of an affected EGU within a given subcategory. The EPA also notes that it is not finalizing the proposed imminent-term or near-term subcategories for affected coal-fired steam generating EGUs. 
ii. Use of RULOF With Compliance Date 
Extension Mechanism 
As discussed in section X.C.1.d of the 
preamble to this final rule, the EPA is allowing states to include in their plans a mechanism to provide a compliance deadline extension of up to 1 year for certain affected EGUs. This mechanism would be available for affected EGUs with standards of performance that require add-on control technologies and that demonstrate the extension is needed for installation of controls due to circumstances outside the control of the affected EGU. In the event the state and affected EGU believe that 1 year will not be sufficient to remedy those circumstances, i.e., that the affected 
EGU will not be able to comply with its standard of performance even with a 1- year extension, the state may also start the process of revising its plan to apply a longer compliance schedule based on consideration of RULOF. In order to demonstrate that there is a fundamental difference between the circumstances of the affected EGU and the information the EPA considered in determining the compliance schedule in the emission guidelines, the state should provide documentation to justify why it is unreasonable for the affected EGU to meet that compliance schedule, even with an additional year (providing that the state has allowed for a 1-year extension), based on one or more of the considerations in 40 CFR 60.24a(e)(1). This documentation should demonstrate that the need to provide a longer compliance schedule was due to circumstances outside the affected EGU’s control and that the affected EGU has met all relevant increments of 
progress and other obligations in a timely manner up to the point at which the delay occurred. That is, the state must demonstrate that the need to invoke RULOF and to provide a longer compliance schedule was not caused by self-created circumstances. As discussed in sections X.C.1.d and X.C.2.a of this preamble, documentation such as permits obtained and/or contracts entered into for the installation of control technology, receipts, invoices, and correspondence with vendors and regulators is helpful evidence for demonstrating that states and affected EGUs have been making progress towards compliance and that the need for a longer compliance schedule is due to circumstances outside the affected EGU’s control. 
In establishing a longer compliance 
schedule pursuant to 40 CFR 60.24a(f)(1), a state must demonstrate that the revised schedule is no longer than necessary to accommodate circumstances that have resulted in the delay. 
3. Increments of Progress for Medium- 
Term and Long-Term Coal-Fired Steam Generating EGUs 
The EPA’s longstanding CAA section 
111 implementing regulations provide that state plans must include legally enforceable Increments of Progress (IoPs) toward achieving compliance for each designated facility when the compliance schedule extends more than a specified length of time from the state plan submission date. Under the subpart Ba revisions finalized in November 2023, IoPs are required when the final compliance deadline (i.e., the date on 
which affected EGUs must start monitoring and reporting emissions data and other information for purposes of demonstrating compliance with standards of performance) is more than 20 months after the plan submittal deadline. These emission guidelines for steam EGUs finalize a 24-month state plan submission deadline and compliance dates of January 1, 2032 (for long-term coal-fired EGUs), and January 1, 2030 (for all other steam generating EGUs), exceeding subpart Ba’s 20-month threshold. Under these emission guidelines, in particular, the lengthy planning and construction processes associated with the CCS and natural gas co-firing BSERs make IoPs an appropriate mechanism to assure steady progress toward compliance and to provide transparency on that progress. 
The EPA received support for the 
proposed approach to IoPs from many commenters; others, however, offered adverse perspectives. Supportive commenters generally emphasized the need for clear, transparent, and enforceable implementation checkpoints between state plan submittal and the compliance dates given the lengthy timelines affected EGUs are being afforded to achieve their standards of performance. These comments were broadly consistent with the proposed rationale for the IoPs. Adverse comments are addressed at the end of this subsection of the preamble. The EPA is finalizing IoPs for affected 
EGUs based on BSERs that involve 
installation of emissions controls: long- term coal-fired EGUs and medium-term coal-fired EGUs. Units complying through the BSER specified for each subcategory, either CCS for the long- term subcategory or natural gas co-firing for the medium-term subcategory, must use IoPs tailored to those BSERs. Units complying through a different control technology must adopt increments that correspond to each of the steps in 40 CFR 60.21a(h). As specified in the proposal, each increment must be assigned a calendar date deadline, but states have discretion to set those dates based on the unique circumstances of each unit. The EPA is also finalizing its proposal to exempt the natural gas- and oil-fired EGU subcategories from IoP requirements. These subcategories have BSERs of routine operation and maintenance, which does not require the installation of significant new emission controls or operational changes. 
The EPA is finalizing the proposed 
approach allowing states to choose the calendar dates for all IoPs for long- and medium-term coal-fired EGUs, subject to two constraints. The IoP corresponding to 40 CFR 60.21a(h)(1), submittal of a final control plan to the air pollution control agency, must be assigned the earliest calendar date deadline among the increments, and the IoP corresponding to 40 CFR 60.21a(h)(5), final compliance, must be assigned a date aligned with the compliance date for each subcategory, either January 1, 2032, for the long-term subcategory or January 1, 2030, for the medium-term subcategory. The EPA believes that this approach will provide states and EGUs with flexibility to account for idiosyncrasies in planning processes, tailor compliance timelines to individual facilities, allow simultaneous work toward separate increments, and ensure full performance by the compliance date. 
For coal-fired EGUs assigned to the 
long-term and medium-term subcategories and that adopt the corresponding BSER (CCS or natural gas co-firing, respectively) as their compliance strategy, the EPA is finalizing BSER-specific IoPs that correspond to the steps in 40 CFR 60.21a(h). Some increments have been adjusted to more closely align with planning, engineering, and construction steps anticipated for affected EGUs that will be complying with standards of performance with natural gas co-firing or CCS, in particular; however, these 
technology-specific increments retain the basic structure and substance of the 
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increments in the general implementing 
regulations under subpart Ba. In addition, consistent with 40 CFR 60.24a(d), the EPA is finalizing similar additional increments of progress for the long-term and medium-term coal-fired subcategories that are specific to pipeline construction in order to ensure timely progress on the planning, permitting, and construction activities related to pipelines that may be required to enable full compliance with the applicable standard of performance. The EPA is also finalizing an additional increment of progress related to the identification of an appropriate sequestration site for the long-term coal- fired subcategory. Finally, the EPA is finalizing a requirement that state plans must require affected EGUs with increments of progress to post the activities or actions that constitute the increments, the schedule required in the state plan for achieving them, and, within 30 business days, any documentation necessary to demonstrate that they have been achieved to the Carbon Pollution Standards for EGUs website, as discussed in section X.E.1.b.ii of this preamble, in a timely manner. 
For coal-fired steam generating units 
in the long-term subcategory adopting CCS as their compliance approach, the EPA is finalizing the following seven IoPs as enforceable elements required to be included in a state plan: (1) Submission of a final control plan for the affected EGU to the appropriate air pollution control agency. The final control plan must be consistent with the subcategory declaration in the state plan and must include supporting analysis for the affected EGU’s control strategy, including a feasibility and/or FEED study, the anticipated timeline to achieve full compliance, and the benchmarks anticipated along the way. (2) Awarding of contracts for emission control systems or for process modifications, or issuance of orders for the purchase of component parts to accomplish emission control or process modification. Affected EGUs can demonstrate compliance with this increment by submitting sufficient evidence that the appropriate contracts have been awarded. (3) Initiation of onsite construction or installation of emission control equipment or process change required to achieve 90 percent CO
2capture on an annual basis. (4) 
Completion of onsite construction or installation of emission control equipment or process change required to achieve 90 percent CO
2capture on an 
annual basis. (5) Demonstration that all permitting actions related to pipeline construction have commenced by a date specified in the state plan. Evidence in support of the demonstration must include pipeline planning and design documentation that informed the permitting process(es), a complete list of pipeline-related permitting applications, including the nature of the permit sought and the authority to which each permit application was submitted, an attestation that the list of pipeline- related permits is complete with respect to the authorizations required to operate the facility at full compliance with the standard of performance, and a timeline to complete all pipeline permitting activities. (6) Submittal of a report identifying the geographic location where CO
2will be injected 
underground, how the CO 2will be 
transported from the capture location to the storage location, and the regulatory requirements associated with the sequestration activities, as well as an anticipated timeline for completing related permitting activities. (7) Final compliance with the standard of performance. States must assign calendar deadlines for each increment consistent with the following requirements: the first increment, submission of a final control plan, must be assigned the earliest calendar date among the increments; the seventh increment, final compliance must be set for January 1, 2032. 
For coal-fired steam generating units 
in the long-term subcategory adopting a compliance approach that differs from CCS, the EPA is finalizing the requirement that states adopt IoPs for each affected EGU that are consistent with the IoPs at 40 CFR 60.21a(h). As with long-term units adopting CCS as their compliance strategy, states must assign calendar deadlines for each increment consistent with the following requirements: the first increment, corresponding to 40 CFR 60.21a(h)(1), must be assigned the earliest calendar date among the increments; the final increment, corresponding to 40 CFR 60.21a(h)(5), must be set for January 1, 2032. 
For coal-fired steam generating units 
in the medium-term subcategory adopting natural gas co-firing as their compliance approach, the EPA is finalizing the following six IoPs as enforceable elements required to be included in a state plan: (1) Submission of a final control plan for the affected EGU to the appropriate air pollution control agency. The final control plan must be consistent with the subcategory declaration in the state plan and must include supporting analysis for the affected EGU’s control strategy, including the design basis for modifications at the facility, the anticipated timeline to achieve full compliance, and the benchmarks anticipated along the way. (2) Awarding of contracts for boiler modifications, or issuance of orders for the purchase of component parts to accomplish such modifications. Affected EGUs can demonstrate compliance with this increment by submitting sufficient evidence that the appropriate contracts have been awarded. (3) Initiation of onsite construction or installation of any boiler modifications necessary to enable natural gas co-firing at a level of 40 percent on an annual average basis. (4) Completion of onsite construction of any boiler modifications necessary to enable natural gas co-firing at a level of 40 percent on an annual average basis. (5) Demonstration that all permitting actions related to pipeline construction have commenced by a date specified in the state plan. Evidence in support of the demonstration must include pipeline planning and design documentation that informed the permitting application process, a complete list of pipeline-related permitting applications, including the nature of the permit sought and the authority to which each permit application was submitted, an attestation that the list of pipeline- related permit applications is complete with respect to the authorizations required to operate the facility at full compliance with the standard of performance, and a timeline to complete all pipeline permitting activities. (6) Final compliance with the standard of performance. States must also assign calendar deadlines for each increment consistent with the following requirements: the first increment, submission of a final control plan, must be assigned the earliest calendar date among the increments; the sixth increment, final compliance, must be set for January 1, 2030. 
For coal-fired steam generating units 
in the medium-term subcategory adopting a compliance approach that differs from natural gas co-firing, the EPA is finalizing the requirement that states adopt IoPs for each affected EGU that are consistent with the increments in 40 CFR 60.21a(h). 
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93888 FR 33390 (May 23, 2023). As with medium-term units adopting 
natural gas co-firing as their compliance strategy, states must assign calendar deadlines for each increment consistent with the following requirements: the first increment, corresponding to 40 CFR 60.21a(h)(1), must be assigned the earliest calendar date among the increments; the final increment, corresponding to 40 CFR 60.21a(h)(5), must be set for January 1, 2030. 
The EPA notes that if an affected EGU 
receives approval for a compliance date extension, the date for at least one, if not several, IoPs must be adjusted to align with the revised compliance date. The new dates for the relevant IoPs must be specified in the application for the extension. The EPA notes that the last increment—final compliance—should be no later than 1 year after the original compliance date, pursuant to the requirements described in section X.C.1.d. 
Comment: The EPA received 
comments that the proposed IoPs are too restrictive and may limit certain implementation flexibilities, namely that the burden to adjust IoPs after state plan submittal will limit sources’ ability to switch subcategories or adjust implementation timelines due to unforeseen circumstances. 
Response: The EPA has considered 
these comments and notes that the final rule includes planning flexibilities to address these situations. The first of these flexibilities is embedded in the subpart Ba regulations governing optional state plan revisions. Plan revisions, including revisions to subcategory assignments and any corresponding IoPs, may be used at a state’s discretion to account for changes in planned compliance approaches. 40 CFR 60.28a. Such revisions can also include RULOF-based adjustments to approved standards of performance as well as the timelines to meet those standards, including the IoPs. Further, as mentioned above, the compliance date extension mechanism described in section X.C.1.d allows for modification of the IoPs to align with an approved compliance date extension. In addition, the subcategory structure of these final emission guidelines differs from that at proposal such that it is less likely that affected coal-fired EGUs will switch subcategories. In the event that an 
affected EGU does switch between the long-term and medium-term subcategories, the state plan revision process is the most appropriate mechanism because a different control strategy may be appropriate. Based on this consideration and the availability of planning flexibilities to account for changes in compliance plans and changed circumstances, the EPA is 
finalizing the approach to IoPs as proposed. 
Comment: Some commenters raised 
concerns related to length of time between the state plan submittal deadline and the final compliance dates, namely that some IoPs will take place too far into the future to be reliably assigned calendar date deadlines. 
Response: As noted above, the EPA 
has concluded that length of time between the state plan submittal deadline and the compliance deadlines for units in the medium-term and long- term subcategories as well as the anticipated complexity for units to comply with the final standards of performance necessitate the use of discrete interim checkpoints prior to final compliance, formally established as increments of progress, to ensure timely and transparent progress toward each unit’s compliance obligation. It would be inconsistent to determine that the same factors necessitating the increments—the length of time between the state plan submittal deadline and the compliance obligation as well as the complex nature of the implementation process—also eliminate the IoPs’ core 
accountability function by prohibiting the assignment of calendar date deadlines. Finally, as described above, the final emission guidelines also allow states and affected EGUs significant flexibility to determine when each increment applies. 
Comment: Some commenters raised 
concerns that the IoPs could limit affected EGUs from selecting compliance approaches that differ from the BSER technology associated with each subcategory, namely averaging and trading. 
Response: Under the approach 
finalized in this rule, units assigned to the long-term and medium-term subcategories that do not adopt the associated BSER as part of their compliance strategy must establish date- specified IoPs consistent with the subpart Ba IoPs codified at 40 CFR 60.21a(h). That is, states will particularize the generic IoPs in subpart Ba as appropriate for affected EGUs that comply with their standards of performance using control technologies other than CCS (for long-term units) or natural gas co-firing (for medium-term units). The EPA discusses considerations relevant to averaging and trading in section X.D of this preamble. 
4. Reporting Obligations and Milestones 
for Affected EGUs That Plan to Permanently Cease Operations 
The EPA proposed legally enforceable 
reporting obligations and milestones for affected EGUs demonstrating that they 
plan to cease operations and use that voluntary commitment for eligibility for the imminent-term, near-term, or medium-term subcategory. No reporting obligations and milestones were proposed for affected EGUs within the long-term subcategory since a voluntary commitment to cease operations was not part of the subcategory’s applicability criteria. The proposed rationale for the milestone requirements recognized that the proposed subcategories were based on the operating horizons of units within each subcategory, and that there were numerous steps that EGUs in these subcategories need to take in order to effectuate their commitments to cease operations. The proposed reporting obligations and milestones were intended to provide transparency and assurance that affected EGUs could complete the steps necessary to qualify for a subcategory with a less stringent standard of performance.
938 
Of the proposed subcategories for 
which the reporting obligations and milestones were proposed to apply, the EPA’s final emission guidelines retain only the medium-term coal-fired subcategory. Though the EPA is finalizing only one subcategory with an associated operational time horizon, the Agency has determined that the original rationale for the milestones is still valid. That is, the BSER determination for EGUs assigned to the medium-term subcategory is contingent on sources within this subcategory having limited operating horizons relative to affected EGUs in the long-term subcategory, and the integrity of the subcategory approach and the environmental integrity of these emission guidelines depend on sources behaving consistent with the operating horizon they have represented in the state plan. The steps required for EGUs to cease operations are numerous and vary across jurisdictions; giving states, the EPA, and other stakeholders insight into these steps and affected EGUs’ progress along these steps provides assurance that they are on track to meeting their state plan requirements. The reporting obligations and milestones the EPA is finalizing under these emission guidelines are a reasonable approach to assuring transparency and timely compliance; they can also serve as an early indication that a state plan revision may be necessary if it becomes apparent that an affected EGU is not meeting its designated milestones. Further, the agency has determined that a similar rationale for requiring reporting obligations and milestones applies to 
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affected EGUs that invoke RULOF based 
on a unit’s remaining useful life. States may apply a less stringent standard of performance to a particular affected EGU if its shorter remaining useful life results in a fundamental difference between the circumstances of that EGU and the information the EPA considered, and that difference makes it unreasonable for the EGU to achieve the presumptive standard of performance. However, if such a unit continues to operate past the date by which it previously committed to cease operating, the basis for the less stringent standard of performance is abrogated and the environmental integrity of the emission guidelines compromised. Therefore, as for affected EGUs in the medium-term subcategory, the reporting obligations and milestones are an essential component of assuring that affected EGUs that invoke RULOF based on a unit’s remaining useful life are actually able to satisfy the condition of receiving the less stringent standard in the first instance. 
The EPA is finalizing the following 
milestones and reporting requirements, explained in more detail below, for both affected EGUs assigned to the medium- term subcategory and affected EGUs that invoke RULOF based on a unit’s remaining useful life. These sources must submit an Initial Milestone Report five years before the date by which it will permanently cease operations, annual Milestone Status Reports for each intervening year between the initial report and the date operations will cease, and a Final Milestone Status Report no later than six months from the date by which the affected EGU has committed to cease operating. 
Commenters expressed a range of 
views regarding the proposed reporting obligations and milestones. Some were broadly supportive of the reporting milestones and the EPA’s stated rationale to provide a mechanism to help ensure that affected EGUs progress steadily toward a commitment to cease operations when that commitment affects the stringency of their standard of performance. Summaries of and responses to additional comments on the reporting obligations and milestones are addressed at the end of this subsection. 
The discussion below refers to 
reporting ‘‘milestones.’’ Owners/ 
operators of sources take a number of process steps in preparing a unit to cease operating (i.e., preparing it to 
deactivate). The EPA is requiring that states select certain of these steps to serve as milestones for the purpose of reporting where a source is in the process; the EPA is designating two milestones in particular and states will 
select additional steps for reporting milestones. The requirements being established under these emission guidelines do not require milestone steps to be taken at any particular time—they merely require reporting on when a source intends to reach each of its designated milestones and whether and when it has actually done so. The reporting obligations and milestone requirements count backward from the calendar date by which an affected EGU has committed to permanently cease operations, which must be included in the state plan, to monitor timely progress toward that date. Five years before any planned date to permanently cease operations or 60 days after state plan submission, whichever is later, the owner or operator of affected EGUs must 
submit an Initial Milestone Report to the applicable air pollution control agency that includes the following: (1) A summary of the process steps required for the affected EGU to permanently cease operation by the date included in the state plan, including the approximate timing and duration of each step and any notification requirements associated with deactivation of the unit. (2) A list of key milestones that will be used to assess whether each process step has been met, and calendar day deadlines for each milestone. These milestones must include at least the initial notice to the relevant reliability authority of an EGU’s deactivation date and submittal of an official retirement filing with the EGU’s reliability authority. (3) An analysis of how the process steps, milestones, and associated timelines included in the Initial Milestone Report compare to the timelines of similar EGUs within the state that have permanently ceased operations within the 10 years prior to the date of promulgation of these emission guidelines. (4) Supporting regulatory documents, including correspondence and official filings with the relevant regional transmission organization (RTO), independent system operator (ISO), balancing authority, public utility commission (PUC), or other applicable authority; any deactivation-related reliability assessments conducted by the RTO or ISO; and any filings pertaining to the EGU with the United States Securities and Exchange Commission (SEC) or notices to investors, including but not limited to references in forms 10–K and 10–Q, in which the plans for the EGU are mentioned; any integrated resource plans and PUC orders approving the EGU’s deactivation; any reliability analyses developed by the RTO, ISO, or relevant reliability authority in response to the EGU’s deactivation notification; any notification from a relevant reliability authority that the EGU may be needed for reliability purposes notwithstanding the EGU’s intent to deactivate; and any notification to or from an RTO, ISO, or balancing authority altering the timing of deactivation for the EGU. 
For each of the remaining years prior 
to the date by which an affected EGU has committed to permanently cease operations that is included in the state plan, it must submit an annual Milestone Status Report that addresses the following: (1) Progress toward meeting all milestones identified in the Initial Milestone Report; and (2) supporting regulatory documents and relevant SEC filings, including correspondence and official filings with the relevant regional transmission organization, balancing authority, public utility commission, or other applicable authority to demonstrate compliance with or progress toward all milestones. 
The EPA is also finalizing a provision 
that affected EGUs with reporting milestones associated with commitments to permanently cease operations would be required to submit a Final Milestone Status Report no later than 6 months following its committed closure date. This report would document any actions that the unit has taken subsequent to ceasing operation to ensure that such cessation is permanent, including any regulatory filings with applicable authorities or decommissioning plans. 
The EPA is finalizing a requirement 
that affected EGUs with reporting milestones for commitments to permanently cease operations must post their Initial Milestone Report, annual Milestone Status Reports, and Final Milestone Status Report, including the schedule for achieving milestones and any documentation necessary to demonstrate that milestones have been achieved, on the Carbon Pollution Standards for EGUs website, as described in section X.E.1.b, within 30 business days of being filed. The EPA recognizes that applicable regulatory authorities, retirement processes, and retirement approval criteria will vary across states and affected EGUs. The proposed milestone reporting requirements are intended to establish a general framework flexible enough to account for significant differences across jurisdictions while assuring timely planning toward the dates by which affected EGUs permanently cease operations. 
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939Zintgraff, Stacey. 2022. Monitoring Insights: 
Relative Accuracy in EPA CAMD’s Power Sector 
Emissions Data. www.epa.gov/system/files/ documents/2022-05/Monitoring%20Insights- %20Relative%20Accuracy.pdf. 940EPA. (2024). Rulemaking Notices for GHG 
Reporting. https://www.epa.gov/ghgreporting/ 
rulemaking-notices-ghg-reporting. 
941International Standards Organization (ISO) 
standard designated as CSA Group (CSA)/American National Standards Institute (ANSI) ISO 27916:2019, Carbon Dioxide Capture, 
Transportation and Geological Storage—Carbon Dioxide Storage Using Enhanced Oil Recovery (CO
2- 
EOR) (referred to as ‘‘CSA/ANSI ISO 27916:2019’’). 
942As described in 87 FR 36920 (June 21, 2022), 
both subpart RR and subpart VV (CSA/ANSI ISO 27916:2019) require an assessment and monitoring of potential leakage pathways; quantification of inputs, losses, and storage through a mass balance approach; and documentation of steps and approaches used to establish these quantities. Primary differences relate to the terms in their respective mass balance equations, how each defines leakage, and when facilities may discontinue reporting. Comment: Some commentors 
questioned the need for the milestone 
reports by pointing to existing closure enforcement mechanisms within their jurisdictions. 
Response: The existence of 
enforceable mechanisms in some jurisdictions does not obviate the need for the reporting milestones under these emission guidelines. First, the closure requirements, the nature of the enforcement mechanisms, and process requirements to cease operations will vary across different jurisdictions, and some jurisdictions may lack mechanisms entirely. The reporting milestones framework sets a uniform floor for reporting progress toward a commitment to cease operations, reducing differences in the quality and scope of information available to the EPA and public regarding closures. Second, the reporting milestones under these emission guidelines serve the additional purpose of transparency and allowing all stakeholders to have access to information related to affected EGUs’ ongoing compliance. 
Comment: Some commentors noted 
the unique EGU closure processes within their own jurisdictions and expressed concern as to whether the milestones requirements were too rigid to accommodate them. 
Response: The reporting milestones 
are designed to create a flexible reporting framework that can accommodate differences in state closure processes. States can satisfy the required elements of the milestone reports by explaining how the process steps for plant closures within their jurisdiction work and establishing milestones corresponding to the process steps required within individual jurisdictions. 
5. Testing and Monitoring Requirements 
a. Emissions Monitoring and Reporting 
The EPA proposed to require that 
state plans must include a requirement 
that affected EGUs monitor and report hourly CO
2mass emissions emitted to 
the atmosphere, total heat input, and total gross electricity output, including electricity generation and, where applicable, useful thermal output converted to gross MWh, in accordance with the 40 CFR part 75 monitoring, reporting, and recordkeeping requirements. The EPA is finalizing a requirement that affected EGUs must use a 40 CFR part 75 certified monitoring methodology and report the hourly data on a quarterly basis, with each quarterly report due to the Administrator 30 days after the last day in the calendar quarter. The 40 CFR part 75 monitoring provisions require most 
coal-fired boilers to use a CO
2 
continuous emissions monitoring system (CEMS), including both a CO
2 
concentration monitor and a stack gas flow monitor. Some oil- and gas-fired boilers may have options to use alternative measurement methodologies (e.g., fuel flow meters combined with 
fuel quality data). 
The EPA received comments 
supporting and opposing the requirement to use 40 CFR part 75 monitoring, reporting, and recordkeeping requirements. 
Comment: Commenters generally 
supported these requirements, noting that the majority of EGUs affected by this rule already monitor and submit emissions reports under 40 CFR part 75 under existing programs, including the Acid Rain Program and/or Regional Greenhouse Gas Initiative—a cooperative of several states formed to reduce CO
2emissions from EGUs. In 
addition, EGUs that are not required to monitor and report under one of those programs may have 40 CFR part 75 certified monitoring systems in place for the MATS or CSAPR. 
Response: The EPA agrees with these 
comments. Relying on the same monitors that are certified and quality assured in accordance with 40 CFR part 
75 reduces implementation costs and ensures consistent emissions data across regulatory programs. 
Comment: Some commenters focused 
on potential measurement bias of 40 CFR part 75 certified monitoring systems, with commenters split on whether the data are biased high or low. 
Response: The EPA disagrees that the 
data reported under 40 CFR part 75 are biased significantly high or low. Each CO
2CEMS must undergo regular quality 
assurance and quality control activities including periodic relative accuracy test audits (RATAs) where a monitoring system is compared to an independent monitoring system using EPA reference methods and NIST-traceable calibration gases. In a May 2022 study conducted by the EPA, the absolute value of the median difference between EGUs’ monitoring systems and independent monitoring systems using EPA reference methods was found to be approximately 2 percent for CO
2concentration 
monitors and stack gas flow monitors in the years 2017 through 2021.
939 b. CCS-Specific Technology Monitoring 
and Reporting 
Affected EGUs employing CCS must 
comply with relevant monitoring and reporting requirements specific to CCS. As described in the proposal, the CCS process is subject to monitoring and reporting requirements under the EPA’s GHGRP (40 CFR part 98). The GHGRP requires reporting of facility-level GHG data and other relevant information from large sources and suppliers in the U.S. The ‘‘suppliers of carbon dioxide’’ source category of the GHGRP (GHGRP subpart PP) requires those affected facilities with production process units that capture a CO
2stream for purposes 
of supplying CO 2for commercial 
applications or that capture and maintain custody of a CO
2stream in 
order to sequester or otherwise inject it 
underground to report the mass of CO 2 
captured and supplied. Facilities that inject a CO
2stream underground for 
long-term containment in subsurface geologic formations report quantities of CO
2sequestered under the ‘‘geologic 
sequestration of carbon dioxide’’ source category of the GHGRP (GHGRP subpart RR). In April 2024, to complement GHGRP subpart RR, the EPA finalized the ‘‘geologic sequestration of carbon dioxide with enhanced oil recovery (EOR) using ISO 27916’’ source category of the GHGRP (GHGRP subpart VV) to provide an alternative method of reporting geologic sequestration in association with EOR.
940 941 942  
As discussed in section VII.C.1.a.vii, 
the EPA is finalizing a requirement that any affected unit that employs CCS technology that captures enough CO
2to 
meet the standard and injects the captured CO
2underground must report 
under GHGRP subpart RR or GHGRP subpart VV. If the emitting EGU sends the captured CO
2offsite, it must transfer 
the CO 2to a facility subject to the 
GHGRP requirements, and the facility injecting the CO
2underground must 
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94388 FR 80533 (November 17, 2023). 
944The EPA has authorized trading or averaging 
as compliance methods in several emission 
guidelines. See, e.g., 70 FR 28606, 28617 (May 18, 
2005) (Clean Air Mercury Rule authorized trading) (vacated on other grounds); 40 CFR 60.24(b)(1) (subpart B CAA section 111 implementing regulations promulgated in 2005 allow states’ standards of performance to be based on an ‘‘allowance system’’); 80 FR 64662, 64840 (October 23, 2015) (CPP authorizing trading or averaging as a compliance strategy). In the recent final emission guidelines for the oil and natural gas industry, the EPA also finalized a determination that states are permitted sources to demonstrate compliance in the aggregate. 89 FR 16820 (March 8, 2024). report under GHGRP subpart RR or 
GHGRP subpart VV. These emission guidelines do not change any of the requirements to obtain or comply with a UIC permit for facilities that are subject to the EPA’s UIC program under the Safe Drinking Water Act. 
The EPA also notes that compliance 
with the standard is determined exclusively by the tons of CO
2captured 
by the emitting EGU. The tons of CO 2 
sequestered by the geologic sequestration site are not part of that calculation, though the EPA anticipates that the quantity of CO
2sequestered will 
be substantially similar to the quantity captured. To verify that the CO
2 
captured at the emitting EGU is sent to a geologic sequestration site, we are leveraging regulatory requirements under the GHGRP. The BSER is determined to be adequately demonstrated based solely on geologic sequestration that is not associated with EOR. However, EGUs also have the compliance option to send CO
2to EOR 
facilities that report under GHGRP subpart RR or GHGRP subpart VV. We also emphasize that these emission guidelines do not involve regulation of downstream recipients of captured CO
2. 
That is, the regulatory standard applies exclusively to the emitting EGU, not to any downstream user or recipient of the captured CO
2. The requirement that the 
emitting EGU transfer the captured CO 2 
to an entity subject to the GHGRP requirements is thus exclusively an element of enforcement of the EGU standard. This will avoid duplicative 
monitoring, reporting, and verification requirements between this proposal and the GHGRP, while also ensuring that the facility injecting and sequestering the CO
2(which may not necessarily be the 
EGU) maintains responsibility for these requirements. Similarly, the existing regulatory requirements applicable to geologic sequestration are not part of the final emission guidelines. 
D. Compliance Flexibilities 
In the finalized subpart Ba revisions, 
Adoption and Submittal of State Plans 
for Designated Facilities: Implementing Regulations Under Clean Air Act Section 111(d), the EPA explained that, under its interpretation of CAA section 111, each state is permitted to include compliance flexibilities, including flexibilities that allow affected EGUs to meet their emission limits in the aggregate, in their state plans. The EPA also explained that, in particular emission guidelines, the Agency may limit compliance flexibilities if necessary to protect the environmental outcomes of the guidelines.
943Thus, in 
the subpart Ba final rule the EPA 
returned to its longstanding position that CAA section 111(d) authorizes the EPA to approve state plans that achieve the requisite emission limitation through aggregate reductions from their sources, including through trading or averaging, where appropriate for a particular emission guideline and consistent with the intended environmental outcomes under CAA section 111.
944 
In developing both the proposed and 
final emission guidelines, the EPA heard from stakeholders that flexibilities are important in complying with standards of performance under these emission guidelines. The EPA proposed to allow states to incorporate emission trading and averaging into their plans under these emission guidelines, provided that states ensure that the use of such flexibilities will result in an aggregate level of emission reduction that is equivalent to each source individually achieving its standard of performance. 
Specifically, a variety of commenters 
from states, industry, RTO/ISOs, and NGOs emphasized the importance of allowing states to incorporate not only flexibilities that allow sources to demonstrate compliance in the aggregate, such as emission trading and averaging, but also unit-specific mass- based compliance into their plans. In particular, commenters expressed a strong preference for mass-based compliance mechanisms, whether unit- specific or emission trading, and cited reliability as a key driver of their support for such mechanisms. However, for the most part commenters did not provide detail on how flexibilities could be designed under the unique circumstances of these emission guidelines. In addition, many commenters did not specify as to the usefulness of certain compliance flexibilities for steam generating EGUs versus combustion turbine EGUs. Because these final emission guidelines only apply to steam generating EGUs, there are fewer affected EGUs that could partake in these flexibilities, which may limit their usefulness. A description of and responses to general comments on these compliance flexibilities can be found at the end of this subsection. 
The EPA notes that many other 
features of the final emission guidelines provide the type of flexibility that the commenters stated they wanted through the use of emission trading, averaging, and/or unit-specific mass-based compliance. First, as noted in section X.C.1.b of this preamble, compliance with presumptively approvable rate- based standards of performance is demonstrated on an annual basis, which already provides flexibility around mass emissions over an annual period (i.e., it 
affords the affected EGU the ability over the course of the year to vary its emission output, which may be useful if, for example, it needs to temporarily turn off its control equipment or otherwise increase its emission rate). Second, the EPA is finalizing two mechanisms, described in section XII.F of this preamble, to address reliability concerns raised by commenters: a short- term reliability mechanism that allows affected EGUs to operate above their standard of performance for a limited time in periods of emergency and a reliability assurance mechanism to ensure sufficient capacity is available. Finally, as described in section X.C.2 of this preamble, states may invoke RULOF to provide for less stringent standards of performance for affected EGUs under certain circumstances (states may invoke RULOF both at the time of initial state plan development as well as through state plan revision should the circumstances of an affected EGU change following state plan submission). 
The EPA believes that the use of 
compliance flexibilities, within the parameters specified in these emission guidelines, may provide some additional operational flexibility to states and affected EGUs in achieving the required emission reductions which, under these emission guidelines, are achieved specifically through cleaner performance. In particular, for aggregate compliance flexibilities like emission averaging and trading, affected EGUs may be able to capitalize on heterogeneity in economic emission reduction opportunities based on minor differences in marginal emission abatement costs and/or operating parameters among EGUs. This heterogeneity may provide some incentive among participating EGUs to overperform (i.e., operate even more 
cleanly than required by the applicable 
standard of performance, because of the opportunity to sell compliance 
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instruments to other units), while also 
providing some limited opportunity for other sources to vary their emission output. 
Therefore, the EPA is finalizing a 
determination that the use of compliance flexibilities, including emission trading, averaging, and unit- specific mass-based compliance, is permissible for affected EGUs in certain subcategories and in certain circumstances under these emission guidelines. Specifically, the EPA is allowing affected EGUs in the medium- and long-term coal-fired subcategories to utilize these compliance flexibilities. The scope of this allowance is tailored to ensure consistency with the fundamental principle under CAA section 111 that state plans maintain the stringency of the EPA’s BSER determination and associated degree of emission limitation as applied through the EPA’s presumptive standards of performance in the context of these emission guidelines. In addition, the EPA believes that the scope of this allowance is consistent and appropriate for providing an incentive for overperformance. Relatedly, the EPA is also providing further elaboration on what it means for states to demonstrate that implementation of a standard of performance using a rate- or mass-based flexibility is at least as stringent as unit- specific implementation of affected EGUs’ standards of performance. States are not required to allow their affected EGUs to use compliance flexibilities but can provide for such flexibilities at their discretion. In order for the EPA to find that a state plan that includes such flexibilities is ‘‘satisfactory,’’ the state plan must demonstrate how it will achieve and maintain the requisite level of emission reduction. 
The EPA stresses that any flexibilities 
involving aggregate compliance would be used to demonstrate compliance with an already-established standard of performance, rather than be used to establish a standard of performance in the first instance. The presumptive standards of performance that the EPA is providing in these emission guidelines are based on control strategies that are applied at the level of individual units. A compliance flexibility may change the way an affected EGU demonstrates compliance with a standard of performance (e.g., by 
allowing that EGU to surrender allowances from another unit in lieu of reducing a portion of its own emissions), but does not alter the benchmark of emission performance against which compliance is evaluated. 
This is in contrast to the RULOF mechanism, which, as described in section X.C.2 of this preamble, states may use to apply a different standard of performance with a different degree of emission limitation than the EPA’s presumptive standard. States incorporating trading or averaging would not need to undergo a RULOF demonstration for sources participating in trading or averaging programs because they are not altering those sources’ underlying standards of performance—just providing an additional way for sources to demonstrate compliance. 
While the EPA acknowledges 
widespread interest in the use of mass- based compliance, in the context of these particular emission guidelines, the Agency has significant concerns about the ability to demonstrate that mass- based compliance approaches achieve at least equivalent emission reduction as the application of rate-based, source- specific standards of performance. As explained in further detail in sections X.D.4 and X.D.5, the EPA is requiring the use of a backstop emission limitation, or backstop rate, in conjunction with mass-based compliance approaches (i.e., for both 
unit-specific mass-based compliance and mass-based emission trading) for both the long-term and medium-term coal-fired subcategories. However, the EPA is finalizing a presumptively approvable unit-specific mass-based compliance approach only for affected EGUs in the long-term subcategory. The use of mass-based compliance approaches—both unit-specific and trading—for affected EGUs in the medium-term coal-fired subcategory in particular poses a high risk of undermining the stringency of these emission guidelines due to inherent uncertainty about the future utilization of these sources. While the EPA is not precluding states from attempting to design mass-based approaches for affected EGUs in the medium-term coal- fired subcategory that satisfy the requirement of achieving at least equivalent stringency as rate-based implementation, the Agency was unable to devise an appropriate, implementable presumptively approvable approach for affected EGUs in the medium-term coal- fired subcategory and is therefore not providing one here. The EPA is also not providing a presumptively approvable approach to emission trading or averaging. Instead, the EPA intends to review emission trading or averaging programs in state plans on a case-by- case basis against the foundational principles for consistency with CAA section 111, as discussed in this section of the preamble. Section X.D.1 of this preamble 
discusses the fundamental requirement 
that compliance flexibilities maintain the level of emission reduction of unit- specific implementation, in order to inform states’ consideration of such flexibilities for any use in their state plans. It also addresses why limitations on the use of compliance flexibilities for certain subcategories are necessary to maintain the intended environmental outcomes of these emission guidelines. Sections X.D.2, X.D.3, X.D.4, and X.D.5 discuss each available type of compliance flexibility and provide information on how they can be used in state plans under these emission guidelines. Section X.D.6 provides information on general implementation features of emission trading and averaging programs that states must consider if they develop such a program. Section X.D.7 discusses interstate emission trading. Finally, section X.D.8 discusses considerations related to existing state programs and the inclusion of compliance flexibilities in a state plan under these emission guidelines. 
Comment: Commenters cited a variety 
of reasons supporting the use of compliance flexibilities, such as emission trading, averaging, and unit- specific mass-based compliance, in these emission guidelines, including the need for flexibility in meeting the degree of emission limitation defined by the BSER, the potential for more cost- effective compliance, and reliability purposes. 
Response: The EPA believes that, in 
certain circumstances, these flexibilities can provide some operational and cost flexibility to states and affected EGUs in complying with these emission guidelines and their standards of performance in state plans. However, as described above, the EPA is addressing reliability-related concerns primarily through other structural changes and mechanisms under these emission guidelines (see section XII.F of this preamble) that may obviate the need to use compliance flexibilities specifically to address reliability concerns. As a general matter, the EPA believes that compliance flexibilities such as emission trading and averaging provide some incentive for overperformance that 
could be beneficial to states and affected EGUs. 
The EPA is finalizing a determination 
that emission trading, averaging, and unit-specific mass-based compliance are permissible for certain subcategories under these emission guidelines, subject to the limitations described in section X.D.1 of this preamble. The EPA believes these limitations are necessary 
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94588 FR 80480 80533–35 (November 17, 2023). 
94688 FR 80534 (November 17, 2023). 
94788 FR 80535 (November 17, 2023). in the context of these emission 
guidelines in order to maintain the level of emission reduction of the EPA’s BSER determination and corresponding degree of emission limitation. 
Comment: Some commenters 
expressed opposition to the use of emission trading and averaging, citing the potential for emission trading and averaging programs to maintain or exacerbate existing disparities in communities with environmental justice concerns. 
Response: The EPA is cognizant of 
these concerns and believes that emission trading and averaging are not necessarily incompatible with environmental justice. The EPA is including limitations on the use of compliance flexibilities in state plans that should help address these EJ concerns. As discussed in more detail in section X.D.1, the EPA is restricting certain subcategories from using trading or averaging as well as, for mass-based compliance mechanisms, requiring the use of a backstop rate, to ensure that the use of compliance flexibilities maintains the level of emission reduction of the EPA’s BSER determination and corresponding degree of emission limitation as well as achieves the statutory objective of these emission guidelines to mitigate air pollution by requiring sources to operate more cleanly. The EPA notes that trading programs can be designed to include measures like unit-specific emission rates that assure that reductions and corresponding benefits accrue proportionally to communities with environmental justice concerns. The EPA also notes that states have the ability to add further features and requirements to emission trading and averaging programs than identified in these emission guidelines, or to forgo their use entirely. 
Pursuant to the requirements of 
subpart Ba, states are required to conduct meaningful engagement on all aspects of their state plans with pertinent stakeholders. This would necessarily include any potential use of flexibilities for sources to demonstrate compliance with the proposed standards of performance through emissions trading or averaging. As discussed in greater detail in section X.E.1.b.i of this preamble, meaningful engagement provides an opportunity for communities most affected by and vulnerable to the impacts of a plan to provide input, including input on any impacts resulting from the use of compliance flexibilities. 
Comment: Some commenters stated 
that allowing trading or averaging is not consistent with the legal opinion in 
West Virginia v. EPA. 
Response: This comment is outside 
the scope of this action. The EPA finalized its interpretation that CAA section 111 does not preclude states from including compliance flexibilities such as trading or averaging in their state plans (although the EPA may limit those flexibilities in particular emission guidelines if necessary to protect the environmental outcomes of those guidelines) when it revised the CAA section 111(d) implementing regulations in subpart Ba.
945As described in the 
final subpart Ba revisions, ‘‘in West Virginia v. EPA, the Supreme Court did 
not directly address the state’s authority to determine their sources’ control measures. Although the Court did hold that constraints apply to the EPA’s authority in determining the BSER, the Court’s discussion of CAA section 111 is consistent with the EPA’s interpretation that the provision does not preclude states from granting sources compliance flexibility.’’
946The 
EPA further explained in the preamble to the subpart Ba final rule that the West Virginia Court was clear that the focus 
of the case was exclusively on whether the EPA acted within the scope of its authority in establishing the BSER: ‘‘The Court did not identify any constraints on the states in establishing standards of performance to their sources, and its holding and reasoning cannot be extended to apply such constraints.’’
947 
The EPA reiterates that, under these 
emission guidelines, the BSER determinations are emission reduction technologies or strategies that apply to 
and reduce the emission rates of individual affected EGUs. Furthermore, states have the option of including emission trading or averaging in their states plans but are by no means required to do so. States that choose to include trading or averaging programs in their state plans are required to demonstrate that those programs are in the aggregate as stringent as each affected EGU individually achieving its rate-based standard of performance. Additionally, as explained elsewhere in sections X.D.4 and X.D.5 of this preamble, the EPA is requiring the use of a backstop emission rate in conjunction with mass-based compliance flexibilities, one result of which is that units cannot comply with their standards of performance merely by shifting their generation to other electricity generators. Therefore, the EPA’s BSERs in these emission guidelines are not based on generation 
shifting and, even if the EPA believed that West Virginia v. EPA implicated the 
use of compliance flexibilities, the permissible use of trading and averaging in this particular case does not implicate the Court’s concerns about generation shifting therein. 
1. Demonstrating Equivalent Stringency 
As stated in the section above, states 
are permitted to use emission trading, 
averaging, and unit-specific mass-based compliance in their plans for certain subcategories under these emission guidelines, provided that the plan demonstrates that any such use will achieve a level of emission reduction that is in the aggregate as environmentally protective as each affected EGU achieving its rate-based standard of performance. This requirement is rooted in the structure and purpose of CAA section 111. Most commenters supported the use of compliance flexibilities in these emission guidelines, and many explicitly expressed support for the EPA’s stringency criterion in this context. Commenters also requested greater clarity on how to demonstrate equivalent stringency in a state plan. In this section, the EPA describes foundational parameters for a demonstration of equivalence in the state plan as well as limitations on the availability of compliance flexibilities for certain affected EGUs, which stem from the EPA’s stringency criterion. Additionally, the EPA offers further explanation of how it will review state plan submissions to determine whether plans that include compliance flexibilities achieve an equivalent (or 
greater) level of emission reduction as each affected EGU individually complying with its unit-specific rate- based standard of performance. 
a. Requirements for Demonstrating 
Equivalent Stringency 
In their plans, states incorporating 
compliance flexibilities must first clearly demonstrate how they calculated the aggregate rate-based emission limitation (for rate-based averaging), mass limit (for unit-specific mass-based compliance), or mass budget (for mass- based emission trading) from unit- specific, rate-based presumptive standards of performance. (For rate- based trading, the standard of performance coupled with, if necessary, an adjustment based on the acquisition of compliance instruments, is used to demonstrate compliance.) In doing so, states must identify the specific affected EGUs that will be using compliance flexibilities; which flexibility each unit 
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will able to use; the unit-specific, rate- 
based presumptive standard of performance; and the standard of performance established in the plan for each unit (rate-based limit or mass limit) or set of units (aggregate rate-based emission limitation or mass budget). The state must document and justify the assumptions made in calculating an aggregate rate-based emission limitation, mass limit, or mass budget, such as how the calculation is weighted or, for mass- based mechanisms, the level of utilization of participating affected EGUs used to calculate the mass limit or budget. This requirement is discussed in more detail in the context of each type of compliance flexibility in the following subsections. 
Next, states must demonstrate how 
the compliance flexibility will maintain the requisite stringency, i.e., how the 
plan will maintain the aggregate level of emission reduction that would be achieved if each unit was individually complying with its rate-based standard of performance. As discussed in section X.C.1 of this preamble, an affected EGU’s standard of performance must generally be no less stringent than the corresponding presumptive standard of performance under these emission guidelines. This is true regardless of whether a standard of performance is expressed in terms of rate or mass. However, under an aggregate compliance approach, a unit may demonstrate compliance with that standard of performance by averaging its emission performance or trading compliance instruments (e.g., allowances) with other affected EGUs. Here, to ensure consistency with the level of emission reductions Congress expected under CAA section 111(a)(1), the state must also demonstrate that the plan overall achieves equivalent stringency, i.e., the same or better 
environmental outcome, as applying the EPA’s presumptive standards of performance to each affected EGU (after accounting for any application of RULOF). That is, in order for the EPA to find a state plan ‘‘satisfactory,’’ that plan must achieve at least the level of emission reduction that would result if each affected EGU was achieving its presumptive standard of performance (again, after accounting for any application of RULOF). 
The requirement that state plans 
achieve equivalent stringency to the EPA’s degree of emission limitation flows from the structure and purpose of CAA section 111, which is to mitigate air pollution that is reasonably anticipated to endanger public health or 
welfare. It achieves this outcome by requiring source categories that cause or contribute to dangerous air pollution to operate more cleanly. Unlike the CAA’s NAAQS-based programs, section 111 is not designed to reach a level of emissions that has been deemed ‘‘safe’’ or ‘‘acceptable’’; there is no air-quality target that tells states and sources when emissions have been reduced ‘‘enough.’’ Rather, CAA section 111 requires affected sources to reduce their emissions to the level that the EPA has determined is achievable through application of the best system of emission reduction, i.e., to achieve 
emission reductions consistent with the applicable presumptive standard of performance. Consistent with the statutory purpose of requiring affected sources to operate more cleanly, the EPA typically expresses presumptive standards of performance as rate-based emission limitations (i.e., limitations on 
the amount of a regulated pollutant that can be emitted per unit of output, per unit of energy or material input, or per unit of time). 
In the course of complying with a 
rate-based standard of performance under a state plan, an affected source takes actions that may or may not affect its ongoing emission reduction obligations. For example, a source may take certain actions that remove it from the source category, e.g., by switching 
fuel type or permanently ceasing operations. Upon doing so, the source is no longer subject to the emission guidelines. Or an affected source may choose to change its operating characteristics in a way that impacts its overall mass of emissions, e.g., by 
changing its utilization, in which case the source is still required to reduce its emission rate consistent with cleaner performance. In either instance, the changes in operation to one affected source do not implicate the obligations of other affected sources. Although changes to certain sources’ operation may reduce emissions from the source category, they do not absolve the remaining affected EGUs from the statutory obligation to reduce their emission rates consistent with the level that the EPA has determined is achievable through application of the BSER. While state plans may, when permitted by the applicable emission guidelines, allow affected sources to translate their rate-based presumptive standards of performance into mass limits and/or comply with their standards of performance in the aggregate through averaging or trading, the fundamental statutory requirement remains: the state plan must demonstrate that, even if individual affected sources are not necessarily achieving their presumptive rate-based 
standards of performance, the plan as a whole must provide for the same level of emission reduction for the affected EGUs as though they were. While states may choose to allow individual sources to emit more or less than the degree of emission limitation determined by the EPA, any compliance flexibilities must be designed to ensure that their use does not erode the emission reduction benefits that would result if each source was individually achieving its presumptive standard of performance (after accounting for any use of RULOF). 
For rate-based averaging and trading, 
discussed in more detail in sections X.D.2 and X.D.3 of this preamble, demonstrating an equivalent level of emission reduction is relatively straightforward, as a rate-based program inherently provides relatively stronger assurance of equivalence with individual rate-based standards of performance. This is due to the fact that the aggregate rate-based emission limitation (for rate-based averaging) or rate-based standard of performance with adjustment for compliance instruments (for rate-based trading) is calculated based on both the emission output and gross generation output (utilization) of the participating affected EGUs. In other words., a rate-based compliance flexibility, such as a rate-based unit- specific standard of performance, inherently adjusts for changes in utilization and preserves the imperative to operate more cleanly. For unit- specific mass-based compliance and mass-based trading, demonstrating equivalent stringency is more complicated, as the use of a mass limit or mass budget on its own may not guarantee that sources are achieving emission reductions commensurate with operating more cleanly. Thus the EPA is requiring that, in order to ensure that the emission outcome that would be achieved through unit-specific rate- based standards of performance are preserved, states must also include a backstop emission rate limitation, or backstop rate, for affected EGUs using a mass-based compliance flexibility, as discussed in more detail in sections X.D.4 and X.D.5 of this preamble. In addition, states employing a mass-based mechanism in their plans must show why assumptions underlying the calculation of utilization for the purposes of establishing a mass limit or mass budget are appropriately conservative to ensure an equivalent level of emission reduction, as discussed more in sections X.D.4 and 
X.D.5 of this preamble. 
In sum, states wishing to employ 
compliance flexibilities in their state 
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plans must demonstrate that the plan 
achieves at least equivalent stringency with each source individually achieving its standard of performance, bearing in mind the discussion and requirements in this section, as well as the discussion and requirements in the following sections specific to each type of mechanism. The EPA will review state plan submissions that include compliance flexibilities to ensure that they are consistent with CAA section 111’s purpose of reducing dangerous air pollution by requiring sources to operate more cleanly. In order for the EPA to find a state plan ‘‘satisfactory,’’ that plan must address each affected EGU within the state and demonstrate that the plan overall achieves at least the level of emission reduction that would result if each affected EGU was achieving its presumptive standard of performance, after accounting for any application of RULOF. 
b. Exclusion of Certain Affected EGUs 
From Compliance Flexibilities 
While the use of compliance 
flexibilities such as emission trading, averaging, and unit-specific mass-based compliance is generally permissible under these emission guidelines, the EPA indicated in the proposal that it may be appropriate for certain groups of sources to be excluded from using these flexibilities in order to ensure an equivalent level of emission reduction with each source individually achieving its standard of performance. In the proposed emission guidelines, the EPA expressed concerns about the use of compliance flexibilities for several subcategories that have BSER determinations of routine methods of operation and maintenance as well as those sources for which states have invoked RULOF to apply a less stringent standard of performance, as their inclusion may undermine the intended level of emission reduction of the BSER for other facilities. The EPA also questioned whether trading and averaging across subcategories should be limited in order to maintain the stringency of unit-specific compliance. Finally, the EPA questioned whether 
affected EGUs that receive the IRC section 45Q tax credit for permanent sequestration of CO
2may have an 
overriding incentive to maximize both the application of the CCS technology and total electric generation, leading to source behavior that may be non- responsive to the economic incentives of a trading program. 
In response to the request for 
comment on these concerns related to the appropriateness of emission trading and averaging for certain subcategories and for sources with a standard based 
on RULOF, the EPA received mixed feedback. Some commenters agreed with the EPA’s concerns about these subcategories participating in trading and averaging and that affected EGUs in these subcategories should be prevented from participating in an emission trading or averaging program. However, several commenters said that it was indeed appropriate to allow all subcategories as well as sources with a standard of performance based on RULOF to participate in trading and averaging and that the program would still achieve an equivalent level of emission reduction, even if those subcategories are of limited stringency. 
In response to the request for 
comment on whether emission trading and averaging should be allowed across subcategories in light of concerns over differing levels of stringency for different subcategories impacting overall achievement of an equivalent level of emission reduction, the EPA also received mixed feedback. Some commenters supported restricting trading and averaging across subcategories because of concerns that EGUs in a subcategory with a relatively higher stringency could acquire allowances from EGUs in a subcategory with a relatively lower stringency in order to comply instead of operating a control technology. Several commenters stated that trading across subcategories need not be limited because, as long as state plans are of an equivalent level of emission reduction, emission trading and averaging would still require the overall aggregate limit to be met. 
Taking into consideration the 
comments on the proposed emission guidelines as well as changes made to the subcategories in the final emission guidelines, the Agency is finalizing the following restrictions on the use of compliance flexibilities by certain subcategories. 
First, emission trading or averaging 
programs must not include affected EGUs for which states have invoked RULOF to apply less stringent standards of performance. The Agency believes that, because RULOF sources have a standard of performance tailored to individual source circumstances that is required to be as stringent as reasonably practicable, these sources should not 
need further operational flexibility and are also unlikely to be able to overperform to any significant or regular degree. This means that their participation in an emission trading or averaging program is, at best, unlikely to add any value to the program (in terms of opportunity for overperformance) or, at worst, may provide an inappropriate opportunity for other sources subject to a relatively more stringent presumptive standard of performance to underperform by obtaining compliance instruments from or averaging their emission performance with affected EGUs that are subject to a relatively less stringent standard of performance based on RULOF. This outcome undermines the ability of the state plan to demonstrate an equivalent level of emission reduction, as non-RULOF sources would face a reduced incentive to operate more cleanly. In addition, affected EGUs with a standard of performance based on RULOF are prohibited from using unit-specific mass-based compliance under these emission guidelines. This is due to the compounding uncertainty regarding how states will use RULOF to particularize the compliance obligations for an affected EGU and the future utilization of affected EGUs that may be subject to RULOF. The RULOF provisions are used where a particular EGU is in unique circumstances and may result in a less stringent standard of performance based on the BSER technology, a less stringent standard of performance based on a different control technology, a longer compliance schedule, or some combination of the three. The bespoke nature of compliance obligations pursuant to RULOF makes it difficult for the EPA to provide principles for and for states to design mass-based compliance strategies that ensure an equivalent level of emission reduction. Additionally, as previously discussed, there is a significant amount of uncertainty in the future utilization of certain affected EGUs, including those with standards of performance pursuant to RULOF. While there is no risk of implicating the compliance obligation of other sources in unit-specific mass- based compliance, the EPA believes that allowing RULOF sources to use unit- specific mass compliance would pose a significant risk in undermining the stringency of the state plan such that these sources may not be achieving the level of emission reduction commensurate with cleaner performance. 
Second, emission trading or averaging 
programs may not include affected EGUs in the natural gas- and oil-fired steam subcategories. The BSER determination and associated degree of emission limitation for affected EGUs in these subcategories do not require any improvement in emission performance and already offer flexibility to sources to account for varying efficiency at different operating levels. As a result, these sources are unlikely to be 
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responsive to an incentive towards 
overperformance, which means that their participation in an emission trading or averaging program is unlikely to add any value to the program (in terms of opportunity for overperformance). In addition, the EPA is concerned that the participation of these sources may undermine the program’s equivalence with the presumptive standards of performance, because other steam sources, which have a relatively more stringent degree of emission limitation, may be inappropriately incentivized to underperform by obtaining compliance instruments from or averaging their emission performance with affected EGUs in the natural gas- and oil-fired steam subcategories. This outcome undermines the ability of the state plan to demonstrate equivalent stringency by reducing the incentive for sources to operate more cleanly. In addition, affected EGUs in the natural gas- and oil-fired steam subcategories are prohibited from using unit-specific mass-based compliance. While there is no risk of implicating the compliance obligation of other sources in unit- specific mass-based compliance, the EPA believes, as previously stated, there is already sufficient flexibility offered to sources in the natural gas- and oil-fired steam subcategories, as the basis for subcategorizing these sources takes into account their varying efficiency at different operating levels. 
The EPA is allowing both coal-fired 
subcategories (both the medium- and long-term) to participate in all types of compliance flexibilities, within the parameters set by the EPA described in the following sections. The Agency believes, and many commenters agreed, that affected EGUs taking advantage of the IRC section 45Q tax credit may still benefit from the operational flexibility provided by emission trading and averaging, as well as unit-specific mass- based compliance. The Agency also believes that overperformance among these sources is possible and worth incentivizing through the use of compliance flexibilities. Incentivizing overperformance can lead to innovation in control technologies that, in turn, can lead to lower costs for, and greater emissions reductions from, control technologies. 
The EPA is not finalizing a restriction 
on trading or averaging across subcategories for the two subcategories that are permitted to participate in these flexibilities. This means that affected EGUs in the medium-term coal-fired subcategory may trade or average their 
compliance with affected EGUs in the long-term coal-fired subcategory. With the aforementioned restrictions on 
participation in trading and averaging, the EPA does not see a need to further restrict the ability of eligible sources to trade or average with other sources. 
2. Rate-Based Emission Averaging 
The EPA proposed to permit states to 
incorporate rate-based averaging into 
their state plans under these emission guidelines. In general, rate-based averaging allows multiple affected EGUs to jointly meet a rate-based standard of performance. The scope of such averaging could apply at the facility level (i.e., units located within a single 
facility) or at the owner or operator level (i.e., units owned by the same utility). 
A description of and responses to comments received on rate-based averaging can be found at the end of this subsection. 
As discussed in the proposed 
emission guidelines, averaging can provide potential benefits to affected sources by allowing for more cost effective and, in some cases, more straightforward compliance. First, averaging offers some flexibility for owners or operators to target cost effective reductions at certain affected EGUs. For example, owners or operators of affected EGUs might target installation of emission control approaches at units that operate more. Second, averaging at the facility level provides greater ease of compliance accounting for affected EGUs with a complex stack configuration (such as a common- or multi-stack configuration). In such instances, unit-level compliance involves apportioning reported emissions to individual affected EGUs that share a stack based on electricity generation or other parameters; this apportionment can be avoided by using facility-level averaging. 
The EPA is finalizing a determination 
that rate-based averaging is permissible for affected EGUs in the medium- and 
long-term coal-fired subcategories. The scope of rate-based averaging may be at the facility level or at the owner/ operator level within the state, as these are the circumstances under which rate- based averaging can provide significant benefits, as identified above, with minimal implementation complexity. Above this level (i.e., across owner/ 
operators or at the state or interstate level), the EPA has determined that a rate-based compliance flexibility must be implemented through rate-based trading, as described in section X.D.3 of this preamble. The EPA is establishing this limitation on the scope of averaging because it believes that the level of complexity associated with utilities, independent power producers, and states attempting to coordinate the real- 
time compliance information needed to assure that either all affected EGUs are meeting their individual standard of performance, or that a sufficient number of affected EGUs are overperforming to allow operational flexibility for other affected EGUs such that the aggregate standard of performance is being achieved, would curtail transparency and limit states’, the EPA’s, and stakeholders’ abilities to track timely compliance. For example, dozens of units trying to average their emission rates would require owners or operators from different utilities and independent power producers to share operating and emissions data in real time. Thus, due to likely limitations on the timely availability of compliance-related information across owners and operators and across states, which is necessary to ensure aggregate compliance, the EPA believes that it is appropriate to limit the scope of rate- based averaging to the facility level or the owner/operator level within one state in order to provide greater compliance certainty and thus better demonstrate an equivalent level of emission reduction. 
Demonstrating equivalence with unit- 
specific implementation of rate-based standards of performance in a rate-based averaging program is straightforward. A state would need to specify in its plan the group of affected EGUs participating in the averaging program that will demonstrate compliance on an aggregate basis, the unit-specific rate-based presumptive standard of performance that would apply to each participating affected EGU, and the aggregate compliance rate that must be achieved for the group of participating affected EGUs and how that aggregate rate is calculated, as described below. For states incorporating owner/operator- level averaging, the state plan would also need to include provisions that specify how the program will address any changes in the owner/operator for one or more participating affected EGUs during the course of program implementation to ensure effective implementation and enforcement of the program. Such provisions should be specified upfront in the plan and be self-executing, such that a state plan revision is not required to address such changes. 
To ensure an equivalent level of 
emission reduction with application of individual rate-based standards of performance, the EPA is requiring that the weighting of the aggregate compliance rate is done on an output 
basis; in other words, participating affected EGUs must demonstrate 
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compliance through achievement of an 
aggregate CO 2emission rate that is a 
gross generation-based weighted average of the required standards of performance of each of the affected EGUs that participate in averaging. Such an approach is necessary to ensure that the aggregate compliance rate is representative of the unit-specific standards of performance that apply to each of the participating affected EGUs. Commenters were generally supportive of this method of calculating an aggregate rate for a group of sources participating in averaging. The Agency emphasizes that only affected EGUs are permitted to be included in the calculation of an aggregate rate-based standard of performance as well as in an aggregate compliance demonstration of a rate-based standard of performance. 
Comment: Commenters supported the 
use of rate-based averaging on the grounds that it can provide operational flexibility to affected EGUs as well as the opportunity for owners and operators to optimize control technology investments. Many commenters supported averaging at the facility- and owner/operator-level as well as on a statewide or interstate basis. 
Response: The EPA believes that rate- 
based trading can provide some additional operational flexibility and is finalizing that rate-based averaging is permissible at the facility- and owner/ operator-level for affected EGUs in the medium- and long-term coal-fired subcategories. However, for reasons discussed above, the EPA believes that rate-based trading, rather than rate- based averaging, should be implemented where a state would like to implement a rate-based compliance flexibility at a state or interstate basis. 
3. Rate-Based Emission Trading 
The EPA proposed to permit states to 
incorporate rate-based trading into their 
state plans under these emission guidelines. In general, a rate-based trading program allows affected EGUs to trade compliance instruments that are generated based on their emission performance. A description of and responses to comments on rate-based trading can be found at the end of this subsection. 
The EPA notes that, like rate-based 
averaging, rate-based trading can provide some flexibility for owners or operators to target cost effective reductions at specific affected EGUs, but can heighten the flexibility relative to averaging by further increasing the number of participating affected EGUs. In addition, emission trading can provide incentive for overperformance. The proposed emission guidelines 
described how rate-based trading could 
work in this context. First, the EPA discussed how it expects states to denote the tradable compliance instrument in a rate-based trading programs as one ton of CO
2. A tradable 
compliance instrument denominated in another unit of measure, such as a MWh, is not fungible in the context of a rate-based emission trading program. A compliance instrument denominated in MWh that is awarded to one affected EGU most likely does not represent an equivalent amount of emissions credit when used by another affected EGU to demonstrate compliance, as the CO
2 
emission rates (lb CO 2/MWh) of the two 
affected EGUs are likely to differ. 
Each affected EGU is required under 
these emission guidelines to have a particular standard of performance, based on the degree of emission limitation achievable through application of the BSER, with which it would have to demonstrate compliance. Under a rate-based trading program, affected EGUs performing at a CO
2 
emission rate below their standard of performance would be awarded compliance instruments at the end of each calendar year denominated in tons of CO
2. The number of compliance 
instruments awarded would be equal to the difference between their standard of performance CO
2emission rate and 
their actual reported CO 2emission rate 
multiplied by their gross generation in MWh. Affected EGUs demonstrating compliance through a rate-based averaging program that are performing worse than their standard of performance would be required to obtain and surrender an appropriate number of compliance instruments when demonstrating compliance, such that their demonstrated CO
2emission 
rate is equivalent to their rate-based standard of performance. Transfer and use of these compliance instruments would be accounted for in the numerator (sum of total annual CO
2 
emissions) of the CO 2emission rate as 
each affected EGU performs its compliance demonstration. Compliance would be demonstrated for an affected EGU based on its reported CO
2emission 
performance (in lb CO 2/MWh) and, if 
necessary, the surrender of an appropriate number of tradable compliance instruments, such that the demonstrated lb CO
2/MWh emission 
performance is equivalent to (or lower than) the rate-based standard of performance for the affected EGU. 
The EPA is finalizing a determination 
that rate-based trading is permissible for 
affected EGUs in the medium- and long- term coal-fired subcategories. The Agency notes, as previously discussed, that rate-based trading (rather than averaging) must be utilized if the state wishes to establish a statewide or interstate rate-based compliance flexibility, in order to ensure compliance and equivalent stringency. For similar reasons, rate-based trading should also be utilized in lieu of owner/ operator-level averaging when an owner/operator wishes to use a rate- based compliance flexibility for a group of its units that are located in more than one state. 
Demonstrating equivalence with unit- 
specific implementation of rate-based standards of performance in a rate-based trading program is relatively straightforward. States would need to specify in their plans the affected EGUs participating in the trading program and their individual standards of performance. Under the method of rate- based trading described in this section, a compliance demonstration would be done for each participating affected EGU based on a combination of the reported emission performance and, if relevant, the surrender of compliance instruments. In addition, the EPA is requiring that the compliance instrument be denominated as one ton of CO
2(rather than another unit such as 
MWh). The Agency believes this requirement is necessary to ensure an equivalent level of emission reduction as application of individual rate-based standards of performance. 
An additional aspect of demonstrating 
equivalence is ensuring that the program achieves and maintains an equivalent level of emission reduction with standards of performance over time, which is much more certain in a rate-based trading program than in a mass-based program. Unlike mass-based trading programs, under which states must make assumptions about units’ future utilization that may become inaccurate as those units’ operations shift over time, rate-based trading programs do not rely on utilization assumptions. Utilization is already accounted for by default in a rate-based trading program. Thus, while mass- based compliance flexibilities require additional design features to ensure the continued accuracy of assumptions about utilization and thus emission limits or budgets over time, such features are not necessary in a rate- based trading program. 
Comment: While commenters broadly 
supported the use of rate-based emission trading under these emission guidelines, as it provides operational flexibility to affected EGUs, some commenters expressed concern that 
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948States may also elect to include the short-term 
reliability mechanism described in section XII.F.3.a 
in their plans to address grid emergency situations. rate-based trading could lead to an 
absolute increase in emissions. 
Response: The EPA notes that, as a 
general matter, CAA section 111 reduces emissions of dangerous air pollutants by requiring affected sources to operate more cleanly. Under the construct of these emission guidelines, so long as a rate-based trading program is appropriately designed to maintain the level of emission reduction that would be achieved through unit-specific, rate- based standards of performance, it would be consistent with CAA section 111. 
4. Unit-Specific Mass-Based Compliance 
Although the EPA discussed mass- 
based trading in the proposed emission 
guidelines, it did not specifically address whether states may include a related flexibility, unit-specific mass- based compliance, in their plans. Several commenters supported mass- based mechanisms, including both unit- specific mass-based compliance and mass-based trading. A description of and responses to comments on unit- specific mass-based compliance can be found at the end of this subsection. 
The EPA’s CAA section 111 
implementing regulations generally permit states to include mass-based limits in their plans, see 40 CFR 60.21a(f), subject to the requirement that standards of performance must be no less stringent than the presumptive standards of performance in the corresponding emission guidelines. 40 CFR 60.24a(c). However, the EPA has significant concerns about the use of unit-specific mass-based compliance in 
the context of these emission guidelines and the ability of states using this mechanism to ensure that such use will result in the same level of emission reduction that would be achieved by applying the rate-based standard of performance. These concerns arise both from the particular focus of these emission guidelines on emission reduction strategies that result in cleaner performance of affected EGUs, and the inherent uncertainty in predicting the utilization of affected EGUs during the compliance period, especially given the long lead times provided. 
Therefore, while the EPA is allowing 
states to include unit-specific mass- based compliance in their plans for affected coal-fired EGUs in the medium- and long-term subcategories, it is also requiring states to use a backstop emission rate in conjunction with the mass-based compliance demonstration. As discussed in section X.D.1 of this preamble, the EPA believes the use of a backstop rate is consistent with the focus on achieving cleaner performance. 
CAA section 111 requires the mitigation of dangerous air pollution, which is generally achieved under this provision by requiring affected sources to operate more cleanly. Thus, standards of performance are typically expressed as a rate. In these emission guidelines, in particular, the BSERs for affected EGUs are control technologies and other systems of emission reduction that reduce the amount of CO
2emitted per 
unit of electricity generation. The EPA is not precluding states from translating those unit-specific rate-based standards of performance into a mass-based limit (for unit-specific mass-based compliance) or budget (for emission trading). However, in order to ensure that the emission reductions required under CAA section 111 are achieved, mass-based limits or budgets must be accompanied by a backstop rate for purposes of demonstrating compliance. In addition, for coal-fired EGUs in the medium-term coal-fired subcategory in particular, it is critical that states’ assumptions about future utilization do not result in inaccurate mass-based limits or budgets that allow units to emit more than they would be permitted to under unit-specific, rate-based compliance. 
The EPA is finalizing a presumptively 
approvable unit-specific mass-based compliance approach for affected EGUs in the long-term coal-fired subcategory, including a methodology for the applicable backstop rate, but is not finalizing a presumptively approvable approach for affected EGUs in the medium-term coal-fired subcategory. As explained below, the EPA has not been able to determine a unit-specific mass- based compliance mechanism for medium-term coal-fired EGUs that would ensure that the mass limit is no less stringent than the presumptive standard of performance under these emission guidelines. 
In general, unit-specific mass-based 
compliance establishes a budget of allowable mass emissions (a mass limit) for an individual affected EGU based on the degree of emission limitation defined by its subcategory and a specified level of anticipated utilization. Standards of performance would be provided in the form of mass limits in tons of CO
2for each individual affected 
EGU, and compliance would be demonstrated through surrender of allowances, with each allowance representing a permit to emit one ton of CO
2. Unlike mass-based emission 
trading, under a unit-specific mass compliance mechanism, these 
allowances would not be tradable with other affected EGUs. To demonstrate compliance, the affected EGU would be 
required to surrender allowances in a number equal to its reported CO
2 
emissions during each compliance period. 
As detailed in section VII.C.1.a.i(B)(7), 
for affected coal-fired EGUs in the long- term subcategory that are installing CCS, considering the potential impacts of variable load, startups, and shutdowns, 90 percent CO
2capture is, in general, 
achievable over the course of a year. However, the EPA believes unit-specific mass-based compliance could provide some benefit by affording long-term affected coal-fired EGUs that adopt this mechanism even greater operational flexibility.
948For example, if an affected 
EGU encounters challenges related to the start-up of the CCS technology or needs to conduct maintenance of the 
capture equipment, unit-specific mass- based compliance would provide a path for the affected EGU to continue operating. At the same time, unit- specific mass-based compliance coupled with a backstop rate would generally ensure that units operate more cleanly and that the required level of emission reduction is achieved. As explained in more detail below, the EPA’s confidence regarding the equivalent stringency of this mass-based compliance approach for units in the long-term subcategory depends on the Agency’s confidence in the likely utilization of a unit that has adopted emissions controls—in this case, CCS. 
For affected EGUs in the long-term 
coal-fired subcategory, the EPA is providing a presumptively approvable approach to unit-specific mass-based compliance. To establish the presumptively approvable mass limit, the presumptively approvable rate (as described in section X.C.1.b.i of this preamble) would be multiplied by a level of gross generation (i.e., utilization 
level) corresponding to an annual capacity factor of 80 percent, which is the capacity factor used for the BSER analysis (see section VII.C.1.a.ii of this preamble) and represents expected utilization based on the incentive provided by the IRC section 45Q tax credit. In addition, under this approach, affected EGUs would need to meet a backstop emission rate, expressed in lb CO
2per MWh on a gross basis, 
equivalent to a reduction relative to baseline emission performance of 80 percent, on an annual calendar-year basis. The EPA believes this backstop rate represents a reasonable level of operational flexibility for affected EGUs 
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in the long-term subcategory, and it 
could provide flexibility for sources to employ other technologies (e.g., membrane and chilled ammonia capture technologies) that can achieve a similarly high degree of emission limitation to CCS with amine-based capture. States may deviate from this approach (however, as previously discussed, the approach must include a backstop rate) and deviations will be reviewed to ensure consistency with the statute and this rule when the EPA reviews the state plan. For example, states may wish to use an assumed utilization level of greater than 80 percent to establish a mass limit. In reviewing such an approach for reasonableness, the EPA would consider, among other things, whether an affected EGU’s capacity factor has historically been greater than 80 percent for any continuous 8 quarters of data. The EPA would review the supporting data and resulting mass limit for consistency with the statute. The EPA has confidence that the presumptively approvable approach achieves an equivalent level of emission reduction as the implementation of the individual presumptive standard of performance because of the high degree of stringency associated with this subcategory as well as the 45Q tax credit, which incentivizes units to maximize capture of CO
2as well as the utilization of the 
affected EGU. 
On the other hand, the EPA does not 
have the same confidence in a mass- based approach to unit-specific compliance for the medium-term coal- fired subcategory for two reasons: the uncertainty in the utilization of these affected EGUs and the relatively lower stringency of the subcategory (i.e., 16 
percent reduction relative to baseline emission performance), particularly as compared to the long-term subcategory. The EPA has not been able to develop a workable approach to mass-based compliance for these units that both preserves the stringency of the presumptive standard of performance and results in an implementable program for affected EGUs. 
First, there are significant challenges 
in selecting an appropriate utilization assumption for the purposes of generating a mass limit for affected EGUs in the medium-term subcategory. When setting the mass limit for a future time period, as would occur in a state plan under these emission guidelines, assumptions about the source’s anticipated level of utilization must be made. Estimating future utilization of affected EGUs in the medium-term 
subcategory is subject to a significant degree of uncertainty, driven by sector- wide factors including changes in 
relative fuel prices, new incentives for technology deployment provided by the IIJA and the IRA, and increasing electrification, as well as EGU-specific factors related to its age and/or operating characteristics. As described in the Power Sector Trends TSD, coal- fired EGUs tend to become less efficient as they age, which may impact utilities’ investment decisions and the utilization of these EGUs. In addition, affected EGUs in this subcategory are unlikely to be earning the IRC section 45Q tax credit, meaning they lack an incentive to maximize both utilization and control of emissions beyond what is required by the subcategory. 
The accuracy of this estimate of 
utilization is critical to maintaining the environmental integrity established by unit-specific, rate-based compliance under these emission guidelines. If a state assumes a level of utilization that is higher than an affected EGU actually operates during the compliance period, the resulting mass limit will be non- binding, i.e., may not reflect any 
emission reductions relative to what the unit would have emitted in the absence of these emission guidelines. In this case a backstop emission rate helps, but the unit would become subject to a de facto less-stringent standard of performance. This result does not preserve environmental integrity consistent with CAA section 111(a)(1). Conversely, assuming a level of utilization for the purpose of setting a mass limit that is lower than an affected EGU actually operates during the compliance period maintains the level of emission reduction of unit-specific, rate-based implementation but may have unintended effects on operational flexibility. Thus, the EPA believes that in many, if not most circumstances it will not be possible for states to accurately predict the future utilization of medium-term affected EGUs. 
Second, the EPA notes that the 
relatively lower stringency of the subcategory further complicates the calculation of an appropriate mass limit. Under mass-based compliance, the quantity of emission reductions that corresponds to a 16 percent reduction in CO
2emission rate is a relatively small 
reduction in terms of tons of CO 2. This 
relatively small reduction is likely to be subsumed by the uncertainty inherent in predicting the utilization of an affected EGU for purposes of determining its mass limit. That is, an EGU in the medium-term subcategory that assumes future utilization consistent with its historical baseline 
but reduces its emission rate by 16 percent would achieve, on paper at least, an emission reduction of 16 percent. However, if its utilization during the compliance period is more than 16 percent lower than it was in the past, the EGU using a mass-based compliance approach would face a reduced or completely eliminated obligation to improve its emission performance. In this case, mass-based compliance results in a lower level of emission reduction than unit-specific rate-based compliance. While this phenomenon is not likely to occur for long-term coal-fired affected EGUs given the much higher degree of stringency of the rate-based emission limitation and the greater certainty in future utilization, the EPA believes it would be widespread amongst medium-term affected EGUs. 
Thus, the EPA is not providing a 
presumptively approvable approach for unit-specific mass-based compliance for affected EGUs in the medium-term coal- fired subcategory. However, it is also not prohibiting states from, in their discretion, allowing the use of unit- specific mass-based compliance. For such use to be approvable in state plans it must meet two requirements. First, as previously noted in section X.D.1 of this preamble, the state must apply a backstop rate in conjunction with a mass limit for the purposes of demonstrating compliance. As a starting point, states could consider basing their backstop rate for medium-term affected EGUs on the percentage reduction from the degree of emission limitation used for the presumptively approvable backstop rate for the long-term coal- fired subcategory, i.e., the 80 percent 
reduction relative to baseline emission performance is approximately 90.5 percent of the 88.4 percent degree of emission limitation. Applying that to the degree of emission limitation for the medium-term coal-fired subcategory is 14.5 percent, so the backstop rate, expressed in lb CO
2per MWh on a gross 
basis, could be set as a 14.5 percent reduction relative to baseline emission performance on an annual calendar-year basis. Second, as described in section X.D.1 of this preamble, states must demonstrate that their plan would achieve an equivalent level of emission reduction as the application of unit- specific, rate-based standards of performance, including showing how the mass limit has been calculated and the basis for any assumptions made (e.g., about utilization). As explained in 
this section, the EPA believes it will be very difficult for states to accurately predict the future utilization of these units, which substantially increases the risk of establishing a mass limit that 
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does not ensure at least an equivalent 
level of emission reduction. The EPA will therefore apply a high degree of scrutiny to assumptions made about the utilization of affected EGUs employing this flexibility in state plans. Only state plans that demonstrate that use of compliance flexibilities will not erode the emission reductions required under these emission guidelines are approvable. 
Comment: Commenters were 
generally supportive of the use of mass- based compliance mechanisms (both unit-specific and aggregate mechanisms such as emission trading) for these emission guidelines. Commenters said that mass-based compliance can help ensure environmental outcomes while also allowing sources to cycle, incorporate variable resources, and respond to grid conditions. 
Response: The EPA is finalizing that 
mass-based compliance mechanisms are permissible when they assure an equivalent level of emission reduction with each source individually achieving its standard of performance, subject to the parameters described by the EPA in this preamble. For unit-specific mass- based compliance, affected EGUs in the medium- and long-term coal-fired subcategories may demonstrate compliance with their standards of performance through a mass limit. The EPA believes unit-specific mass-based compliance may offer some additional operational flexibility to states and affected EGUs, which could include allowing for cycling and incorporating variable resources. The EPA notes that sources must still be in compliance with the requisite backstop rate. 
Comment: Many commenters 
expressed support for mass-based compliance mechanisms on the grounds that it facilitates calibration with existing state programs affecting the same sources that are affected under these emission guidelines. 
Response: The EPA acknowledges 
that states may find it more straightforward to compare emission 
reduction obligations under these emission guidelines and existing state programs by using mass-based compliance mechanisms for state plans under these emission guidelines. However, the EPA notes that mass-based compliance mechanisms, including unit-specific mass-based compliance, are only available to certain sources affected by these emission guidelines, as described in this section of the preamble, which may be a smaller universe of sources than are affected by existing state programs. State plans must ensure an equivalent level of emission reduction from the sources that are affected sources under these 
emission guidelines. That is, states cannot rely on or account for emission reductions occurring at non-affected sources. 
Section X.D.8 of this preamble 
discusses more considerations related to the relationship between the inclusion of compliance flexibilities in state plans under these emission guidelines and existing state programs. 
Comment: Many commenters 
requested presumptively approvable mass-based standards of performance. 
Response: As discussed above, the 
EPA is finalizing a presumptively approvable unit-specific mass-based compliance approach for units in the long-term coal-fired subcategory that includes a backstop rate to ensure an equivalent level of emission reduction. The EPA emphasizes that states should take into account the discussions of stringency in section X.B and of demonstrating equivalence in section X.D.1 of this document, as well as guidance in each subsection on particular compliance flexibilities in considering mass-based compliance approaches that deviate from the presumptively approvable method or for sources for which the EPA is not 
providing a presumptively approvable approach. 
5. Mass-Based Emission Trading 
The EPA proposed that states would 
be permitted to incorporate mass-based 
trading into their state plans under these emission guidelines. While several commenters supported the use of mass- based emission trading, as with unit- specific mass-based compliance, the EPA has significant concerns about states’ ability using this mechanism to maintain an equivalent level of emission reduction to unit-specific, rate-based standards of performance. A description of and responses to comments on mass- based trading can be found at the end of this subsection. 
Under these final emission guidelines, 
the EPA is allowing states to include mass-based emission trading for affected coal-fired EGUs in the medium- and long-term subcategories in their plans. The same requirements and caveats discussed in section X.D.4 of this preamble above apply to the respective subcategories as for unit-specific mass- based compliance. Specifically, the EPA is requiring the use of a unit-specific backstop rate in conjunction with the mass-based compliance demonstration, which is necessary for consistency with the purpose of these emission guidelines to achieve the emission reductions required under CAA section 111(a)(1) through cleaner emission performance. The Agency similarly 
believes it will be very difficult for states to design mass-based trading programs that include affected EGUs in the medium-term coal-fired subcategory and that maintain the level of emission reduction that would be achieved under unit-specific compliance with the presumptive standards of performance. 
In general, a mass-based trading 
program establishes a budget of allowable mass emissions for a group of affected EGUs, with tradable instruments (typically referred to as ‘‘allowances’’) issued to affected EGUs in the amount equivalent to the mass emission budget. To establish a mass budget under these emission guidelines, states would use the rate-based standard of performance and an assumed level of utilization for each participating affected EGU, and sum the resulting individual mass limits to an aggregate mass budget. Additionally, states would need to specify in the plan how allowances would be distributed to participating affected EGUs. Each allowance would represent a tradable permit to emit one ton of CO
2, with 
affected EGUs required to surrender allowances at the end of the compliance period in a number determined by their reported CO
2emissions. Total emissions 
from all participating affected EGUs should be no greater than the total mass budget. In addition, each participating affected EGU would need to demonstrate compliance with the unit- specific backstop rate. 
The EPA sees similar potential 
benefits related to operational flexibility of mass-based emission trading as with unit-specific mass-based compliance, discussed in section X.D.4 of this preamble. These benefits could be heightened by having a larger pool of allowances available to affected EGUs. In addition, the EPA notes that emission trading can provide incentive for overperformance. 
While there is indeed the potential for 
heightened benefits from mass-based emission trading due to a larger pool of allowances resulting from the inclusion of multiple sources, the EPA believes that there is also a heightened risk that the mass budget will not be appropriately calculated due to the compounding uncertainty resulting from multiple participating sources. As 
noted in section X.D.4 of this preamble, projecting the utilization of affected EGUs has become increasingly challenging, driven by changes in technology, fuel prices, and electricity demand. In generating a mass budget, assumptions about utilization must be made for each participating source, which magnifies the risk, particularly 
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for affected EGUs in the medium-term 
coal-fired subcategory, that an improper assumption about utilization for one affected EGU implicates the compliance obligation of other affected EGUs. Based on the understanding that a trading program that ensures the level of emission reduction of unit-specific, rate- based compliance under these emission guidelines would necessarily have to be designed with highly conservative utilization assumptions, the EPA is not providing a presumptively approvable approach for mass-based trading. The EPA additionally does not believe a presumptively approvable mass-based trading approach is warranted because, as noted in the introduction to this section, there are fewer sources covered by the final emission guidelines than the proposed emission guidelines, which may limit interest in and the utility of the use of mass-based trading for these emission guidelines. 
The EPA is not prohibiting states from 
developing their own approaches to mass-based trading under these emission guidelines; however, they must apply a unit-specific backstop rate for all participating affected EGUs (see section X.D.4 of this preamble for a discussion of the backstop rate under unit-specific mass-based compliance), and they must demonstrate, as described in section X.D.1 of this preamble, that their plan would achieve an equivalent level of emission reduction as the application of individual rate-based standards of performance, including showing how the mass limit has been calculated and the basis for any assumptions made (e.g., about utilization). As with unit- 
specific mass-based compliance, the EPA will apply a high degree of scrutiny to assumptions made about the utilization of affected EGUs participating in a mass-based trading program in state plans. States must also specify the structure and purpose of any other trading program design feature(s) (e.g., mass budget adjustment 
mechanism) and how they impact the demonstration of an equivalent level of emission reduction. 
Comment: Many commenters 
supported the use of mass-based trading under these emission guidelines. Commenters stated that because many states are familiar with the mechanism, having used it for other pollutants in this sector or, in the case of some existing state programs, for CO
2, it 
would be easy to employ in the context of these emission guidelines and provide needed flexibility. In addition, commenters cited ensuring reliability as 
a motivation for using mass-based trading. Response: While the EPA is finalizing 
that mass-based trading is permissible 
under these emission guidelines for affected EGUs in the medium- and long- term coal-fired subcategories, the EPA believes that some of the flexibility desired by commenters is addressed by other features of and changes made to the final emission guidelines, as described in the beginning of section X.D of this preamble. Despite familiarity on the part of states and sources with mass-based trading programs, the EPA is concerned that the unique circumstances of the EGUs affected by these final emission guidelines, including uncertainty over their future utilization as well as the relatively lower stringency of the medium-term coal-fired subcategory, pose a challenge for states in demonstrating an equivalent level of emission reduction of mass-based trading programs to the application of individual rate-based standards. 
Comment: Some commenters 
expressed concern with whether and how mass-based trading would achieve and sustain the emission performance identified in the determination of BSER. 
Response: The EPA shares these 
concerns, and for that reason is requiring the use of a unit-specific backstop rate in conjunction with mass- based compliance flexibilities, including mass-based trading. The EPA has also described its concerns over states’ ability to estimate future utilization and will thus apply a high degree of scrutiny to assumptions made about the utilization of affected EGUs participating in mass-based trading in state plans. 
6. General Emission Trading and 
Averaging Program Implementation Features 
As noted in the proposed emission 
guidelines, states would need to establish the procedures and systems 
necessary to implement and enforce an emission averaging or trading program, whether it is rate-based or mass-based, if they elect to incorporate such flexibilities into their state plans. This would include, but is not limited to, establishing the mechanics for demonstrating compliance under the program (e.g., surrender of compliance 
instruments as necessary based on monitoring and reporting of CO
2 
emissions and generation); establishing requirements for continuous monitoring and reporting of CO
2emissions and 
generation; and developing a tracking system for tradable compliance instruments. The EPA requested comment on whether there was interest in capitalizing on the existing trading program infrastructure developed by the 
EPA for other trading programs, and some states and one utility expressed support for states’ ability to use EPA’s allowance management system for such programs. In addition to providing such resources for regional and national emission trading and averaging programs, the EPA has also provided technical support and resources to various non-EPA state and regional emission trading programs. In the event states choose to create emission averaging or trading programs under these emission guidelines, the EPA can provide technical support for such programs, including through the use of the Agency’s existing trading program infrastructure, and is available to consult with states during the plan development process about the appropriateness of using such resources, such as the EPA’s allowance management system, based on the design of state programs. 
States may also need to consider how 
to handle differing compliance dates for affected EGUs in an emission averaging or trading program, given that under these emission guidelines the date when standards of performance apply varies depending on the subcategory for the affected EGU. The most straightforward way to address this, and which commenters supported, is to initially only include those sources with a compliance date of January 1, 2030, and then subsequently add sources into the program (and thus factor them into the aggregate standard of performance that must be achieved in the case of rate- based averaging or mass-based budget in the case of mass-based compliance approaches) at the start of the first year in which their standard of performance applies. 
Another topic that states 
incorporating emission averaging or trading would need to consider is whether to provide for banking of tradable compliance instruments (hereafter referred to as ‘‘allowance banking,’’ although it is relevant for both mass-based and rate-based trading programs). Allowance banking has potential implications for a trading program’s ability to maintain the requisite level of emission reduction of the standards of performance. The EPA recognizes that allowance banking—that is, permitting allowances that remain unused in one control period to be carried over for use in future control periods—may provide incentives for earlier emission reductions, promote operational flexibility and planning, and facilitate market liquidity. Many 
commenters supported allowing banking for these reasons. However, the 
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949Federal ‘‘Good Neighbor Plan’’ for the 2015 
Ozone National Ambient Air Quality Standards, 88 
FR 36654 (June 5, 2023). Under the allowance bank recalibration provisions, EPA will recalibrate the ‘‘Group 3’’ allowance bank for the 2024–2029 control periods to meet the target bank level of 21 percent of the sum of the state emission budgets for that control period. For control periods 2030 and later, the target bank level is 10.5 percent of the sum of the state emission budgets. If the overall bank is less than the target bank level for a given control period, then no bank recalibration will occur for that control period. EPA has observed that unrestricted 
allowance banking from one control period to the next (absent provisions that adjust future control period budgets to account for banked allowances) may result in a long-term allowance surplus that has the potential to undermine a trading program’s ability to ensure that, at any point in time, the affected sources are achieving the required level of emission performance. In the Good Neighbor Plan’s trading program provisions, for example, the EPA implemented an annual allowance bank recalibration to prevent allowance surpluses from accumulating and adversely impacting program stringency.
949While the requirement to 
include a backstop rate for mass-based compliance flexibilities can mitigate 
some concerns that unrestricted allowance banking will undermine the program’s calibration towards achieving emission reductions through cleaner performance, the EPA urges that states considering allowing trading also consider restricting allowance banking (whether all or only a portion) in order to ensure that a program continues to be calibrated towards equivalent stringency with individual rate-based standards of performance, which several commenters did support. 
Comment: Many commenters 
expressed the need for expanding the state plan submission timeline beyond 24 months to allow more time to design emission trading and averaging programs. 
Response: As discussed in section 
X.E.2 of this preamble, the EPA is finalizing a 24-month state plan development timeframe. Because there are significantly fewer sources covered under the final emission guidelines and because the EPA is restricting certain subcategories from using compliance flexibilities such as emission averaging and trading and unit-specific mass- based compliance, the EPA believes 24 months is a reasonable amount of time to develop state plans, including time necessary to develop compliance flexibility approaches. Moreover, the EPA is offering a presumptively approvable approach to unit-specific mass-based compliance for affected EGUs in the long-term coal-fired 
subcategory, which can further simplify the process for developing compliance approaches in state plans. 
7. Interstate Emission Trading 
In the proposed emission guidelines, 
the EPA requested comment on 
whether, and under what circumstances or conditions, to allow interstate emission trading under these emission guidelines. Given the interconnectedness of the power sector and given that many utilities and power generators operate in multiple states, interstate emission trading may increase compliance flexibility. The EPA also took comment on whether the scope of rate-based averaging should be limited to a certain level of geographic aggregation (i.e., intrastate but not 
interstate). 
Many commenters expressed support 
for interstate trading and averaging, arguing that it further augments the flexibility offered by these mechanisms. Because electricity markets are often operated on an interstate basis, commenters stated that interstate trading and averaging would facilitate better electricity market planning. In particular, some commenters noted that interstate programs would also allow for better grid reliability planning across areas with regional planning entities. 
While the EPA is finalizing a 
determination that states can incorporate both rate- and mass-based interstate emission trading programs into their state plans, the EPA has significant stringency-related and logistical concerns about the use of 
interstate emission trading for these particular emission guidelines. For mass-based trading in particular, the EPA has concerns that further increasing the number of sources participating in the program heightens the risk that the mass budget will not be appropriately calculated due to the uncertainty in estimating future utilization of affected EGUs, thus inhibiting the ability of states to demonstrate that their program achieves an equivalent level of emission reduction. This concern is somewhat alleviated for rate-based compliance flexibilities, but the EPA notes that states that wish to implement such flexibilities on an interstate basis should do so through rate-based trading, as discussed in section X.D.2. Interstate trading programs must adhere to the same requirements described in section X.D.1 and must demonstrate equivalence of the program for all participating affected EGUs. 
For interstate emission trading 
programs to function successfully, all participating states would need to, at a 
minimum, use the same form of trading and have consistent design elements and identical trading program requirements. Each state participating in an interstate trading program would need to submit their own individual state plan, subject to the state plan component and submission requirements described in section X.E, but the states would coordinate their individual plan provisions addressing the interstate trading program. Additionally, each state plan would need provisions to ensure that affected EGUs within their state are in compliance taking into account the actions of affected EGUs participating in the interstate trading program in other states. The EPA would need all state plan submissions that incorporate interstate emission trading before evaluating any of the individual state plans in order to ensure consistency among all participating states. The EPA is willing to provide technical assistance to states during the state plan development process about the use of interstate emission trading, but notes that states may need to coordinate their individual state plan submissions among different EPA regions. 
8. Relationship to Existing State 
Programs 
As described in the proposed 
emission guidelines, the EPA recognizes that many states have adopted policies and programs (with both a supply-side and demand-side focus) under their own authorities that have significantly reduced CO
2emissions from EGUs, that 
these policies will continue to achieve future emission reductions, and that states may continue to adopt new power sector policies addressing CO
2 
emissions. States have exercised their power sector authorities for a variety of purposes, including economic development, energy supply and resilience goals, conventional and GHG pollution reduction, and generating allowance proceeds for investments in communities disproportionately impacted by environmental harms. The scope and approach of the EPA’s final 
emission guidelines differ significantly from the range of policies and programs employed by states to reduce power sector CO
2emissions, and these 
emission guidelines operate more narrowly to improve the CO
2emission 
performance of a subset of EGUs within the broader electric power sector. 
Several commenters requested 
guidance on how states can count existing state programs, many of which include requirements to reduce CO
2 
emissions at sources not affected by this 
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95040 CFR 60.20a(a)(1). 95140 CFR 60.27a(g)(2) and (3). rule, in their state plans under these 
emission guidelines. The EPA is not providing such guidance in this action but would be open to consulting with states during the state plan development process about the requirements of these emission guidelines in relation to existing state programs. States may make determinations about whether and how to design their plans, accounting for state-specific programs or requirements that apply to the same affected EGUs included in a state plan. However, as noted in section X.B, emission reductions from sources not affected by this rule cannot be used to demonstrate compliance with a standard of performance established to meet the emission guidelines. Only emission reductions at affected EGUs may count towards compliance with the state plan, including towards demonstrating compliance with the equivalent stringency criterion applied to compliance flexibilities. States may employ compliance flexibilities (such as mass-based mechanisms) described in this section in order to facilitate comparison between the requirements under existing state programs and under these emission guidelines; however, the EPA emphasizes that individual affected EGUs or groups of affected EGUs must comply with the requirements established for such units in the state plan, and that such compliance cannot incorporate measures taken by EGUs not affected by these emission guidelines. 
E. State Plan Components and 
Submission 
This section describes the 
requirements for the contents of state plans and the timing of state plan submissions as well as the EPA’s review of and action on state plan submissions. This section also discusses issues related to the applicability of a Federal plan and timing for the promulgation of any Federal Plan, if necessary. 
As explained earlier in this preamble, 
the requirements of 40 CFR part 60, subpart Ba, govern state plan 
submissions under these emission guidelines. Where the EPA is finalizing requirements that add to, supersede, or otherwise vary from the requirements of subpart Ba for the purposes of state plan submissions under these particular emission guidelines,
950those 
requirements are addressed explicitly in section X.E.1.b on specific state plan requirements and in other parts of section X of this preamble. Unless expressly amended or superseded in these final emission guidelines, the 
provisions of subpart Ba apply. 
1. Components of a State Plan 
Submission 
A state plan must include a number 
of discrete components, including but not limited to those that apply for all state plans pursuant to 40 CFR part 60, subpart Ba. In this action, the EPA is also finalizing additional plan components that are specific to state plans submitted pursuant to these emission guidelines. For example, the EPA is finalizing plan components that are necessary to implement and enforce the specific types of standards of performance for affected EGUs that would be adopted by a state and incorporated into its state plan. 
a. General Components 
The CAA section 111 implementing 
regulations at 40 CFR part 60, subpart 
Ba, provide separate lists of administrative and technical criteria that must be met in order for a state plan submission to be deemed complete.
951 
The complete list of applicable administrative completeness criteria for state plan submissions is: (1) A formal letter of submittal from the Governor or the Governor’s designee requesting EPA approval of the plan or revision thereof; (2) Evidence that the state has adopted the plan in the state code or body of regulations; or issued the permit, order, or consent agreement (hereafter ‘‘document’’) in final form. That evidence must include the date of adoption or final issuance as well as the effective date of the plan, if different 
from the adoption/issuance date; (3) Evidence that the state has the necessary legal authority under state law to adopt and implement the plan; (4) A copy of the actual regulation, or document submitted for approval and incorporation by reference into the plan, including indication of the changes made (such as redline/strikethrough) to the existing approved plan, where applicable. The submittal must be a copy of the official state regulation or document signed, stamped, and dated by the appropriate state official indicating that it is fully enforceable by the state. The effective date of the regulation or document must, whenever possible, be indicated in the document itself. The state’s electronic copy must be an exact duplicate of the hard copy. If the regulation/document provided by the state for approval and incorporation by reference into the plan is a copy of an existing publication, the state submission should, whenever possible, include a copy of the publication cover 
page and table of contents; (5) Evidence that the state followed all applicable procedural requirements of the state’s regulations, laws, and constitution in conducting and completing the adoption/issuance of the plan; (6) Evidence that public notice was given of the plan or plan revisions with procedures consistent with the requirements of 40 CFR 60.23a, including the date of publication of such notice; (7) Certification that public hearing(s) were held in accordance with the information provided in the public notice and the state’s laws and constitution, if applicable and consistent with the public hearing requirements in 40 CFR 60.23a; (8) Compilation of public comments and the state’s response thereto; and (9) Documentation of meaningful engagement, including a list of pertinent stakeholders, a summary of the engagement conducted, a summary of stakeholder input received, and a description of how stakeholder input was considered in the development of the plan or plan revisions. 
Pursuant to subpart Ba, the technical 
criteria that all plans must meet include the following: (1) Description of the plan approach and geographic scope; (2) Identification of each designated facility (i.e., affected EGU); identification of 
standards of performance for each affected EGU; and monitoring, recordkeeping, and reporting requirements that will determine compliance by each designated facility; (3) Identification of compliance schedules and/or increments of progress; (4) Demonstration that the state plan submission is projected to achieve emission performance under the applicable emission guidelines; (5) Documentation of state recordkeeping and reporting requirements to determine the performance of the plan as a whole; and (6) Demonstration that each standard is quantifiable, permanent, verifiable, enforceable, and nonduplicative. 
b. Specific State Plan Requirements for 
These Emission Guidelines 
To ensure that state plans submitted 
pursuant to these emission guidelines 
are consistent with the statutory requirements and the requirements of subpart Ba, the EPA is finalizing additional regulatory requirements that state plans must meet for all affected EGUs subject to a standard of performance, as well as certain subcategory-specific requirements. The EPA reiterates that standards of performance for affected EGUs included in a state plan must be quantifiable, 
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952Consistent with CAA section 111(d)(1), state 
plans must include commitments to cease operation 
as necessary for the implementation and enforcement of standards of performance. When such commitments are the predicate for receiving a particular standard of performance, adherence to those commitments is necessary to maintain the level of emission reduction Congress required under CAA section 111(a)(1). See 40 CFR 60.24a(g) (operating conditions within the control of a designated facility that are relied on for purposes of RULOF must be included as enforceable requirements in state plans); see also, e.g., ‘‘Affordable Clean Energy Rule,’’ 84 FR 32520, 32558 (July 8, 2019) (repealed on other grounds) (requiring that retirement dates associated with standards of performance be included in state plans and become federally enforceable upon approval by the EPA); 76 FR 12651, 12660–63 (March 8, 2011) (best available retrofit technology requirements based on enforceable retirements that were made federally enforceable in state implementation plan); Guidance for Regional Haze State Implementation Plans for the Second Implementation Period at 34, EPA–457/B–19–003, August 2019 (to the extent a state replies on an enforceable shutdown date for a reasonable progress determination, that measure would need to be included in the SIP and/or be federally enforceable). verifiable, permanent, enforceable, and 
non-duplicative. Additionally, per CAA section 302(l), standards of performance must be continuous in nature. Additional state plan requirements finalized as part of this action include: 
•Identification of each affected EGU 
and the subcategory to which each affected EGU is assigned; 
•A requirement that state plans 
include, in the regulatory portion of the plan, a list of coal-fired steam- generating EGUs that are existing sources at the time of state plan submission and that plan to permanently cease operation before January 1, 2032, and the calendar dates by which they have committed to do so. The state plan must provide that an EGU operating past the date listed in the plan is no longer exempt from these emission guidelines and is in violation of that plan, except to the extent the existing coal-fired steam generating EGU has received a time-limited extension of its date for ceasing operation pursuant to the reliability assurance mechanism described in section XII.F.3.b of this preamble; 
•Standards of performance for each 
affected EGU, including provisions for implementation and enforcement of such standards as well as identification of the control technology or other system of emission reduction affected EGUs intend to implement to achieve the standards of performance. Standards of performance must be expressed in lb CO
2/MWh gross basis or, for affected 
EGUs in the low load natural gas- and oil-fired subcategory, lb CO
2/MMBtu, or, 
if a state is allowing the use of mass- based compliance, tons CO
2per year; 
•For each affected EGU, 
identification of baseline emission 
performance, including CO 2mass and 
electricity generation data or, for affected EGUs in either the low load natural gas-fired subcategory or the low load oil-fired subcategory, heat input data from 40 CFR part 75 reporting for the 5-year period immediately prior to the date this final rule is published in the Federal Register and what 
continuous 8-quarter period from the 5- year period was used to calculate baseline emission performance; 
•Where a state plan provides for the 
use of a compliance flexibility, such as an alternative form of the standard (e.g., mass limit; aggregate emission rate limitation) and/or the use of emission averaging or trading, identification of the presumptive unit-specific rate-based standard of performance in lb CO
2/ 
MWh-gross that would apply for each affected EGU in the absence of the compliance flexibility mechanism; the standard of performance (aggregate emission rate limitation, mass limit, or mass budget) that is actually applied for affected EGUs under the compliance flexibility mechanism and how it is calculated; provisions for the implementation and enforcement of the compliance flexibility mechanism, which includes provisions that address assurance of achievement of equivalent emission reduction, including, for mass- based compliance flexibilities, identification of the unit-specific backstop emission limitation; and a demonstration that the state plan will achieve an equivalent level of emission reduction with individual rate-based standards of performance through incorporation of the compliance flexibility mechanism; 
•Increments of progress and 
reporting obligations and milestones as required for affected EGUs within the applicable subcategories or pursuant to consideration of RULOF, included as enforceable elements of a state plan; 
•For affected EGUs in the medium- 
term coal-fired steam generating EGU subcategory and affected EGUs relying on a plan to permanently cease operation for application of a less stringent standard of performance pursuant to RULOF, the state plan must include an enforceable commitment to permanently cease operation by a date certain. The state plan must clearly identify the calendar dates by which such affected EGUs have committed to permanently cease operation;
952 
•A requirement that state plans 
provide that any existing coal-fired steam generating EGU shall operate only subject to a standard of performance pursuant to these emission guidelines or under an exemption from applicability provided under 40 CFR 60.5850b 
(including any time-limited extension of the date by which an EGU has committed to permanently cease operations pursuant to the reliability assurance mechanism); and 
•Monitoring, reporting, and 
recordkeeping requirements for affected EGUs. 
These final emission guidelines 
include requirements pertaining to the methodologies for establishing a presumptively approvable standard of performance for an affected EGU within a given subcategory. These presumptive methodologies are specified for each of the subcategories of affected EGUs in section X.C.1 of this preamble. 
As discussed in sections X.C and X.D 
of this preamble, in order for the EPA to find a state plan ‘‘satisfactory,’’ that plan must demonstrate that it achieves the level of emission reduction that would result if each affected source was individually achieving its presumptive standard of performance, after accounting for any application of RULOF. That is, while states have the discretion to establish the applicable standards of performance for affected sources in their state plans (including whether to allow compliance to be demonstrated through the use of compliance flexibilities), the structure and purpose of CAA section 111 require that those plans achieve an equivalent level of emission reduction as applying the EPA’s presumptive standards of performance to those sources (again, after accounting for any application of RULOF). 
Thus, state plans must adequately 
document and support the process and underlying data used to establish standards of performance pursuant to these emission guidelines. Providing such documentation is critical to the EPA’s review of state plans to determine whether they are satisfactory. In particular, states must include in their plan submissions information and data related to affected EGUs’ emissions and operations, including CO
2mass 
emissions and corresponding electricity 
generation data or, for affected EGUs in either the low load natural gas-fired subcategory or the oil-fired subcategory, heat input data, from 40 CFR part 75 reporting for the 5-year period immediately prior to the date the final rule is published in the Federal Register and identify the period from which states and affected EGUs select 8 continuous quarters of data to determine unit-specific baselines. States must include data and documentation sufficient for the EPA to understand and replicate their calculations in applying the applicable degree of emission 
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95340 CFR 60.23(c)–(g); 40 CFR 60.23a(c)–(h). 
95440 CFR 60.21a(k); 88 FR 80480, 80500 
(November 17, 2023). 
955Id. 
95640 CFR 60.21a(l); 88 FR 80480, 80500 
(November 17, 2023). 
95788 FR 80480, 80500 (November 17, 2023). 958Id. 
959See id. at 80502. limitation to individual affected EGUs 
to establish their standards of performance. They must also provide any methods, assumptions, and calculations necessary for the EPA to review plans containing compliance flexibilities and to determine whether they achieve an equivalent (or better) level of emission reduction as unit- specific implementation of rate-based standards of performance. Plans must also adequately document and demonstrate the methods employed to implement and enforce the standards of performance such that the EPA can review and identify measures that assure transparent and verifiable implementation. 
i. Requirements Related to Meaningful 
Engagement 
Public engagement is a cornerstone of 
CAA section 111(d) state plan development. In November 2023, the EPA finalized requirements in the CAA section 111(d) implementing regulations at 40 CFR part 60 subpart Ba to ensure that that all affected members of the public, not just a particular subset, have an opportunity to participate in the state plan development process. These requirements are intended to ensure that the perspectives, priorities, and concerns of affected communities, including communities that are most affected by and vulnerable to emissions from affected EGUs as well as energy communities and energy workers that are affected by EGU operation and construction of pollution controls, are included in the process of establishing and implementing standards of performance for existing EGUs, including decisions about compliance strategies and compliance flexibilities that may be included in a state plan. The final requirements for meaningful engagement in subpart Ba are in addition to the preexisting public notice requirements under subpart Ba that apply to state plan development. This section describes the meaningful engagement requirements finalized separately in subpart Ba and provides guidance to states in the application of these requirements to the development 
of state plans under these emission guidelines. 
The fundamental purpose of CAA 
section 111 is to reduce emissions from categories of stationary sources that cause, or significantly contribute to, air pollution which may reasonably be anticipated to endanger public health or welfare. Therefore, a key consideration in the state’s development of a state plan is the potential impact of the proposed plan requirements on public health and welfare. Meaningful engagement is a corollary to the longstanding requirement for public participation, including through public hearings, in the course of state plan development under CAA section 111(d).
953A robust and meaningful 
engagement process is critical to ensuring that the entire public has an opportunity to participate in the state plan development process and that states understand and consider the full range of impacts of a proposed plan on public health and welfare. 
The EPA finalized the following 
definition of meaningful engagement in the final subpart Ba revisions in November 2023: ‘‘timely engagement with pertinent stakeholders and/or their representatives in the plan development or plan revision process.’’
954 
Furthermore, the definition provides that ‘‘[s]uch engagement should not be disproportionate in favor of certain stakeholders and should be informed by available best practices.’’
955The 
regulations also define pertinent stakeholders, which ‘‘include, but are not limited to, industry, small businesses, and communities most affected by and/or vulnerable to the impacts of the plan or plan revision.’’
956 
The preamble for the final revisions to subpart Ba notes that ‘‘[i]ncreased vulnerability of communities may be attributable to, among other reasons, an accumulation of negative environmental, health, economic, or social conditions within these populations or communities, and a lack of positive conditions.’’
957Consistent 
with the requirements of subpart Ba, it is important for states to recognize and engage the communities most affected by and/or vulnerable to the impacts of a state plan, particularly as these communities may not have had a voice when the affected EGUs were originally constructed. 
Most commenters were generally 
supportive of the requirement to conduct meaningful engagement. Commenters acknowledged that some states and utilities have already started to conduct meaningful engagement with stakeholders like that which is required by the final subpart Ba revisions in other policy contexts. Some commenters requested more time in the state plan development process specifically to facilitate conducting meaningful engagement (comments related to the state plan development timeline are 
addressed section X.E.2). 
In the proposed emission guidelines, 
the EPA provided some information to assist states in identifying potential pertinent stakeholders. Some commenters sought more guidance from the EPA on how to identify pertinent stakeholders. The Agency is providing the following discussion of the potential impacts of the emission guidelines to assist states in identifying their pertinent stakeholders. The EPA believes that this discussion provides a starting point and expects that states will use their more targeted knowledge of state- and source-specific circumstances to hone the identification of pertinent stakeholders and conduct the necessary meaningful engagement. As acknowledged by the EPA in the final revisions to subpart Ba, ‘‘states are highly diverse in, among other things, their local conditions, resources, and established practices of engagement,’’
958so the EPA is not 
finalizing any additional requirements regarding the states’ identification of a pertinent stakeholders for the purposes of these emission guidelines. States should consider the unique circumstances of their state and the sources within their state, with the following discussion in mind, to tailor their meaningful engagement. In addition, the EPA notes that the preamble to the final subpart Ba revisions provides discussion of best practices related to meaningful engagement.
959 
The air pollutant of concern in these 
emission guidelines is defined as greenhouse gases, and the air pollution addressed is elevated concentrations of these gases in the atmosphere. These elevated concentrations result in warming temperatures and other changes to the climate system that are leading to serious and life-threatening environmental and human health impacts, including increased incidence of drought and flooding, damage to 
crops and disruption of associated food, fiber, and fuel production systems, increased incidence of pests, increased incidence of heat-induced illness, and impacts on water availability and water quality. The Agency therefore expects that states’ pertinent stakeholders will include communities within the state that are most affected by and/or vulnerable to the impacts of climate change, including those exposed to more extreme drought, flooding, and other severe weather impacts, including extreme heat and cold (states should 
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960An April 2023 report of the Federal 
Interagency Working Group on Coal and Power 
Plant Communities and Economic Revitalization (Energy Communities IWG) summarizes how the Bipartisan Infrastructure Law, CHIPS and Science Act, and Inflation Reduction Act have greatly increased the amount of Federal funding relevant to meeting the needs of energy communities, as well as how the Energy Communities IWG has launched an online Clearinghouse of broadly available Federal funding opportunities relevant for meeting the needs and interests of energy communities, with information on how energy communities can access Federal dollars and obtain technical assistance to make sure these new funds can connect to local projects in their communities. Interagency Working Group on Coal and Power Plant Communities and Economic Revitalization. ‘‘Revitalizing Energy Communities: Two-Year Report to the President’’ (April 2023). https://energycommunities.gov/wp- content/uploads/2023/04/IWG-Two-Year-Report-to- the-President.pdf. 
961Colorado Legislature, Senate Law 19–236. 
https://leg.colorado.gov/sites/default/files/2019a _
236_ signed.pdf. 962Nicolle S. Tulve, Andrew M. Geller, Scot 
Hagerthey, Susan H. Julius, Emma T. Lavoie, Sarah L. Mazur, Sean J. Paul, H. Christopher Frey, Challenges and opportunities for research supporting cumulative impact assessments at the United States environmental protection agency’s office of research and development, The Lancet Regional Health—Americas, Volume 30, 2024, 100666, ISSN 2667–193X, https://doi.org/10.1016/ j.lana.2023.100666. 
963EPA Response to Draft Office of Inspector 
General Report, The EPA Lacks Agencywide Policies and Guidance to Address Cumulative Impacts and Disproportionate Health Effects on Communities with Environmental Justice Concerns. https://www.epaoig.gov/sites/default/files/reports/ 2023-08/_ epaoig_ 20230822-23-p-0029.pdf. refer to section III of this preamble, on 
climate impacts, to further assist them in identifying their pertinent stakeholders that are impacted by the pollution at issue in these emission guidelines). Commenters were supportive of the notion that those impacted by climate change are pertinent stakeholders. 
Additionally, the EPA expects that 
another set of pertinent stakeholders will be communities located near affected EGUs and those near pipelines. These communities may experience impacts associated with implementation of the state plan, including the construction and operation of infrastructure required under a state plan. Activities related to the construction and operation of new natural gas and CO
2pipelines may 
impact individuals and communities both locally and at larger distances from affected EGUs but near any associated pipelines. Commenters were supportive of the notion that communities impacted by infrastructure development required by the state plan are pertinent stakeholders. 
Because these emission guidelines 
address air pollution that becomes well mixed and is long-lived in the atmosphere, the collective impact of a state plan is not limited to the immediate vicinity of EGUs and any associated infrastructure. The EPA therefore expects that states will consider communities and populations within the state that are both most impacted by particular affected EGUs and associated pipelines as well as those that will be most affected by the overall stringency of state plans. 
The EPA also expects that states will 
include the energy communities impacted by each affected EGU, including the energy workers employed at affected EGUs (including employment in operation and maintenance), workers who may construct and install pollution 
control technology, and workers employed in associated industries such as fuel extraction and delivery and CO
2 
transport and storage, as pertinent stakeholders. These communities are impacted by power sector trends on an ongoing basis. The EPA acknowledges that a variety of Federal programs are available to support these communities and encourages states to consider these programs when conducting meaningful engagement and analyzing the impacts of compliance choices.
960Commenters supported encouraging states to both 
consider these communities as part of meaningful engagement under these emission guidelines as well as to take advantage of Federal resources available for employment and training assistance, and highlighted a Colorado state law
961 
requiring utilities to share workforce data and develop a workforce transition plan. The EPA supports such 
approaches to workforce data transparency and encourages states to provide such data in the course of meaningful engagement and the development of state plans. 
The EPA also expects that states will 
include relevant balancing authorities, systems operators and reliability coordinators that have authority to maintain electric reliability in their jurisdiction as part of their constructive engagement under these requirements. These stakeholders are impacted by a state plan as they are the entities authorized to plan for electric reliability. Visibility into unit-specific compliance plans will help ensure those entities have adequate lead time to plan and address any potential reliability- related issues. Early notification and periodic follow up on unit-specific decisions, including control technology installation and voluntary cease operation choices and timeframes will greatly assist reliability planning authorities. 
Several commenters noted the need 
for consideration of communities overburdened by existing air pollution issues, including both greenhouse gases and co-pollutants, as pertinent stakeholders in these emission guidelines. The Agency urges states to consider the cumulative burden of pollution when identifying their pertinent stakeholders for these emission guidelines, as these stakeholders may be especially vulnerable to the impacts of a state plan or plan revision due to ‘‘an accumulation of negative environmental . . . conditions,’’ as defined in the final subpart Ba revisions. Many states are 
already implementing policies to consider cumulative impacts in overburdened communities, including California and New Jersey. It is also important to note that the EPA is ‘‘prioritizing cumulative impacts research to address the multiple stressors to which people and communities are exposed, and studying how combinations of stressors affect health, well-being, and quality of life at each developmental stage throughout the course of one’s life.’’
962 
Additionally, the EPA is in the process of developing a workplan that lays out actions the agency will take to integrate and implement cumulative impacts within the EPA’s work through FY25. The EPA’s commitments, as stated in the EPA’s response to the OIG Report, include continuing to refine analytic techniques based on best available science, increasing the body of relevant data and knowledge, and using outcome-based metrics to measure progress, including quantifiable pollution reduction benefits in communities.
963 
The EPA recognizes that facility- and 
community-specific circumstances, including the exposure of overburdened communities to additional chemical and non-chemical stressors, may also exist. The meaningful engagement process is designed to allow states to identify and to enable consideration of these and other facility- and community-specific circumstances. This includes consideration of facility- and community-specific concerns with emissions control systems, including CCS. States should design meaningful engagement to elicit input from pertinent stakeholders on facility- and community-specific issues related to implementation of emissions control systems generally, as well as on any considerations for particular systems. 
The EPA encourages states to consider 
regional implications, explore opportunities for collaboration, and to 
share best practices. In some cases, an affected EGU may be located near state 
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964https://www.epa.gov/power-sector/power- 
plant-environmental-justice-screening- 
methodology. 
965https://www.epa.gov/ejscreen. or Tribal borders and impact 
communities in neighboring states or Tribal lands. Some commenters suggested that those near state or Tribal borders may be pertinent stakeholders. The EPA agrees that it could be reasonable, in cases where EGUs are located near borders, for the state to consider identifying pertinent stakeholders in the neighboring state or Tribal land and to work with the relevant air pollution control authority of that state or Tribe to conduct meaningful engagement that addresses cross-border impacts. Some commenters supported the notion that those near state or Tribal borders may be pertinent stakeholders. 
The revisions to subpart Ba in 
November of 2023 established requirements for demonstrating how states provided meaningful engagement with pertinent stakeholders, and these requirements apply here. According to the requirements under subpart Ba, the state will be required to describe, in its plan submittal: (1) A list of the pertinent stakeholders identified by the state; (2) a summary of engagement conducted; (3) a summary of the stakeholder input received; and (4) a description of how stakeholder input was considered in the development of the plan or plan revisions. The EPA will review the state plan to ensure that it includes these required descriptions regarding meaningful public engagement as part of its completeness evaluation of a state plan submittal. If a state plan submission does not include the required elements for notice and opportunity for public participation, including the procedural requirements at 40 CFR 60.23a(i) and 60.27a(g)(2)(ix) for meaningful engagement, this may be grounds for the EPA to find the submission incomplete or (where a plan has become complete by operation of law) to disapprove the plan. 
In approaching meaningful 
engagement, states should first identify their pertinent stakeholders. As previously noted, the state should allow for balanced participation, including communities most vulnerable to the impacts of the plan. Next, states should develop a strategy for engagement with the identified pertinent stakeholders. This includes ensuring that information is made available in a timely and transparent manner, with adequate and accessible notice. As part of this strategy for engagement, states should also ensure that they share information and solicit input on plan development and on any accompanying assessments or analyses. In providing transparent and 
adequate notice of plan development, states should consider that internet notice alone may not be appropriate for 
all stakeholders, given lack of access to broadband infrastructure in many communities. Thus, in addition to internet notice, examples of prominent advertisement for engagement and public hearing may include notice through newspapers, libraries, schools, hospitals, travel centers, community centers, places of worship, gas stations, convenience stores, casinos, smoke shops, Tribal Assistance for Needy Families offices, Indian Health Services, clinics, and/or other community health and social services as appropriate for the emission guideline addressed. The state should also consider any geographic, linguistic, or other barriers 
to participation in meaningful engagement for members of the public. 
The EPA notes that several EPA 
resources are available to assist states and stakeholders in considering options for state plans. For example, included in the docket for this rulemaking is a unit- level proximity analysis that includes information about the population within 5 kilometers and 10 kilometers of each EGU covered by this rule. This analysis includes information about air emissions from each facility, and the potential emission implications of installing CCS. Additionally, the EPA’s Power Plant Environmental Justice Screening Methodology (PPSM)
964 
incorporates several peer-reviewed approaches that combine air quality modeling with environmental burden and population characteristics data to identify and connect power plants to geographic areas potentially exposed to air pollution by those power plants and to quantify the relative potential for environmental justice concern in those areas. This information provides states and stakeholders with the ability to identify the census block groups that are potentially exposed to air pollution by each EGU, including air pollutants in the vicinity of each EGU as well as pollutants that can travel significant distances. Another resource available to assist states and stakeholders is the EPA’s Environmental Justice Screening and Mapping Tool (EJScreen),
965which 
includes information at the census block group level about existing environmental burdens as well as socioeconomic information. Other federal resources include the Energy Communities Interagency Working Group’s online Clearinghouse, which lists federal funding opportunities relevant for meeting the needs and interests of energy communities, some 
of which may be relevant for state plan development. 
In their plan submittal, states must 
demonstrate evidence that they conducted meaningful engagement. In addition to a list of pertinent stakeholders and a summary of the engagement conducted, states must provide a summary of the input received and a description of how the input they received was considered in plan development. The type of information states may receive from their pertinent stakeholders could include data on the population and demographics of communities located near affected EGUs and associated pipelines; identification of and data on any overburdened communities vulnerable to the impacts of the state plan; data on the energy workers affected by anticipated compliance strategies on the part of owners and operators; data on workforce needs (e.g., expected number and type of jobs created, and skills required in anticipation of compliance with the state plan); and, if relevant, data on the population and demographics of communities near state and Tribal borders that may be vulnerable to the impacts of the state plan. The EPA encourages states to include such data in their demonstration of meaningful engagement in their state plan submittal. 
The EPA emphasizes to states that the 
meaningful engagement process is 
intended to include community perspectives, particularly those communities that, historically, may not have had a role in the state plan development process, in the development of standards of performance, compliance strategies, and compliance flexibilities for affected EGUs by which they are impacted. 
ii. Requirements for Transparency and 
Compliance Assurance 
The EPA proposed and requested 
comment on several requirements designed to help states ensure timely compliance by affected EGUs with standards of performance, as well as to assist the public in tracking affected EGUs’ progress towards their compliance dates. 
First, the EPA requested comment on 
whether to require that an affected EGU’s enforceable commitment for subcategory applicability (e.g., a state 
elects to rely on an affected coal-fired steam-generating unit’s commitment to permanently cease operations before January 1, 2039, to meet the applicability requirements for the medium-term subcategory), must be in 
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966See Document ID No. EPA–HQ–OAR–2023– 
0072–0781. 967See https://www.epa.gov/coalash/list-publicly- 
accessible-internet-sites-hosting-compliance-data- 
and-information-required for a list of websites for 
facilities posting Coal Combustion Residuals Rule compliance information, see also 80 FR 21301 (April 17, 2015). 
968See Document ID No. EPA–HQ–OAR–2023– 
0072–0813. the form of an emission limit of 0 lb 
CO 2/MWh that applies on the relevant 
date. Such an emission limit would be included in a state regulation, permit, order, or other acceptable legal instrument and submitted to the EPA as part of a state plan. If approved, the affected EGU would have a federally enforceable emission limit of 0 lb CO
2/ 
MWh that would become effective as of the date that the EGU permanently ceases operations. The EPA requested comment on whether such an emission limit would have any advantages or disadvantages for compliance and enforceability relative to the alternative, which is an enforceable commitment in a state plan to cease operation by a certain date. 
The EPA received few comments on 
this topic. One commenter,
966in 
particular, did not support a specific requirement that the permit or other enforceable commitment must be in the form of an emission limit of 0 lb CO
2/ 
MWh, claiming it seems needlessly prescriptive. This commenter also encouraged the EPA to recognize delegated or SIP-approved states’ enforceable permit conditions, certifications, and voiding of authorizations, as practically enforceable. 
The EPA is not finalizing a 
requirement that states must include commitments to permanently cease operating in state plans in the form of 0 lb CO
2/MWh emission limits. The 
Agency is concluding that it is within the discretion of the state to create an enforceable commitment to permanently cease operation, where applicable, in 
the form it deems appropriate. Such commitments may be codified in a state regulation, permit, order, or other acceptable legal instrument and submitted to the EPA as part of a state plan. It is important to note that if an emission limit or some other requirement that creates an enforceable commitment to cease operation is initially included in a title V permit before the submission of a state plan, that condition must be labeled as ‘‘state- only’’ or ‘‘state-only enforceable’’ until the EPA approves the state plan, at which point the permit should be revised to make that requirement federally enforceable. Including state instruments (such as state permits, certifications, and other authorizations) reflecting affected EGUs’ intent to permanently cease operation in the state plan, when such intent is the basis of receiving a less stringent standard of performance, is necessary because state instruments can be revised without a 
corresponding revision to the state plan or standard of performance. This outcome—a source continuing to operate into the future with a less- stringent standard of performance that is not necessarily warranted—would undermine the integrity of these emission guidelines. 
Second, the EPA proposed and is 
finalizing a requirement that state plans that include affected EGUs that plan to permanently cease operation must require that each such affected EGU comply with applicable state and Federal requirements for permanently ceasing operation, including removal from its respective state’s air emissions inventory and amending or revoking all applicable permits to reflect the permanent shutdown status of the EGU. This requirement covers affected coal- fired steam generating EGUs in the medium-term subcategory as well as affected EGUs that are relying on a commitment to permanently cease operating to obtain a less stringent standard of performance pursuant to consideration of RULOF. This requirement merely reinforces the application of requirements under state and Federal laws that are necessary in this context for transparency and the orderly administration of these emission guidelines. 
Third, the EPA proposed and is 
finalizing a requirement that each state plan must require owners and operators of affected EGUs to establish publicly accessible websites, referred to here as a ‘‘Carbon Pollution Standards for EGUs website,’’ to which all reporting and recordkeeping information for each affected EGU subject to the state plan would be posted, including the aforementioned information required to be submitted as part of the state plan. This information includes, but is not limited to, emissions data and other information relevant to determining compliance with applicable standards of performance, information relevant to the designation and determination of compliance with increments of progress and reporting obligations including milestones for affected EGUs that plan to permanently cease operations, and any extension requests made and granted pursuant to the compliance date extension mechanism or the reliability assurance mechanism. Although this information will also be required to be submitted directly to the EPA and the relevant state regulatory authority, both the EPA and stakeholders have an interest in ensuring that the information is made accessible in a timely manner. 
Some commenters agreed with these requirements. The EPA anticipates that the owners or operators of some affected 
EGUs may already be posting comparable reporting and recordkeeping information to publicly available websites under the EPA’s April 2015 Coal Combustion Residuals Rule,
967 
such that the burden of this website requirement for these units could be minimal. 
Comment: Several commenters argued 
that this was a duplicative requirement, noting that utilities already report GHG emissions data under the Acid Rain Program and Mandatory GHG Reporting Program. Commenters also stated that this requirement would pose a burden for companies who would have to dedicate staff to maintaining the website. One commenter
968suggested 
that EPA include more specific requirements related to the format of data, notification of uploads and removal of documentation, and 
summarization of content. 
Response: The EPA disagrees that this 
requirement is duplicative of reporting requirements under other programs. In addition to affected EGUs having unique standards of performance and compliance schedules under these emission guidelines, these emission guidelines also include unique reporting requirements that are not covered by the programs identified by the commenters, including increments of progress and reporting on milestones. In addition, the EPA believes that this information should be made broadly available to all stakeholders in a timely manner, which is not necessarily accomplished via the programs and reporting mechanisms identified by the commenters. Accordingly, the EPA is finalizing a requirement that each state plan must require owners and operators of affected EGUs to establish publicly accessible websites and to post the relevant information described in this section. Additionally, data should be available in a readily downloadable format. 
Fourth, to promote transparency and 
to assist the EPA and the public in assessing progress towards compliance with state plan requirements, the EPA proposed and is finalizing a requirement that state plans include a requirement that the owner or operator of each affected EGU shall report any deviation from any federally enforceable state plan increment of progress or reporting milestone within 30 business days after 
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969See Document ID No. EPA–HQ–OAR–2023– 
0072–0770. 
970Id. 971The milestone reporting requirements for 
affected coal-fired steam generating EGUs in the 
medium-term subcategory and those relying on a shorter remaining useful life for a less-stringent standard of performance pursuant to RULOF are authorized under both CAA sections 114(a) and 111(d)(1), the latter of which provides that state plans shall provide for the implementation and enforcement of standards of performance. In that the owner or operator of the affected 
EGU knew or should have known of the event. That is, the owner or operator must report within 30 business days if it is behind schedule such that it has missed an increment of progress or reporting milestone. In the report, the owner or operator of the affected EGU will be required to explain the cause or causes of the deviation and describe all measures taken or to be taken by the owner or operator of the EGU to cure the reported deviation and to prevent such deviations in the future, including the timeframes in which the owner or operator intends to cure the deviation. The owner or operator of the EGU must submit the report to the state regulatory agency and concurrently post the report to the affected EGU’s Carbon Pollution Standards for EGUs website. 
Fifth, in the proposed action, the EPA 
explained its general approach to 
exercising its enforcement authorities through administrative compliance orders (‘‘ACOs’’) to ensure compliance while addressing genuine risks to electric system reliability. The EPA solicited comment on whether to promulgate requirements in the final emission guidelines pertaining to the demonstrations, analysis, and information the owner or operator of an affected EGU would have to submit to the EPA in order to be considered for an ACO. The EPA is not finalizing the proposed approach to use ACOs to address risks to grid reliability. 
Comment: One commenter argued 
that the conditions to qualify for an ACO would make it challenging for an EGU to obtain an ACO in instances of urgent reliability.
969Commenters 
argued that there are not any guarantees that the EPA would act on such requests for an ACO in a timely manner, particularly because the EPA has not set any deadline for review and presumably would argue that any decision falls within the EPA’s enforcement discretion and is not subject to judicial review. Additionally, one commenter argued that the proposal is unworkable for the purposes of addressing more immediate reliability needs, specifying that EGUs may not be able to readily obtain the information or analysis necessary for preparing documentation for the EPA from their regional entity or state.
970 
Another commenter argued that the 
proposed mechanism provides no relief during an energy crisis because they would be offered only after the fact to resolve any alleged violations. Therefore, the possibility of future enforcement discretion and ACOs will 
not help a power generator decide in the moment whether to keep running and risk a violation or shut down, risking grid reliability and affecting our customers. the commenter also stated that ACOs are enforcement actions that carry negative implications and the potential for significant civil penalties, and citizen groups are unlikely to exercise discretion similar to that of the EPA, even if the EPA decides that a low (or no) penalty is appropriate. Lastly, this commenter noted that ACOs are typically intended to resolve relatively short-term noncompliance events that can be remedied and that do not reflect a fundamental inability to comply. 
Response: As discussed in section 
XII.F and elsewhere in this preamble, the EPA has made several adjustments and provided several mechanisms in this final rule that have the effect of or are expressly intended to provide grid operators and reliability authorities methods to address grid reliability. For example, the EPA is providing that states may include in their state plans a short-term reliability mechanism that allows affected EGUs to comply with an emission limitation corresponding to their baseline emission rate during periods of grid emergency. For further detail, see section XII.F.3.a of this preamble. This mechanism is intended to allow states to respond quickly to emergency situations, and to avoid affected EGUs being out of compliance or needing to work towards compliance through an ACO. Considering the structural changes the EPA has made in these final emission guidelines and the mechanisms it is providing states to address grid reliability, the EPA does not believe that states and affected EGUs will need to rely on ACOs to address compliance during periods of grid emergency. 
Finally, as explained in section VII.B 
of this preamble, coal-fired steam generating EGUs that plan to permanently cease operating before January 1, 2032, are not covered by these emission guidelines, i.e., they are 
not affected EGUs. However, to maintain the environmental integrity of these emission guidelines, it is critical that any existing sources that are operating as of January 1, 2032, are doing so subject to a requirement to operate more cleanly, and therefore essential that sources report on their actions to qualify for the exemption. As explained in the preamble to the proposed rule and section X.C.4 of this preamble, there are many steps the owners or operators of EGUs must take 
as they get ready to permanently cease operations and those steps vary between units and jurisdictions. Procession in a 
timely manner through these steps is the best indicator the EPA has of whether or 
not an existing source remains qualified for an exemption from these emission guidelines. Should a source’s plans to cease operating change, e.g., because the 
relevant planning authority has called on it to remain in operation for reliability or resource adequacy, the state, the public, and the EPA need to be aware of that change as soon as possible in order to appropriately address the source under these emission guidelines. The EPA therefore believes that having sources that plan to cease operation before January 1, 2032, report to the Agency on the steps they have taken towards doing so is critical to ensuring that those sources remain qualified for the exemption and thus to maintaining the environmental integrity of these emission guidelines. 
The EPA is requiring existing coal- 
fired steam generating EGUs that are in existence as of the date of a state plan submission but plan to cease operating before January 1, 2032, to comply with certain reporting requirements pursuant to CAA section 114(a). Among other things, this provision gives the EPA authority to require recordkeeping and reporting of sources for the purpose of ‘‘developing or assisting in the development of any implementation plan under . . . section 7411(d) of this title[ or] any standard of performance under section 7411 of this title,’’ ‘‘determining whether any person is in violation of any such standard of any requirement of such a plan,’’ or ‘‘carrying out any provision of this chapter.’’ Owners or operators of coal- fired steam generating EGUs that would be covered by these emission guidelines but for their plans to permanently cease operating are required to make reports necessary to ascertain whether they will in fact qualify for the exemption. This reporting obligation is necessary for preserving the integrity of the rule, and is consistent with ensuring that states develop plans that include standards of performance for all existing sources and for anticipating whether a state plan may need to be revised to include a standard of performance for an existing source that will not be eligible for an exemption from these emission guidelines.
971 
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case, reporting requirements are necessary to ensure 
that the predicate conditions for the sources’ standards of performance are satisfied. 
97288 FR 33240, 33402–03 (May 23, 2023). The reporting requirements the EPA is 
promulgating for sources that plan to 
permanently cease operation before January 1, 2032, are similar to the reporting requirements the Agency is requiring for medium-term coal-fired steam generating affected EGUs and affected EGUs relying on a shorter remaining useful life for a less-stringent standard of performance through RULOF. Those requirements are described in section X.C.4 of this preamble and require the definition of milestones tailored to individual units which are then embedded in periodic reporting requirements to assess progress toward the cessation of operations. However, consistent with CAA section 114, the requirements for sources that are exempt from these emission guidelines are limited to reporting and do not include the establishment of milestones. Thus, the requirements are as follows: Five years before any planned date to permanently cease operations or by the date upon which state plan is submitted, whichever is later, the owner or operator of the EGU must submit an initial report to the EPA that includes the following: (1) A summary of the process steps required for the EGU to permanently cease operation by the date included in the state plan, including the approximate timing and duration of each step and any notification 
requirements associated with deactivation of the unit. These process steps may include, e.g., initial notice to 
the relevant reliability authority of the deactivation date and submittal of an official retirement filing (or equivalent filing) made to the EGU’s reliability authority. (2) Supporting regulatory documents, including correspondence and official filings with the relevant regional RTO, ISO, balancing authority, PUC, or other applicable authority; any deactivation-related reliability assessments conducted by the RTO or ISO; and any filings pertaining to the EGU with the SEC or notices to investors, including but not limited to references in forms 10–K and 10–Q, in which the plans for the EGU are mentioned; any integrated resource plans and PUC orders referring to or approving the EGU’s deactivation; any reliability analyses developed by the RTO, ISO, or relevant reliability authority in response to the EGU’s deactivation notification; any notification from a reliability authority that the EGU may be needed for reliability purposes notwithstanding the EGU’s intent to deactivate; and any 
notification to or from an RTO, ISO, or relevant reliability authority altering the timing of deactivation for the EGU. 
For each of the remaining years prior 
to the date by which an EGU has committed to permanently cease operations, the operator or operator of an EGU must submit an annual status report to the EPA that includes: (1) Progress on each of the process steps identified in the initial report; and (2) supporting regulatory documents, including correspondence and official filings with the relevant RTO, balancing authority, PUC, or other applicable authority to demonstrate progress toward all steps; and (3) regulatory documents, and relevant SEC filings (listed in the preceding paragraph) that have been issued, filed or received since the prior report. 
The EPA is also requiring that EGUs 
that plan to permanently cease operation by January 1, 2032, submit a final report to the EPA no later than 6 months following its committed closure date. This report would document any actions that the unit has taken subsequent to ceasing operation to ensure that such cessation is permanent, including any regulatory filings with applicable authorities or decommissioning plans. 
2. Timing of State Plan Submissions 
The EPA proposed a state plan 
submission deadline that is 24 months 
from the date of publication of the final emission guidelines, which, at that time was 9 months longer than the default state plan submission timeline in the proposed 40 CFR part 60, subpart Ba implementing regulations. The EPA finalized subpart Ba with a default timeline of 18 months for state plan submissions, 40 CFR 60.23a(a)(1); regardless, the EPA is superseding subpart Ba’s timeline under these emission guidelines and is requiring that state plans be submitted 24 months after publication of this final rule in the Federal Register. 
As discussed in the preamble to the 
proposed rule,
972these emission 
guidelines apply to a relatively complex source category and state plan development will require significant analysis, consultation, and coordination between states, utilities, reliability authorities, and the owners or operators of individual affected EGUs. The power sector is subject to layers of regulatory and other requirements under different authorities (e.g., environmental, electric 
reliability, SEC) and the decisions states make under these emission guidelines will necessarily have to accommodate 
overlapping considerations and processes. States’ plan development may have to integrate decision making by not only the relevant air agency or agencies, but also ISOs, RTOs, or other balancing authorities. While 18 months is a reasonable timeframe to accommodate state plan development for source categories that do not require this level of coordination, the EPA does not believe it is reasonable to expect states and affected EGUs to undertake the coordination and planning necessary to ensure that plans for implementing these emission guidelines are consistent with the broader needs and trajectory of the power sector within the default period provided under subpart Ba. 
However, there are also notable 
differences between the circumstances of the proposed versus these final emission guidelines that are relevant to the state plan submission timeline. First, the EPA is not finalizing emission guidelines applicable to combustion turbine EGUs, which will significantly decrease the number of affected EGUs that states must address in their plans. Relative to proposal, there are approximately 184 fewer individual units to which these emission guidelines will apply (based on information at the time of the final rule), and the final emission guidelines do not include co-firing with low-GHG hydrogen as a BSER. The analytical and other burdens associated with state planning will thus be significantly lighter than anticipated at proposal, as states will have to address not only fewer sources but also a smaller universe of potential control strategies. Additionally, as explained in section VII.B.1 of this preamble, these final emission guidelines do not apply to existing coal-fired EGUs that plan to permanently cease operation prior to January 1, 2032. While under the proposed emission guidelines states would have had to establish standards of performance for every existing source operating as of January 1, 2030, states will be able to forgo addressing a subset of these existing sources under this final rule. 
In addition to states needing to 
address far fewer existing sources in their state plans than anticipated under the proposed emission guidelines, it is also not expected that the owners or operators of sources will begin implementation of control strategies before state plan submission. At proposal the EPA believed that some owners or operators of affected EGUs 
would do feasibility and FEED studies for CCS during state plan development, 
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97388 FR 33240, 33402 (May 23, 2023). 974See, e.g., 88 FR 80480, 80486 (November 17, 
2023). 975Am. Lung Ass’n v. EPA, 985 F.3d 914, 994 
(D.C. Cir. 2021). 
97688 FR 80480, 80488 (November 17, 2023). i.e., before state plan submission. For 
other affected coal-fired EGUs, the EPA 
anticipated that owners or operators would undertake certain planning, design, and permitting steps prior to state plan submission.
973In developing 
these final emission guidelines, the EPA changed its earlier assumption that states and affected EGUs would take significant steps towards planning and implementing control strategies prior to state plan submission. There are certain preliminary steps, such as an initial feasibility study, that the EPA expects that states and/or affected EGUs will undertake as a typical part of the state planning process. Under any rule or circumstances, it would not be reasonable for a state to commit an affected EGU to installation and operation of a certain control technology without undertaking at least an initial assessment of that technology—this is what is accomplished by feasibility studies. However, while the Agency believes that some sources are currently or will be undertaking FEED studies or other significant steps towards implementing pollution controls independent of these emission guidelines at earlier times, the EPA is not assuming when setting the compliance deadline that EGUs will be taking such steps prior to the existence of a state law requirement to do so (i.e., prior to state plan adoption and submission). 
The EPA received a number of 
comments on the proposed 24-month timeline for state plan submissions, which are discussed in detail below. As a general matter, many of these comments requested a longer timeframe for developing and submitting state plans. However, given that the number of affected EGUs state plans will have to cover under these final emission guidelines is very likely to be significantly lower than anticipated based on the proposal and that the EPA is not expecting states or owners or operators of affected EGUs to conduct FEED studies or otherwise start work on implementation prior to state plan submission, the EPA continues to believe that 24 months is an appropriate timeframe. Additionally, as discussed in the preamble to the recent revisions to the 40 CFR part 60, subpart Ba implementing regulations, the EPA’s approach to timelines for state plan submission and review under CAA section 111(d) is informed by the need to minimize the impacts of emissions of dangerous air pollutants on public health and welfare by proceeding as expeditiously and as reasonably possible while accommodating the time needed for states to develop an effective plan.
974To this end, the EPA is 
promulgating a timeframe for state plan submissions that is based on the minimum administrative time that is reasonably necessary given the need for states and owners or operators of affected EGUs to coordinate with reliability authorities in the development of state plans. In this case, the EPA believes that providing an additional 6 months beyond subpart Ba’s 18 months for state plan submissions is sufficient to accommodate this additional coordination, particularly given that the number of affected EGUs that states will be addressing in their plans is far fewer than expected under the proposed emission guidelines. 
Comment: Several commenters 
supported the EPA’s proposed 24-month timeframe for state plan submissions and stressed the importance of achieving emission reductions as quickly as possible. Commenters also noted that, based on anecdotal evidence, 24 months is generally sufficient to incorporate legislative, regulatory, and other administrative procedures associates with submitting state plans. Many commenters, however, requested that the EPA provide additional time for states to develop and submit their state plans; many requested 36 months with some commenters asserting that even more time would be required. Commenters asking for a longer timeframe cited reasons including the size of states’ EGU fleets and the 
specific BSERs proposed for certain subcategories (i.e., CCS and hydrogen 
co-firing), the need for owners or operators of affected EGUs to conduct systems analyses and update their integrated resource plans (IRPs) prior to making final decisions for state plans, and the need for states to get their choices approved by the appropriate reliability and other regulatory commissions. 
Response: As explained above, the 
EPA has made a number of changes in these final emission guidelines that have the effect of decreasing the planning burden on states, including not finalizing requirements for combustion turbine EGUs, exempting coal-fired EGUs that plan to cease operating by January 1, 2032, finalizing fewer subcategories for coal-fired EGUs, and not finalizing the subcategory for coal-fired EGUs that was based on utilization level. In general, these changes will decrease the number of units that state plans must address and 
also decrease the number and complexity of decisions states must make with regard to those units. Furthermore, 24 months is sufficient time for states to complete the steps necessary to develop and submit a state plan. Owners and operators are already or should already be considering how they will operate in a future environment where sources operating more cleanly are valued more. The EPA expects that states are already working or will work closely with the operators and operators of affected EGUs as those owners and operators update their IRPs and proceed through any necessary processes with, e.g., PUCs and 
reliability authorities. Thus, the Agency expects that consultation with and between owners and operators, PUCs, and reliability authorities is currently ongoing and will remain so throughout state plan development and implementation. Against this backdrop of ongoing planning and consultation, the EPA’s obligation in these emission guidelines is to ensure that state plan development and submission occurs within a timeframe consistent with the 
‘‘adherence to [the EPA’s] 2015 finding of an urgent need to counteract the threats posed by unregulated carbon dioxide emissions from coal-fired power plants.’’
975The timeframe the EPA is 
providing for state plan development upfront coupled with the long lead times it is providing for compliance with standards of performance provides states and owners or operators ample time to ensure the orderly implementation of the control requirements under these emission guidelines. 
Comment: Several commenters 
asserted that the EPA should provide longer than 24 months for state plan submissions to provide time for states to work through their necessary rulemaking, legislative, and/or administrative processes. Some commenters similarly stated that more than 24 months is needed in order to accommodate meaningful engagement on draft state plans. 
Response: The default timeline 
provided for state plan development and submission under 40 CFR part 60, subpart Ba is 18 months. As the EPA acknowledged when it promulgated this timeframe, state regulatory and legislative processes and resources can vary significantly and influence the time needed to develop and submit state plans.
976However, the CAA contains 
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97740 CFR 60.23a(a)(2), 60.28a. numerous, long-standing requirements 
under other programs for states to develop and submit plans in 18 or fewer months. The EPA therefore believes that states should be well positioned to accommodate an 18-month state plan submission timeframe, let alone at 24- month timeframe, from the perspective of the timing of state processes. The Agency does not believe it would be reasonable or consistent with CAA section 111’s purpose of reducing air pollution that endangers public health and the environment to extend state plan submission deadlines to defer to lengthy state administrative processes. 
Similarly, the EPA believes that 24 
months provides sufficient time for states to conduct meaningful engagement with pertinent stakeholders under these emission guidelines. As discussed in section X.E.1.b.i of this preamble, the EPA is providing additional information in these final emission guidelines that states may use to inform their meaningful engagement strategies and that can help them to fulfill their obligations in a timely and diligent fashion. For example, the EPA has noted a number of types of stakeholder communities to assist states in identifying their pertinent stakeholders. It has also provided information and tools that states may use in considering options for state plans, including facility-specific information on air emissions and the potential emissions implications of installing CCS. Commenters also pointed out that several states have recently adopted regulations, programs, and tools relevant to identifying pertinent stakeholders and conducting meaningful engagement; such programs and tools, in addition to states’ growing body of knowledge and experience pursuant to state initiatives and priorities, will aid states and stakeholders alike in conducting robust meaningful engagement in the timeframe for state plan development. 
3. State Plan Revisions 
As discussed in the preamble of the 
proposed action, the EPA expects that 
the 24-month state plan submission deadline for these emission guidelines 
would give states, utilities and independent power producers, and stakeholders sufficient time to determine into which subcategory each of the affected EGUs should fall and to formulate and submit a state plan accordingly. However, the EPA also acknowledges that, despite states’ best efforts to accurately reflect the plans of owners or operators with regard to affected EGUs at the time of state plan submission, such plans may subsequently change. In general, states 
have the authority and discretion to submit revised state plans to the EPA for approval.
977State plan revisions are 
generally subject to the same requirements as initial state plan submissions under these emission guidelines and the subpart Ba implementing regulations, including meaningful engagement, and the EPA reviews state plan revisions against the applicable requirements of these emission guidelines and the subpart Ba implementing regulations in the same manner in which it reviews initial state plan submissions pursuant to 40 CFR 60.27a. Requirements of the initial state plan approved by the EPA remain federally enforceable unless and until the EPA approves a plan revision that supersedes such requirements. States and affected EGUs should plan accordingly to avoid noncompliance. 
The EPA is finalizing a state plan 
submission date that is 24 months after the publication of the final emission guidelines and is finalizing the first compliance date for affected coal-fired EGUs in the medium-term subcategory and affected natural gas- and oil-fired EGUs of January 1, 2030. A state may choose to submit a plan revision prior to the compliance dates in its existing state plan; however, the EPA reiterates that any already approved federally enforceable requirements, including milestones, increments of progress, and standards of performance, will remain in place unless and until the EPA approves the plan revision. 
The EPA requested comment on 
whether it would be helpful to states to impose a cutoff date for the submission of plan revisions before the first compliance date. This would, in effect, establish a temporary moratorium on 
plan submissions in order to allow the EPA to act on the plans. State plan revisions would again be permitted after the final compliance date. The EPA is not finalizing such cutoff date to provide more flexibility to states in submitting revisions closer to the first compliance date, in the case that EPA may be able to review those revisions before the first compliance date. 
Comment: Several commenters 
generally disagreed with establishing a cutoff date for state plan revisions before the first compliance date, arguing these timelines would be unworkable because state plan revisions may require public notice and stakeholder engagement. 
Response: The EPA is not finalizing 
an explicit cutoff date that would in effect establish a temporary moratorium on plan submissions; however, the EPA 
notes that, because the first compliance date under the final emission guidelines is January 1, 2030, a plan revision submitted after November 1, 2028 (taking into consideration 1 year for EPA action on a state plan revision plus up to 60 days, approximately, for a completeness determination) may not provide sufficient time for the EPA to review and approve the plan sufficiently in advance of that compliance date to allow sources to appropriately plan for compliance. The EPA reiterates that EGUs will be expected to comply with any requirements already approved in the state plan until such time as the plan revision is approved. 
4. Dual-Path Standards of Performance 
for Affected EGUs 
As discussed in the proposed action, 
under the structure of these emission guidelines, states would assign affected coal-fired EGUs to subcategories in their state plans, and an affected EGU would not be able to change its applicable subcategory without a state plan revision. This is because, due to the nature of the BSERs for coal-fired steam generating units, an affected EGU that switches into either the medium-term or long-term subcategory may not be able to meet the compliance obligations for a new and different subcategory without considerable lead time; in order to ensure timely emission reductions, it is important that states identify which subcategories affected EGUs fall into in their state plan submissions so that affected EGUs have certainty about their expected regulatory obligations. Therefore, as a general matter, states must assign each affected EGU to a subcategory and have in place all the legal instruments necessary to implement the requirements for that subcategory by the time of state plan 
submission. 
However, the EPA also solicited 
comment on a dual-path approach that would allow coal-fired steam generating units to have two different standards of performance submitted to the EPA in a state plan based on potential inclusion in two different subcategories. This proposal was based in large part on the proposed structure of the subcategories for coal-fired affected EGUs, under which it would have been realistic to expect that sources could prepare to comply with either the presumptive standard of performance for, e.g., the 
imminent-term subcategory and the near-term subcategory or the imminent- term subcategory and the medium-term subcategory. 
Because the final emission guidelines 
include only two subcategories for coal- 
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97840 CFR 60.27a(b), (g)(1). 
979See generally 40 CFR 60.27a. 98040 CFR 60.27a(b). 
981See Document ID No. EPA–HQ–OAR–2023– 
0072–0660. 
982See Document ID No. EPA–HQ–OAR–2023– 
0072–0764. 98340 CFR 60.27a(c). 
98440 CFR 60.27a(d). 
98540 CFR 60.27a(f). fired affected EGUs and do not include 
the two subcategories for which the dual-path approach would have been appropriate, the EPA is not finalizing an approach that allows coal-fired steam generating units to have two different standards of performance submitted to the EPA in a state plan based on potential inclusion in two different subcategories. 
Comment: In general, commenters 
supported a dual-path approach; however, several commenters requested that the EPA accommodate a multi- pathway approach (three or more pathways) due to the complexity of state plans and potential for numerous compliance pathways because of factors beyond the EGU owner or operator’s control, such as infrastructure for CCS projects and increase in electric power demand due to electrification of the transportation sector. 
Response: As stated above, the EPA is 
not finalizing the dual-path approach, 
nor a multi-pathway approach. If an affected EGU wishes to switch subcategories after the initial state plan approval, the state should submit a state plan revision sufficiently in advance of the compliance date for the subcategory into which it was assigned to permit the EPA’s review and action on that plan revision. 
5. EPA Action on State Plans 
Pursuant to the final revisions to 40 
CFR part 60, subpart Ba, in this action, 
the EPA is subject to a 60-day timeline for the Administrator’s determination of completeness of a state plan submission and a 12-month timeline for action on state plans.
978The timeframes and 
requirements for state plan submissions described in this section also apply to state plan revisions.
979 
As discussed in the proposed action, 
the EPA would first review the components of the state plan to determine whether the plan meets the completeness criteria of 40 CFR 60.27a(g). The EPA must determine whether a state plan submission has met the completeness criteria within 60 days of its receipt of that submission. If the EPA has failed to make a completeness determination for a state plan submission within 60 days of receipt, the submission shall be deemed, by operation of law, complete as of that date. Subpart Ba requires the EPA to take final action on a state plan submission within 12 months of that submission’s being deemed complete. The EPA will review the components of state plan submissions against the applicable requirements of subpart Ba and these emission guidelines, consistent with the underlying requirement that state plans must be ‘‘satisfactory’’ ’ per CAA section 111(d). The Administrator would have the option to fully approve; fully disapprove; partially approve and partially disapprove; or conditionally approve a state plan submission.
980Any 
components of a state plan submission that the EPA approves become federally enforceable. 
The EPA solicited comment on the 
use of the timeframes regarding EPA action on state plans in subpart Ba and commenters encouraged reconsidering the schedule, suggesting either increasing or decreasing the amount of time for action on state plans. In the final emission guidelines, the EPA is not superseding the timeframes in subpart Ba regarding EPA action on state plans and plan revisions. 
Comment: One commenter suggested 
that the EPA should provide for automatic extension of compliance dates for affected EGUs if the Agency does not meet its 12-month deadline for plan approval.
981Other commenters 
expressed concerns that the EPA will be unable to review all plans in the 12- month timeframe. One commenter suggested that the EPA should strive to review plans in less than the proposed 12-month timeframe.
982 
Response: The EPA does not believe 
it is appropriate to provide automatic extensions of compliance dates based on the timeframe for EPA action on state plan submissions. While there may be some degree of regulatory uncertainty that stems from waiting for the Agency to act on a state plan submission, it would not be a reasonable solution to add to that uncertainty by also making compliance dates contingent on the date of EPA’s action. This additional uncertainty could have the effect of unnecessarily extending the compliance schedule and delaying emission reductions. Given that the dates on which the EPA takes final action on individual state plans are likely to be many and varied (based on, inter alia, when each state plan was submitted to the Agency), such extensions would create unnecessary confusion and potentially uneven application of the requirements for state plans. In this action, the EPA does not find a reason to supersede the timelines finalized in subpart Ba; therefore, review of and action on state plan submissions will be 
governed by the requirements of revised subpart Ba. 
6. Federal Plan Applicability and 
Promulgation Timing 
The provisions of 40 CFR part 60, 
subpart Ba, apply to the EPA’s promulgation of any Federal plans under these emission guidelines. The EPA’s obligation to promulgate a Federal plan is triggered in three situations: where a state does not submit a plan by the plan submission deadline; where the EPA determines that a state plan submission does not meet the completeness criteria and the time period for state plan submission has elapsed; and where the EPA fully or partially disapproves a state’s plan.
983 
Where a state has failed to submit a plan by the submission deadline, subpart Ba gives the EPA 12 months from the state 
plan submission due date to promulgate a Federal plan; otherwise, the 12-month period starts, as applicable, from the date the state plan submission is deemed incomplete or from the date of the EPA’s disapproval. If the state submits and the EPA approves a state plan submission that corrects the relevant deficiency within the 12-month period, before the EPA promulgates a Federal plan, the EPA’s obligation to promulgate a Federal plan is relieved.
984 
As provided by 40 CFR 60.27a(e), a 
Federal plan will prescribe standards of performance for affected EGUs of the same stringency as required by these emission guidelines and will require compliance with such standards as expeditiously as practicable but no later than the final compliance date under these guidelines. However, 40 CFR 60.27a(e)(2) provides that, upon application by the owner or operator of an affected EGU, the EPA may provide for the application of a less stringent standard of performance or longer compliance schedule than provided by these emission guidelines, in which case the EPA would follow the same process and criteria in the regulations that apply to states’ provision of RULOF standards. Under subpart Ba, the EPA is also required to conduct meaningful engagement with pertinent stakeholders prior to promulgating a Federal plan.
985 
As discussed in section X.E.2 of this 
preamble, the EPA is finalizing a deadline for state plan submissions of 24 months after publication of these final emission guidelines in the Federal Register. Therefore, if a state fails to timely submit a state plan, the EPA 
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98640 CFR 52.21(b)(1)(i). 
98740 CFR 52.21(b)(2)(i) and the term ‘‘net 
emissions increase’’ as defined at 40 CFR 
52.21(b)(3). 988For the PSD program, ‘‘regulated NSR 
pollutant’’ includes any pollutant for which a NAAQS has been promulgated (‘‘criteria pollutants’’) and any other air pollutant that meets the requirements of 40 CFR 52.21(b)(50). Some of these non-criteria pollutants include greenhouse gases, fluorides, sulfuric acid mist, hydrogen sulfide, and total reduced sulfur. 
989In re Shell Gulf of Mexico, Inc., 15 E.A.D. 103, 
149 and n.71 (EAB 2010) (internal citations omitted). would be obligated to promulgate a 
Federal plan within 36 months of publication of these final emission guidelines. Note that this will be the earliest possible obligation for the EPA to promulgate a Federal plan and that different triggers (e.g., a disapproved 
state plan) will result in later obligations to promulgate Federal plans for other states, contingent on when the obligation is triggered. 
Finally, the EPA acknowledges that, if 
a Tribe does not seek and obtain the authority from the EPA to establish a TIP, the EPA has the authority to establish a Federal CAA section 111(d) plan for areas of Indian country where designated facilities are located. A Federal plan would apply to all designated facilities located in the areas of Indian country covered by the Federal plan unless and until the EPA approves an applicable TIP applicable to those facilities. 
XI. Implications for Other CAA 
Programs 
A. New Source Review Program 
The CAA’s New Source Review (NSR) 
preconstruction permitting program 
applies to stationary sources that emit pollutants resulting from new construction and modifications of existing sources. The NSR program is authorized by CAA section 110(a)(2)(C), which requires that each state implementation plan (SIP) ‘‘include a program to provide for the . . . regulation of the modification and construction of any stationary source within the areas covered by the plan as necessary to assure that [NAAQS] are achieved, including a permit program as 
required in parts C and D [of title I of the CAA].’’ The ‘‘permit program as required in parts C and D’’ refers to the ‘‘major NSR’’ program, which applies to new ‘‘major stationary sources’’
986and 
‘‘major modifications’’987of existing 
stationary sources. The ‘‘minor NSR’’ program applies to new construction and modifications of stationary sources that do not meet the emission thresholds for major NSR. NSR applicability is pollutant-specific, so a source seeking to newly construct or modify may need to obtain both major NSR and minor NSR permits before it can begin construction. 
Under the CAA, states have primary 
responsibility for issuing NSR permits, and they can customize their programs within the limits of EPA regulations. The Federal NSR rules applying to state permitting authorities are found at 40 
CFR 51.160 to 51.166. The EPA’s primary role is to approve state program regulations and to review, comment on, and take any other necessary actions on draft and final permits to assure consistency with the EPA’s rules, the SIP, and the CAA. When a state does not have EPA-approved authority to issue NSR permits, the EPA issues the NSR permits within the state, or delegates authority to the state to issue the NSR permits on behalf of the EPA, pursuant to rules at 40 CFR 49.151–173, 40 CFR 52.21, and 40 CFR 124. 
For the major NSR program, the 
requirements that apply to a source depend on the air quality designation at the location of the source for each of its emitted pollutants at the time the permit is issued. Major NSR permits for sources 
located in an area that is designated as attainment or unclassifiable for the NAAQS for its pollutants are referred to as Prevention of Significant Deterioration (PSD) permits. PSD permits can include requirements for specific pollutants for which there are no NAAQS.
988Sources subject to PSD 
must, among other requirements, comply with emission limitations that reflect the Best Available Control Technology (BACT) for ‘‘each pollutant subject to regulation’’ as specified by CAA sections 165(a)(4) and 169(3). Major NSR permits for sources located in nonattainment areas and that emit at or above the specified major NSR threshold for the pollutant for which the area is designated as nonattainment are referred to as Nonattainment NSR (NNSR) permits. Sources subject to NNSR must, among other requirements, meet the Lowest Achievable Emission Rate (LAER) pursuant to CAA sections 171(3) and 173(a)(2) for any pollutant subject to NNSR. For the minor NSR program, neither the CAA nor the EPA’s rules set forth a minimum control technology requirement. 
In keeping with the goal of progress 
toward attaining the NAAQS, sources seeking NNSR permits must provide or purchase ‘‘offsets’’—i.e., decreases in 
emissions that compensate for the increases from the new source or modification. For sources seeking PSD permits, offsets are not required, but they must demonstrate that the emissions from the project will not cause or contribute to a violation of the NAAQS or the ‘‘PSD increments’’ (i.e., 
margins of ‘‘significant’’ air quality deterioration above a baseline concentration that establish an air quality ceiling, typically below the NAAQS, for each PSD area). Sources can often make this air quality demonstration based on the BACT level of control or by accepting more stringent air quality-based limitations. However, if these methods are insufficient to show that increased emissions from the source will not cause or contribute to a violation of air quality standards, applicants may undertake mitigation measures that are analogous to offsets in order to satisfy this PSD permitting criterion. 
When the EPA is making NSR 
permitting decisions, it has legal authority to consider potential 
disproportionate environmental burdens on a case-by-case basis. Based on Executive Order (E.O.) 12898, the EPA’s Environmental Appeals Board (EAB) has held that environmental justice considerations must be considered in connection with the issuance of Federal PSD permits issued by EPA Regional Offices or states acting under delegations of Federal authority. The EAB ‘‘has . . . encouraged permit issuers to examine any ‘superficially plausible’ claim that a minority or low- income population may be disproportionately affected by a particular facility.’’
989EPA guidance 
and EAB decisions do not advise EPA Regional Offices or delegated NSR permitting authorities to integrate environmental justice considerations into any particular component of the PSD permitting review, such as the determination of BACT. The practice of EPA Regional Offices and delegated states has been to conduct a largely freestanding environmental justice analysis for PSD permits that can take into account case-specific factors germane to any individual permit decision. 
The minimum requirements for an 
approvable state NSR permitting program do not require state permitting authorities to reflect environmental justice considerations in their permitting decisions. However, states that implement NSR programs under an EPA-approved SIP have discretion to consider environmental justice in their NSR permitting actions and adopt additional requirements in the permitting decision to address potential disproportionate environmental burdens. Additionally, in some cases, a 
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990See Memorandum from Gary S. Guzy, EPA 
General Counsel, titled EPA Statutory and 
Regulatory Authorities Under Which Environmental Justice Issues May Be Addressed in Permitting (December 1, 2000). 99142 U.S.C. 7479(3) (‘‘In no event shall 
application of ‘best available control technology’ result in emissions of any pollutants which will exceed the emissions allowed by any applicable standard established pursuant to [CAA Section 111 or 112].’’). 
992For more information on EPA’s recommended 
BACT approach, see U.S. Environmental Protection Agency, New Source Review Workshop Manual (October 1990; Draft) at https://www.epa.gov/sites/ default/files/2015-07/documents/1990wman.pdf and U.S. Environmental Protection Agency, PSD and Title V Permitting Guidance for Greenhouse Gases (March 2011; EPA–457/B–11–001) at https:// 
www.epa.gov/sites/default/files/2015-07/ 
documents/ghgguid.pdf. state law requires consideration of 
environmental justice in the state’s permitting decisions. 
Through the NSR permit review 
process, permitting authorities have requirements for public participation in decision-making, which provide discretion for permitting authorities to provide enhanced engagement for communities with environmental justice concerns. This includes opportunities to enhance environmental justice by facilitating increased public participation in the formal permit consideration process (e.g., by granting 
requests to extend public comment periods, holding multiple public meetings, or providing translation services at hearings in areas with limited English proficiency). The permitting authority can also take informal steps to enhance participation earlier in the process, such as inviting community groups to meet with the permitting authority and express their concerns before a draft permit is issued. 
Additionally, in accordance with 
CAA 165(a)(2), the PSD regulations require the permitting authority to ‘‘[p]rovide opportunity for a public hearing for interested persons to appear and submit written or oral comments on the air quality impact of the source, alternatives to it, the control technology required, and other appropriate considerations.’’ 40 CFR 51.166(q)(2)(v). The ‘‘alternatives’’ and ‘‘other appropriate considerations’’ language in CAA 165(a)(2) can be interpreted to provide the permitting authority with discretion to incorporate siting and environmental justice considerations when issuing PSD permits—specifically, to impose permit conditions on the basis of environmental justice considerations raised in public comments regarding the air quality impacts of a proposed source. The EAB has recognized that consideration of the need for a facility is within the scope of CAA 165(a)(2) when a commenter raises the issue. The EPA has recognized that this language provides a potential statutory foundation in the CAA for this discretion.
990The Federal regulations 
for NNSR permits also have an analysis of alternatives required by CAA 173(a)(5). 40 CFR 51.165(i). 
1. Control Technology Reviews for 
Major NSR Permits 
The statutory and regulatory basis for 
a control technology review for a source undergoing major NSR permitting differs from the criteria required in establishing an NSPS or emission guidelines. As such, sources that are permitted under major NSR may have differing control requirements for a 
pollutant than what is required by an applicable standard under CAA section 111. As noted above, sources permitted under the minor NSR program do not have a minimum control technology standard specified by statute or EPA rule, so a permitting authority has more flexibility in its determination of control technology for aminor NSR permit. 
For PSD permits, the permitting 
authority must establish emission limitations based on BACT for each pollutant that is subject to PSD at the new major stationary source or at each emissions unit involved in the major modification. BACT is assessed on a case-by-case basis, and the permitting authority, in its analysis of BACT for each pollutant, evaluates the emission reductions that each available emissions-reducing technology or technique would achieve, as well as the energy, environmental, economic, and other costs associated with each technology or technique. The CAA also specifies that BACT cannot be less stringent than any applicable standard of performance under the NSPS.
991 
In conducting a BACT analysis, many 
permitting authorities apply the EPA’s five-step ‘‘top-down’’ approach, which the EPA recommends to ensure that all the criteria in the CAA’s definition of BACT are considered. This approach begins with the permitting authority identifying all available control options that have the potential for practical application for the regulated NSR pollutant and emissions unit under evaluation. The analysis then evaluates each option and eliminates options that are technically infeasible, ranks the remaining options from most to least effective, evaluates the energy, environmental, economic impacts, and other costs of the options, eliminates options that are not achievable based on these considerations from the top of the list down, and ultimately selects the most effective remaining option as BACT.
992 While the BACT review process is 
intended to capture a broad array of 
potential options for pollution control, the EPA has recognized that the list of available control options need not necessarily include inherently lower polluting processes that would fundamentally redefine the nature of the source proposed by the permit applicant. Thus, BACT should generally not be applied to regulate the permit applicant’s purpose or objective for the proposed facility. However, this approach does not preclude a permitting authority from considering options that would change aspects (either minor or significant) of an applicants’ proposed facility design in order to achieve pollutant reductions that may or may not be deemed achievable after further evaluation at later steps of the process. The EPA does not interpret the CAA to prohibit fundamentally redefining the source and has recognized that permitting authorities have the discretion to conduct a broader BACT analysis if they desire. The ‘‘redefining the source’’ issue is ultimately a question of degree that is within the discretion of the permitting authority, and any decision to exclude an option on ‘‘redefining the source’’ grounds should be explained and documented in the permit record. 
In conducting the analysis of energy, 
environmental and economic impacts arising from each control option remaining under consideration, permitting authorities have considerable discretion in deciding the specific form of the BACT analysis and the weight to be given to the particular impacts under consideration. The EPA and other permitting authorities have most often used this analysis to eliminate more stringent control technologies with significant or unusual effects that are unacceptable in favor of the less stringent technologies with more 
acceptable collateral environmental effects. Permitting authorities may consider a wide variety of environmental impacts in this analysis, such as solid or hazardous waste generation, discharges of polluted water from a control device, visibility impacts, demand on local water resources, and emissions of other pollutants subject to NSR or pollutants not regulated under NSR such as air toxics. A permitting authority could place more weight on the collateral environmental effect of a control alternative on local communities—e.g., if emission increases 
of co-pollutants from operating the control device may disproportionately 
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993New Source Review Workshop Manual 
(October 1990; Draft), page G.4. 
99442 U.S.C. 7501(3); 40 CFR 51.165(a)(1)(xiii); 40 
CFR part 51, appendix S, section II.A.18. 995Certain stationary sources that emit or have 
the potential to emit a pollutant at a level that is 
equal to or greater than specified thresholds are subject to major source requirements. See, e.g., CAA 
sections 165(a)(1), 169(1), 501(2), 502(a). A synthetic minor limitation is a legally and practicably enforceable restriction that has the effect of limiting emissions below the relevant level and that a source voluntarily obtains to avoid major stationary source requirements, such as the PSD or title V permitting programs. See, e.g., 40 CFR 
52.21(b)(4), 51.166(b)(4), 70.2 (definition of ‘‘potential to emit’’). affect a minority or low-income 
population—which may result in the permitting authority eliminating that control option and ultimately selecting a less stringent control technology for the target pollutant as BACT because it has more acceptable collateral impacts. 
In addition, this analysis may extend 
to considering reduced, or excessive, energy or environmental impacts of the control alternative at an offsite location that is in support the operation of the facility obtaining the permit. For example, in the case of a facility that proposes to co-fire its new stationary combustion turbines with hydrogen procured from an offsite production facility, a permitting authority may determine it is appropriate to weigh favorably a control option that involves co-firing with hydrogen produced from low-GHG emitting processes, such as electrolysis powered by renewable energy, to recognize the reduced environmental impact of producing the fuel for the control option. 
For NNSR permits, the statutory 
requirement for establishing LAER is more prescriptive and, consequently, tends to provide less discretion to permitting authorities than the discretion allowed under BACT. For new major stationary sources and major modifications in nonattainment areas, LAER is defined as the most stringent emission limitation required under a SIP or achieved in practice for a class or category of sources. Thus, unlike BACT, the LAER requirement does not consider economic, energy, or other environmental factors, except that LAER is not considered achievable if the cost of control is so great that a major new stationary source could not be built or operated.
993As with BACT 
determinations, a determination of LAER cannot be less stringent than any applicable NSPS.
994 
2. NSR Implications of the NSPS 
Any source that is planning to install 
a new or reconstructed EGU that meets the applicability of this final NSPS will likely require an NSR permit prior to its construction. In addition to including conditions for GHG emissions, the NSR permit would contain emission limitations for the non-GHG pollutants emitted by the new or reconstructed EGU. Depending on the level of emissions for each pollutant, the source may require a major NSR permit, minor NSR permit, or a combination of both types of permits. As GHGs are regulated pollutants 
under the PSD program, this NSPS 
serves as the minimum level of control in determining BACT for any new major stationary source or major modification that meets the applicability of this NSPS and commences construction on its affected EGU(s) after the date of publication of the proposed NSPS in the Federal Register. However, as explained above, the fact that a minimum control requirement for BACT is established by an applicable NSPS does not mean that a permitting authority cannot select a more stringent control level for the PSD permit or consider control technologies for BACT beyond those that were considered in developing the NSPS. The authority for BACT is separate from that of BSER, and it requires a case-by-case review of a specific stationary source at the time its owner or operator applies for a PSD permit. Accordingly, the BACT analysis for a source with an applicable NSPS should reflect source- specific factors and any advances in control technology, reductions in the costs or other impacts of using particular control strategies, or other relevant information that may have become available after the EPA issued the NSPS. 
3. NSR Implications of the Emission 
Guidelines 
With respect to the final emission 
guidelines, each state will develop a plan that establishes standards of performance for each affected EGU in the state that meets the applicability criteria of this emission guidelines. In doing so, a state agency may develop a plan that requires an existing stationary source to undertake a physical or operational change. Under the NSR program, when a stationary source undertakes a physical or operational change, even if it is doing so to comply with a national or state level requirement, the source may need to obtain a preconstruction NSR permit, with the type of permit (i.e., NNSR, 
PSD, or minor NSR) depending on the amount of the emissions increase resulting from the change and the air quality designation at the location of the 
source for its emitted pollutants. However, since emission guidelines are intended to reduce emissions at an existing stationary source, a NSR permit may not be needed to perform the physical or operational change required by the state plan if the change will not increase emissions at the source. 
As noted elsewhere in this preamble, 
sources that will be complying with their state plan’s standards of performance by installing and operating CCS could experience criteria pollutant emission increases that may result in 
the source triggering major NSR requirements. If a source with an affected EGU does trigger major NSR requirements for one or more pollutants as a result of complying with its standards of performance, the permitting authority would conduct a control technology review (i.e., BACT or 
LAER, as appropriate) for each of the pollutants and require that the source comply with the other applicable major NSR requirements. As noted in section 
VII of this preamble, in light of concerns expressed by stakeholders over possible co-pollutant increases from CCS retrofit projects, the EPA plans to review its NSR guidance and determine how it can be updated to better assist permit applicants and permitting authorities in conducting BACT reviews for sources that intend to install CCS. 
States may also establish the 
standards of performance in their plans in such a way so that their affected sources, in complying with those standards, in fact would not have emission increases that trigger major NSR requirements. To achieve this, the state would need to conduct an analysis consistent with the NSR regulatory requirements that supports its determination that as long as affected sources comply with the standards of performance, their emissions would not increase in a way that trigger major NSR requirements. For example, a state could, as part of its state plan, develop enforceable conditions for a source expected to trigger major NSR that would effectively limit the unit’s ability to increase its emissions in amounts that would trigger major NSR (effectively establishing a synthetic minor limitation).
995Some commenters 
asserted that base load units may not be able to readily rely on this option to limit their emission increases given the need for those units to respond to demand and maintain grid reliability. In these cases, states may adopt other strategies in their state plans to ensure that base load units have the needed flexibility to operate and do so without triggering major NSR requirements. 
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996See 40 CFR 70.7(f)(1)(i). 
997See 40 CFR 70.7(f)(2). 
998The EPA also examined the final rules under 
a variety of different assumptions regarding demand, gas price, and contemporaneous 
rulemakings and determined that those alternative projections, inclusive of CCS buildout and cost 
profiles, would not alter any BSER design parameters selected in this action. For further 
discussion, see the technical memorandum, IPM Sensitivity Runs, available in the rulemaking 
docket. B. Title V Program 
Title V regulations require each 
permit to include emission limitations 
and standards, including operational requirements and limitations that assure compliance with all applicable requirements. Requirements resulting from these rules that are imposed on EGUs or other potentially affected entities that have title V operating permits are applicable requirements under the title V regulations and would need to be incorporated into the source’s title V permit in accordance with the schedule established in the title V regulations. For example, if the permit has a remaining life of 3 years or more, a permit reopening to incorporate the newly applicable requirement shall be completed no later than 18 months after promulgation of the applicable requirement. If the permit has a remaining life of less than 3 years, the newly applicable requirement must be incorporated at permit renewal.
996 
Additionally, proceedings to reopen and issue a permit shall follow the same procedures that apply to initial permit issuance and only affect the parts of the permit for which cause to reopen exists. The reopening of permits is expected to be made as expeditiously as possible.
997 
In the proposal, the EPA also 
indicated that if a state needs to include provisions related to the state plan in a source’s title V permit before submitting the plan to the EPA, these limits should be labeled as ‘‘state-only’’ or ‘‘not federally enforceable’’ until the EPA has approved the state plan. The EPA solicited comments on whether, and under what circumstances, states might use this mechanism. While no specific comments were received on this point, the EPA would like to further clarify that in finalizing this direction, the intention is to ensure that meaningful public participation is available during the development of a state plan, rather than limiting engagement to the permitting process. While the public would have the opportunity to comment on the individual permit provisions, this would not allow for the opportunity to comment on the plan as a whole 
before it is finalized. 
XII. Summary of Cost, Environmental, 
and Economic Impacts 
In accordance with E.O. 12866 and 
13563, the guidelines of the Office of Management and Budget (OMB) Circular A–4 and the EPA’s Guidelines for Preparing Economic Analyses, the EPA prepared an RIA for these final actions. The RIA is separate from the EPA’s statutory BSER determinations and did not influence the EPA’s choice of BSER for any of the regulated source categories or subcategories. This RIA presents the expected economic consequences of the EPA’s final rules, including analysis of the benefits and costs associated with the projected emission reductions for three illustrative scenarios. The first scenario represents the final NSPS and emission guidelines in combination. The second and third scenarios represent different stringencies of the combined policies. All three illustrative scenarios are compared against a single baseline. For detailed descriptions of the three illustrative scenarios and the baseline, see section 1 of the RIA, which is titled ‘‘Regulatory Impact Analysis for the New Source Performance Standards for Greenhouse Gas Emissions from new, Modified, and Reconstructed Fossil Fuel-Fired Electric Generating Units; Emission Guidelines for Greenhouse Gas Emissions from Existing Fossil Fuel-Fired Electric Generating Units; and Repeal of the Affordable Clean Energy Rule’’ and is available in the rulemaking docket.
998 
The three scenarios detailed in the 
RIA, including the final rules scenario, are illustrative in nature and do not represent the plans that states may ultimately pursue. As there are considerable flexibilities afforded to states in developing their state plans, the EPA does not have sufficient information to assess specific 
compliance measures on a unit-by-unit basis. Nonetheless, the EPA believes that such illustrative analysis can provide important insights. In the RIA, the EPA evaluates the 
potential impacts of the three 
illustrative scenarios using the present value (PV) of costs, benefits, and net benefits, calculated for the years 2024 to 2047 from the perspective of 2019. In addition, the EPA presents the assessment of costs, benefits, and net benefits for specific snapshot years, consistent with the Agency’s historic practice. These specific snapshot years are 2028, 2030, 2035, 2040, and 2045. In addition to the core benefit-cost analysis, the RIA also includes analyses of anticipated economic and energy impacts, environmental justice impacts, and employment impacts. 
The analysis presented in this 
preamble section summarizes key results of the illustrative final rules scenario. For detailed benefit-cost results for the three illustrative scenarios and results of the variety of impact analysis just mentioned, please see the RIA, which is available in the docket for this action. 
It should be noted that for the RIA for 
this rulemaking, the EPA undertook the same approach to determine benefits and costs as it has generally taken in prior rulemakings concerning the electric power sector. It does not rely on the benefit-cost results included in the RIA as part of its BSER analysis. Rather, the BSER analysis considers the BSER 
criteria as set out in CAA section 111(a)(1) and the caselaw—including the costs of the controls to the source, the amount of emission reductions, and other criteria—as described in section V.C.2. 
A. Air Quality Impacts 
For the analysis of the final rules, 
total cumulative power sector CO
2 
emissions between 2028 and 2047 are 
projected to be 1,382 million metric tons lower under the illustrative final rules scenario than under the baseline. Table 4 shows projected aggregate annual electricity sector emission changes for the illustrative final rules scenario, relative to the baseline. 
TABLE 4—P ROJECTED ELECTRICITY SECTOR EMISSION IMPACTS FOR THE ILLUSTRATIVE FINAL RULES SCENARIO , 
RELATIVE TO THE BASELINE  
CO 2 
(million metric 
tons) Annual NO X 
(thousand 
short tons) Ozone season 
NO X 
(thousand 
short tons) Annual SO 2 
(thousand 
short tons) Direct PM 2.5 
(thousand 
short tons) Mercury 
(tons) 
2028 ............................................................. ¥38 ¥20 ¥6 ¥34 ¥2 ¥0.1 
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999Results using the 2 percent discount rate were 
not included in the proposals for these actions. The 
2003 version of OMB’s Circular A–4 had generally 
recommended 3 percent and 7 percent as default rates to discount social costs and benefits. The analysis of the proposed rules used these two recommended rates. In November 2023, OMB 
finalized an update to Circular A–4, in which it recommended the general application of a 2 percent 
rate to discount social costs and benefits (subject to regular updates). The Circular A–4 update also recommended consideration of the shadow price of capital when costs or benefits are likely to accrue 
to capital. As a result of the update to Circular A– 4, we include cost and benefits results calculated using a 2 percent discount rate. TABLE 4—P ROJECTED ELECTRICITY SECTOR EMISSION IMPACTS FOR THE ILLUSTRATIVE FINAL RULES SCENARIO , 
RELATIVE TO THE BASELINE —Continued 
CO 2 
(million metric 
tons) Annual NO X 
(thousand 
short tons) Ozone season 
NO X 
(thousand 
short tons) Annual SO 2 
(thousand 
short tons) Direct PM 2.5 
(thousand 
short tons) Mercury 
(tons) 
2030 ............................................................. ¥50 ¥20 ¥7 ¥20 ¥2 ¥0.1 
2035 ............................................................. ¥123 ¥49 ¥19 ¥90 ¥1 ¥0.1 
2040 ............................................................. ¥54 ¥6 ¥6 ¥4 2 0.2 
2045 ............................................................. ¥42 ¥24 ¥14 ¥41 ¥2 ¥0.2 
Note: Ozone season is the May through September period in this analysis. 
B. Compliance Cost Impacts 
The power industry’s compliance 
costs are represented in this analysis as 
the change in electric power generation costs between the baseline and illustrative scenarios, including the cost of monitoring, reporting, and recordkeeping. In simple terms, these costs are an estimate of the increased power industry expenditures required to comply with the final actions. 
The compliance assumptions—and, 
therefore, the projected compliance costs—set forth in this analysis are illustrative in nature and do not represent the plans that states may ultimately pursue. The illustrative final rules scenario is designed to reflect, to the extent possible, the scope and nature of the final rules. However, there is uncertainty with regards to the precise measures that states will adopt to meet the requirements because there are flexibilities afforded to the states in developing their state plans. 
The IRA is projected to accelerate the 
ongoing shift towards lower-emitting technology. In particular, under the baseline tax credits for low-emitting technology results in growing generation share for renewable resources and the deployment of 11 GW of CCS retrofits on existing coal-fired steam generating units by 2035. New 
combined cycle builds are 20 GW by 2030, and existing coal capacity continues to decline, falling to 84 GW by 2030 and 31 GW by 2040. Under the 
illustrative final rules scenario, the EPA projects an incremental 8 GW of CCS retrofits on existing coal-fired steam generating units by 2035 relative to the baseline. By 2035, relative to the baseline, new combined cycle builds are 
2 GW lower, new combustion turbine builds are 10 GW higher, and wind and solar additions are 15 GW higher. Total coal capacity is projected to be 73 GW in 2030 and 19 GW by 2040. As a result, the compliance cost of the final rules is lower than it would be absent the IRA. 
We estimate the PV of the projected 
compliance costs for the analysis of the final standards for new combustion turbines and for existing steam generating EGUs over the 2024 to 2047 period, as well as estimate the equivalent annual value (EAV) of the flow of the compliance costs over this period. The EAV represents a flow of constant annual values that, had they occurred annually, would yield a sum equivalent to the PV. All dollars are in 2019 dollars. We estimate the PV and EAV using discount rates of 2 percent, 3 percent, and 7 percent.
999The PV of 
compliance costs discounted at the 2 percent rate is estimated to be about 19 billion, with an EAV of about 0.98 billion. At the 3 percent rate, the PV of compliance costs is estimated to be about 15 billion, with an EAV of about 0.91 billion. At the 7 percent discount rate, the PV of compliance costs is estimated to be about 7.5 billion, with 
an EAV of about 0.65 billion. To put this in perspective, this levelized compliance cost is roughly one percent of the total projected levelized cost to produce electricity over the same timeframe under the baseline. 
Section 3 of the RIA presents detailed 
discussions of the compliance cost projections for the final rule requirements, as well as projections of compliance costs for less and more stringent regulatory options. 
C. Economic and Energy Impacts 
These final actions have economic 
and energy market implications. The 
energy impact estimates presented here reflect the EPA’s illustrative analysis of the final rules. States are afforded flexibility to implement the final rules, and thus the estimated impacts could be different to the extent states make different choices than those assumed in the illustrative analysis. In addition, as discussed in section VII.E.1 of this preamble, the factors driving these impacts, including potential revenue streams for captured carbon, may 
change over the next 25 years, leading the estimated impacts to be different than reality. Table 5 presents a variety of energy market impact estimates for 2028, 2030, 2035, 2040, and 2045 for the illustrative final rules scenario, relative to the baseline. 
TABLE 5—S UMMARY OF CERTAIN ENERGY MARKET IMPACTS FOR THE ILLUSTRATIVE FINAL RULES SCENARIO , RELATIVE  
TO THE BASELINE  
[Percent change] 
2028 (%) 2030 (%) 2035 (%) 2040 (%) 2045 (%) 
Retail electricity prices ............................................................................. ¥1 0 1 0 1 
Average price of coal delivered to power sector ..................................... ¥1 ¥1 0 0 ¥32 
Coal production for power sector use ..................................................... ¥6 ¥4 ¥21 15 ¥84 
Price of natural gas delivered to power sector ........................................ ¥2 0 3 0 0 
Price of average Henry Hub (spot) .......................................................... ¥2 ¥1 3 0 0 
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1000U.S. EPA. 2017. SAB Advice on the Use of 
Economy-Wide Models in Evaluating the Social 
Costs, Benefits, and Economic Impacts of Air Regulations. EPA–SAB–17–012. 
1001U.S. EPA. 2020. Technical Review of EPA’s 
Computable General Equilibrium Model, SAGE. EPA–SAB–20–010. TABLE 5—S UMMARY OF CERTAIN ENERGY MARKET IMPACTS FOR THE ILLUSTRATIVE FINAL RULES SCENARIO , RELATIVE  
TO THE BASELINE —Continued 
[Percent change] 
2028 (%) 2030 (%) 2035 (%) 2040 (%) 2045 (%) 
Natural gas use for electricity generation ................................................ ¥1 ¥2 4 0 2 
These and other energy market 
impacts are discussed more extensively 
in section 3 of the RIA. 
More broadly, changes in production 
in a directly regulated sector may have effects on other markets when output from that sector—for these rules, electricity—is used as an input in the production of other goods. It may also affect upstream industries that supply goods and services to the sector, along with labor and capital markets, as these suppliers alter production processes in response to changes in factor prices. In addition, households may change their demand for particular goods and services due to changes in the price of electricity and other final goods prices. Economy-wide models—and, more specifically, computable general equilibrium (CGE) models—are analytical tools that can be used to evaluate the broad impacts of a regulatory action. A CGE-based approach to cost estimation concurrently considers the effect of a regulation across all sectors in the economy. 
In 2015, the EPA established a 
Science Advisory Board (SAB) panel to consider the technical merits and challenges of using economy-wide models to evaluate costs, benefits, and economic impacts in regulatory analysis. In its final report, the SAB recommended that the EPA begin to integrate CGE modeling into applicable regulatory analysis to offer a more comprehensive assessment of the effects of air regulations.
1000In response to the 
SAB’s recommendations, the EPA developed a new CGE model called SAGE designed for use in regulatory analysis. A second SAB panel performed a peer review of SAGE, and the review concluded in 2020.
1001 
The EPA used SAGE to evaluate 
potential economy-wide impacts of these final rules, and the results are contained in section 5.2 of the RIA. Note that SAGE does not currently estimate changes in emissions nor account for environmental benefits. The annualized 
social cost estimated in SAGE for the finalized rules is approximately $1.32 billion (2019 dollars) between 2024 and 2047 using a 4.5 percent discount rate that is consistent with the internal discount rate in the model. Under the assumption that compliance costs from IPM in 2056 continue until 2081, the equivalent annualized value for social costs in the SAGE model is $1.51 billion (2019 dollars) over the period from 2024 to 2081, again using a 4.5 percent discount rate that is consistent with the internal discount rate of the model. The social cost estimate reflects the combined effect of the final rules’ requirements and interactions with IRA subsidies for specific technologies that are expected to see increased use in response to the final rules. We are not able to identify their relative roles currently. 
At proposal, the EPA solicited 
comment on the SAGE analysis presented in the RIA appendix. The SAGE analysis of the final rules is responsive to those comments. The comments received were supportive of the use of SAGE for estimating economy-wide social costs and other economy-wide impacts alongside the IPM-based cost and benefit estimates. The comments also suggested a variety of sensitivity analyses and several longer-term research goals for improving the capabilities of SAGE, such as adding a representation of emissions changes. For more detailed comment summaries and responses, see the response to comments in the docket for these actions. 
Environmental regulation may affect 
groups of workers differently, as changes in abatement and other compliance activities cause labor and other resources to shift. An employment impact analysis describes the characteristics of groups of workers potentially affected by a regulation, as well as labor market conditions in affected occupations, industries, and geographic areas. Employment impacts of these final actions are discussed more extensively in section 5 of the RIA. D. Benefits 
This section includes the estimated 
total benefits and the estimated net 
benefits of the final rules. 
1. Total Benefits 
Pursuant to E.O. 12866, the RIA for 
these actions analyzes the benefits 
associated with the projected emission changes under the final rules to inform the EPA and the public about these projected impacts. These final rules are projected to reduce national emissions 
of CO
2, SO 2, NO X, and PM 2.5, which we 
estimate will provide climate benefits and public health benefits. The potential climate, health, welfare, and water quality impacts of these emission changes are discussed in detail in the RIA. In the RIA, the EPA presents the projected monetized climate benefits due to reductions in CO
2emissions and 
the monetized health benefits attributable to changes in SO
2, NO X, and 
PM 2.5emissions, based on the emissions 
estimates in illustrative scenarios described previously. We monetize benefits of the final rules and evaluate other costs in part to enable a comparison of costs and benefits pursuant to E.O. 12866, but we recognize that there are substantial uncertainties and limitations in monetizing benefits, including benefits that have not been quantified or monetized. 
We emphasize that the monetized 
benefits analysis is entirely distinct from the statutory BSER determinations finalized herein and is presented solely for the purposes of complying with E.O. 12866. As discussed in more detail in the proposal and earlier in this action, the EPA weighed the relevant statutory factors to determine the appropriate standards and did not rely on the monetized benefits analysis for purposes of determining the standards. E.O. 12866 separately requires the EPA to perform a benefit-cost analysis, including monetizing costs and benefits where practicable, and the EPA has conducted such an analysis. 
The EPA estimates the climate 
benefits of GHG emissions reductions expected from the final rules using estimates of the social cost of greenhouse gases (SC–GHG) that reflect recent advances in the scientific 
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1002National Academies of Sciences, Engineering, 
and Medicine (National Academies). 2017. Valuing 
Climate Damages: Updating Estimation of the Social Cost of Carbon Dioxide. National Academies Press. 
1003U.S. EPA. (2023). Supplementary Material for 
the Regulatory Impact Analysis for the Final Rulemaking, Standards of Performance for New, 
Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review, ‘‘Report on the Social Cost of Greenhouse Gases: Estimates Incorporating Recent Scientific Advances.’’ Washington, DC: U.S. EPA. 1004Ibid. 
1005The EPA strives to base its analyses on the 
best available science and economics, consistent with its responsibilities, for example, under the Information Quality Act. 
1006U.S. EPA. (2023). Supplementary Material for 
the Regulatory Impact Analysis for the Final Rulemaking, Standards of Performance for New, 
Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review, ‘‘Report on the Social Cost of Greenhouse Gases: Estimates Incorporating Recent Scientific Advances.’’ Washington, DC: U.S. EPA. 
1007Ibid. 1008Interagency Working Group on Social Cost of 
Carbon (IWG). 2021 (February). Technical Support Document: Social Cost of Carbon, Methane, and Nitrous Oxide: Interim Estimates under Executive Order 13990. United States Government. 
1009Supplementary Material for the Regulatory 
Impact Analysis for the Final Rulemaking, Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review, ‘‘Report on the Social Cost of Greenhouse Gases: Estimates Incorporating Recent Scientific Advances,’’ Docket ID No. EPA–HQ– OAR–2021–0317, November 2023. literature on climate change and its 
economic impacts and that incorporate recommendations made by the National Academies of Science, Engineering, and Medicine.
1002The EPA published and 
used these estimates in the RIA for the Final Oil and Gas Rulemaking, Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review, which was signed by the EPA Administrator on December 2, 2023.
1003The EPA solicited public 
comment on the methodology and use of these estimates in the RIA for the Agency’s December 2022 Oil and Gas Supplemental Proposal and has conducted an external peer review of these estimates, as described further below. Section 4 of the RIA lays out the details of the updated SC–GHG used within this final rule. 
The SC–GHG is the monetary value of 
the net harm to society associated with a marginal increase in GHG emissions in a given year, or the benefit of avoiding that increase. In principle, SC–GHG includes the value of all climate change impacts (both negative and positive), including (but not limited to) changes in 
net agricultural productivity, human health effects, property damage from increased flood risk and natural disasters, disruption of energy systems, risk of conflict, environmental migration, and the value of ecosystem services. The SC–GHG, therefore, reflects the societal value of reducing emissions of the gas in question by 1 metric ton and is the theoretically appropriate value to use in conducting benefit-cost analyses of policies that affect GHG emissions. In practice, data and modeling limitations restrain the ability of SC–GHG estimates to include all physical, ecological, and economic impacts of climate change, implicitly assigning a value of zero to the omitted climate damages. The estimates are, therefore, a partial accounting of climate change impacts and likely underestimate the marginal benefits of abatement. 
Since 2008, the EPA has used 
estimates of the social cost of various greenhouse gases (i.e., SC–CO
2, SC–CH 4, and SC–N 2O), collectively referred to as 
the ‘‘social cost of greenhouse gases’’ 
(SC–GHG), in analyses of actions that affect GHG emissions. The values used by the EPA from 2009 to 2016, and since 2021—including in the proposal—have been consistent with those developed and recommended by the IWG on the SC–GHG; and the values used from 2017 to 2020 were consistent with those required by E.O. 13783, which disbanded the IWG. During 2015–2017, the National Academies conducted a comprehensive review of the SC–CO
2 
and issued a final report in 2017 recommending specific criteria for future updates to the SC–CO
2estimates, 
a modeling framework to satisfy the 
specified criteria, and both near-term updates and longer-term research needs pertaining to various components of the estimation process.
1004The IWG was 
reconstituted in 2021 and E.O. 13990 directed it to develop a comprehensive update of its SC–GHG estimates, recommendations regarding areas of decision-making to which SC–GHG should be applied, and a standardized review and updating process to ensure that the recommended estimates continue to be based on the best available economics and science going forward. 
The EPA is a member of the IWG and 
is participating in the IWG’s work under E.O. 13990. As noted in previous EPA RIAs (including in the proposal RIA for this rulemaking), while that process continues, the EPA is continuously reviewing developments in the scientific literature on the SC–GHG, including more robust methodologies for estimating damages from emissions, and is looking for opportunities to further improve SC–GHG estimation.
1005In the December 2022 
Oil and Gas Supplemental Proposal RIA,
1006the Agency included a 
sensitivity analysis of the climate benefits of that rule using a new set of SC–GHG estimates that incorporates recent research addressing recommendations of the National Academies
1007in addition to using the 
interim SC–GHG estimates presented in the Technical Support Document: 
Social Cost of Carbon, Methane, and Nitrous Oxide Interim Estimates under Executive Order 13990
1008that the IWG 
recommended for use until updated estimates that address the National Academies’ recommendations are available. 
The EPA solicited public comment on 
the sensitivity analysis and the accompanying draft technical report, External Review Draft of Report on the Social Cost of Greenhouse Gases: Estimates Incorporating Recent Scientific Advances, which explains the methodology underlying the new set of estimates and was included as supplemental material to the RIA for the December 2022 Oil and Gas Supplemental Proposal.
1009The 
response to comments document can be found in the docket for that action. 
To ensure that the methodological 
updates adopted in the technical report are consistent with economic theory and reflect the latest science, the EPA also initiated an external peer review panel to conduct a high-quality review of the technical report, completed in May 2023. The peer reviewers commended the Agency on its development of the draft update, calling it a much-needed improvement in estimating the SC–GHG and a significant step toward addressing the National Academies’ recommendations with defensible modeling choices based on current science. The peer reviewers provided numerous recommendations for refining the presentation and for future modeling improvements, especially with respect to climate change impacts and associated damages that are not currently included in the analysis. Additional discussion of omitted impacts and other updates were incorporated in the technical report to address peer reviewer recommendations. Complete information about the external peer review, including the peer reviewer selection process, the final report with individual recommendations from peer reviewers, and the EPA’s response to each recommendation is available on 
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1010https://www.epa.gov/environmental- 
economics/scghg-tsd-peer-review. 
1011U.S. EPA (2023). Supplementary Material for 
the Regulatory Impact Analysis for the Final 
Rulemaking, Standards of Performance for New, 
Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review, ‘‘Report on the Social Cost of Greenhouse Gases: Estimates 
Incorporating Recent Scientific Advances.’’ Washington, DC: U.S. EPA. 
1012U.S. EPA. (2023). Estimating PM 2.5- and 
Ozone-Attributable Health Benefits. Research Triangle Park, NC: U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, Health and Environmental Impact Division. 1013Monetized climate benefits are discounted 
using a 2 percent discount rate, consistent with the EPA’s updated estimates of the SC–CO
2. The 2003 
version of OMB’s Circular A–4 had generally recommended 3 percent and 7 percent as default discount rates for costs and benefits, though as part of the Interagency Working Group on the Social Cost of Greenhouse Gases, OMB had also long recognized that climate effects should be discounted only at appropriate consumption-based discount rates. In November 2023, OMB finalized an update to Circular A–4, in which it recommended the general application of a 2 percent discount rate to costs and benefits (subject to regular updates), as well as the consideration of the shadow price of capital when costs or benefits are likely to accrue to capital (OMB 2023). Because the SC–CO
2estimates reflect net climate change 
damages in terms of reduced consumption (or monetary consumption equivalents), the use of the social rate of return on capital (7 percent under OMB Circular A–4 (2003)) to discount damages estimated in terms of reduced consumption would inappropriately underestimate the impacts of climate change for the purposes of estimating the SC–CO
2. See section 4.2 of the RIA for more 
discussion. the EPA’s website.1010An overview of 
the methodological updates 
incorporated into the new SC–GHG estimates is provided in the RIA section 4.2. A more detailed explanation of each input and the modeling process is provided in the technical report, EPA Report on the Social Cost of Greenhouse Gases: Estimates Incorporating Recent Scientific Advances.
1011 
In addition to CO 2, these final rules 
are expected to reduce annual, national total emissions of NO
Xand SO 2and 
direct PM 2.5. Because NO Xand SO 2are 
also precursors to secondary formation of ambient PM
2.5, reducing these 
emissions would reduce human exposure to annual average ambient PM
2.5and would reduce the incidence 
of PM 2.5-attributable health effects. 
These final rules are also expected to reduce national ozone season NO
X 
emissions. In the presence of sunlight, NO
Xand VOCs can undergo a chemical 
reaction in the atmosphere to form ozone. Reducing NO
Xemissions in most 
locations reduces human exposure to ozone and the incidence of ozone- related health effects, though the degree to which ozone is reduced will depend in part on local concentration levels of VOCs. The RIA estimates the health benefits of changes in PM
2.5and ozone 
concentrations. The health effect endpoints, effect estimates, benefit unit- values, and how they were selected are described in the Estimating PM
2.5- and 
Ozone-Attributable Health Benefits TSD.
1012Our approach for updating the 
endpoints and to identify suitable epidemiologic studies, baseline incidence rates, population demographics, and valuation estimates is summarized in section 4 of the RIA. 
The following PV and EAV estimates 
reflect projected benefits over the 2024 to 2047 period, discounted to 2024 in 2019 dollars, for the analysis of the final rules. We monetize benefits of the final rules and evaluate other costs in part to enable a comparison of costs and benefits pursuant to E.O. 12866, but we recognize that there are substantial uncertainties and limitations in monetizing benefits, including benefits that have not been quantified. The projected PV of monetized climate benefits is about $270 billion, with an EAV of about $14 billion using the SC– CO
2discounted at 2 percent.1013The 
projected PV of monetized health benefits is about $120 billion, with an EAV of about $6.3 billion discounted at 2 percent. Combining the projected monetized climate and health benefits yields a total PV estimate of about $390 billion and EAV estimate of $21 billion. 
At a 3 percent discount rate, these 
final rules are expected to generate projected PV of monetized health benefits of about $100 billion, with an EAV of about $6.1 billion. Climate benefits remain discounted at 2 percent in this benefits analysis and are estimated to be about $270 billion, with an EAV of about $14 billion using the SC–CO
2. Thus, these final rules would 
generate a PV of monetized benefits of about $370 billion, with an EAV of about $20 billion discounted at a 3 percent rate. 
At a 7 percent discount rate, these 
final rules are expected to generate projected PV of monetized health benefits of about $59 billion, with an EAV of about $5.2 billion. Climate benefits remain discounted at 2 percent in this benefits analysis and are 
estimated to be about $270 billion, with an EAV of about $14 billion using the SC–CO
2. Thus, these final rules would 
generate a PV of monetized benefits of about $330 billion, with an EAV of about $19 billion discounted at a 7 percent rate. 
The results presented in this section 
provide an incomplete overview of the effects of the final rules. The monetized climate benefits estimates do not include important benefits that we are unable to fully monetize due to data and 
modeling limitations. In addition, important health, welfare, and water quality benefits anticipated under these final rules are not quantified. We anticipate that taking non-monetized effects into account would show the total benefits of the final rules to be greater than this section reflects. Discussion of the non-monetized health, climate, welfare, and water quality benefits is found in section 4 of the RIA. 
2. Net Benefits 
The final rules are projected to reduce 
greenhouse gas emissions in the form of 
CO
2, producing a projected PV of 
monetized climate benefits of about $270 billion, with an EAV of about $14 billion using the SC–CO
2discounted at 
2 percent. The final rules are also projected to reduce emissions of NO
X, 
SO 2and direct PM 2.5leading to national 
health benefits from PM 2.5and ozone in 
most years, producing a projected PV of monetized health benefits of about $120 billion, with an EAV of about $6.3 billion discounted at 2 percent. Thus, these final rules are expected to generate a PV of monetized benefits of $390 billion, with an EAV of $21 billion discounted at a 2 percent rate. The PV of the projected compliance costs are $19 billion, with an EAV of about $0.98 billion discounted at 2 percent. Combining the projected benefits with the projected compliance costs yields a net benefit PV estimate of about $370 billion and EAV of about $20 billion. 
At a 3 percent discount rate, the final 
rules are expected to generate projected PV of monetized health benefits of about $100 billion, with an EAV of about $6.1 billion. Climate benefits remain discounted at 2 percent in this net benefits analysis. Thus, the final rules would generate a PV of monetized benefits of about $370 billion, with an EAV of about $20 billion discounted at 
3 percent. The PV of the projected compliance costs are about $15 billion, with an EAV of $0.91 billion discounted at 3 percent. Combining the projected benefits with the projected compliance costs yields a net benefit PV estimate of about $360 billion and an EAV of about $19 billion. 
At a 7 percent discount rate, the final 
rules are expected to generate projected PV of monetized health benefits of about $59 billion, with an EAV of about $5.2 billion. Climate benefits remain discounted at 2 percent in this net benefits analysis. Thus, the final rules would generate a PV of monetized benefits of about $330 billion, with an EAV of about $19 billion discounted at 7 percent. The PV of the projected compliance costs are about $7.5 billion, 
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1014https://www.federalregister.gov/documents/ 
2023/04/26/2023-08955/revitalizing-our-nations- 
commitment-to-environmental-justice-for-all. 
1015See https://www.epa.gov/ 
environmentaljustice/technical-guidance-assessing- environmental-justice-regulatory-analysis. 1016See https://www.epa.gov/ 
environmentaljustice/technical-guidance-assessing- environmental-justice-regulatory-analysis. 
1017The baseline for proximity analyses is current 
population information, whereas the baseline for ozone exposure analyses are the future years in which the regulatory options will be implemented (e.g., 2023 and 2026). with an EAV of $0.65 billion discounted 
at 7 percent. Combining the projected benefits with the projected compliance costs yields a net benefit PV estimate of about $320 billion and an EAV of about $19 billion. 
See section 7 of the RIA for additional 
information on the estimated net benefits of these rules. 
E. Environmental Justice Analytical 
Considerations and Stakeholder Outreach and Engagement 
For this action, the analysis described 
in this section and in the RIA is presented for the purpose of providing the public with an analysis of potential EJ concerns associated with these rulemakings, consistent with E.O. 14096. This analysis did not inform the determinations made to support the final rules. 
The EPA defines EJ as ‘‘the just 
treatment and meaningful involvement of all people regardless of income, race, color, national origin, Tribal affiliation, or disability, in agency decision-making and other Federal activities that affect human health and the environment so that people: (i) Are fully protected from disproportionate and adverse human health and environmental effects (including risks) and hazards, including those related to climate change, the cumulative impacts of environmental 
and other burdens, and the legacy of racism or other structural or systemic barriers; and (ii) have equitable access to a healthy, sustainable, and resilient environment in which to live, play, work, learn, grow, worship, and engage in cultural and subsistence practices.’’
1014In recognizing that 
particular communities of EJ concern often bear an unequal burden of environmental harms and risks, the EPA continues to consider ways of protecting them from adverse public health and environmental effects of air pollution. 
1. Analytical Considerations 
For purposes of analyzing regulatory 
impacts, the EPA relies upon its June 
2016 ‘‘Technical Guidance for Assessing Environmental Justice in Regulatory Analysis,’’
1015which provides 
recommendations that encourage analysts to conduct the highest quality analysis feasible, recognizing that data limitations, time, resource constraints, and analytical challenges will vary by media and circumstance. The Technical Guidance states that a regulatory action may involve potential EJ concerns if it 
could: (1) Create new disproportionate impacts on communities with EJ concerns; (2) exacerbate existing disproportionate impacts on communities with EJ concerns; or (3) present opportunities to address existing disproportionate impacts on communities with EJ concerns through this action under development. 
The EPA’s EJ technical guidance 
states that ‘‘[t]he analysis of potential EJ concerns for regulatory actions should address three questions: (1) Are there potential EJ concerns associated with environmental stressors affected by the regulatory action for population groups of concern in the baseline? (2) Are there potential EJ concerns associated with environmental stressors affected by the regulatory action for population groups of concern for the regulatory option(s) under consideration? (3) For the 
regulatory option(s) under consideration, are potential EJ concerns created or mitigated compared to the baseline?’’
1016 
To address these questions in the 
context of these final rules, the EPA developed a unique analytical approach that considers the purpose and specifics of these rulemakings, as well as the nature of known and potential disproportionate and adverse exposures and impacts. However, due to data limitations, it is possible that our analysis failed to identify disparities that may exist, such as potential EJ characteristics (e.g., residence of 
historically redlined areas), environmental impacts (e.g., other 
ozone metrics), and more granular spatial resolutions (e.g., neighborhood 
scale) that were not evaluated. Also due to data and resource limitations, we discuss climate EJ impacts of this action qualitatively (section 6.3 of the RIA). 
For these rules, we employ two types 
of analysis to respond to the previous three questions: proximity analyses and exposure analyses. Both types of analysis can inform whether there are potential EJ concerns for population groups of concern in the baseline (question 1).
1017In contrast, only the 
exposure analyses, which are based on future air quality modeling, can inform whether there will be potential EJ concerns due to the implementation of the regulatory options under consideration (question 2) and whether potential EJ concerns will be created or 
mitigated compared to the baseline (question 3). 
In section 6 of the RIA, we utilize the 
two types of analysis to address the three EJ questions by quantitatively evaluating: (1) the proximity of affected facilities to populations of potential EJ concern (section 6.4); and (2) the potential for disproportionate ozone and PM
2.5concentrations in the baseline and 
concentration changes after rule implementation across different demographic groups on the basis of race, ethnicity, poverty status, employment status, health insurance status, life expectancy, redlining, Tribal land, age, sex, educational attainment, and degree of linguistic isolation (section 6.5). It is important to note that due to the corresponding small magnitude of the ozone and PM
2.5 
concentration changes relative to the baseline concentrations in each modeled future year, these rules are expected to have a small impact on the distribution of exposures across each demographic group. Each of these analyses should be considered independently of each other as each was performed to answer separate questions and is associated with unique limitations and uncertainties. 
a. Proximity Analyses 
Baseline demographic proximity 
analyses can be relevant for identifying 
populations that may be exposed to local environmental stressors, such as local NO
2and SO 2emitted from affected 
sources in these final rules, traffic, or noise. The Agency has conducted a demographic analysis of the populations living near facilities impacted by these rules including 114 facilities for which the EPA is unaware of existing retirement plans by 2032, 23 facilities (a subset of the 114 facilities) with known retirement plans between 2033–2040, and 94 facilities (also a subset of the 114 facilities) without known retirement plans before 2040. The baseline analysis indicates that on average the populations living within 5 km and 10 km of 114 facilities impacted by the final rules without announced retirement by 2032 have a higher 
percentage of the population that is American Indian, below the Federal poverty level, and below two times the Federal poverty level than the national average. In addition, the population living within 50 kilometers of the same 114 facilities has a higher percentage of the population that is Black. Relating these results to EJ question 1, we conclude that there may be potential EJ concerns associated with directly emitted pollutants that are affected by 
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the regulatory actions for certain 
population groups of concern in the baseline (question 1). However, as proximity to affected facilities does not capture variation in baseline exposures across communities, nor does it indicate that any exposures or impacts will occur, these results should not be interpreted as a direct measure of exposure impact. The full results of the demographic analysis can be found in RIA section 6.4. The methodology and the results of the demographic analysis for the final rules are presented in a technical report, Analysis of Demographic Factors for Populations Living Near Coal-Fired Electric Generating Units (EGUs) for the Section 111 NSPS and Emissions Guidelines— Final, available in the docket for these 
actions. 
b. Exposure Analyses 
While the exposure analyses can 
respond to all three EJ questions, 
correctly interpreting the results requires an understanding of several important caveats. First, recognizing the flexibility afforded to each state in implementing the final guidelines, the results below are based on analysis of several illustrative compliance scenarios which represent potential compliance outcomes in each state. This analysis does not consider any potential impact of the meaningful engagement provisions or all of the other protections that are in place that can reduce the risks of localized emissions increases in a manner that is protective of public health, safety, and the environment. It is also important to note that the potential emissions changes discussed below are relative to a projected baseline, and any localized decreases or increases are subject to the uncertainty of the baseline projections discussed in section 3.7 of the RIA. This uncertainty becomes increasingly relevant in later years in which baseline modeling projects substantial reductions in emissions relative to today. Furthermore, several additional caveats should be noted that are specific to the exposure analysis. For example, the air pollutant exposure metrics are limited to those used in the benefits assessment. For ozone, that is the maximum daily 8-hour average, averaged across the April through September warm season (AS–MO3) and for PM
2.5that is the annual average. This 
ozone metric likely smooths potential daily ozone gradients and is not directly relatable to the NAAQS whereas the 
PM
2.5metric is more similar to the long- 
term PM 2.5standard. The air quality 
modeling estimates are also based on state and fuel level emission data paired with facility-level baseline emissions and provided at a resolution of 12 
square kilometers. Additionally, here we focus on air quality changes due to these rulemakings and infer post-policy ozone and PM
2.5exposure burden 
impacts. Note, we discuss climate EJ impacts of these actions qualitatively (section 6.3 of the RIA). 
Exposure analysis results are 
provided in two formats: aggregated and distributional. The aggregated results provide an overview of potential ozone exposure differences across populations at the national- and state-levels, while the distributional results show detailed information about ozone concentration changes experienced by everyone within each population. 
These rules are also expected to 
reduce emissions of direct PM
2.5, NO X, 
and SO 2nationally. Because NO Xand 
SO 2are also precursors to secondary 
formation of ambient PM 2.5and because 
NO Xis a precursor to ozone formation, 
reducing these emissions would impact human exposure. Quantitative ozone and PM
2.5exposure analyses can 
provide insight into all three EJ questions, so they are performed to evaluate potential disproportionate impacts of these rulemakings. Even though both the proximity and exposure analyses can potentially improve understanding of baseline EJ concerns (question 1), the two should not be directly compared. This is because the demographic proximity analysis does not include air quality information and is based on current, not future, population information. 
The baseline analysis of ozone and 
PM
2.5concentration burden responds to 
question 1 from the EPA’s EJ technical guidance more directly than the proximity analyses, as it evaluates a form of the environmental stressor targeted by the regulatory action. As discussed in the RIA, our analysis indicates that baseline ozone and PM
2.5 
concentration will decline substantially relative to today’s levels for all demographic groups in all future modeled years, and these baseline levels of ozone and PM
2.5can be considered to 
be relatively low. However, there are differences in exposure among demographic groups within these relatively low levels of baseline exposure. Baseline PM
2.5and ozone 
exposure analyses show that certain 
populations, such as residents of redlined census tracts, those linguistically isolated, Hispanic populations, Asian populations, and those without a high school diploma may experience higher ozone and PM
2.5 
exposures as compared to the national average. American Indian populations, residents of Tribal Lands, populations with higher life expectancy or with life 
expectancy data unavailable, children, and unemployed populations may also experience disproportionately higher ozone concentrations than the reference group. Black populations may also experience disproportionately higher PM
2.5concentrations than the reference 
group. Therefore, also in response to question 1, there likely are potential EJ concerns associated with ozone and PM
2.5exposures affected by the 
regulatory actions for population groups of concern in the baseline. However, these baseline exposure results have not been fully explored and additional analyses are likely needed to understand potential implications. 
Relative to the low baseline levels of 
exposure modeled in future years for PM
2.5and ozone, exposure analyses 
show that the final rules will result in modest but widespread reductions in PM
2.5and ozone concentrations in 
virtually all areas of the country, although some limited areas may experience small increases in ozone concentrations relative to forecasted conditions without the rule. The extent of areas experiencing ozone increases varies among snapshot years. Due to the small magnitude of the exposure changes across population demographics associated with these rulemakings relative to the magnitude of the baseline disparities, we infer that post-policy EJ ozone and PM
2.5 
concentration burdens are likely to remain after implementation of the regulatory action (question 2). 
Question 3 asks whether potential EJ 
concerns will be created or mitigated compared to the baseline. Due to the very small magnitude of differences across demographic population post- policy impacts, we do not find evidence that disparities among communities with EJ concerns will be exacerbated or mitigated by the regulatory alternatives under consideration regarding PM
2.5 
exposures in all future years evaluated and ozone exposures for most demographic groups in the future years evaluated. In 2035, under the illustrative compliance scenarios analyzed, it is possible that Asian populations, Hispanic populations, and those linguistically isolated, and those living on Tribal land may experience a slight exacerbation of ozone exposure disparities at the national level (question 3), compared to baseline ozone levels. Additionally at the national level, those living on Tribal land may experience a slight exacerbation of ozone exposure disparities in 2040 and a slight 
mitigation of ozone exposure disparities in 2028 and 2030. At the state level, 
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1018EPA–HQ–OAR–2022–0723. ozone exposure disparities may be 
either mitigated or exacerbated for certain demographic groups, also to a small degree. As discussed above, it is important to note that this analysis does not consider any potential impact of the meaningful engagement provisions or all of the other protections that are in place that can reduce the risks of localized emissions increases in a manner that is protective of public health, safety, and the environment. 
2. Outreach and Engagement 
As part of the regulatory development 
process for these rulemakings, and 
consistent with directives set forth in multiple Executive Orders, the EPA conducted extensive outreach with interested parties including Tribal nations and communities with environmental justice concerns. This outreach allowed the EPA to gather information from a variety of viewpoints while also providing parties with an overview of the EPA’s work to reduce GHG emissions from the power sector. 
Prior to the May 2023 proposal, the 
EPA opened a public docket for pre- proposal input.
1018The EPA continued 
to engage with interested parties by speaking on the EPA National Community Engagement call and the National Tribal Air Association Policy Update call in September 2022. Following publication of the proposal, the EPA hosted two informational webinars on June 6 and 7, 2023, specially targeted towards tribal environmental professionals, tribal nations, and communities with environmental justice concerns. The purpose of these webinars was to provide an overview of the proposal, information on how to effectively engage in the regulatory process and provide the EPA an opportunity to answer questions. The EPA held virtual public hearings on June 13, 14, and 15, 2023, that allowed the public an opportunity to present comments and information regarding the proposed rules. 
The EPA recently finalized revisions 
to the subpart Ba implementing regulations requiring states to conduct meaningful engagement with pertinent stakeholders as part of the state plan development process. The EPA underscores the importance of this part of the state plan development process. For more detailed information on meaningful engagement, see section X.E.1.b.i of this preamble. F. Grid Reliability Considerations and 
Reliability-Related Mechanisms 
1. Overview 
The Federal Energy Regulatory 
Commission (FERC) is the federal 
agency with vested authority to ensure reliability of the bulk power system (16 U.S.C. 824o). FERC oversees and approves reliability standards that are developed by NERC and then become mandatory for all owners and operators of the bulk power system. Regional wholesale energy markets, like RTOs, ISOs, public service commissions, balancing authorities, and reliability coordinators all have reliability related responsibilities. The EPA’s role under the CAA section 111 is to reduce emissions of dangerous air pollutants, including those emitted from the electric power sector. In doing so, it has a long, and exemplary history of ensuring its public-health-based emissions standards and guidelines that impact the power sector are sensitive to reliability-related issues and constructed in a manner that does not interfere with grid operators’ responsibility to deliver reliable power. The EPA met with many entities with responsibility over the reliability of the bulk power system in crafting these final rules to make certain the rules will not impede their ability to ensure reliability of the bulk power system. This section outlines the array of modifications made in these final actions, outlined in section I.G of this preamble, that collectively help ensure that these final actions will not interfere with systems operators’ ability to continue providing reliable power. Additional to this suite of adjustments, the EPA is introducing both a short-term reliability mechanism for emergency situations and a reliability assurance mechanism available for states to include in their state plans for additional flexibility. In response to the May 2023 proposed rule, the EPA received extensive comments regarding grid reliability and resource adequacy from balancing authorities, independent system operators and regional transmission organizations, state regulators, power companies, and other stakeholders. The EPA engaged with each of these group of commenters to garner a granular understanding of their reliability-related concerns. Additionally, the EPA met repeatedly with technical staff and Commissioners of FERC, DOE, NERC, and other 
reliability experts during the course of this rulemaking. At FERC’s invitation, the EPA participated in FERC’s Annual Reliability Technical Conference on November 9, 2023. Further, the EPA solicited additional comment on reliability-related mechanisms as part of the November 2023 supplemental proposed rule. 
Comment: Several comments from 
grid operators raised the concern that the proposed rules have the potential to trigger material negative impacts to grid reliability. Concerns coalesced around the loss of firm dispatchable assets which they view as outpacing the development and interconnection of new assets that do not possess commensurate reliability attributes. Other commenters maintained that the proposals included adequate lead times for reliability planning, and that reliability attributes are currently sourced by a collection of assets, and as such a collection of future assets will be able to provide the requisite reliability attributes. Some commenters also asserted that the proposals would actually improve transparency around unit-specific decisions, which are often not communicated transparently with adequate notice, leading to a better reliability planning process. 
Response: These final rules include a 
number of flexibilities and rule adjustments that will accommodate appropriate planning decisions by affected sources, system planners, and reliability authorities in a way that allows for the continued reliable operation of the electric grid. These final actions also include adjustments and improvements, with specific provisions related to compliance timing and system emergencies, that address reliability concerns. The rules do not interfere with ongoing efforts by key stakeholders to appropriately plan for an evolving electric system. The EPA agrees that transparency around unit- specific planning is of paramount importance to enabling systems operators advanced notice to plan for continued reliable bulk power operations. 
The EPA initiated follow-up 
conversations with all balancing authorities and systems operators that submitted public comments to ensure a granular and thorough understanding of all reliability-related concerns raised in response to the proposed rules. In addition, the EPA solicited additional comment on reliability related mechanisms in the supplemental proposal issued in November 2023. The EPA examined the record carefully and responded with a suite of changes to the proposal that, though not always explicitly directed at addressing concerns raised with respect to reliability, nonetheless collectively help ensure EPA’s rules will not interfere 
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1019‘‘Electric System Reliability and EPA 
Regulation of GHG Emissions from Power Plants: 
2023,’’ Susan Tierney, Analysis Group, November 7, 2023. 1020‘‘Electric System Reliability and EPA 
Regulation of GHG Emissions from Power Plants: 
2023,’’ Susan Tierney, November 7, 2023. 
1021‘‘Modernizing Governance: Key to Electric 
Grid Reliability’’, Kleinman Center for Energy 
Policy, University of Pennsylvania, March 2024. with grid operators’ responsibilities to 
provide reliable power. 
As discussed earlier in this preamble, 
the EPA is finalizing several adjustments to provisions in the proposed rules that address reliability concerns and ensure that these rules provide adequate flexibilities and assurance mechanisms that allow grid operators to continue to fulfill their responsibilities to maintain the reliability of the bulk-power system. These adjustments include restructuring the subcategories for coal-fired steam generating EGUs: the EPA is not finalizing the proposed imminent or near term subcategory structure which should provide states with a wider planning latitude, and units with cease operations dates prior to January 1, 2032 are not regulated by this final rule. Importantly, the compliance timeline for installing CCS in the long-term subcategory has been extended by an additional 2 years. The EPA is not finalizing the 30 percent hydrogen co- firing BSER for the intermediate subcategory for new combustion turbines. These changes facilitate reliability planning and operations by providing more lead time for CCS installation-related compliance. The adjusted scope of these actions also provides additional time for the EPA to consult with a broad range of stakeholders, including grid operators, to deliberate and determine the best way to address emissions from existing gas turbines while respecting their contribution to electric reliability in the foreseeable future. In addition to these adjustments, as detailed in section X.D of this preamble, the EPA is offering states a suite of voluntary compliance flexibilities that could be used to address reliability concerns. These compliance flexibilities include clarifying the circumstances under which it may be appropriate for states to employ RULOF to establish source specific standards of performance and compliance schedules for affected EGUs to address reliability, allowing emission averaging, trading, and unit-specific mass-based compliance mechanisms for certain subcategories—provided that they achieve an equivalent level of emission reduction consistent with the application of individual rate-based standards of performance, and, for certain mechanisms, that they include a backstop emission rate, and offering a compliance date extension for affected new and existing EGUs that encounter unanticipated delays with control technology implementation. 
The EPA believes the adjustments 
made to the final rules outlined above 
are sufficient to ensure the rules can be implemented without impairing the ability of grid operators to deliver reliable power. The EPA is nonetheless finalizing additional reliability-related instruments to provide further certainty that implementation of these final rules will not intrude on grid operators’ ability to ensure reliability. The short- term reliability mechanism is available for both new and existing units and is designed to provide additional flexibility through an alternative compliance strategy during acute system emergencies that threaten reliability. The reliability assurance mechanism will be available for existing units that intend to cease operating, but, for unforeseen reasons, need to temporarily remain online to support reliability beyond the planned cease operation date. This reliability assurance mechanism, which requires a specific and adequate showing of reliability need that is satisfactory to the EPA, is intended for circumstances where there is insufficient time to complete a state plan revision, and it is limited to the amount of time substantiated, which may not exceed 1 year. The EPA intends to consult with FERC for advice on applications of reliability need that exceed 6 months. These instruments will be presumptively approvable, provided they meet the requirements defined in these emission guidelines, if states choose to incorporate them into their plans. 
Comment: Commenters from industry 
and grid operators expressed support for the inclusion of a requirement that states include in their state plans a demonstration of consultation with all relevant reliability authorities to facilitate planning. Other commenters asserted that the proposals included sufficient coordination with reliability authorities, through the Initial Reporting Milestone Status Report requirements. 
Response: The EPA agrees that 
planning for reliability is critically important. Indeed, all stakeholders generally agree that effective planning is essential to ensuring electric reliability is maintained.
1019State planning, 
including coordination and transparency across jurisdictions, is particularly important given that state plans in one jurisdiction can impact the reliability and resource adequacy of other system operators. The EPA is finalizing, as part of the state plan development process, that states are required to conduct meaningful engagement with stakeholders. As part of this required meaningful engagement, 
states are strongly encouraged to consult with the relevant balancing authorities and reliability coordinators for their affected sources and to share available unit-specific requirements and compliance information in a timely fashion. Sharing regulatory requirements and unit-specific compliance information with balancing authorities and reliability coordinators in a timely manner will promote early and informed reliability planning. Strong system-planning processes of utility transmission companies and RTOs are among the most important tools to assure that reliability will not be adversely affected by regulations.
1020 1021  
A robust planning process that recognizes the different roles of states and their relevant balancing authorities, transmission planners, and reliability coordinators should help to identify potential resource adequacy or reliability issues early in the state planning process. States will also be able to address reliability-related issues through a revision in their state plan, including to address issues that were not foreseen during the state planning process. 
In addition to these measures, DOE 
has authority pursuant to section 202(c) of the Federal Power Act to, on its own motion or by request, order, among other things, the temporary generation of electricity from particular sources in certain emergency conditions, including during events that would result in a shortage of electric energy, when the Secretary of Energy determines that doing so will meet the emergency and serve the public interest. An affected source operating pursuant to such an order is deemed not to be operating in violation of its environmental requirements. Such orders may be issued for 90 days and may be extended in 90-day increments after consultation with EPA. DOE has historically issued section 202(c) orders at the request of electric generators and grid operators such as RTOs in order to enable the supply of additional generation in times of expected emergency-related generation shortfalls. 
Congress provided section 202(c) as 
the primary mechanism to ensure that when generation is needed to meet an emergency, environmental protections will not prevent a source from meeting that need. To date, section 202(c) has worked well, allowing, for example, 
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1022DOE. DOE’s Use of Federal Power Act 
Emergency Authority. https://www.energy.gov/ 
ceser/does-use-federal-power-act-emergency- authority. 
1023See Resource Adequacy Analysis document 
for further analysis and exploration of these important elements. 1025‘‘In the current environment, grid operators 
are unsure about when resources may retire, 
increasing uncertainty and making planning harder. The proposed rules have long timelines for enactment, giving states, utilities, and grid operators plenty of time to plan for the transition.’’ From ‘‘Prepared Statement of Ric O’Connell 
Executive Director, GridLab,’’ Testimony before FERC Annual Reliability Technical Conference on November 9, 2023. 1026‘‘Electric System Reliability and EPA 
Regulation of GHG Emissions from Power Plants,’’ 
Susan Tierney, November 7, 2023. 
1027‘‘Greenhouse Gas Emission Reductions From 
Existing Power Plants: Options to Ensure Electric System Reliability,’’ Susan Tierney, May 2014. additional generation to come online to 
meet demand in the California Independent System Operator and PJM territories in 2022.
1022Section 202(c) 
has also been used to allow generators to remain online pending completion of infrastructure needed to facilitate reliable replacement of those generators. The EPA continues to believe that section 202(c) is an effective mechanism for meeting the purpose of ensuring that all physically available generation will be available as needed to meet an emergency situation, regardless of environmental regulatory constraints. Given the heightened concerns about reliability expressed by commenters in the context of this rule and ongoing changes in the electricity sector, however, this final action includes an additional supplemental short-term reliability mechanism that states may elect to include in their state plans. States that adopt this mechanism could make it available for sources to use without needing action by DOE under section 202(c). Of course, section 202(c) would continue to be available for sources subject to this rule for emergency situations where EPA’s short-term reliability mechanism would not apply. 
Many electric reliability and bulk- 
power system authorities, including FERC and the regulated wholesale markets, are actively engaged in activities to ensure the reliability of the transmission grid, while paying careful attention to the changing resource mix and the ongoing trends in the power sector.
1023 1024 There are multiple 
agencies and entities that have some authority and responsibility to ensure electric reliability. These include state utility commissions, balancing authorities, reliability coordinators, DOE, FERC, and NERC. The EPA’s central mission is to protect human health and the environment and the EPA does not have direct authority or responsibility to ensure electric reliability. Still, the EPA believes reliability of the bulk power system is of paramount importance, and has included additional measures in these final actions that are delineated throughout this section, evaluated the resource adequacy implications in the final TSD, Resource Adequacy Analysis, 
and conducted capacity expansion modeling of the final rules in a manner that takes into account resource adequacy needs. Additionally, the EPA 
performed a variety of other sensitivity analyses including an examination of higher electricity demand (many areas are reporting accelerated load growth forecasts due to data centers, increased manufacturing, crypto currency, electrification and other factors) and the impact of the EPA’s additional regulatory actions affecting the power sector. These sensitivity analyses indicate that, in the context of higher demand and other pending power sector rules, the industry has available pathways to comply with this rule that respect NERC reliability considerations and constraints. These results are detailed in the technical memoranda in the docket titled, IPM Sensitivity Runs and Resource Adequacy Analysis: 
Vehicle Rules, Final 111 EGU Rules, ELG, and MATS. 
The EPA has carefully examined all 
comments related to reliability that were submitted during the public comment period for the proposal and for the supplemental notice. The Agency has engaged in dialogue with each of the balancing authorities regarding the content of their submitted comments. Based on this extensive engagement and consultation, the Agency’s analysis of the impacts of these rules, and the various features of this rule that will work in tandem to ensure the standards and emission guidelines finalized here are achievable and can respond to future reliability and resource adequacy needs, the EPA has concluded these final rules will not interfere with grid operators’ ability to continue delivering reliable power. 
The EPA received a range of opinions 
during the comment process, and also during FERC’s Annual Reliability Conference, some of which expressed that the proposed rule could provide a net benefit to reliability planning given the enhanced visibility into unit- specific compliance plans.
1025This 
section discusses the additional compliance flexibilities and reliability instruments that have been included in these final rules. 
The EPA has carefully considered the 
importance of reliability of the bulk- power system in developing these final rules. Stakeholders have recognized the EPA’s long and successful history of ensuring its power sector rules are crafted to deliver significant public health benefits while not impairing the ability of grid operators to ensure reliable power.
1026The entities 
responsible for ensuring reliability, which encompass electric utilities, RTOs and ISOs, reliability coordinators, other grid operators, utility and non- utility energy companies, and Federal and state regulators, have also historically met challenges in navigating power sector environmental obligations while maintaining reliability.
1027 
2. Compliance Flexibilities for New and Existing Affected EGUs 
These final rules include three key 
compliance flexibilities for new and existing sources and reliability coordinators so that they can continue to plan for the reliable operation of the electric system; RULOF, emissions averaging and trading, and compliance extensions of up to 1 year for units installing control technology. As discussed in section X.C.2 of this preamble, states may use the RULOF provisions to address circumstances in which reliability or resource adequacy is a concern. Use of RULOF may be appropriate where reliability or resource adequacy considerations for a particular EGU are fundamentally different from those considered when developing these emission guidelines, which may make it unreasonable for an affected EGU to comply with a standard of performance by the prescribed date. Under these circumstances, the state may choose to particularize the compliance obligations for the affected EGU in order to address the reliability or resource adequacy concern. As explained in section X.C.2, the EPA believes any adjustments that are needed will take the form of different compliance timelines. RULOF is relevant at the stage of establishing standards of performance and compliance schedules to affected EGUs as a state plan is being developed or revised. 
States have the ability to use emission 
averaging or trading, as well as unit- specific mass-based compliance, as described in section X.D of this preamble, which may also provide reliability-related benefits. The use of these alternative compliance flexibilities is not required, but states may employ these flexibilities, provided they demonstrate that their programs achieve an equivalent level of emission 
reduction with unit-specific application 
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1028Assuming the affected EGU is in a state that 
has included the extension mechanism in its 
approved plan. 1029https://www.energy.gov/ceser/does-use- 
federal-power-act-emergency-authority. of rate-based standards of performance 
and apply requirements relevant to the particular flexibility, as specified in section X.D. These compliance flexibilities are voluntary, and states may choose whether to allow their use in state plans, subject to certain conditions. However, states may find that the reliability-specific adjustments discussed below provide sufficient flexibility in lieu of the mechanisms described in section X.D. 
States may incorporate into their state 
plans a mechanism that allows compliance date extensions up to 1 year for an existing affected EGU that is in the process of installing a control technology to meet its standard of performance in the state plan, under specific circumstances, a detailed discussion can be found in section X.C.1.d of this document. As discussed in section VIII.N of this document, the Administrator may provide a similar extension for new combustion turbines. The state or Administrator may allow the extension of the compliance date if the source demonstrates a delay in the construction or implementation of the control technology resulting from causes that are entirely outside the owner or operator’s control. These may include delays in obtaining a final construction permit, after a timely and complete application, or delays due to documented supply chain issues; for example, a backlog for step-up transformer equipment. This compliance date extension is not expressly offered for reliability purposes, but rather as a flexibility to account for unforeseen and uncontrollable lags in construction or implementation of control technology to meet the unit’s standard of performance, in instances where a source can demonstrate efforts to comply by the required timeframes as part of these final actions, including evidence that it took the necessary steps to comply with sufficient lead time to meet the compliance schedule absent unusual problems, and that those problems are entirely outside the source’s control and the source’s actions or inactions did not contribute to the delay. This potential extension can help ensure that sufficient capacity is available by providing additional time for an affected EGU to operate for a specific amount of time while it resolves delays related to installation of pollution controls. 
If the owner/operator of an affected 
EGU encounters a delay outside of the owner or operator’s control, and which prevents the source from meeting its compliance obligations, the affected 
EGU must follow the procedures outlined in the state plan for documenting the basis for the extension.
1028Any delay in 
implementation that will necessitate a compliance date extension of more than 1 year must be done through a state plan revision to adjust the compliance schedule using RULOF as a basis. See section X.C.2 of this preamble for information on RULOF. 
A similar 1-year compliance date 
extension flexibility for units implementing control technologies that encounter a delay outside of the owner or operator’s control which prevents the source from meeting compliance obligations is also available to certain new sources, which are directly regulated by the EPA. This is described in section VIII.N of this preamble. 
3. Reliability Mechanisms 
While the EPA believes the significant 
structural adjustments and compliance 
flexibilities that are discussed above are adequate to ensure that the implementation of these final rules does not interfere with systems operators’ ability to ensure electric reliability, the EPA is also finalizing two reliability- related mechanisms as additional safeguards. These mechanisms include a short-term reliability mechanism for unexpected and short-duration emergency events, and a reliability assurance mechanism for units with retirement dates that are enforceable in the state plan, provided there is a documented and verified reliability concern. The EPA notes that these mechanisms must be included in the state plan to be utilized by the owners/ operators of existing affected EGUs subject to requirements in the state plan. Sections XII.3.a, and XII.3.b of this preamble describe presumptively approvable methodologies for incorporating these mechanisms into a state plan. 
a. Short-Term Reliability Mechanism 
Comment: Multiple commenters 
requested an explicit short-term 
mechanism which could accommodate emergency situations and provide additional flexibility to affected sources. Commenters requested that the mechanism include additional rule flexibilities that could potentially be used during emergency conditions that would help reliability authorities avert a load shed event. A mechanism would function as an additional automated flexibility measure with a clearly articulated emergency provision for affected sources to respond to short- duration emergency grid situations. 
Some commenters requested a mechanism that is distinct from the process established by DOE’s emergency authority under the Federal Power Act (section 202(c)), whereby DOE is required by the terms of section 202(c) to issue orders tailored to best meet particularized emergency circumstances.
1029Other commenters 
highlighted the numerous rule flexibilities that were designed to accommodate reliability concerns and emergency conditions and indicated that the EPA’s rule need not overly accommodate reliability and resource adequacy concerns since the primary burden for developing solutions falls to industry, grid operators, reliability coordinators, state planners, and other stakeholders. These commenters indicated that it is important to consider any trade-offs with additional flexibility measures, in particular any trade-offs with emissions implications. 
Response: The EPA agrees with the 
latter commenters and expects that the broader adjustments in the final rules, in addition to the compliance flexibilities offered to states in section X.D of this document, along with DOE’s pre-existing section 202(c) authority, are sufficient to enable an affected unit to respond to emergencies as needed and still comply with the annual requirements of these actions. As an additional safeguard measure, the EPA is finalizing a short-term reliability mechanism to assure that these final actions will not interfere with grid operators’ ability to ensure electric 
reliability. More specifically, the EPA has determined that some accommodation during grid emergencies, which are rare, is warranted in order to provide some additional flexibility to help system planners, affected sources, state regulators, and reliability authorities meet demand and avert load shed when such emergencies occur. The EPA believes this additional flexibility is warranted, given the projected increase in extreme weather events exacerbated by climate change. 
A short-term reliability mechanism 
for new sources is included in the final NSPS. Similarly, a short-term mechanism is offered to states to include in state plans for use with existing sources during specific and defined periods of time where the grid is under extreme strain. The short-term reliability mechanism is linked to specific conditions under which the system operators may not have 
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1030The performance standard shall be the Phase 
I standard for the affected new source under the 
NSPS. 
1031The baseline emission rate for existing 
sources is the CO 2mass emissions and 
corresponding electricity generation data for a given 
affected EGU from any continuous 8-quarter period from 40 CFR part 75 reporting within the 5-year period immediately prior to the date the final rule is published in the Federal Register. 
1032NERC Reliability Standards, https://
www.nerc.com/pa/Stand/Pages/ ReliabilityStandards.aspx, and NERC Emergency Preparedness and Operations (Reliability Standard EOP–011–2). https://www.nerc.com/pa/Stand/ 
Reliability%20Standards/EOP-011-2.pdf. 
10332023 State of Reliability Technical 
Assessment, NERC. https://www.nerc.com/pa/ RAPA/PA/Performance%20Analysis%20DL/NERC_SOR_ 2023_ Technical_ Assessment.pdf. 
1034Ibid. 1035Since 2021, ERCOT issued two EEA–1 events, 
two EEA–2 events, and one EEA–3 event (all for 
events occurring over an 8-hour period one day in 2021, and for 1 hour in 2023). In SPP, since 2021, there were eight EEA–1 events, five EEA–2 events, 
and two EEA–3 events (occurring over 5 days). The EEA–1 and EEA–2 events lasted between 1 and 19 hours. In MISO, there was a 2-day event in 2021 that resulted in an EEA magnitude 1, 2, or 3 alert through the day and into the next day. One EEA– 1 event in 2022 lasted for a half hour and an EEA– 2 event for 3 hours. In 2023, there was an EEA–2 event for 9.5 hours. In PJM, no alerts were issued in 2021. In 2022, roughly a dozen alerts were issued. Some lasted minutes, while others lasted half a day. One event stretched for 3 days. There were two alerts issued in 2023, lasting roughly 3 and 1 hours each. While this data is not comprehensive, it is indicative of the frequency and duration of emergency events that fall under the NERC reliability standard alert process. See: ERCOT Market Notices, SPP Historical Advisories and Alerts, https://www.oasis.oati.com/SWPP/; MISO 
Maximum Generation Emergency Declarations (2023), https://www.oasis.oati.com/woa/docs/ 
MISO/MISOdocs/Capacity_ Emergency_ Historical_
Information.pdf; and MISO Maximum Generation Emergency Declarations (2023), https://www.oasis.oati.com/woa/docs/MISO/MISOdocs/ Capacity_ Emergency_ Historical_ Information.pdf. 
See also PJM Emergency Procedures and Postings, https://emergencyprocedures.pjm.com/ep/pages/ dashboard.jsf. 
1036NERC Organization Certification (January 
2024). https://www.nerc.com/pa/comp/Pages/ 
Registration.aspx. 
1037https://www.nerc.com/comm/PC/ 
Performance%20Analysis%20Subcommittee%20PAS%202013/M-11_ Energy_
Emergency_ Alerts.pdf. 
1038https://www.nerc.com/pa/RAPA/ri/Pages/ 
EEA2andEEA3.aspx. sufficient available generation to call 
upon to meet electric demand, and various reliability authorities have issued emergency alerts to rectify the situation. These emergency alerts are most often associated with extreme weather events where electric demand increases and there are often unexpected transmission and generation outages. Recent examples of short-term emergency alert conditions include Winter Storm Uri in 2021 and Winter Storm Elliot in 2022, both of which included unanticipated generator outages and triggered emergency grid operations. The EPA expects that the broader adjustments to the final rules, in combination with the compliance flexibilities described in section XII.F.2 of this document, are sufficient to enable an affected unit to respond to grid emergencies as needed and still comply with the annual requirements of these actions. Nonetheless, the EPA is finalizing this short-term reliability mechanism, available to states to include at their discretion, to provide an additional layer of assurance that these final actions will not interfere with the grid operator’s ability to ensure electric reliability. 
A short-term reliability mechanism is 
included for new sources in the final NSPS, and additionally offered to states to include in state plans for existing sources. The mechanism provides affected sources additional flexibility during rare and extreme emergency events, when all available generators are called upon to meet electric demand. For new sources, the mechanism allows sources to calculate applicability and compliance without using the emissions and operational data produced during these discrete events, with appropriate documentation.
1030For existing sources, 
the mechanism allows sources to use the baseline emission rate during these discrete events, also with appropriate documentation.
1031 
The mechanism is only applicable 
during an Energy Emergency Alert level 2 or 3 as defined by NERC Reliability Standard EOP–011–2 or its successor, which requires plans and sets procedures for reliability entities to help avert disruptions in electric service 
during emergency conditions.
1032The NERC reliability standard articulates 
roles and responsibilities, defines notification processes for reliability coordinators and operators, requires a 
plan for grid management practices, and specifies a compliance monitoring process. Notably, the standard defines three levels of Energy Emergency Alerts (EEA) that guide reliability coordinators during energy emergencies and assist with communicating information across the system and with the public to avert potential disruptions: 
•EEA–1: All available generation 
resources in use—The Balancing Authority is experiencing conditions where all available generation resources are committed to meet firm load, firm transactions, and reserve commitments, and is concerned about sustaining its required Contingency Reserves. 
•EEA–2: Load management 
procedures in effect—The Balancing Authority is no longer able to provide its expected energy requirements and is an energy deficient Balancing Authority. An energy deficient Balancing Authority has implemented its Operating Plan(s) to mitigate Emergencies. An energy deficient Balancing Authority is still able to maintain its minimum Contingency Reserve requirement. 
•EEA–3: Firm Load interruption is 
imminent or in progress—The energy deficient Balancing Authority is unable to meet minimum Contingency Reserve requirements. 
The alerts are typically issued in 
reaction to emergencies as they develop, are generally rare, and most often have been issued during extreme weather events, such as hurricanes, cold weather events, and heatwaves. The most concerning alert is EEA–3, where interruption of electric service through controlled load shed is imminent for some areas, although load shed does not necessarily occur under every EEA–3 declaration. According to NERC, 25 EEA–3s were declared in 2022, an increase of 15 EEA–3 declarations over 2021. Nine of the EEA–3 declarations in 2022 included shedding of firm load. While the number of declarations increased from 2021, the amount of load that was shed during the 2022 events was less than 10 percent of the previous year.
1033All of the EEA–3 declarations 
in 2022 were related to extreme weather impacts, according to NERC.
1034 Other emergency events (EEA–1 and 
EEA–2) are more frequent, although also 
relatively rare, based upon recent data. Data for the largest ISOs and RTOs indicate that EEA–1 and EEA–2 can occur several times over a year, for relatively brief periods in most instances, in response to developing reliability emergencies.
1035Across the 
country, reliability coordinators (RCs) are charged by NERC to implement reliability standards and issue EEAs.
1036 
The RCs monitor, track, and issue alerts according to the NERC alert protocol. This data is also generally supposed to be publicly available on each reliability coordinator’s website, which documents the frequency and duration of emergency alerts. However, while there are requirements to report events where EEA–3 was declared to NERC
1037and 
NERC publicly tracks use of EEA–3,1038 
EEA–1 events are the least likely to be documented consistently, for example, there is no similar publicly available tracking and reporting for use of EEA– 1 alerts in a centralized and consistent manner. 
Energy Emergency Alerts also have an 
important geographic and/or regional component, since most emergencies affect a particular geographic zone, and hence a smaller number of generators are subject to the alert in most instances. 
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10392023 State of Reliability Technical 
Assessment, NERC. https://www.nerc.com/pa/ 
RAPA/PA/Performance%20Analysis%20DL/NERC _
SOR_ 2023_ Technical_ Assessment.pdf. 
1040For example, the entire footprint of SPP 
currently includes roughly 50 individual coal-steam 
units, reflecting roughly 19 GW of capacity. 
1040For PJM, there are currently roughly 65 
individual coal-steam units with total capacity of roughly 30 GW, which could potentially be covered by a regionwide alert. These estimates are considerably lower when known and committed coal-steam retirements are excluded. Within the 
PJM footprint, there are 27 control areas or transmission zones where emergency procedures are applied. 1041For example, units with installed CCS 
technology may be called upon to run at full 
capacity (i.e., without the parasitic load of the 
carbon capture equipment). The EPA does not expect this to be a typical response as units are economically disincentivized to shut off or bypass control equipment given the tax credit incentives in IRC section 45Q. During extreme and large-scale weather 
events, the alerts often cover a much broader geographic area, such as when Winter Storm Elliott impacted two- thirds of the lower 48 states and rapidly intensified into a bomb cyclone in December 2022. Many areas declared EEAs, and four states experienced operator-controlled load shed and 2.1 million customers experienced power outages.
1039When these events occur, a 
much larger group of affected sources would be potentially covered.
1040It 
should be noted that issuance of EEA’s is not just dependent on a generator’s availability, but also, generation deliverability, as transmission constraints due to operational conditions or planned maintenance activities can lead to issuance of EEA’s that help ensure system stability and reliability. 
The EPA’s assessment is that these 
alerts generally occur infrequently, only rarely persist for as long as several days, and are indicative of a grid under strain. When the alerts are more prolonged, lasting for several days, they are generally dictated by persistent extreme weather with widespread impacts and a higher probability of load shed. The short-term reliability mechanism offers sources that come under a documented level 2 and or 3 EEA, combined with a documented request from the balancing authority to deviate from its scheduled operations, for example, by increasing output in response to the alert. In other words, only the specific units called upon, or otherwise instructed to increase output beyond the planned day-ahead or other near-term expected output during an EEA level 2 or 3 event are eligible for this flexibility, with proper documentation. 
For new sources, the emissions and/ 
or generation data will not be counted when determining applicability and the use of the sources’ Phase 1 standard of performance may be used for compliance determinations through the duration of these events, as long as appropriate documentation is provided. For existing sources, states may choose to temporarily apply an alternative standard of performance, or a unit’s baseline emission performance rate, when demonstrating compliance with the final standards, with appropriate documentation. It should be emphasized that these final emission guidelines require compliance with the standards of performance on an annual basis (or rolling annual average for new sources), as opposed to a shorter period such as hourly, daily, or monthly. This relatively long compliance period provides significant flexibility for sources that face circumstances whereby their emission performance may change temporarily due to various factors, including in response to grid emergency conditions. Nonetheless, this mechanism is included in these final rules to ensure that affected sources have the additional flexibility needed to meet demand during emergency conditions.
1041 
The short-term reliability mechanism 
references EEA–2 and EEA–3 for several reasons. First, balancing authorities and grid operators do not necessarily have to take action under EEA–1 conditions, such as calling on interruptible loads. 
As such, there is much less cost or inconvenience to declaring EEA–1, as a general matter, and EEA–2 and EEA–3 events are more aligned with events that are rare or truly represent emergency conditions. Second, EEA–1 events are a preparatory step in anticipation of potentially worsening conditions, as opposed to an indicator of imminent load-shed. Thus, under EEA–1, balancing authorities and grid operators do not generally take actions such as calling for voluntary demand reduction or calling on interruptible loads, and reliability coordinators are afforded more discretion for declaring an EEA–1. As such, there is much less cost or inconvenience to declaring EEA–1, as a general matter, and providing operational or cost relief under EEA–1 could create an incentive to deploy it more routinely. In addition, waiving significant regulatory requirements before taking actions such as calling for voluntary demand reductions or calling upon contractually arranged interruptible loads would not be commensurate to the significance of the various response actions. Third, reliability coordinators are afforded more discretion for declaring an EEA–1, and thus may have a potential incentive to deploy it more routinely if there is 
some operational or cost relief associated with it. And lastly, the reporting of EEA–1 is not consistent throughout the country, and there is some degree of opaqueness associated with the frequency and duration of EEA–1 events, thus making it a less robust mechanism threshold for purposes of aligning it with the requirements of this final action. For these reasons, the EPA believes that EEA–2 and EEA–3 are the appropriate threshold for inclusion in the short-term reliability mechanism and better represent rare or truly emergency conditions in which providing a limited exemption from a significant environmental requirement is justifiable. 
Thus, the EPA believes that the 
selection of EEA–2 and EEA–3 are aligned with the conditions envisioned where an affected source might need temporarily relief, in order to offer reliability coordinators and balancing authorities the flexibility needed during emergency events to maintain reliability. In addition, as explained earlier, DOE’s 202(c) authority is an additional mechanism that can be deployed under certain emergency conditions, which may occur outside any EEA–2 or EEA–3 event. These tools, either individually or in combination, help provide additional assurance that sources and reliability coordinators can continue to maintain a reliable system. 
The mechanism is available to states 
to include in their state plans in an explicit manner, which will allow additional flexibility to sources in those states during short-term reliability emergencies. Inclusion of the reliability mechanism in a state plan must be part of the public comment process that each state must undertake. The comment process will afford full notice and the opportunity for the public comment, and the state plan will need to specify alternative performance standards for each specific affected source during these events (as defined in this section). The state plan must clearly indicate the specific parameters of emergency alerts cited as part of this mechanism, the relevant reliability coordinators that are authorized to issue the alerts in the state, and the compliance entities who are affected by this action (i.e., affected 
sources). These sources must provide documentation of emergencies, as indicated in this section. The documentation must include evidence of the alert from the issuing entity, duration of the alert, and requests by reliability entities to sources to increase 
output in response to the emergency. The source must supply this 
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1042https://www.nerc.com/pa/Stand/ 
Reliability%20Standards/EOP-011-2.pdf. 1043‘‘Bulk System Reliability for Tomorrow’s 
Grid’’ The Brattle Group, December 20, 2023. 
1044‘‘The Future of Resource Adequacy’’ The 
Department of Energy, April 2024. 1045https://www.epa.gov/sites/default/files/ 
documents/mats-erp.pdf. information to the state regulatory 
entities and to the EPA when demonstrating compliance with the annual performance standards. This demonstration will indicate the discrete periods where the alternative standards or emission rates were in place, coinciding with the emergency alerts. 
The calculation of the emission rate 
for an affected source in a state that adopts the short-term reliability mechanism must adhere to the following during potential emergency alerts: 
•When demonstrating annual 
compliance with the standard of performance, the existing affected source may apply its baseline emission rate in lieu of its standard of performance for the hours of operation that correspond to the duration of the alert; and 
•The existing affected EGU would 
demonstrate compliance based on application of its baseline emission performance rate standard of performance for the documented hours it operated under a revised schedule due to an EEA 2 or 3. 
•For new sources, the EGU would 
demonstrate compliance based on application of its phase 1 performance standard for the documented hours it operated under a revised schedule due to an EEA 2 or 3. with the same documentation listed above. 
Supplemental reporting, 
recordkeeping and documentation required: 
•Documentation that the EEA was in 
effect from the entity issuing the alert, along with documentation of the exact duration of the event;
1042 
•Documentation from the entity 
issuing the alert that the EEA included the affected source/region where the unit was located; and 
•Documentation that the source was 
instructed to increase output beyond the planned day-ahead or other near-term expected output and/or was asked to remain in operation outside of its scheduled dispatch during emergency conditions from a reliability coordinator, balancing authority, or ISO/RTO. 
b. Reliability Assurance Mechanism 
The EPA gave considerable attention 
and thought to comments from all 
stakeholders concerning potential reliability-related considerations. As noted earlier, the EPA engaged in extensive stakeholder outreach and provided additional opportunity for public comment as part of the supplemental notice for small 
businesses, since similar reliability- 
related concerns were raised. This section provides additional background, as well as approvable language, for a reliability assurance mechanism that states have the option to incorporate into their state plans. 
Comment: Some commenters 
cautioned that EPA rules could exacerbate an ongoing concern that firm, dispatchable assets are exiting the grid at a faster pace than new capacity can be deployed and that most new electric generating capacity does not provide the equivalent reliability attributes as the capacity being retired. Several commenters provided examples where units with publicly announced retirement dates were delayed by reliability entities and coordinators due, in part, to the potential for energy shortfalls that might increase reliability risks in the ISO. Many commenters cited findings from NERC that highlighted the potential for capacity shortfalls, some of which are already in effect in some areas. Other commenters asserted that there is no need for a reliability assurance mechanism given the sufficient lead times in the proposal and the various flexibilities already provided. Some commenters included analysis that showed resource adequacy shortfalls over the forecasted time horizon were limited and manageable under the proposal. 
Response: The EPA believes that the 
provisions in these final actions are sufficient to accommodate installation of pollution controls and reliability planning. The EPA has further articulated the use of RULOF, which can be deployed under the state planning and revision processes, for specific circumstances related to reliability. The EPA is also finalizing compliance flexibilities that can address delays to the installation or permitting of control technologies or associated infrastructure that are beyond the control of the EGU owner/operator. The EPA acknowledges that isolated issues could unfold over the course of the implementation timeline that could not have been foreseen during the planning process and that may require units to remain online beyond their planned cease operation dates to maintain reliability. 
The EPA does not agree that the final 
rule will result in long-term adverse reliability impacts.
1043 1044 Nevertheless, 
as an added safeguard, the EPA is finalizing a reliability assurance 
mechanism for existing affected sources that have committed to cease operation but, for unforeseen reasons, need to temporarily remain online to support reliability for a discrete amount of time beyond their planned date to cease operations. The primary mechanism to address reliability-related issues for units with cease operations dates is through the state plan revision process. This reliability assurance mechanism is designed to enable extensions for cease operation dates when there is insufficient time to complete a state plan revision. Under this reliability assurance mechanism, which can only be accessed if included in a state plan, units could obtain up to a 1-year extension of a cease operation date. If a state decides to include the mechanism in its state plan, then the mechanism must be disclosed during the public comment process that states must undertake. Under this reliability assurance mechanism, units may obtain extensions only for the amount of time substantiated through their applications and approved by the appropriate EPA Regional Administrator. For extension requests greater than 6 months, EPA will seek the advice of FERC in these cases and therefore applications must be submitted to FERC, as well as to the appropriate EPA Regional Administrator. The date from which an extension can be given is the enforceable date in the state plan, including any cease operation dates in state plans that are prior to January 1, 2032. 
These provisions are similar in part to 
a reliability-related flexibility provided by the EPA for the MATS rule finalized in December 2011. On December 16, 2011, the EPA issued a memorandum
1045outlining an 
Enforcement Response Policy whereby affected sources enter into a CAA 
section 113(a) administrative order for up to 1 year for narrow circumstances including when the deactivation of a unit or delay in installation of controls due to factors beyond the owner’s/ operator’s control could have an adverse, localized impact on electric reliability. Under MATS, affected sources were required to come into compliance with standards within 3 years of the effective date. The EPA believed flexibility was warranted given potential constraints around the availability of control equipment and associated skilled workforce for all affected sources within the compliance window. While a 1-year extension as 
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1046December 16, 2011, memorandum, ‘‘The 
Environmental Protection Agency’s Enforcement 
Response Policy For Use Of Clean Air Act Section 113(a) Administrative Orders In Relation To Electric Reliability And The Mercery and Air Toxics Standard’’ from Cynthia Giles, Assistant Administrator of the Office of Enforcement and Compliance Assurance. 
1047See FERC Docket No. PL12–1–000. 
1048https://www.epa.gov/enforcement/ 
enforcement-response-policy-mercury-and-air- toxics-standard-mats. 
1049https://www.ferc.gov/sites/default/files/2020- 
04/E-5_ 9.pdf. part of CAA section 112(i)(3)(B) was 
broadly available to affected sources, additional time through an administrative order was limited to units that were demonstrated to be critical for reliability purposes under the Enforcement Response Policy.
1046 
FERC’s role in this process, which was developed with extensive stakeholder input,
1047was to assess the submitted 
request to ensure any application was adequately substantiated with respect to its reliability-related claims. While several affected EGUs requested and were granted a 1-year CAA section 112(i)(3)(B) compliance extension by their permitting authority, OECA only issued five administrative orders in connection to the Enforcement Response Policy.
1048These orders relied 
upon a FERC review of the reliability risks associated with the loss of specific units, following the accompanying FERC policy memorandum guidance.
1049The 2012 MATS Final 
Rule was ultimately implemented over the 2015–2016 timeframe without challenges to grid reliability. 
Given the array of adjustments made 
to the rule explained above, and the ability of states to address unanticipated changes in circumstances through the state plan revision process, the EPA does not anticipate that this mechanism, if included by states in the planning process, will be heavily utilized. This mechanism provides an assurance to system planners and affected sources, which can provide additional time for 
the state to execute a state plan revision, if needed. For states choosing to include this option in their state plans, the reliability assurance mechanism can provide units up to a 1-year extension of the scheduled cease operation date without a state plan revision, provided the reliability need is adequately justified and the extension is limited to the time for which the reliability need is demonstrated. This mechanism can accommodate situations when, with little notice, the relevant reliability authority determines that an EGU scheduled to cease operations is needed beyond that date, in order to maintain reliability during the 12 months leading up to or after the EGU is scheduled to retire. For potential situations in which system planners, affected sources, and reliability authorities identify a reliability concern, including a potential resource adequacy shortfall and an associated demonstration of increased loss of load expectation, more than one year in advance, this approach allows for the time needed for states to undertake a state plan revision process. The EPA recognizes that successful reliability planning involves many stakeholders and is a complex long-term process. For this reason, the EPA is encouraging states to consult electric reliability authorities during the state plan process, as part of the requirements under Meaningful Engagement (see section X.E.1.b.i of this document). The EPA acknowledges that there may be isolated instances in which the deactivation or retirement of a unit could have impacts on the electric grid in the future that cannot be predicted or planned for with specificity during the state planning process, wherein all anticipated reliability-related issues would be analyzed and addressed. This mechanism is not intended for use with units encountering unforeseen delays in installation of control technologies, as such issues are addressed through compliance flexibilities discussed in section XII.F.2, or for units subject to an obligation to operate that is not based on the reliability criteria included here. 
To ensure that reliability claims, 
following the specific requirements delineated below, submitted through this mechanism are sufficiently well documented, the EPA is requiring that the unit’s relevant reliability Planning Authority(ies) certify that the claims are accurate and that the identified reliability problem both exists and requires the specific relief requested. Additionally, the EPA intends to seek the advice of FERC, the Federal agency with authority to oversee the reliability of the bulk-power system, to incorporate a review of applications for this mechanism that request more than 6 months of additional operating time beyond the existing date by which the unit is scheduled to cease operations to resolve a reliability issue. Additional operating time is available for up to 12 months from the unit’s cease operation date through this mechanism. Any relief request exceeding 12 months would need to be addressed through the state plan revision process outlined in section X.E.3. In determining whether to grant a request under this mechanism, the EPA will assess whether the associated Planning Authority’s reliability analysis identifies and supports, in a detailed and reasoned 
fashion, anticipated noncompliance with a Reliability Standard, substantiated by specific metrics described below, should a unit go offline per its established commitment. To assist in its determination, the EPA will seek FERC’s advice regarding whether analysis of the reliability risk and the potential for violation of a mandatory Reliability Standard or increased loss of load expectation is adequately supported in the filed documentation. 
This mechanism is for existing 
sources that have relied on a commitment to cease operating for purposes of these emission guidelines. Such reliance might occur in three circumstances: (1) units that plan to cease operation before January 1, 2032, and that are therefore exempt because they have elected to have enforceable cease operations dates in the state plan; (2) affected EGUs that choose to employ 40 percent natural gas co-firing by 2030 with a retirement date of no later than January 1, 2039; or (3) affected EGUs that have source-specific standards of performance based on remaining useful life, pursuant to the RULOF provisions outlined in section X.C.2 of this document. In each of these cases, units would have a commitment to cease operating by a date certain. This mechanism would allow for extensions of those dates to address unforeseen reliability or reserve margin concerns that arise due to changes in circumstances after the state plan has been finalized. Therefore, the date from which an extension can be given under this mechanism is the enforceable cease operations date in the state plan, including those prior to January 1, 2032. Only operators/owners of units that have satisfied all applicable milestones, metrics, and reporting obligations outlined in section X.C.3, and section X.C.4 for units with cease operation dates prior to January 1, 2032, would be eligible to use this mechanism. 
This mechanism creates additional 
flexibility for specified narrow circumstances for existing sources and provides additional time and flexibility to allow a state, if necessary, to submit a plan revision should circumstances persist. In other words, this mechanism 
would be for use only when there is insufficient time to complete a state plan revision. 
States can decide whether to include 
this extension mechanism in their state plans. If included in a state plan, the mechanism would be triggered when a unit submits an application to the EPA Regional Administrator where it faces an unforeseen situation that creates a 
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1050Probabilistic Assessment: Technical 
Guideline Document, NERC, August 2016. 1051‘‘Policy Statement on the Commission’s Role 
Regarding the Environmental Protection Agency’s 
Mercury and Air Toxics Standards’’ FERC, Issued May 17, 2012, at PL12–1–000. reliability issue should that unit go 
offline consistent with its commitment to cease operations—for example, if the reliability coordinator identifies an unexpected capacity shortfall and determines that a specific unit(s) in a state(s) is needed to remain operational to satisfy a specific and documented reliability concern related to a unit’s planned retirement. This mechanism would allow extensions, if approved by the Regional EPA Administrator, for units to operate after committed retirement dates without a full state plan revision. Any existing standard of performance finalized in the state plan under RULOF or the natural gas co- firing subcategory would remain in place. States have the discretion to place additional requirements on units requesting extensions. The relevant EPA Regional Administrator would approve the reliability assurance application or reject it if it were found that that the reliability assertion was not adequately supported. Units would need to substantiate the claim that they must remain online for reliability purposes with documentation demonstrating a forecasted reliability failure should the unit be taken offline, and this justification would need to be submitted to the appropriate EPA Regional Administrator and, for extensions exceeding 6 months, also to FERC, as described below. Extensions would be granted only for the duration of time demonstrated through the documentation, not to exceed 12 months, inclusive of the 6-month extension that is available and the relevant Planning Authority(ies) must certify that the claims are accurate and that the identified reliability problem both exists and requires the specific relief requested. Any further extension would require a state plan revision. 
The process and documentation 
required to demonstrate that a unit is required to stay online because it is reliability-critical is described in this section. 
In order to use this mechanism for an 
extension, certain conditions must be met by the unit and substantiated in written electronic notification to the appropriate EPA Regional Administrator, with an identical copy submitted to FERC for extension requests exceeding 6 months. More specifically, those conditions are that, where appropriate, the EGU owner complied with all applicable reporting obligations and milestones as described in sections X.C.4 (for units in the medium-term subcategory and units relying on a cease operation date for a 
less stringent standard of performance pursuant to RULOF), and section X.E.1.b.ii (for units with cease operation 
dates before January 1, 2032). No less than 30 days prior to the compliance date for applications for extensions of less than 6 months, and no less than 45 days prior to the compliance date for applications for extensions exceeding 6 months, but no earlier than 12 months prior to the compliance date (any requests over 12 months prior to a compliance date should be addressed through state plan revisions), a written complete application to activate the reliability assurance mechanism must be submitted to the appropriate EPA Regional Administrator, with a copy submitted to the state, including information responding to each of the seven elements listed as follows. 
A copy of an extension request 
exceeding 6 months must also be submitted to FERC through a process and at an office of FERC’s designation, including any additional specific information identified by FERC and responding to each of the following elements: 
(1) Analysis of the reliability risk if 
the unit were not in operation demonstrating that the continued operation of the unit after the applicable compliance date is critical to maintaining electric reliability, such that retirement of that unit would trigger one or more of the following: (A) would result in noncompliance with at least one of the mandatory reliability standards approved by FERC, or (B) would cause the loss of load expectation to increase beyond the level targeted by regional system planners as part of their established procedures for that 
particular region; specifically, this requires a clear demonstration that each unit would be needed to maintain the targeted level of resource adequacy.
1050 
In addition, a projection substantiating the duration of the requested extension must be included for the length of time that the unit is expected to extend its cease-operations date because it is reliability-critical with accompanying analysis supporting the timeframe, not to exceed 12 months. The demonstration must satisfactorily substantiate at least one of the two conditions outlined above. Any unit that has received a Reliability Must Run Designation or equivalent from a reliability coordinator or balancing authority would fit this description. The types of information that will be helpful, based on the prior reliability extension process developed for MATS between the EPA and FERC include, but are not limited to, system planning and operations studies, system restoration studies or plans, operating procedures, and mitigation plans required by applicable Reliability Standards as defined by FERC in its May 17, 2012, Policy Statement issued to clarify requirements for the reliability extensions available through MATS.
1051 
(2) Analysis submitted by the relevant 
Planning Authority that verifies the reliability related claims, or presents a separate and equivalent analysis, confirming the asserted reliability risk if the unit were not in operation, or an explanation of why such a concurrence or separate analysis cannot be provided, and where necessary, any related system wide or regional analysis. This analysis or concurrence must include a substantiation for the duration of the extension request. 
(3) Copies of any written comments 
from third parties regarding the extension. 
(4) Demonstration from the unit 
owner/operator, grid operator and other relevant entities that they have a plan that includes appropriate actions, including bringing on new capacity or transmission, to resolve the underlying reliability issue, including the steps and timeframes for implementing measures to rectify the underlying reliability issue. 
(5) Retirement date extensions 
allowed through this mechanism will be granted for only the increment of time that is substantiated by the reliability need and supporting documentation and may not exceed 12 months, inclusive of the 6-month extensions available with RTO, ISO, and reliability coordinator certification. 
(6) For units affected by these 
emissions guidelines, states may choose to require the application to identify the level of operation that is required to avoid the documented reliability risk, and consistent with that level propose alternative compliance requirements, such as alternative standards or consistent utilization constraints for the duration of the extension. The EPA Regional Office may, within 30 days of the submission, reject the application if the submission is incomplete with respect to the above requirements or if the reliability assertion is not adequately supported. 
(7) Only owners/operators of units 
that have satisfied all applicable milestone and reporting requirements and obligations under section X.C.3., and section X.C.4 for units with cease 
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operation dates prior to January 1, 2032, 
may use this mechanism for an extension as those sources will have provided information enabling the state and the public to assess that the units have diligently taken all actions necessary to meet their enforceable cease operations dates and demonstrate the use of all available tools to meet reliability challenges. Units that have failed to meet these obligations may make extension requests through the state plan revision process. 
The EPA intends to consult with 
FERC in a timely manner on reliability- critical claims given FERC’s expertise on reliability issues. The EPA may also seek advice from other reliability experts, to inform the EPA’s decision. The EPA intends to decide whether it will grant a compliance extension for a retiring unit based on a documented reliability need within 30 days of receiving the application for applications less than 6 months, and within 45 days for applications exceeding 6 months to account for time needed to consult with FERC. Whether to grant an extension to an owner/ operator is solely the decision of the EPA Regional Administrator. 
For units already subject to standards 
of performance through state plans including those co-firing until 2039, and for units with specific, tailored and differentiated compliance dates developed through RULOF that employ this mechanism, those standards would apply during the extension. 
4. Considerations for Evaluating 111 
Final Actions With Other EPA Rules 
Consistent with the EPA’s statutory 
obligations under a range of CAA programs, the Agency has recently initiated and/or finalized multiple rulemakings to reduce emissions of air pollutants, air toxics, and greenhouse gases from the power sector. The EPA has conducted an assessment of the 
potential impacts of these regulatory efforts on grid resource adequacy, which is examined and discussed in the final TSD, Resource Adequacy Analysis. This 
analysis is informed by regional reserve margin targets, regional transmission capability, and generator availability. Moreover, as described in this action, the EPA designs its programs, implementation compliance flexibilities, and backstop mechanisms to be robust to future uncertainties and various compliance pathways for the collective of market and regulatory drivers. Finally, the backstop reliability mechanisms discussed in this section are, by design, similar to mechanisms utilized in the EPA’s proposed Effluent Limitations Guidelines (ELG) rulemaking. There, to ensure that units 
choosing to permanently cease the combustion of coal by a particular date in their permits are not restricted from operation in the event of an emergency related to load balancing, the permit conditions allow for grid emergency exemptions (88 FR 18900). Harmonizing the use of similar criteria for emergency related reliability concerns across the two rules further buttresses unit confidence that grid reliability and environmental responsibilities will not come into conflict. It also streamlines the demonstrations and evidence that a unit must provide in such events. This cross-regulatory harmonization ensures that the Agency can successfully meet its CWA and CAA responsibilities regarding public health in a manner consistent with grid stability as it has consistently done throughout its 54-year history. 
The EPA has taken into consideration, 
to the extent possible, the alignment of compliance timeframes and other 
aspects of these policies for affected units. For each regulatory effort, there has been coordination and alignment of requirements and timelines, to the extent possible. The potential impact of these various regulatory efforts is further examined in the final TSD, Resource Adequacy Analysis. Additionally, the EPA considered the impact of this suite of power sector rules by performing a variety of sensitivity analyses described in XII.F.3. These considerations are discussed in the technical memoranda, IPM Sensitivity Runs and Resource Adequacy Analysis: Vehicle Rules, Final 111 EGU Rules, ELG, and MATS, available in the rulemaking docket. 
XIII. Statutory and Executive Order 
Reviews 
Additional information about these 
statutes and Executive orders can be found at https://www.epa.gov/laws- regulations/laws-and-executive-orders. 
A. Executive Order 12866: Regulatory 
Planning and Review and Executive Order 14094: Modernizing Regulatory Review 
This action is a ‘‘significant regulatory 
action’’ as defined under section 3(f)(1) of Executive Order 12866, as amended by Executive Order 14094. Accordingly, EPA, submitted this action to the Office of Management and Budget (OMB) for Executive Order 12866 review. Any changes made in response to recommendations received as part of Executive Order 12866 review have been documented in the docket. 
The EPA prepared an analysis of the 
potential costs and benefits associated with these actions. This analysis, ‘‘Regulatory Impact Analysis for the New Source Performance Standards for Greenhouse Gas Emissions from New, Modified, and Reconstructed Fossil Fuel-Fired Electric Generating Units; Emission Guidelines for Greenhouse Gas Emissions from Existing Fossil Fuel-Fired Electric Generating Units; and Repeal of the Affordable Clean Energy Rule,’’ is available in the docket and describes in detail the EPA’s assumptions and characterizes the various sources of uncertainties affecting the estimates. 
Table 6 presents the estimated present 
values (PV) and equivalent annualized values (EAV) of the projected climate benefits, health benefits, compliance costs, and net benefits of the final rules in 2019 dollars discounted to 2024. This analysis covers the impacts of the final standards for new combustion turbines and for existing steam generating EGUs. The estimated monetized net benefits are the projected monetized benefits minus the projected monetized costs of the final rules. 
Under E.O. 12866, the EPA is directed 
to consider the costs and benefits of its actions. Accordingly, in addition to the projected climate benefits of the final rules from anticipated reductions in CO
2 
emissions, the projected monetized health benefits include those related to public health associated with projected reductions in PM
2.5and ozone 
concentrations. The projected health benefits are associated with several point estimates and are presented at real discount rates of 2, 3 and 7 percent. As shown in section 4.3.9 of the RIA, there are health benefits in the years 2028, 2030, 2035, and 2045 and health disbenefits in 2040. The projected climate benefits in this table are based on estimates of the social cost of carbon (SC–CO
2) at a 2 percent near-term 
Ramsey discount rate and are discounted using a 2 percent discount rate to obtain the PV and EAV estimates in the table. The power industry’s compliance costs are represented in this analysis as the change in electric power generation costs between the baseline and illustrative policy scenarios. In simple terms, these costs are an estimate of the increased power industry expenditures required to implement the final requirements. 
These results present an incomplete 
overview of the potential effects of the final rules because important categories of benefits—including benefits from reducing HAP emissions—were not monetized and are therefore not reflected in the benefit-cost tables. The EPA anticipates that taking non- monetized effects into account would 
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show the final rules to have a greater net 
benefit than this table reflects. 
TABLE 6—P ROJECTED BENEFITS , COMPLIANCE COSTS , ANDNETBENEFITS OF THE FINAL RULES , 2024 T HROUGH 2047 
[Billions 2019$, discounted to 2024]a 
Present value (PV) 
2% Discount rate 3% Discount rate 7% Discount rate 
Climate Benefitsc....................................................................................................... 270 270 270 
Health Benefitsd........................................................................................................ 120 100 59 
Compliance Costs ...................................................................................................... 19 15 7.5 
Net Benefitse............................................................................................................. 370 360 320 
Equivalent Annualized Value (EAV)b 
Climate Benefitsc....................................................................................................... 14 14 14 
Health Benefitsd........................................................................................................ 6.3 6.1 5.2 
Compliance Costs ...................................................................................................... 0.98 0.91 0.65 
Net Benefitse............................................................................................................. 20 19 19 
Non-Monetized Benefitse.......................................................................................... Benefits from reductions in HAP emiss ions 
Ecosystem benefits associated with reductions in emissions 
of CO 2, NO X, SO 2, PM, and HAP 
Reductions in exposure to ambient NO 2and SO 2 
Improved visibility (reduced haze) from PM 2.5reductions 
aValues have been rounded to two significant figures. Rows may not appear to sum correctly due to rounding. 
bThe annualized present value of costs and benefits are calculated over the 24-year period from 2024 to 2047. 
cMonetized climate benefits are based on reductions in CO 2emissions and are calculated using three different estimates of the SC–CO 2 
(under 1.5 percent, 2.0 percent, and 2.5 percent near-term Ramsey discount rates). For the presentational purposes of this table, we show the 
climate benefits associated with the SC–CO 2at the 2 percent near-term Ramsey discount rate. Please see section 4 of the RIA for the full range 
of monetized climate benefit estimates. 
dThe projected monetized air quality related benefits include those related to public health associated with reductions in PM 2.5and ozone con-
centrations. The projected health benefits are associated with several point estimates and are presented at real discount rates of 2, 3, and 7 per-cent. This table presents the net health benefit impact over the analytic timeframe of 2024 to 2047. As shown in section 4.3.9 of the RIA, there are health benefits in the years 2028, 2030, 2035, and 2045 and health disbenefits in 2040. 
eSeveral categories of climate, human health, and welfare benefits from CO 2, NO X, SO 2, PM and HAP emissions reductions remain 
unmonetized and are thus not directly reflected in the quantified benefit estimates in this table. See section 4.2 of the RIA for a discussion of cli-mate effects that are not yet reflected in the SC–CO
2and thus remain unmonetized and section 4.4 of the RIA for a discussion of other non- 
monetized benefits. 
As shown in table 6, the final rules 
are projected to reduce greenhouse gas 
emissions in the form of CO 2, producing 
a projected PV of monetized climate benefits of about $270 billion, with an EAV of about $14 billion using the SC– CO
2discounted at 2 percent. The final 
rules are also projected to reduce emissions of NO
X, SO 2and direct PM 2.5 
leading to national health benefits from PM
2.5and ozone in most years, 
producing a projected PV of monetized health benefits of about $120 billion, with an EAV of about $6.3 billion discounted at 2 percent. Thus, these final rules are expected to generate a PV of monetized benefits of $390 billion, with an EAV of $21 billion discounted at a 2 percent rate. The PV of the projected compliance costs are $19 billion, with an EAV of about $0.98 billion discounted at 2 percent. Combining the projected benefits with the projected compliance costs yields a net benefit PV estimate of about $370 billion and EAV of about $20 billion. 
At a 3 percent discount rate, the final 
rules are expected to generate projected PV of monetized health benefits of about $100 billion, with an EAV of about $6.1 billion. Climate benefits remain discounted at 2 percent in this net benefits analysis. Thus, the final rules would generate a PV of monetized benefits of about $370 billion, with an EAV of about $20 billion discounted at 3 percent. The PV of the projected compliance costs are about $15 billion, with an EAV of $0.91 billion discounted at 3 percent. Combining the projected benefits with the projected compliance costs yields a net benefit PV estimate of about $360 billion and an EAV of about $19 billion. 
At a 7 percent discount rate, the final 
rules are expected to generate projected PV of monetized health benefits of about $59 billion, with an EAV of about $5.2 billion. Climate benefits remain discounted at 2 percent in this net benefits analysis. Thus, the final rules would generate a PV of monetized benefits of about $330 billion, with an EAV of about $19 billion discounted at 7 percent. The PV of the projected compliance costs are about $7.5 billion, with an EAV of $0.65 billion discounted at 7 percent. Combining the projected benefits with the projected compliance costs yields a net benefit PV estimate of about $320 billion and an EAV of about 
$19 billion. 
We also note that the RIA follows the 
EPA’s historic practice of using a detailed technology-rich partial equilibrium model of the electricity and related fuel sectors to estimate the incremental costs of producing 
electricity under the requirements of proposed and final major EPA power sector rules. In section 5.2 of the RIA for these actions, the EPA has also included an economy-wide analysis that considers additional facets of the economic response to the final rules, including the full resource requirements of the expected compliance pathways, some of which are paid for through subsidies. The social cost estimates in the economy-wide analysis and discussed in section 5.2 of the RIA are still far below the projected benefits of the final rules. 
B. Paperwork Reduction Act (PRA) 1. 40 CFR Part 60, Subpart TTTT 
This action does not impose any new 
information collection burden under the 
PRA. OMB has previously approved the information collection activities 
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1052See Document ID No. EPA–HQ–OAR–2023– 
0072–8109 and Document ID No. EPA–HQ–OAR– 
2023–0072–8108. contained in the existing regulations 
and has assigned OMB control number 2060–0685. 
2. 40 CFR Part 60, Subpart TTTTa 
The information collection activities 
in this rule have been submitted for 
approval to the OMB under the PRA. The Information Collection Request (ICR) document that the EPA prepared has been assigned EPA ICR number 2771.01. You can find a copy of the ICR in the docket for this rule, and it is briefly summarized here. The information collection requirements are not enforceable until OMB approves them. 
Respondents/affected entities: 
Owners and operators of fossil-fuel fired EGUs. 
Respondent’s obligation to respond: 
Mandatory. 
Estimated number of respondents: 2. 
Frequency of response: Annual. Total estimated burden: 110 hours 
(per year). Burden is defined at 5 CFR 
1320.3(b). 
Total estimated cost: $12,000 (per 
year), includes $0 annualized capital or operation & maintenance costs. 
An agency may not conduct or 
sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for the EPA’s regulations in 40 CFR are listed in 40 CFR part 9. When OMB approves this ICR, the Agency will announce that approval in the Federal Register and publish a technical 
amendment to 40 CFR part 9 to display the OMB control number for the approved information collection activities contained in this final rule. 
3. 40 CFR Part 60, Subpart UUUUa 
This action does not impose an 
information collection burden under the 
PRA. 
4. 40 CFR Part 60, Subpart UUUUb 
The information collection activities 
in this rule have been submitted for 
approval to the OMB under the PRA. The ICR document that the EPA prepared has been assigned EPA ICR number 2770.01. You can find a copy of the ICR in the docket for this rule, and it is briefly summarized here. The information collection requirements are not enforceable until OMB approves them. 
This rule imposes specific 
requirements on state governments with existing fossil fuel-fired steam generating units. The information collection requirements are based on the recordkeeping and reporting burden associated with developing, implementing, and enforcing a plan to limit GHG emissions from these existing EGUs. These recordkeeping and reporting requirements are specifically authorized by CAA section 114 (42 U.S.C. 7414). All information submitted to the EPA pursuant to the recordkeeping and reporting requirements for which a claim of confidentiality is made is safeguarded according to Agency policies set forth in 40 CFR part 2, subpart B. 
The annual burden for this collection 
of information for the states (averaged over the first 3 years following promulgation) is estimated to be 89,000 hours at a total annual labor cost of $11.7 million. The annual burden for the Federal government associated with the state collection of information (averaged over the first 3 years following promulgation) is estimated to be 24,000 hours at a total annual labor cost of $1.7 million. Burden is defined at 5 CFR 1320.3(b). 
Respondents/affected entities: States 
with one or more designated facilities covered under subpart UUUUb. 
Respondent’s obligation to respond: 
Mandatory. 
Estimated number of respondents: 43. 
Frequency of response: Once. Total estimated burden: 89,000 hours 
(per year). Burden is defined at 5 CFR 
1320.3(b). 
Total estimated cost: $11.7 million, 
includes $35,000 annualized capital or operation & maintenance costs. 
An agency may not conduct or 
sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for the EPA’s regulations in 40 CFR are listed in 40 CFR part 9. When OMB approves this ICR, the Agency will announce that approval in the Federal Register and publish a technical 
amendment to 40 CFR part 9 to display the OMB control number for the approved information collection activities contained in this final rule. 
C. Regulatory Flexibility Act (RFA) 
Pursuant to sections 603 and 609(b) of 
the RFA, the EPA prepared an initial 
regulatory flexibility analysis (IRFA) for the proposed rule and convened a Small Business Advocacy Review (SBAR) Panel to obtain advice and recommendations from small entity representatives that potentially would be subject to the rule’s requirements. Summaries of the IRFA and Panel recommendations are presented in the supplemental proposed rule at 88 FR 80582 (November 20, 2023). The complete IRFA and Panel Report are available in the docket for this 
action.
1052 
As required by section 604 of the 
RFA, the EPA prepared a final regulatory flexibility analysis (FRFA) for this action. The FRFA provides a statement of the need for, and objectives of, the rule; addresses the issues raised by public comments on the IRFA for the proposed rule, including public comments filed by the Chief Counsel for Advocacy of the Small Business Administration; describes the small 
entities to which the rule will apply; describes the projected reporting, recordkeeping and other compliance requirements of the rule and their impacts; and describes the steps the agency has taken to minimize impacts on small entities consistent with the stated objectives of the Clean Air Act. The complete FRFA is available for review in the docket and is summarized here. The scope of the FRFA is limited to the NSPS. The impacts of the emission guidelines are not evaluated here because the emission guidelines do not place explicit requirements on the regulated industry. Those impacts will be evaluated pursuant to the development of a Federal plan. 
In 2009, the EPA concluded that GHG 
emissions endanger our nation’s public health and welfare. Since that time, the evidence of the harms posed by GHG emissions has only grown and Americans experience the destructive and worsening effects of climate change every day. Fossil fuel-fired EGUs are the nation’s largest stationary source of GHG emissions, representing 25 percent of the United States’ total GHG emissions in 2021. At the same time, a range of cost-effective technologies and approaches to reduce GHG emissions from these sources are available to the power sector, and multiple projects are in various stages of operation and development. Congress has also acted to provide funding and other incentives to encourage the deployment of these technologies to achieve reductions in GHG emissions from the power sector. 
In this notice, the EPA is finalizing 
several actions under CAA section 111 to reduce the significant quantity of GHG emissions from fossil fuel-fired EGUs by establishing emission guidelines and NSPS that are based on available and cost-effective technologies that directly reduce GHG emissions from these sources. Consistent with the statutory command of CAA section 111, the final NSPS and emission guidelines reflect the application of the BSER that, 
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taking into account costs, energy 
requirements, and other statutory factors, is adequately demonstrated. 
These final actions ensure that EGUs 
reduce their GHG emissions in a manner that is cost-effective and improve the emissions performance of the sources, consistent with the applicable CAA requirements and caselaw. These standards and emission guidelines will significantly decrease GHG emissions from fossil fuel-fired EGUs and the associated harms to human health and welfare. Further, the EPA has designed these standards and emission guidelines in a way that is compatible with the nation’s overall need for a reliable supply of affordable electricity. 
The significant issues raised in public 
comments specifically in response to the initial regulatory flexibility analysis came from the Office of Advocacy within the Small Business Administration (Advocacy). The EPA agreed that convening a SBAR Panel was warranted because the EPA solicited comment on a number of policy options that, if finalized, could affect the estimate of total compliance costs and therefore the impacts on small entities. The EPA issued an IRFA and solicited comment on regulatory flexibilities for small business in a supplemental proposed rule, published in November 2023. 
Advocacy provided further 
substantive comments on the IRFA that accompanied the November 2023 supplemental proposed rule. The comments reiterated the concerns raised in its original comment letter on the proposed rule and further made the following claims: (1) the IRFA does not provide small entities an accurate 
description of the impacts of the proposed rule, (2) small entities remain concerned that the EPA has not taken reliability concerns seriously. 
In response to these comments and 
feedback during the SBAR Panel, the EPA revised its small business assessment to incorporate the final SBA guidelines (effective March 17th 2023) when performing the screening analysis to identify small businesses that have built or have planned/committed builds of combustion turbines since 2017. The EPA also treated additional entities within this subset as small based on feedback received during the panel process. The net effect of these changes is to increase the total compliance cost attributed to small entities, and the number of small entities potentially affected. The EPA additionally increased the assumed delivered hydrogen price to $1.15/kg. 
Further, the EPA is finalizing multiple 
adjustments to the proposed rule that ensure the requirements in the final 
actions can be implemented without compromising the ability of power companies, grid operators, and state and Federal energy regulators to maintain resource adequacy and grid reliability. 
To estimate the number of small 
businesses potentially impacted by the NSPS, the EPA performed a small entity screening analysis for impacts on all affected EGUs by comparing compliance costs to historic revenues at the ultimate parent company level. The EPA reviewed historical data and planned builds since 2017 to determine the universe of NGCC and natural gas combustion turbine additions. Next, the EPA followed SBA size standards to determine which ultimate parent entities should be considered small entities in this analysis. 
Once the costs of the rule were 
calculated, the costs attributed to small entities were calculated by multiplying the total costs to the share of the historical build attributed to small entities. These costs were then shared to individual entities using the ratio of their build to total small entity additions in the historical dataset. 
The EPA assessed the economic and 
financial impacts of the rule using the ratio of compliance costs to the value of revenues from electricity generation, focusing in particular on entities for which this measure is greater than 1 percent. Of the 14 entities that own NGCC units considered in this analysis, three are projected to experience compliance costs greater than or equal to 1 percent of generation revenues in 2035 and none are projected to experience compliance costs greater than or equal to 3 percent of generation 
revenues in 2035. 
Prior to the November 2023 
supplemental proposed rule, the EPA convened a SBAR Panel to obtain recommendations from small entity representatives (SERs) on elements of the regulation. The Panel identified significant alternatives for consideration by the Administrator of the EPA, which were summarized in a final report. Based on the Panel recommendations, as well as comments received in response to both the May 2023 proposed rule and the November 2023 supplemental proposed rule, the EPA is finalizing several regulatory alternatives that could accomplish the stated objectives of the Clean Air Act while minimizing any significant economic impact of the final rule on small entities. Discussion of those alternatives is provided below. 
Mechanisms for reliability relief: As 
described in section XII.F of this preamble, the EPA is finalizing several adjustments to provisions in the 
proposed rules that address reliability concerns and ensure that the final rules provide adequate flexibilities and assurance mechanisms that allow grid operators to continue to fulfill their responsibilities to maintain the reliability of the bulk-power system. The EPA is additionally finalizing additional reliability-related instruments to provide further certainty that implementation of these final rules will not intrude on grid operator’s ability to ensure reliability. The short- term reliability emergency mechanism, which is available for both new and existing units, is designed to provide an alternative compliance strategy during acute system emergencies when reliability might be threatened. The reliability assurance mechanism will be available for existing units that intend to cease operating, but, for unforeseen reasons, need to temporarily remain online to support reliability beyond the planned cease operation date. This reliability assurance mechanism, which requires an adequate showing of reliability need, is intended to apply to circumstances where there is insufficient time to complete a state plan revision. Whether to grant an extension to an owner/operator is solely the decision of the EPA. Concurrence or approval of FERC is not a condition but may inform EPA’s decision. These instruments will be presumptively approvable, provided they meet the requirements defined in these emission guidelines, if states choose to incorporate them into their plans. 
Throughout the SBAR Panel outreach, 
SERs expressed concerns that the proposed rule will have significant reliability impacts, including that areas with transmission system limitations and energy market constraints risk power interruption if replacement generation cannot be put in place before retirements. SERs recommended that Regional Transmission Organizations (RTOs) be involved to evaluate safety and reliability concerns. 
SERs additionally stated that the 
proposed rule relies on the continued development of technologies not currently in wide use and large-scale investments in new infrastructure and that the proposed rule pushes these technologies significantly faster than the infrastructure will be ready and sooner than the SERs can justify investment to their stakeholders and ratepayers. SERs stated that this is of particular concern for small entities that are retiring generation in response to other regulatory mandates and need to replace 
that generation to continue serving their customers. 
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1053See Document ID No. EPA–HQ–OAR–2023– 
0072–0033. The suite of comprehensive 
adjustments in the final rules, along 
with the two explicit reliability mechanisms are directly responsive to SER’s statements and concerns about grid reliability and the impact of retiring generating on small businesses. 
Subcategories: Throughout the SBAR 
Panel, SERs expressed concerns that control requirements on rural electric cooperatives may be an additional hardship on economically disadvantaged communities and small entities. SERs stated that the EPA should further evaluate increased energy costs, transmission upgrade costs, and infrastructure encroachment which are concrete effects on the disproportionately impacted communities. Additionally, SERs stated hydrogen and CCS cannot be BSER because they are not commercially available and viable in very rural areas. 
The EPA solicited comment on 
potential exclusions or subcategories for small entities that would be based on the class, type, or size of the source and be consistent with the Clean Air Act. The EPA also solicited comment on whether rural electric cooperatives and small utility distribution systems (serving 50,000 customers or less) can expect to have access to hydrogen and CCS infrastructure, and if a subcategory for these units is appropriate. 
The EPA evaluated public comments 
received and determined that establishing a separate subcategory for rural electric cooperatives was not warranted. However, the EPA is not finalizing the low-GHG hydrogen BSER pathway. In response to concerns raised by small business and other commenters, the EPA conducted additional analysis of the BSER criteria and its proposed determination that low-GHG hydrogen co-firing qualified as the BSER. This additional analysis led the EPA to assess that the cost of low- GHG hydrogen in 2030 will likely be higher than proposed, and these higher cost estimates and associated uncertainties related to its nationwide availability were key factors in the EPA’s decision to revise its 2030 cost estimate for delivered low-GHG hydrogen and are reflected in the increased price. For CCS, as discussed in sections VIII.F.4.c.iv and VII.C.1.a of this preamble, the EPA considered 
geographic availability of sequestration, as well as the timelines, materials, and workforce necessary for installing CCS, and determined they are sufficient. Moreover, while the BSER is premised on source-to-sink CO
2pipelines and 
sequestration, the EPA notes that many EGUs in rural areas are primed to take advantage of synergy with the broader deployment of CCS in other industries. 
Capture, pipelines, and sequestration are already in place or in advanced stages of deployment for ethanol production from corn, an industry rooted in rural areas. The high purity CO
2from ethanol production provides 
advantageous economics for CCS. 
The EPA believes the decision to not 
finalize a low-GHG hydrogen BSER pathway is responsive to SER’s statements and concerns regarding the availability of low-GHG hydrogen in very rural areas. 
In addition, the EPA is preparing a 
Small Entity Compliance Guide to help small entities comply with this rule. The guide will be available 60 days after publication of the final rule at https:// 
www.epa.gov/stationary-sources-air- 
pollution/greenhouse-gas-standards- and-guidelines-fossil-fuel-fired-power. 
D. Unfunded Mandates Reform Act of 
1995 (UMRA) 
The NSPS contain a Federal mandate 
under UMRA, 2 U.S.C. 1531–1538, that may result in expenditures of $100 million or more for the private sector in any one year. The NSPS do not contain an unfunded mandate of $100 million or more as described in UMRA, 2 U.S.C. 1531–1538 for state, local, and tribal governments, in the aggregate. 
Accordingly, the EPA prepared, under section 202 of UMRA, a written statement of the benefit-cost analysis, which is in section XIII.A of this preamble and in the RIA. 
The repeal of the ACE Rule and 
emission guidelines do not contain an unfunded mandate of $100 million or more as described in UMRA, 2 U.S.C. 1531–1538, and do not significantly or uniquely affect small governments. The emission guidelines do not impose any direct compliance requirements on regulated entities, apart from the requirement for states to develop plans to implement the guidelines under CAA section 111(d) for designated EGUs. The burden for states to develop CAA section 111(d) plans in the 24-month period following promulgation of the emission guidelines was estimated and is listed in section XIII.B, but this burden is estimated to be below $100 million in any one year. As explained in section X.E.6, the emission guidelines do not impose specific requirements on tribal governments that have designated EGUs located in their area of Indian country. 
These actions are not subject to the 
requirements of section 203 of UMRA because they contain no regulatory requirements that might significantly or uniquely affect small governments. In light of the interest in these actions among governmental entities, the EPA 
initiated consultation with governmental entities. The EPA invited the following 10 national organizations representing state and local elected officials to a virtual meeting on September 22, 2022: (1) National Governors Association, (2) National Conference of State Legislatures, (3) Council of State Governments, (4) National League of Cities, (5) U.S. Conference of Mayors, (6) National Association of Counties, (7) International City/County Management Association, (8) National Association of Towns and Townships, (9) County Executives of America, and (10) Environmental Council of States. These 10 organizations representing elected state and local officials have been identified by the EPA as the ‘‘Big 10’’ organizations appropriate to contact for purpose of consultation with elected officials. Also, the EPA invited air and utility professional groups who may have state and local government members, including the Association of Air Pollution Control Agencies, 
National Association of Clean Air Agencies, and American Public Power Association, Large Public Power Council, National Rural Electric Cooperative Association, and National Association of Regulatory Utility Commissioners to participate in the meeting. The purpose of the consultation was to provide general background on these rulemakings, answer questions, and solicit input from state and local governments. For a summary of the UMRA consultation see the memorandum in the docket titled Federalism Pre-Proposal Consultation Summary.
1053 
E. Executive Order 13132: Federalism 
These actions do not have federalism 
implications as that term is defined in E.O. 13132. Consistent with the cooperative federalism approach directed by the Clean Air Act, states will establish standards of performance for existing sources under the emission guidelines set out in this final rule. These actions 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. 
Although the direct compliance costs 
may not be substantial, the EPA nonetheless elected to consult with representatives of state and local governments in the process of 
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1054See Document ID No. EPA–HQ–OAR–2023– 
0072–0033. developing these actions to permit them 
to have meaningful and timely input into their development. The EPA’s consultation regarded planned actions for the NSPS and emission guidelines. The EPA invited the following 10 national organizations representing state and local elected officials to a virtual meeting on September 22, 2022: (1) National Governors Association, (2) National Conference of State Legislatures, (3) Council of State Governments, (4) National League of Cities, (5) U.S. Conference of Mayors, (6) National Association of Counties, (7) International City/County Management Association, (8) National Association of Towns and Townships, (9) County Executives of America, and (10) Environmental Council of States. These 10 organizations representing elected state and local officials have been identified by the EPA as the ‘‘Big 10’’ organizations appropriate to contact for purpose of consultation with elected officials. Also, the EPA invited air and utility professional groups who may have state and local government members, including the Association of Air Pollution Control Agencies, National Association of Clean Air Agencies, and American Public Power Association, Large Public Power Council, National Rural Electric Cooperative Association, and National Association of Regulatory Utility 
Commissioners to participate in the meeting. The purpose of the consultation was to provide general background on these rulemakings, answer questions, and solicit input from state and local governments. For a summary of the Federalism consultation see the memorandum in the docket titled Federalism Pre-Proposal 
Consultation Summary.
1054 
F. Executive Order 13175: Consultation and Coordination With Indian Tribal Governments 
These actions do not have tribal 
implications, as specified in Executive Order 13175. The NSPS imposes requirements on owners and operators of new or reconstructed stationary combustion turbines and the emission guidelines do not impose direct requirements on tribal governments. Tribes are not required to develop plans to implement the emission guidelines developed under CAA section 111(d) for designated EGUs. The EPA is aware of two fossil fuel-fired steam generating units located in Indian country, and one fossil fuel-fired steam generating units owned or operated by tribal entities. The EPA notes that the emission 
guidelines do not directly impose specific requirements on EGU sources, including those located in Indian country, but before developing any standards for sources on tribal land, the EPA would consult with leaders from affected tribes. Thus, Executive Order 13175 does not apply to these actions. 
Because the EPA is aware of tribal 
interest in these rules and consistent with the EPA Policy on Consultation and Coordination with Indian Tribes, the EPA offered government-to- government consultation with tribes and conducted outreach and engagement. 
G. Executive Order 13045: Protection of 
Children From Environmental Health Risks and Safety Risks Populations and Low-Income Populations 
This action is subject to Executive 
Order 13045 (62 FR 19885, April 23, 1997) because it is a significant regulatory action as defined by E.O. 12866(3)(f)(1), and the EPA believes that the environmental health or safety risk addressed by this action has a disproportionate effect on children. Accordingly, the Agency has evaluated the environmental health and welfare effects of climate change on children. GHGs contribute to climate change and are emitted in significant quantities by the power sector. The EPA believes that the GHG emission reductions resulting from implementation of these standards and guidelines will further improve children’s health. The assessment literature cited in the EPA’s 2009 Endangerment Findings concluded that certain populations and life stages, including children, the elderly, and the poor, are most vulnerable to climate- related health effects (74 FR 66524, December 15, 2009). The assessment literature since 2016 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 III of this preamble. Under these final actions, the EPA expects that CO
2emissions reductions will improve 
air quality and mitigate climate impacts which will benefit the health and welfare of children. 
H. Executive Order 13211: Actions 
Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use 
These actions, which are significant 
regulatory actions under Executive Order 12866, are likely to have to have a significant adverse effect on the supply, distribution or use of energy. The EPA has prepared a Statement of Energy Effects for these actions as follows. The EPA estimates a 1.4 percent increase in retail electricity prices on average, across the contiguous U.S. in 2035, and a 42 percent reduction in coal-fired electricity generation in 2035 as a result of these actions. The EPA projects that utility power sector delivered natural gas prices will increase 3 percent in 2035. As outlined in the Final TSD, Resource Adequacy Analysis, available in the docket for this 
rulemaking, the EPA demonstrates that compliance with the final rules can be achieved while maintaining resource adequacy, and that the rules include additional flexibility measures designed to address reliability-related concerns. For more information on the estimated energy effects, please refer section 3 of the RIA, which is in the public docket. 
I. National Technology Transfer and 
Advancement Act (NTTAA) and 1 CFR Part 51 
This rulemaking involves technical 
standards. Therefore, the EPA 
conducted searches for the New Source Performance Standards for Greenhouse Gas Emissions from New, Modified, and Reconstructed Fossil Fuel-Fired Electric Generating Units; Emission Guidelines for Greenhouse Gas Emissions from Existing Fossil Fuel-Fired Electric Generating Units; and Repeal of the Affordable Clean Energy Rule through the Enhanced National Standards Systems Network (NSSN) Database managed by the American National Standards Institute (ANSI). Searches were conducted for EPA Method 19 of 40 CFR part 60, appendix A. No applicable voluntary consensus standards (VCS) were identified for EPA Method 19. For additional information, please see the March 23, 2023, memorandum titled Voluntary Consensus Standard Results for New Source Performance Standards for 
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1055See Document ID No. EPA–HQ–OAR–2023– 
0072–0032. Greenhouse Gas Emissions from New, 
Modified, and Reconstructed Fossil Fuel-Fired Electric Generating Units; Emission Guidelines for Greenhouse Gas Emissions from Existing Fossil Fuel- Fired Electric Generating Units; and Repeal of the Affordable Clean Energy Rule.
1055 
In accordance with the requirements 
of 1 CFR part 51, the EPA is incorporating the following 10 voluntary consensus standards by reference in the final rule. 
•ANSI C12.20–2010, American 
National Standard for Electricity Meters—0.2 and 0.5 Accuracy Classes (Approved August 31, 2010) is cited in the final rule to assure consistent monitoring of electric output. This standard establishes the physical aspects and acceptable performance criteria for 0.2 and 0.5 accuracy class electricity meters. These meters would be used to measure hourly electric output that would be used, in part, to calculate compliance with an emissions 
standard. 
•ASME PTC 22–2014, Gas Turbines: 
Performance Test Codes, (Issued December 31, 2014), is cited in the final rule to provide directions and rules for conduct and reporting of results of thermal performance tests for open cycle simple cycle combustion turbines. The object is to determine the thermal performance of the combustion turbine when operating at test conditions and correcting these test results to specified reference conditions. PTC 22 provides explicit procedures for the determination of the following performance results: corrected power, corrected heat rate (efficiency), corrected exhaust flow, corrected exhaust energy, and corrected exhaust temperature. Tests may be designed to satisfy different goals, including absolute performance and comparative performance. 
•ASME PTC 46–1996, Performance 
Test Code on Overall Plant Performance, (Issued October 15, 1997), is cited in the final rule to provide uniform test methods and procedures for the determination of the thermal performance and electrical output of heat-cycle electric power plants and combined heat and power units (PTC 46 is not applicable to simple cycle combustion turbines). Test results provide a measure of the performance of a power plant or thermal island at a specified cycle configuration, operating disposition and/or fixed power level, and at a unique set of base reference conditions. PTC 46 provides explicit procedures for the determination of the 
following performance results: corrected net power, corrected heat rate, and corrected heat input. 
•ASTM D388–99 (Reapproved 2004), 
Standard Classification of Coals by Rank, covers the classification of coals by rank, that is, according to their degree of metamorphism, or progressive alteration, in the natural series from lignite to anthracite. It is used to define coal as a fuel type which is then referenced when defining coal-fired electric generating units, one of the subjects of this rule. 
•ASTM D396–98, Standard 
Specification for Fuel Oils, covers grades of fuel oil intended for use in various types of fuel-oil-burning equipment under various climatic and operating conditions. These include Grades 1 and 2 (for use in domestic and small industrial burners), Grade 4 (heavy distillate fuels or distillate/ residual fuel blends used in commercial/industrial burners equipped for this viscosity range), and Grades 5 and 6 (residual fuels of increasing viscosity and boiling range, used in industrial burners). 
•ASTM D975–08a, Standard 
Specification for Diesel Fuel Oils, covers seven grades of diesel fuel oils based on grade, sulfur content, and volatility. These grades range from Grade No. 1–D S15 (a special-purpose, light middle distillate fuel for use in diesel engine applications requiring a fuel with 15 ppm sulfur (maximum) and higher volatility than that provided by Grade No. 2–D S15 fuel) to Grade No. 4–D (a heavy distillate fuel, or a blend of distillate and residual oil, for use in low- and medium-speed diesel engines 
in applications involving predominantly constant speed and load). 
•ASTM D3699–08, Standard 
Specification for Kerosine, including Appendix X1, (Approved September 1, 2008) covers two grades of kerosene suitable for use in critical kerosene burner applications: No. 1–K (a special low sulfur grade kerosene suitable for use in non-flue-connected kerosene burner appliances and for use in wick- fed illuminating lamps) and No. 2–K (a regular grade kerosene suitable for use in flue-connected burner appliances and for use in wick-fed illuminating lamps). It is used to define kerosene, which is a type of uniform fuel listed in this rule. 
•ASTM D6751–11b, Standard 
Specification for Biodiesel Fuel Blend Stock (B100) for Middle Distillate Fuels, including Appendices X1 through X3, (Approved July 15, 2011) covers biodiesel (B100) Grades S15 and S500 for use as a blend component with middle distillate fuels. It is used to define biodiesel, which is a type of 
uniform fuel listed in this rule. 
•ASTM D7467–10, Standard 
Specification for Diesel Fuel Oil, Biodiesel Blend (B6 to B20), including Appendices X1 through X3, (Approved August 1, 2010) covers fuel blend grades of 6 to 20 volume percent biodiesel with the remainder being a light middle or middle distillate diesel fuel, collectively designated as B6 to B20. It is used to define biodiesel blends, which is a type of uniform fuel listed in this rule. 
•ISO 2314:2009(E), Gas turbines– 
Acceptance tests, Third edition (December 15, 2009) is cited in the final rule for its guidance on determining performance characteristics of stationary combustion turbines. ISO 2314 specifies guidelines and procedures for preparing, conducting and reporting thermal acceptance tests in order to determine and/or verify electrical power output, mechanical power, thermal efficiency (heat rate), turbine exhaust gas energy and/or other performance characteristics of open-cycle simple cycle combustion turbines using combustion systems supplied with gaseous and/or liquid fuels as well as closed-cycle and semi closed-cycle simple cycle combustion turbines. It can also be applied to simple cycle combustion turbines in combined cycle power plants or in connection with other heat recovery systems. ISO 2314 includes procedures for the determination of the following performance parameters, corrected to the reference operating parameters: electrical or mechanical power output (gas power, if only gas is supplied), thermal efficiency or heat rate; and combustion turbine engine exhaust energy (optionally exhaust temperature and flow). 
The EPA determined that the ANSI, 
ASME, ASTM, and ISO standards, notwithstanding the age of the standards, are reasonably available because they are available for purchase from the following addresses: American National Standards Institute (ANSI), 25 West 43rd Street, 4th Floor, New York, NY 10036–7422, +1.212.642.4900, info@ansi.org, www.ansi.org; American 
Society of Mechanical Engineers (ASME), Two Park Avenue, New York, NY 10016–5990, +1.800.843.2763, customercare@asme.org, www.asme.org; 
ASTM International, 100 Barr Harbor 
Drive, Post Office Box C700, West Conshohocken, PA 19428–2959, +1.610.832.9500, www.astm.org; 
International Organization for Standardization (ISO), Chemin de Blandonnet 8, CP 401, 1214 Vernier, Geneva, Switzerland, +41.22.749.01.11, customerservice@iso.org, www.iso.org. 
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J. Executive Order 12898: Federal 
Actions To Address Environmental Justice in Minority Populations and Low-Income Populations and Executive Order 14096: Revitalizing Our Nation’s 
Commitment to Environmental Justice for All 
The EPA believes that the human 
health or environmental conditions that exist prior to these actions result in or have the potential to result in disproportionate and adverse human health or environmental effects on communities with environmental justice concerns. Baseline PM
2.5and ozone and 
exposure analyses show that certain populations, such as residents of redlined census tracts, those linguistically isolated, Hispanic, Asian, and those without a high school diploma may experience higher ozone and PM
2.5exposures as compared to the 
national average. American Indian populations, residents of Tribal Lands, populations with life expectancy data unavailable, children, and unemployed populations may also experience disproportionately higher ozone concentrations than the national average. Black populations may also experience disproportionately higher PM
2.5concentrations than the national 
average. 
For existing sources, the EPA believes 
that this action is not likely to change existing disproportionate and adverse disparities among communities with EJ concerns regarding PM
2.5exposures in 
all future years evaluated and ozone exposures for most demographic groups in the future years evaluated. However, in 2035, under the illustrative compliance scenarios analyzed, it is possible that Asian populations, Hispanic populations, and those linguistically isolated, and those living on Tribal land may experience a slight exacerbation of ozone exposure disparities at the national level (EJ question 3). Additionally at the national level, those living on Tribal land may experience a slight exacerbation of ozone exposure disparities in 2040 and a slight mitigation of ozone exposure disparities in 2028 and 2030. At the state level, ozone exposure disparities may be either mitigated or exacerbated for certain demographic groups analyzed, also to a small degree. As discussed above, it is important to note that this analysis does not consider any potential impact of the meaningful engagement provisions or all of the other protections that are in place that can reduce the risks of localized emissions increases in a manner that is protective of public health, safety, and the environment. For new sources, the EPA believes 
that it is not practicable to assess 
whether this action is likely to result in new disproportionate and adverse effects on communities with environmental justice concerns, because the location and number of new sources is unknown. However, the EPA believes that the projected total cumulative power sector reduction of 1,365 million metric tons of CO
2emissions between 
2028 and 2047 will have a beneficial effect on populations at risk of climate change effects/impacts. Research indicates that racial, ethnic, and low socioeconomic status, vulnerable lifestages, and geographic locations may leave individuals uniquely vulnerable to climate change health impacts in the U.S. 
The information supporting this 
Executive Order review is contained in 
section XII.E of this preamble and in section 6, Environmental Justice Impacts of the RIA, which is in the public docket. 
K. Congressional Review Act (CRA) 
This action is subject to the CRA, and 
the EPA will submit the rule report to 
each House of the Congress and to the Comptroller General of the United States. This action meets the criteria set forth in 5 U.S.C. 804(2). 
XIV. Statutory Authority 
The statutory authority for the actions 
in this rulemaking is provided by 
sections 111, 302, and 307(d)(1) of the CAA as amended (42 U.S.C. 7411, 7602, 7607(d)(1)). These actions are subject to section 307(d) of the CAA (42 U.S.C. 7607(d)). 
List of Subjects in 40 CFR Part 60 
Environmental protection, 
Administrative practice and procedures, 
Air pollution control, Incorporation by reference, Reporting and recordkeeping requirements. 
Michael S. Regan, 
Administrator. 
For the reasons set forth in the 
preamble, the EPA amends 40 CFR part 
60 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. 
Subpart A—General Provisions 
■2. Section 60.17 is amended by: 
■a. Revising paragraphs (d)(1), (g)(15) 
and (16), (h)(38), (43), (47), (145), (206), and (212), the introductory text of paragraph (i); 
■b. Removing note 1 to paragraph (k) 
and paragraph (l); 
■c. Redesignating paragraphs (j) 
through (u) as shown in the following table: 
Old paragraph New paragraph 
(j) ............................... (k). 
(k) .............................. (m). 
(m) through (o) .......... (n) through (p). 
(p) through (r) ............ (r) through (t). 
(s) .............................. (q). 
(t) ............................... (j). 
(u) .............................. (l). 
■d. Revising newly-redesignated 
paragraphs (j) and (l), the introductory text to newly-redesignated paragraph (m), newly-redesignated paragraph (n), and the introductory text to newly- redesignated paragraphs (o), (q), and (r). 
The revisions read as follows: 
§ 60.17 Incorporations by reference. 
* * * * * 
(d) * * * 
(1) ANSI No. C12.20–2010 American 
National Standard for Electricity 
Meters—0.2 and 0.5 Accuracy Classes (Approved August 31, 2010); IBR approved for §§ 60.5535(d); 60.5535a(d); 60.5860b(a). 
* * * * * 
(g) * * * 
(15) ASME PTC 22–2014, Gas 
Turbines: Performance Test Codes, 
(Issued December 31, 2014); IBR approved for §§ 60.5580; 60.5580a. 
(16) ASME PTC 46–1996, 
Performance Test Code on Overall Plant Performance, (Issued October 15,1997); IBR approved for §§ 60.5580; 60.5580a. 
* * * * * 
(h) * * * 
(38) ASTM D388–99 (Reapproved 
2004) e
1(ASTM D388–99R04), Standard 
Classification of Coals by Rank, 
(Approved June 1, 2004); IBR approved for §§ 60.41; 60.45(f); 60.41Da; 60.41b; 60.41c; 60.251; 60.5580; 60.5580a. 
* * * * * 
(43) ASTM D396–98, Standard 
Specification for Fuel Oils, (Approved 
April 10, 1998); IBR approved for §§ 60.41b; 60.41c; 60.111(b); 60.111a(b); 60.5580; 60.5580a. 
* * * * * 
(47) ASTM D975–08a, Standard 
Specification for Diesel Fuel Oils, 
(Approved October 1, 2008); IBR approved for §§ 60.41b; 60.41c; 60.5580; 60.5580a. 
* * * * * 
(145) ASTM D3699–08, Standard 
Specification for Kerosine, including 
Appendix X1, (Approved September 1, 
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2008); IBR approved for §§ 60.41b; 
60.41c; 60.5580; 60.5580a. 
* * * * * 
(206) ASTM D6751–11b, Standard 
Specification for Biodiesel Fuel Blend 
Stock (B100) for Middle Distillate Fuels, including Appendices X1 through X3, (Approved July 15, 2011), IBR approved for §§ 60.41b, 60.41c, 60.5580, and 60.5580a. 
* * * * * 
(212) ASTM D7467–10, Standard 
Specification for Diesel Fuel Oil, 
Biodiesel Blend (B6 to B20), including Appendices X1 through X3, (Approved 
August 1, 2010), IBR approved for §§ 60.41b, 60.41c, 60.5580, and 60.5580a. 
* * * * * 
(i) Association of Official Analytical 
Chemists, 1111 North 19th Street, Suite 
210, Arlington, VA 22209; phone: (301) 927–7077; website: https://www.aoac.org/. 
* * * * * 
(j) CSA Group (CSA) (formerly 
Canadian Standards Association), 178 
Rexdale Boulevard, Toronto, Ontario, Canada; phone: (800) 463–6727; website: https://shop.csa.ca. 
(1) CSA B415.1–10, Performance 
Testing of Solid-fuel-burning Heating Appliances, (March 2010), IBR approved for §§ 60.534; 60.5476. 
(2) [Reserved] 
* * * * * 
(l) European Standards (EN), 
European Committee for Standardization, Management Centre, Avenue Marnix 17, B–1000 Brussels, Belgium; phone: + 32 2 550 08 11; website: https://www.en-standard.eu. 
(1) DIN EN 303–5:2012E (EN 303–5), 
Heating boilers—Part 5: Heating boilers for solid fuels, manually and automatically stoked, nominal heat output of up to 500 kW—Terminology, requirements, testing and marking, (October 2012), IBR approved for § 60.5476. 
(2) [Reserved] 
* * * * * 
(m) GPA Midstream Association, 6060 
American Plaza, Suite 700, Tulsa, OK 74135; phone: (918) 493–3872; website: www.gpamidstream.org. 
* * * * * 
(n) International Organization for 
Standardization (ISO), 1, ch. de la Voie- 
Creuse, Case postale 56, CH–1211 Geneva 20, Switzerland; phone: + 41 22 749 01 11; website: www.iso.org. 
(1) ISO 8178–4: 1996(E), 
Reciprocating Internal Combustion Engines—Exhaust Emission Measurement—part 4: Test Cycles for Different Engine Applications, IBR approved for § 60.4241(b). (2) ISO 2314:2009(E), Gas turbines– 
Acceptance tests, Third edition (December 15, 2009), IBR approved for §§ 60.5580; 60.5580a. 
(3) ISO 8316: Measurement of Liquid 
Flow in Closed Conduits—Method by Collection of the Liquid in a Volumetric Tank (1987–10–01)—First Edition, IBR approved for § 60.107a(d). 
(4) ISO 10715:1997(E), Natural gas— 
Sampling guidelines, (First Edition, June 1, 1997), IBR approved for § 60.4415(a). 
(o) National Technical Information 
Services (NTIS), 5285 Port Royal Road, Springfield, Virginia 22161. 
* * * * * 
(q) Pacific Lumber Inspection Bureau 
(formerly West Coast Lumber Inspection 
Bureau), 1010 South 336th Street #210, Federal Way, WA 98003; phone: (253) 835.3344; website: www.plib.org. 
* * * * * 
(r) Technical Association of the Pulp 
and Paper Industry (TAPPI), 15 
Technology Parkway South, Suite 115, Peachtree Corners, GA 30092; phone (800) 332–8686; website: www.tappi.org. 
* * * * * 
Subpart TTTT—Standards of 
Performance for Greenhouse Gas Emissions for Electric Generating Units 
■3. Section 60.5508 is revised to read 
as follows: 
§ 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 or an integrated gasification combined cycle (IGCC) facility that commences construction after January 8, 2014, commences reconstruction after June 18, 2014, or commences modification after January 8, 2014, but on or before May 23, 2023. This subpart also establishes emission standards and compliance schedules for the control of GHG emissions from a stationary combustion turbine that commences construction after January 8, 2014, but on or before May 23, 2023, or commences reconstruction after June 18, 2014, but on or before May 23, 2023. An affected steam generating unit, IGCC, or stationary combustion turbine shall, for the purposes of this subpart, be referred to as an affected electric generating unit (EGU). 
■4. Section 60.5509 is revised to read 
as follows: § 60.5509 What are my general 
requirements for complying with 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 or IGCC 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 (2) of this section. The GHG standards included in this subpart also apply to any stationary combustion turbine that commenced construction after January 8, 2014, but on or before May 23, 2023, or commenced reconstruction after June 18, 2014, but on or before May 23, 2023, that meets the relevant applicability conditions in paragraphs (a)(1) and (2) of this section. 
(1) Has a base load rating greater than 
260 gigajoules per hour (GJ/h) (250 million British thermal units per hour (MMBtu/h)) of fossil fuel (either alone or in combination with any other fuel); and 
(2) Serves a generator or generators 
capable of selling greater than 25 megawatts (MW) of electricity to a utility power distribution system. 
(b) You are not subject to the 
requirements of this subpart if your affected EGU meets any of the conditions specified in paragraphs (b)(1) through (10) of this section. 
(1) Your EGU is a steam generating 
unit or IGCC whose annual net-electric sales have never exceeded one-third of its potential electric output or 219,000 megawatt-hour (MWh), whichever is greater, and is currently subject to a federally enforceable permit condition limiting annual net-electric sales to no more than one-third of its potential electric output or 219,000 MWh, whichever is greater. 
(2) Your EGU is capable of deriving 50 
percent or more of the heat input from non-fossil fuel at the base load rating and is also subject to a federally enforceable permit condition limiting the annual capacity factor for all fossil fuels combined of 10 percent (0.10) or less. 
(3) Your EGU is a combined heat and 
power unit that is subject to a federally enforceable permit condition limiting annual net-electric sales to no more than either 219,000 MWh or the product of the design efficiency and the potential electric output, whichever is greater. 
(4) Your EGU serves a generator along 
with other steam generating unit(s), IGCC, or stationary combustion turbine(s) where the effective generation capacity (determined based on a prorated output of the base load rating 
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of each steam generating unit, IGCC, or 
stationary combustion turbine) is 25 MW or less. 
(5) Your EGU is a municipal waste 
combustor that is subject to subpart Eb of this part. 
(6) Your EGU is a commercial or 
industrial solid waste incineration unit that is subject to subpart CCCC of this part. 
(7) Your EGU is a steam generating 
unit or IGCC that undergoes a modification resulting in an hourly increase in CO
2emissions (mass per 
hour) of 10 percent or less (2 significant figures). Modified units that are not subject to the requirements of this subpart pursuant to this paragraph (b)(7) continue to be existing units under section 111 with respect to CO
2 
emissions standards. 
(8) Your EGU is a stationary 
combustion turbine that is not capable of combusting natural gas (e.g., not 
connected to a natural gas pipeline). 
(9) Your EGU derives greater than 50 
percent of the heat input from an industrial process that does not produce any electrical or mechanical output or useful thermal output that is used outside the affected EGU. 
(10) Your EGU is subject to subpart 
TTTTa of this part. 
■5. Section 60.5520 is revised to read 
as follows: 
§ 60.5520 What CO 2emissions 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 CO
2in excess of the applicable 
CO 2emission standard specified in table 
1 or 2 to this subpart, consistent with paragraphs (b), (c), and (d) of this section, as applicable. 
(b) Except as specified in paragraphs 
(c) and (d) of this section, you must comply with the applicable gross or net energy output standard, and your operating permit must include monitoring, recordkeeping, and reporting methodologies based on the applicable gross or net energy output standard. For the remainder of this subpart (for sources that do not qualify under paragraphs (c) and (d) of this section), where the term ‘‘gross or net energy output’’ is used, the term that applies to you is ‘‘gross energy output.’’ 
(c) As an alternate to meeting the 
requirements in paragraph (b) of this section, an owner or operator of a stationary combustion turbine may petition the Administrator in writing to comply with the alternate applicable net energy output standard. If the Administrator grants the petition, beginning on the date the Administrator grants the petition, the affected EGU must comply with the applicable net energy output-based standard included in this subpart. Your operating permit must include monitoring, recordkeeping, and reporting methodologies based on the applicable net energy output standard. For the remainder of this subpart, where the term ‘‘gross or net energy output’’ is used, the term that applies to you is ‘‘net energy output.’’ Owners or operators complying with the net output-based standard must petition the Administrator to switch back to complying with the gross energy output- based standard. 
(d) Owners or operators of a stationary 
combustion turbine that maintain 
records of electric sales to demonstrate that the stationary combustion turbine is subject to a heat input-based standard in table 2 to this subpart that are only permitted to burn one or more uniform fuels, as described in paragraph (d)(1) of this section, are only subject to the monitoring requirements in paragraph (d)(1). Owners or operators of all other stationary combustion turbines that maintain records of electric sales to demonstrate that the stationary combustion turbines are subject to a heat input-based standard in table 2 are only subject to the requirements in paragraph (d)(2) of this section. 
(1) Owners or operators of stationary 
combustion turbines that are only permitted to burn fuels with a consistent chemical composition (i.e., uniform fuels) that result in a consistent emission rate of 69 kilograms per gigajoule (kg/GJ) (160 lb CO
2/MMBtu) or 
less are not subject to any monitoring or reporting requirements under this subpart. These fuels include, but are not limited to hydrogen, natural gas, methane, butane, butylene, ethane, ethylene, propane, naphtha, propylene, jet fuel kerosene, No. 1 fuel oil, No. 2 fuel oil, and biodiesel. Stationary combustion turbines qualifying under this paragraph are only required to maintain purchase records for permitted fuels. (2) Owners or operators of stationary 
combustion turbines permitted to burn fuels that do not have a consistent chemical composition or that do not have an emission rate of 69 kg/GJ (160 lb CO
2/MMBtu) or less (e.g., non- 
uniform fuels such as residual oil and non-jet fuel kerosene) must follow the monitoring, recordkeeping, and reporting requirements necessary to complete the heat input-based calculations under this subpart. 
■6. Section 60.5525 is revised to read 
as follows: 
§ 60.5525 What are my general 
requirements for complying with this subpart? 
Combustion turbines qualifying under 
§ 60.5520(d)(1) are not subject to any 
requirements in this section other than the requirement to maintain fuel purchase records for permitted fuel(s). For all other affected sources, compliance with the applicable CO
2 
emission standard of this subpart shall be determined on a 12-operating-month rolling average basis. See table 1 or 2 to this subpart for the applicable CO
2 
emission standards. 
(a) You must be in compliance with 
the emission standards in this subpart that apply to your affected EGU at all times. However, you must determine compliance with the emission standards only at the end of the applicable operating month, as provided in paragraph (a)(1) of this section. 
(1) For each affected EGU subject to 
a CO
2emissions standard based on a 12- 
operating-month rolling average, you must determine compliance monthly by calculating the average CO
2emissions 
rate for the affected EGU at the end of the initial and each subsequent 12- operating-month period. 
(2) Consistent with § 60.5520(d)(2), if 
your affected stationary combustion turbine is subject to an input-based CO
2 
emissions standard, you must determine the total heat input in GJ or MMBtu from natural gas (HTIP
ng) and the total 
heat input from all other fuels combined (HTIP
o) using one of the methods under 
§ 60.5535(d)(2). You must then use the following equation to determine the applicable emissions standard during the compliance period: 
Equation 1 to Paragraph (a)(2) 
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Where: 
CO 2emission standard = the emission 
standard during the compliance period 
in units of kg/GJ (or lb/MMBtu). 
HTIP ng= the heat input in GJ (or MMBtu) 
from natural gas. 
HTIP o= the heat input in GJ (or MMBtu) 
from all fuels other than natural gas. 
50 = allowable emission rate in kg/GJ for heat 
input derived from natural gas (use 120 if electing to demonstrate compliance using lb CO
2/MMBtu). 
69 = allowable emission rate in kg/GJ for heat 
input derived from all fuels other than natural gas (use 160 if electing to 
demonstrate compliance using lb CO
2/ 
MMBtu). 
(b) At all times you must operate and 
maintain each affected EGU, including 
associated equipment and monitors, in a manner consistent with safety and good air pollution control practice. The Administrator will determine if you are using consistent operation and maintenance procedures based on information available to the Administrator that may include, but is not limited to, fuel use records, monitoring results, review of operation and maintenance procedures and records, review of reports required by this subpart, and inspection of the EGU. 
(c) Within 30 days after the end of the 
initial compliance period (i.e., no more 
than 30 days after the first 12-operating- month compliance period), you must make an initial compliance determination for your affected EGU(s) with respect to the applicable emissions standard in table 1 or 2 to 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 40 CFR 72.2) on or after October 23, 2015, 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) Section 60.5555(c)(3)(i), for units 
subject to the Acid Rain Program; or 
(ii) Section 60.5555(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 40 CFR 72.2) prior to October 23, 2015: 
(i) If the date on which emissions 
reporting is required to begin under 40 CFR 75.64(a) has passed prior to October 23, 2015, emissions reporting shall begin according to § 60.5555(c)(3)(i) (for Acid Rain program units), or according to § 60.5555(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 40 CFR 75.64(a) occurs on or after October 23, 2015, then the first month of the initial compliance period shall be the first operating month (as defined in § 60.5580) after the calendar month in which emissions reporting is required to begin under § 60.5555(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 § 60.5555(c)(3)(iii). 
(4) Electric sales by your affected 
facility generated when it operated during a system emergency as defined in § 60.5580 are excluded for applicability with the base load standard if you can sufficiently provide the documentation listed in § 60.5560(i). 
■7. Section 60.5535 is amended by 
revising paragraphs (a), (b), (c)(3), (d)(1), (e), and (f) to read as follows: 
§ 60.5535 How do I monitor and collect 
data to demonstrate compliance? 
(a) Combustion turbines qualifying 
under § 60.5520(d)(1) are not subject to 
any requirements in this section other than the requirement to maintain fuel purchase records for permitted fuel(s). If your combustion turbine uses non- uniform fuels as specified under § 60.5520(d)(2), you must monitor heat input in accordance with paragraph (c)(1) of this section, and you must monitor CO
2emissions in accordance 
with either paragraph (b), (c)(2), or (c)(5) of this section. For all other affected sources, you must prepare a monitoring plan to quantify the hourly CO
2mass 
emission rate (tons/h), in accordance with the applicable provisions in 40 CFR 75.53(g) and (h). 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(d) and (e)). 
(b) You must determine the hourly 
CO
2mass emissions in 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 EGU that combusts 
coal you must, and for all other affected EGUs you may, install, certify, operate, maintain, and calibrate a CO
2 
continuous emission monitoring system (CEMS) to directly measure and record hourly average CO
2concentrations 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 40 CFR 75.10(a)(3)(i). As an alternative to direct measurement of CO
2concentration, provided that your 
EGU does not use carbon separation (e.g., carbon capture and storage), you 
may use data from a certified oxygen (O
2) monitor to calculate hourly average 
CO 2concentrations, in accordance with 
40 CFR 75.10(a)(3)(iii). If you measure CO
2concentration on a dry basis, you 
must also install, certify, operate, maintain, and calibrate a continuous moisture monitoring system, according to 40 CFR 75.11(b). Alternatively, you may either use an appropriate fuel- specific default moisture value from 40 CFR 75.11(b) or submit a petition to the Administrator under 40 CFR 75.66 for a site-specific default moisture value. 
(2) For each continuous monitoring 
system that you use to determine the 
CO
2mass emissions, you must meet the 
applicable certification and quality assurance procedures in 40 CFR 75.20 and appendices A and B to 40 CFR part 75. 
(3) You must use only unadjusted 
exhaust gas volumetric flow rates to determine the hourly CO
2mass 
emissions rate from the affected EGU; you must not apply the bias adjustment factors described in Section 7.6.5 of appendix A to 40 CFR part 75 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 40 CFR part 75. 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 CO
2mass 
emissions (kg) as described in paragraphs (b)(5)(i) through (iv) of this section. Perform this calculation only for ‘‘valid operating hours’’, as defined in § 60.5540(a)(1). 
(i) Begin with the hourly CO
2mass 
emission rate (tons/h), obtained either from equation F–11 in appendix F to 40 
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CFR part 75 (if CO 2concentration is 
measured on a wet basis), or by 
following the procedure in section 4.2 of appendix F to part 75 (if CO
2 
concentration is measured on a dry basis). 
(ii) Next, multiply each hourly CO
2 
mass emission rate by the EGU or stack operating time in hours (as defined in 40 CFR 72.2), to convert it to tons of CO
2. 
(iii) Finally, multiply the result from 
paragraph (b)(5)(ii) of this section by 907.2 to convert it from tons of CO
2to 
kg. Round off to the nearest kg. 
(iv) The hourly CO 2tons/h values and 
EGU (or stack) operating times used to calculate CO
2mass emissions are 
required to be recorded under 40 CFR 75.57(e) and must be reported electronically under 40 CFR 75.64(a)(6). You must use these data to calculate the hourly CO
2mass emissions. 
(c) * * * 
(3) For each ‘‘valid operating hour’’ 
(as defined in § 60.5540(a)(1), multiply 
the hourly tons/h CO 2mass emission 
rate from paragraph (c)(2) of this section by the EGU or stack operating time in hours (as defined in 40 CFR 72.2), to convert it to tons of CO
2. Then, multiply 
the result by 907.2 to convert from tons of CO
2to kg. Round off to the nearest 
two significant figures. 
* * * * * 
(d) * * * 
(1) If you operate a source subject to 
an emissions standard established on an 
output basis (e.g., lb of CO 2per gross or 
net MWh of energy output), you must install, calibrate, maintain, and operate a sufficient number of watt meters to continuously measure and record the hourly gross electric output or net electric output, as applicable, from the affected EGU(s). These measurements must be performed using 0.2 class electricity metering instrumentation and calibration procedures as specified under ANSI No. C12.20–2010 (incorporated by reference, see § 60.17). 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 and/or direct mechanical energy contributed by each EGU to the electric generator. 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. You may also elect to develop, demonstrate, and provide information satisfactory to the Administrator on alternate methods to apportion the gross energy output. The Administrator may approve such alternate methods for apportioning the gross energy output whenever the demonstration ensures accurate estimation of emissions regulated under this part. 
(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 you must monitor hourly CO
2 
mass emissions in accordance with one of the following procedures: 
(1) If the EGUs are subject to the same 
emissions standard in table 1 or 2 to this subpart, you may monitor the hourly CO
2mass 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 40 CFR 72.2). 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. 
(2) As an alternative, or if the EGUs 
are subject to different emission standards in table 1 or 2 to this subpart, you must either: 
(i) Monitor each EGU separately by 
measuring the hourly CO
2mass 
emissions prior to mixing in the common stack or 
(ii) Apportion the CO
2mass emissions 
based on the unit’s load contribution to the total load associated with the common stack and the appropriate F- factors. You may also elect to develop, demonstrate, and provide information satisfactory to the Administrator on alternate methods to apportion the CO
2 
emissions. The Administrator may approve such alternate methods for apportioning the CO
2emissions 
whenever the demonstration ensures accurate estimation of emissions 
regulated under this part. 
* * * * * 
■8. Section 60.5540 is revised to read 
as follows: 
§ 60.5540 How do I demonstrate 
compliance with my CO 2emissions 
standard and determine excess emissions? 
(a) In accordance with § 60.5520, if 
you are subject to an output-based 
emission standard or you burn non- uniform fuels as specified in § 60.5520(d)(2), you must demonstrate compliance with the applicable CO
2 
emission standard in table 1 or 2 to this subpart as required in this section. For the initial and each subsequent 12- 
operating-month rolling average compliance period, you must follow the procedures in paragraphs (a)(1) through (8) of this section to calculate the CO
2 
mass emissions rate for your affected EGU(s) in units of the applicable emissions standard (e.g., either kg/MWh 
or kg/GJ). You must use the hourly CO
2 
mass emissions calculated under § 60.5535(b) or (c), as applicable, and either the generating load data from § 60.5535(d)(1) for output-based calculations or the heat input data from § 60.5535(d)(2) for heat-input-based calculations. Combustion turbines firing non-uniform fuels that contain CO
2 
prior to combustion (e.g., blast furnace 
gas or landfill gas) may sample the fuel stream to determine the quantity of CO
2 
present in the fuel prior to combustion and exclude this portion of the CO
2 
mass emissions from compliance determinations. 
(1) Each compliance period shall 
include only ‘‘valid operating hours’’ in the compliance period, i.e., operating 
hours for which: 
(i) ‘‘Valid data’’ (as defined in 
§ 60.5580) are obtained for all of the parameters used to determine the hourly CO
2mass emissions (kg) and, if a heat 
input-based standard applies, all the parameters used to determine total heat input for the hour are also obtained; and 
(ii) The corresponding hourly gross or 
net energy output value is also valid data (Note: For hours with no useful 
output, zero is considered to be a valid value). 
(2) You must exclude operating hours 
in which: 
(i) The substitute data provisions of 
40 CFR 75 are applied for any of the parameters used to determine the hourly CO
2mass emissions or, if a heat input- 
based standard applies, for any parameters used to determine the hourly heat input; 
(ii) An exceedance of the full-scale 
range of a continuous emission monitoring system occurs for any of the 
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parameters used to determine the hourly 
CO 2mass emissions or, if applicable, to 
determine the hourly heat input; or 
(iii) The total gross or net energy 
output (P gross/net ) or, if applicable, the 
total heat input is unavailable. 
(3) For each compliance period, at 
least 95 percent of the operating hours in the compliance period must be valid operating hours, as defined in paragraph (a)(1) of this section. 
(4) You must calculate the total CO
2 
mass emissions by summing the valid hourly CO
2mass 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 CO
2mass emissions, 
you must determine P gross/net (the 
corresponding hourly gross or net 
energy output in MWh) according to the procedures in paragraphs (a)(5)(i) and (ii) of this section, as appropriate for the 
type of affected EGU(s). For an operating hour in which a valid CO
2mass 
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 CO
2mass 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 P
gross/net for your affected 
EGU using the following equation. All terms in the equation must be expressed in units of MWh. To convert each hourly gross or net energy output (consistent with § 60.5520) value reported under 40 CFR part 75 to MWh, multiply by the corresponding EGU or stack operating time. 
Equation 1 to paragraph (a)(5)(i) 
Where: 
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. 
(Pe)
A= Electric energy used for any auxiliary 
loads in MWh. Not applicable for determining P
gross. 
(Pt) PS= Useful thermal output of steam 
(measured relative to standard ambient temperature and pressure (SATP) conditions, as applicable) that is used for applications that do not generate additional electricity, produce mechanical energy output, or enhance the performance of the affected EGU. This is calculated using the equation specified in paragraph (a)(5)(ii) of this section in MWh. 
(Pt)
HR= Non steam useful thermal output 
(measured relative to SATP conditions, 
as applicable) from heat recovery that is used for applications other than steam generation or performance enhancement of the affected EGU in MWh. 
(Pt)
IE= Useful thermal output (relative to 
SATP conditions, as applicable) from any integrated equipment is used for applications that do not generate additional steam, electricity, produce mechanical energy output, or enhance the performance of the affected EGU in 
MWh. 
TDF = Electric Transmission and Distribution 
Factor of 0.95 for a combined heat and power affected EGU where at least 20.0 percent of the total gross or net energy output consists of electric or direct mechanical output and 20.0 percent of the total gross or net energy output consists of useful thermal output on a 12-operating-month rolling average basis, or 1.0 for all other affected EGUs. 
(ii) If applicable to your affected EGU 
(for example, for combined heat and 
power), you must calculate (Pt) PSusing 
the following equation: 
Equation 2 to Paragraph (a)(5)(ii) 
Where: 
Qm= Measured useful thermal output flow in 
kg (lb) for the operating hour. 
H = Enthalpy of the useful thermal output at 
measured temperature and pressure 
(relative to SATP conditions or the energy in the condensate return line, as applicable) in Joules per kilogram (J/kg) (or Btu/lb). 
CF = Conversion factor of 3.6 × 10
9J/MWh 
or 3.413 × 106Btu/MWh. 
(6) Sources complying with energy 
output-based standards must calculate 
the basis (i.e., denominator) of their 
actual 12-operating month emission rate in accordance with paragraph (a)(6)(i) of this section. Sources complying with heat input based standards must calculate the basis of their actual 12- operating month emission rate in accordance with paragraph (a)(6)(ii) of this section. 
(i) In accordance with § 60.5520 if you 
are subject to an output-based standard, you must calculate the total gross or net energy output for the affected EGU’s 
compliance period by summing the hourly gross or net energy output values for the affected EGU that you determined under paragraph (a)(5) of this section for all of the valid operating hours in the applicable compliance period. 
(ii) If you are subject to a heat input- 
based standard, you must calculate the total heat input for each fuel fired during the compliance period. The calculation of total heat input for each individual fuel must include all valid operating hours and must also be consistent with any fuel-specific procedures specified within your selected monitoring option under § 60.5535(d)(2). 
(7) If you are subject to an output- 
based standard, you must calculate the CO
2mass emissions rate for the affected 
EGU(s) (kg/MWh) by dividing the total CO
2mass emissions value calculated 
according to the procedures in paragraph (a)(4) of this section by the total gross or net energy output value calculated according to the procedures in paragraph (a)(6)(i) of this section. Round off the result to two significant figures if the calculated value is less than 1,000; round the result to three significant figures if the calculated value 
is greater than 1,000. If you are subject to a heat input-based standard, you must calculate the CO
2mass emissions 
rate for the affected EGU(s) (kg/GJ or lb/ MMBtu) by dividing the total CO
2mass 
emissions value calculated according to the procedures in paragraph (a)(4) of this section by the total heat input calculated according to the procedures in paragraph (a)(6)(ii) of this section. 
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Round off the result to two significant 
figures. 
(b) In accordance with § 60.5520, to 
demonstrate compliance with the applicable CO
2emission standard, for 
the initial and each subsequent 12- operating-month compliance period, the CO
2mass emissions rate for your 
affected EGU must be determined according to the procedures specified in paragraph (a)(1) through (8) of this section and must be less than or equal to the applicable CO
2emissions 
standard in table 1 or 2 to this subpart, or the emissions standard calculated in accordance with § 60.5525(a)(2). 
■9. Section 60.5555 is amended by 
revising paragraphs (a)(2)(iv) and (v), (f), and (g) to read as follows. 
§ 60.5555 What reports must I submit and 
when? 
(a) * * * 
(2) * * * (iv) The percentage of valid operating 
hours in each 12-operating-month 
compliance period described in paragraph (a)(1) 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 CO
2 
emissions standard (as identified in table 1 or 2 to this subpart) with which your affected EGU must comply; and 
* * * * * 
(f) If your affected EGU captures CO
2 
to meet the applicable emissions 
standard, 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, or subpart VV, if injection occurs on-site; 
(2) Transfer the captured CO
2to an 
EGU or facility that reports in accordance with the requirements of 40 CFR part 98, subpart RR, or subpart VV, if injection occurs off-site; or 
(3) Transfer the captured CO
2to a 
facility that has received an innovative technology waiver from EPA pursuant to paragraph (g) of this section. 
(g) Any person may request the 
Administrator to issue a waiver of the requirement that captured CO
2from an 
affected EGU be transferred to a facility reporting under 40 CFR part 98, subpart RR, or subpart VV. To receive a waiver, the applicant must demonstrate to the Administrator that its technology will store captured CO
2as effectively as 
geologic sequestration, and that the proposed technology will not cause or contribute to an unreasonable risk to public health, welfare, or safety. In making this determination, the 
Administrator shall consider (among other factors) operating history of the technology, whether the technology will increase emissions or other releases of any pollutant other than CO
2, and 
permanence of the CO 2storage. The 
Administrator may test the system or require the applicant to perform any tests considered by the Administrator to be necessary to show the technology’s effectiveness, safety, and ability to store captured CO
2without release. The 
Administrator may grant conditional approval of a technology, with the approval conditioned on monitoring and reporting of operations. The 
Administrator may also withdraw approval of the waiver on evidence of releases of CO
2or other pollutants. The 
Administrator will provide notice to the public of any application under this provision and provide public notice of any proposed action on a petition before the Administrator takes final action. 
■10. Section 60.5560 is amended by 
adding paragraphs (h) and (i) to read as follows: 
§ 60.5560 What records must I maintain? 
* * * * * 
(h) For stationary combustion 
turbines, you must keep records of electric sales to determine the applicable subcategory. 
(i) You must keep the records listed 
in paragraphs (i)(1) through (3) of this section to demonstrate that your affected facility operated during a system emergency. 
(1) Documentation that the system 
emergency to which the affected EGU was responding was in effect from the entity issuing the alert, and documentation of the exact duration of the event; 
(2) Documentation from the entity 
issuing the alert that the system emergency included the affected source/ region where the affected facility was located, and 
(3) Documentation that the affected 
facility was instructed to increase output beyond the planned day-ahead or other near-term expected output and/ or was asked to remain in operation outside its scheduled dispatch during emergency conditions from a Reliability Coordinator, Balancing Authority, or Independent System Operator/Regional Transmission Organization. 
■11. Section 60.5580 is amended by: 
■a. Revising the definitions for 
‘‘Annual capacity factor’’, and ‘‘Base load rating’’; 
■b. Revising and republishing the 
definition for ‘‘Coal’’; and 
■c. Revising the definitions for 
‘‘Combined cycle unit’’, ‘‘Combined head and power unit or CHP unit’’, ‘‘Design efficiency’’, ‘‘Distillate oil’’, ‘‘ISO conditions’’, ‘‘Net electric sales’’, and ‘‘System emergency’’. 
The revisions and republications read 
as follows: 
§ 60.5580 What definitions apply to this 
subpart? 
* * * * * 
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. Actual and potential heat input derived from non-combustion sources (e.g., solar 
thermal) are not included when calculating the annual capacity factor. 
Base load rating means the maximum 
amount of heat input (fuel) that an EGU can combust on a steady state basis plus the maximum amount of heat input derived from non-combustion source (e.g., solar thermal), as determined by 
the physical design and characteristics of the EGU at International Organization for Standardization (ISO) conditions. For a stationary combustion turbine, base load rating includes the heat input from duct burners. 
Coal means all solid fuels classified as 
anthracite, bituminous, subbituminous, or lignite by ASTM International in ASTM D388–99R04 (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. 
Combined cycle unit means 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 simultaneously produces both electric (or mechanical) and useful thermal output from the same primary energy source. 
Design efficiency means the rated 
overall net efficiency (e.g., electric plus 
useful thermal output) on a lower heating value basis at the base load rating, at ISO conditions, and at the maximum useful thermal output (e.g., CHP unit with condensing steam turbines would determine the design efficiency at the maximum level of extraction and/or bypass). Design efficiency shall be determined using one 
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of the following methods: ASME PTC 
22–2014, ASME PTC 46–1996, ISO 2314:2009(E) (all incorporated by reference, see § 60.17), or an alternative approved by the Administrator. 
Distillate oil means fuel oils that 
comply with the specifications for fuel oil numbers 1 and 2, as defined in ASTM D396–98 (incorporated by reference, see § 60.17); diesel fuel oil numbers 1 and 2, as defined in ASTM D975–08a (incorporated by reference, see § 60.17); kerosene, as defined in ASTM D3699–08 (incorporated by reference, see § 60.17); biodiesel as defined in ASTM D6751–11b (incorporated by reference, see § 60.17); or biodiesel blends as defined in ASTM D7467–10 (incorporated by reference, see § 60.17). 
* * * * * 
ISO conditions means 288 Kelvin (15 
°C, 59 °F), 60 percent relative humidity and 101.3 kilopascals (14.69 psi, 1 atm) 
pressure. 
* * * * * 
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 a 12-operating month basis, the gross electric sales to the utility power distribution system minus purchased power of the thermal host facility or facilities. 
(3) Electricity supplied to other 
facilities that produce electricity to offset auxiliary loads are included when calculating net-electric sales. 
(4) Electric sales during a system 
emergency are not included when 
calculating net-electric sales. 
* * * * * System emergency means periods 
when the Reliability Coordinator has 
declared an Energy Emergency Alert level 2 or 3 as defined by NERC Reliability Standard EOP–011–2 or its successor. 
* * * * * 
■12. Table 1 to subpart TTTT is revised 
to read as follows: 
Table 1 to Subpart TTTT of Part 60— 
CO2Emission Standards for Affected 
Steam Generating Units and Integrated 
Gasification Combined Cycle Facilities That Commenced Construction After January 8, 2014, and Reconstruction or Modification After June 18, 2014 
[Note: Numerical values of 1,000 or 
greater have a minimum of 3 significant figures and numerical values of less than 1,000 have a minimum of 2 significant figures] 
Affected EGU CO 2Emission standard 
Newly constructed steam generating unit or integrated gasification 
combined cycle (IGCC).640 kg CO 2/MWh of gross energy output (1,400 lb CO 2/MWh-gross). 
Reconstructed steam generating unit or IGCC that has base load rating 
of 2,100 GJ/h (2,000 MMBtu/h) or less.910 kg CO 2/MWh of gross energy output (2,000 lb CO 2/MWh-gross). 
Reconstructed steam generating unit or IGCC that has a base load rat-
ing greater than 2,100 GJ/h (2,000 MMBtu/h).820 kg CO 2/MWh of gross energy output (1,800 lb CO 2/MWh-gross). 
Modified steam generating unit or IGCC ................................................. A unit-specific emission limit determined by the unit’s best historical an-
nual CO 2emission rate (from 2002 to the date of the modification); 
the emission limit will be no lower than: 
(1) 820 kg CO 2/MWh of gross energy output (1,800 lb CO 2/MWh- 
gross) for units with a base load rating greater than 2,100 GJ/h 
(2,000 MMBtu/h); or 
(2) 910 kg CO 2/MWh of gross energy output (2,000 lb CO 2/MWh- 
gross) for units with a base load rating of 2,100 GJ/h (2,000 MMBtu/ h) or less. 
■13. Table 2 to subpart TTTT is revised 
to read as follows: Table 2 to Subpart TTTT of Part 60— 
CO2Emission Standards for Affected 
Stationary Combustion Turbines That Commenced Construction After January 8, 2014, and Reconstruction After June 18, 2014 (Net Energy Output-Based Standards Applicable as Approved by the Administrator) 
[Note: Numerical values of 1,000 or 
greater have a minimum of 3 significant figures and numerical values of less 
than 1,000 have a minimum of 2 significant figures] 
Affected EGU CO 2Emission standard 
Newly constructed or reconstructed stationary combustion turbine that 
supplies more than its design efficiency or 50 percent, whichever is 
less, times its potential electric output as net-electric sales on both a 12-operating month and a 3-year rolling average basis and combusts more than 90% natural gas on a heat input basis on a 12-operating- month rolling average basis.450 kg CO
2/MWh (1,000 lb CO 2/MWh) of gross energy output; or 
470 kg CO 2/MWh (1,030 lb CO 2/MWh) of net energy output. 
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Affected EGU CO 2Emission standard 
Newly constructed or reconstructed stationary combustion turbine that 
supplies its design efficiency or 50 percent, whichever is less, times 
its potential electric output or less as net-electric sales on either a 12-operating month or a 3-year rolling average basis and combusts more than 90% natural gas on a heat input basis on a 12-operating- month rolling average basis].50 kg CO
2/GJ (120 lb CO 2/MMBtu) of heat input. 
Newly constructed and reconstructed stationary combustion turbine that 
combusts 90% or less natural gas on a heat input basis on a 12-op-erating-month rolling average basis.Between 50 to 69 kg CO
2/GJ (120 to 160 lb CO 2/MMBtu) of heat input 
as determined by the procedures in § 60.5525. 
■14. Table 3 to subpart TTTT is revised 
to read as follows: Table 3 to Subpart TTTT of Part 60— 
Applicability of Subpart A of Part 60 (General Provisions) to Subpart TTTT 
General provisions citation Subject of citation Applies to subpart TTTT Explanation 
§ 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. Dupli-
cate submittals are not required. 
§ 60.5 ................................... Determination of construction or modi-
fication.Yes.
§ 60.6 ................................... Review of plans ....................................... Yes.
§ 60.7 ................................... Notification and Recordkeeping .............. Yes .................................... Only the requirements to submit the noti-
fications in § 60.7(a)(1) and (3) and to keep records of malfunctions in § 60.7(b), if applicable. 
§ 60.8(a) ............................... Performance tests ................................... No.
§ 60.8(b) ............................... Performance test method alternatives .... Yes .................................... Administrator can approve alternate 
methods 
§ 60.8(c)–(f) .......................... Conducting performance tests ................ No.
§ 60.9 ................................... Availability of Information ........................ Yes.
§ 60.10 ................................. State authority ......................................... Yes.
§ 60.11 ................................. Compliance with standards and mainte-
nance requirements.No. 
§ 60.12 ................................. Circumvention .......................................... Yes.
§ 60.13 (a)–(h), (j) ................ Monitoring requirements .......................... No ...................................... All monitoring is done according to part 
75. 
§ 60.13 (i) ............................. Monitoring requirements .......................... Yes .................................... Administrator can approve alternative 
monitoring procedures or requirements 
§ 60.14 ................................. Modification ............................................. Yes (steam generating 
units and IGCC facilities).
No (stationary combustion 
turbines).
§ 60.15 ................................. Reconstruction ......................................... Yes.
§ 60.16 ................................. Priority list ................................................ No.
§ 60.17 ................................. Incorporations by reference .................... Yes.
§ 60.18 ................................. General control device requirements ...... No.
§ 60.19 ................................. General notification and reporting re-
quirements.Yes .................................... Does not apply to notifications under 
§ 75.61 or to information reported through ECMPS. 
■15. Add subpart TTTTa to read as 
follows: 
Subpart TTTTa—Standards of Performance 
for Greenhouse Gas Emissions for Modified Coal-Fired Steam Electric Generating Units and New Construction and Reconstruction Stationary Combustion Turbine Electric Generating Units 
Applicability 
Sec. 
60.5508a What is the purpose of this 
subpart? 
60.5509a Am I subject to this subpart? Emissions Standards 
60.5515a Which pollutants are regulated by 
this subpart? 
60.5520a What CO
2emissions standard 
must I meet? 
60.5525a What are my general requirements 
for complying with this subpart? 
Monitoring and Compliance Determination 
Procedures 
60.5535a How do I monitor and collect data 
to demonstrate compliance? 
60.5540a How do I demonstrate compliance 
with my CO 2emissions standard and 
determine excess emissions? Notification, Reports, and Records 
60.5550a What notifications must I submit 
and when? 
60.5555a What reports must I submit and 
when? 
60.5560a What records must I maintain? 
60.5565a In what form and how long must 
I keep my records? 
Other Requirements and Information 
60.5570a What parts of the general 
provisions apply to my affected EGU? 
60.5575a Who implements and enforces 
this subpart? 
60.5580a What definitions apply to this 
subpart? 
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Table 1 to Subpart TTTTa of Part 60—CO 2 
Emission Standards for Affected 
Stationary Combustion Turbines That Commenced Construction or Reconstruction After May 23, 2023 (Gross or Net Energy Output-Based Standards Applicable as Approved by 
the Administrator) 
Table 2 to Subpart TTTTa of Part 60—CO
2 
Emission Standards for Affected Steam Generating Units or IGCC That Commenced Modification After May 23, 2023 
Table 3 to Subpart TTTTa of Part 60— 
Applicability of Subpart A of Part 60 (General Provisions) to Subpart TTTTa 
Subpart TTTTa—Standards of 
Performance for Greenhouse Gas Emissions for Modified Coal-Fired Steam Electric Generating Units and New Construction and Reconstruction Stationary Combustion Turbine Electric Generating Units 
Applicability 
§ 60.5508a 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 coal-fired steam generating unit or integrated gasification combined cycle facility (IGCC) that commences modification after May 23, 2023. This subpart also establishes emission standards and compliance schedules for the control of GHG emissions from a stationary combustion turbine that commences construction or reconstruction after May 23, 2023. An affected coal-fired steam generating unit, IGCC, or stationary combustion turbine shall, for the purposes of this subpart, be referred to as an affected electric generating unit (EGU). 
§ 60.5509a 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 or IGCC that combusts coal and that commences modification after May 23, 2023, that meets the relevant applicability conditions in paragraphs (a)(1) and (2) of this section. The GHG standards included in this subpart also apply to any stationary combustion turbine that commences construction or reconstruction after May 23, 2023, that meets the relevant applicability conditions in paragraphs (a)(1) and (2) of this section. 
(1) Has a base load rating greater than 
260 gigajoules per hour (GJ/h) (250 million British thermal units per hour (MMBtu/h)) of fossil fuel (either alone or in combination with any other fuel); and (2) Serves a generator or generators 
capable of selling greater than 25 megawatts (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 (8) of this section. 
(1) Your EGU is a steam generating 
unit or IGCC whose annual net-electric sales have never exceeded one-third of its potential electric output or 219,000 megawatt-hour (MWh), whichever is greater, and is currently subject to a federally enforceable permit condition limiting annual net-electric sales to no more than one-third of its potential electric output or 219,000 MWh, whichever is greater. 
(2) Your EGU is capable of deriving 50 
percent or more of the heat input from non-fossil fuel at the base load rating and is also subject to a federally enforceable permit condition limiting the annual capacity factor for all fossil fuels combined of 10 percent (0.10) or less. 
(3) Your EGU is a combined heat and 
power unit that is subject to a federally enforceable permit condition limiting annual net-electric sales to no more than either 219,000 MWh or the product of the design efficiency and the potential electric output, whichever is greater. 
(4) Your EGU serves a generator along 
with other steam generating unit(s), IGCC, or stationary combustion turbine(s) where the effective generation capacity (determined based on a prorated output of the base load rating of each steam generating unit, IGCC, or stationary combustion turbine) is 25 MW or less. 
(5) Your EGU is a municipal waste 
combustor that is subject to subpart Eb of this part. 
(6) Your EGU is a commercial or 
industrial solid waste incineration unit that is subject to subpart CCCC of this part. 
(7) Your EGU is a steam generating 
unit or IGCC that undergoes a modification resulting in an hourly increase in CO
2emissions (mass per 
hour) of 10 percent or less (2 significant figures). Modified units that are not subject to the requirements of this subpart pursuant to this subsection continue to be existing units under section 111 with respect to CO
2 
emissions standards. 
(8) Your EGU derives greater than 50 
percent of the heat input from an industrial process that does not produce any electrical or mechanical output or useful thermal output that is used outside the affected EGU. Emission Standards 
§ 60.5515a Which pollutants are regulated 
by this subpart? 
(a) The pollutants regulated by this 
subpart are greenhouse gases. The 
greenhouse gas standard in this subpart is in the form of a limitation on emission of carbon dioxide. 
(b) PSD and Title V thresholds for 
greenhouse gases. 
(1) For the purposes of 40 CFR 
51.166(b)(49)(ii), with respect to GHG emissions from affected facilities, the ‘‘pollutant that is subject to the standard promulgated under section 111 of the Act’’ shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in 40 CFR 51.166(b)(48) and in any SIP approved by the EPA that is interpreted to incorporate, or specifically incorporates, 40 CFR 51.166(b)(48). 
(2) For the purposes of 40 CFR 
52.21(b)(50)(ii), with respect to GHG emissions from affected facilities, the ‘‘pollutant that is subject to the standard promulgated under section 111 of the Act’’ shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in 40 CFR 52.21(b)(49). 
(3) For the purposes of 40 CFR 70.2, 
with respect to greenhouse gas emissions from affected facilities, the ‘‘pollutant that is subject to any standard promulgated under section 111 of the Act’’ shall be considered to be the pollutant that otherwise is ‘‘subject to regulation’’ as defined in 40 CFR 70.2. 
(4) For the purposes of 40 CFR 71.2, 
with respect to greenhouse gas emissions from affected facilities, the ‘‘pollutant that is subject to any standard promulgated under section 111 of the Act’’ shall be considered to be the pollutant that otherwise is ‘‘subject to regulation’’ as defined in 40 CFR 71.2. 
§ 60.5520a What CO 2emissions 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 CO
2in excess of the applicable 
CO 2emission standard specified in table 
1 to this subpart, consistent with paragraphs (b), (c), and (d) of this section, as applicable. 
(b) Except as specified in paragraphs 
(c) and (d) of this section, you must comply with the applicable gross or net energy output standard, and your operating permit must include monitoring, recordkeeping, and reporting methodologies based on the applicable gross or net energy output standard. For the remainder of this subpart (for sources that do not qualify 
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under paragraphs (c) and (d) of this 
section), where the term ‘‘gross or net energy output’’ is used, the term that applies to you is ‘‘gross energy output.’’ 
(c) As an alternative to meeting the 
requirements in paragraph (b) of this section, an owner or operator of a stationary combustion turbine may petition the Administrator in writing to comply with the alternate applicable net energy output standard. If the Administrator grants the petition, beginning on the date the Administrator grants the petition, the affected EGU must comply with the applicable net energy output-based standard included in this subpart. Your operating permit must include monitoring, recordkeeping, and reporting methodologies based on the applicable net energy output standard. For the remainder of this subpart, where the term ‘‘gross or net energy output’’ is used, the term that applies to you is ‘‘net energy output.’’ Owners or operators complying with the net output-based standard must petition the Administrator to switch back to complying with the gross energy output- based standard. 
(d) Owners or operators of a stationary 
combustion turbine that maintain records of electric sales to demonstrate that the stationary combustion turbine is subject to a heat input-based standard in table 1 to this subpart that are only permitted to burn one or more uniform fuels, as described in paragraph (d)(1) of this section, are only subject to the monitoring requirements in paragraph (d)(1). Owners or operators of all other stationary combustion turbines that maintain records of electric sales to 
demonstrate that the stationary combustion turbines are subject to a heat input-based standard in table 1 are only subject to the requirements in paragraph (d)(2) of this section. 
(1) Owners or operators of stationary 
combustion turbines that are only permitted to burn fuels with a consistent chemical composition (i.e., uniform fuels) that result in a consistent emission rate of 69 kilograms per gigajoule (kg/GJ) (160 lb CO
2/MMBtu) or 
less are not subject to any monitoring or reporting requirements under this subpart. These fuels include, but are not limited to hydrogen, natural gas, methane, butane, butylene, ethane, ethylene, propane, naphtha, propylene, jet fuel, kerosene, No. 1 fuel oil, No. 2 fuel oil, and biodiesel. Stationary combustion turbines qualifying under this paragraph are only required to maintain purchase records for permitted fuels. 
(2) Owners or operators of stationary 
combustion turbines permitted to burn fuels that do not have a consistent chemical composition or that do not have an emission rate of 69 kg/GJ (160 lb CO
2/MMBtu) or less (e.g., non- 
uniform fuels such as residual oil and non-jet fuel kerosene) must follow the monitoring, recordkeeping, and reporting requirements necessary to complete the heat input-based calculations under this subpart. 
§ 60.5525a What are my general 
requirements for complying with this subpart? 
Combustion turbines qualifying under 
§ 60.5520a(d)(1) are not subject to any requirements in this section other than 
the requirement to maintain fuel purchase records for permitted fuel(s). For all other affected sources, compliance with the applicable CO
2 
emission standard of this subpart shall be determined on a 12-operating-month rolling average basis. See table 1 to this subpart for the applicable CO
2emission 
standards. 
(a) You must be in compliance with 
the emission standards in this subpart that apply to your affected EGU at all times. However, you must determine compliance with the emission standards only at the end of the applicable operating month, as provided in paragraph (a)(1) of this section. 
(1) For each affected EGU subject to 
a CO
2emissions standard based on a 12- 
operating-month rolling average, you must determine compliance monthly by calculating the average CO
2emissions 
rate for the affected EGU at the end of the initial and each subsequent 12- operating-month period. 
(2) Consistent with § 60.5520a(d)(2), if 
your affected stationary combustion turbine is subject to an input-based CO
2 
emissions standard, you must determine the total heat input in GJ or MMBtu from natural gas (HTIPng) and the total heat input from all other fuels combined (HTIPo) using one of the methods under § 60.5535a(d)(2). You must then use the following equation to determine the applicable emissions standard during the compliance period: 
Equation 1 to Paragraph (a)(2) 
Where: 
CO 2emission standard = the emission 
standard during the compliance period 
in units of kg/GJ (or lb/MMBtu). 
HTIP ng= the heat input in GJ (or MMBtu) 
from natural gas. 
HTIP o= the heat input in GJ (or MMBtu) 
from all fuels other than natural gas. 
50 = allowable emission rate in lb kg/GJ for 
heat input derived from natural gas (use 120 if electing to demonstrate 
compliance using lb CO 2/MMBtu). 
69 = allowable emission rate in lb kg/GJ for 
heat input derived from all fuels other 
than natural gas (use 160 if electing to demonstrate compliance using lb CO
2/ 
MMBtu). 
(3) Owners/operators of a base load 
combustion turbine with a base load 
rating of less than 2,110 GJ/h (2,000 MMBtu/h) and/or an intermediate or base load combustion turbine burning 
fuels other than natural gas may elect to determine a site-specific emissions rate using one of the following equations. Combustion turbines co-firing hydrogen are not required to use the fuel adjustment parameter. 
(i) For base load combustion turbines: 
Equation 2 to Paragraph (a)(3)(i) 
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HTIPng + HTIP0 40038 Federal Register / Vol. 89, No. 91 / Thursday, May 9, 2024 / Rules and Regulations 
Where: 
CO 2emission standard = the emission 
standard during the compliance period 
in units of kg/MWh (or lb/MWh) 
BLER L= Base load emissions standard for 
natural gas-fired combustion turbines with base load ratings greater than 2,110 GJ/h (2,000 MMBtu/h). 360 kg CO
2/ 
MWh-gross (800 lb CO 2/MWh-gross) or 
370 kg CO 2/MWh-net (820 lb CO 2/MWh- 
net); 43 kg CO 2/MWh-gross (100 lb CO 2/ 
MWh-gross) or 42 kg CO 2/MWh-net (97 
lb CO 2/MWh-net); as applicable BLER S= Base load emissions standard for 
natural gas-fired combustion turbines 
with a base load rating of 260 GJ/h (250 MMBtu/h). 410 kg CO
2/MWh-gross (900 
lb CO 2/MWh-gross) or 420 kg CO 2/MWh- 
net (920 lb CO 2/MWh-net); 49 kg CO 2/ 
MWh-gross (108 lb CO 2/MWh-gross) or 
50 kg CO 2/MWh-net (110 lb CO 2/MWh- 
net); as applicable 
BLR L= Minimum base load rating of large 
combustion turbines 2,110 GJ/h (2,000 MMBtu/h) 
BLR
S= Base load rating of smallest 
combustion turbine 260 GJ/h (250 
MMBtu/h) BLR A= Base load rating of the actual 
combustion turbine in GJ/h (or MMBtu/ 
h) 
HIER A= Heat input-based emissions rate of 
the actual fuel burned in the combustion turbine (lb CO
2/MMBtu). Not to exceed 
69 kg/GJ (160 lb CO 2/MMBtu) 
HIER NG= Heat input-based emissions rate of 
natural gas 50 kg/GJ (120 lb CO 2/MMBtu) 
(ii) For intermediate load combustion 
turbines: 
Equation 3 to Paragraph (a)(3)(ii) 
Where: 
CO 2emission standard = the emission 
standard during the compliance period 
in units of kg/MWh (or lb/MWh) 
ILER = Intermediate load emissions rate for 
natural gas-fired combustion turbines. 520 kg/MWh-gross (1,150 lb CO
2/MWh- 
gross) or 530 kg CO 2/MWh-net (1,160 lb 
CO 2/MWh-net) or 450 kg/MWh-gross 
(1,100 lb CO 2/MWh-gross) or 460 kg 
CO 2/MWh-net (1,110 lb CO 2/MWh-net) 
as applicable 
HIER A= Heat input-based emissions rate of 
the actual fuel burned in the combustion turbine (lb CO
2/MMBtu). Not to exceed 
69 kg/GJ (160 lb CO 2/MMBtu) 
HIER NG= Heat input-based emissions rate of 
natural gas 50 kg/GJ (120 lb CO 2/MMBtu) 
(b) At all times you must operate and 
maintain each affected EGU, including 
associated equipment and monitors, in a manner consistent with safety and good air pollution control practice. The Administrator will determine if you are using consistent operation and maintenance procedures based on information available to the Administrator that may include, but is not limited to, fuel use records, monitoring results, review of operation and maintenance procedures and records, review of reports required by this subpart, and inspection of the EGU. 
(c) Within 30 days after the end of the 
initial compliance period (i.e., no more 
than 30 days after the first 12-operating- month compliance period), you must make an initial compliance determination for your affected EGU(s) with respect to the applicable emissions standard in table 1 to 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 40 CFR 72.2), the first month of the initial compliance period shall be the first operating month (as defined in 
§ 60.5580a) after the calendar month in which emissions reporting is required to begin under: 
(i) Section 60.5555a(c)(3)(i), for units 
subject to the Acid Rain Program; or 
(ii) Section 60.5555a(c)(3)(ii), for units 
that are not in the Acid Rain Program. 
(2) 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 § 60.5580a) after the calendar month in which emissions reporting is required to begin under § 60.5555a(c)(3)(iii). 
(3) Emissions of CO
2emitted by your 
affected facility and the output of the affected facility generated when it operated during a system emergency as defined in § 60.5580a are excluded for both applicability and compliance with the relevant standards of performance if you can sufficiently provide the documentation listed in § 60.5560a(i). The relevant standard of performance for affected EGUs that operate during a system emergency depends on the subcategory, as described in paragraphs (c)(3)(i) and (ii) of this section. 
(i) For intermediate and base load 
combustion turbines that operate during a system emergency, you comply with the standard for low load combustion turbines specified in table 1 to this subpart. 
(ii) For modified steam generating 
units, you must not discharge from the affected EGU any gases that contain CO
2 
in excess of 230 lb CO 2/MMBtu. 
Monitoring and Compliance Determination Procedures 
§ 60.5535a How do I monitor and collect 
data to demonstrate compliance? 
(a) Combustion turbines qualifying 
under § 60.5520a(d)(1) are not subject to 
any requirements in this section other than the requirement to maintain fuel purchase records for permitted fuel(s). If 
your combustion turbine uses non- uniform fuels as specified under § 60.5520a(d)(2), you must monitor heat input in accordance with paragraph (c)(1) of this section, and you must monitor CO
2emissions in accordance 
with either paragraph (b), (c)(2), or (c)(5) of this section. For all other affected sources, you must prepare a monitoring plan to quantify the hourly CO
2mass 
emission rate (tons/h), in accordance with the applicable provisions in 40 CFR 75.53(g) and (h). 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 § 60.5555a(d) and (e)). 
(b) You must determine the hourly 
CO
2mass emissions in 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 EGU that combusts 
coal you must, and for all other affected EGUs you may, install, certify, operate, maintain, and calibrate a CO
2 
continuous emission monitoring system (CEMS) to directly measure and record hourly average CO
2concentrations 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 40 CFR 75.10(a)(3)(i). As an alternative to direct measurement of CO
2concentration, provided that your 
EGU does not use carbon separation (e.g., carbon capture and storage), you 
may use data from a certified oxygen 
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CO2 emissions standard = ILER* [HIERN) 40039 Federal Register / Vol. 89, No. 91 / Thursday, May 9, 2024 / Rules and Regulations 
(O2) monitor to calculate hourly average 
CO 2concentrations, in accordance with 
40 CFR 75.10(a)(3)(iii). If you measure CO
2concentration on a dry basis, you 
must also install, certify, operate, maintain, and calibrate a continuous moisture monitoring system, according to 40 CFR 75.11(b). Alternatively, you may either use an appropriate fuel- specific default moisture value from 40 CFR 75.11(b) or submit a petition to the Administrator under 40 CFR 75.66 for a site-specific default moisture value. 
(2) For each continuous monitoring 
system that you use to determine the CO
2mass emissions, you must meet the 
applicable certification and quality assurance procedures in 40 CFR 75.20 
and appendices A and B to 40 CFR part 75. 
(3) You must use only unadjusted 
exhaust gas volumetric flow rates to determine the hourly CO
2mass 
emissions rate from the affected EGU; you must not apply the bias adjustment factors described in Section 7.6.5 of appendix A to 40 CFR part 75 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 40 CFR part 75. 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 CO
2mass 
emissions (kg) as described in paragraphs (b)(5)(i) through (iv) of this section. Perform this calculation only for ‘‘valid operating hours’’, as defined in § 60.5540(a)(1). 
(i) Begin with the hourly CO
2mass 
emission rate (tons/h), obtained either from Equation F–11 in appendix F to 40 CFR part 75 (if CO
2concentration is 
measured on a wet basis), or by following the procedure in section 4.2 of appendix F to 40 CFR part 75 (if CO
2 
concentration is measured on a dry basis). 
(ii) Next, multiply each hourly CO
2 
mass emission rate by the EGU or stack operating time in hours (as defined in 40 CFR 72.2), to convert it to tons of CO
2. 
(iii) Finally, multiply the result from 
paragraph (b)(5)(ii) of this section by 907.2 to convert it from tons of CO
2to 
kg. Round off to the nearest kg. 
(iv) The hourly CO 2tons/h values and 
EGU (or stack) operating times used to calculate CO
2mass emissions are 
required to be recorded under 40 CFR 75.57(e) and must be reported electronically under 40 CFR 75.64(a)(6). You must use these data to calculate the hourly CO
2mass 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 CO
2mass 
emissions according to paragraphs (c)(1) through (4) of this section. If you use non-uniform fuels as specified in § 60.5520a(d)(2), you may determine CO
2mass emissions during the 
compliance period according to paragraph (c)(5) of this section. 
(1) If you are subject to an output- 
based standard and you do not install CEMS in accordance with paragraph (b) of this section, you must implement the applicable procedures in appendix D to 40 CFR part 75 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 40 CFR part 75 to calculate the hourly CO
2mass emission 
rate (tons/h). You may determine site- specific carbon-based F-factors (Fc) using Equation F–7b in section 3.3.6 of appendix F to 40 CFR part 75, 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 CO
2mass emission 
rate from paragraph (c)(2) of this section by the EGU or stack operating time in hours (as defined in 40 CFR 72.2), to convert it to tons of CO
2. Then, multiply 
the result by 907.2 to convert from tons of CO
2to kg. Round off to the nearest 
two significant figures. 
(4) The hourly CO 2tons/h values and 
EGU (or stack) operating times used to calculate CO
2mass emissions are 
required to be recorded under 40 CFR 75.57(e) and must be reported electronically under 40 CFR 75.64(a)(6). You must use these data to calculate the hourly CO
2mass emissions. 
(5) If you operate a combustion 
turbine firing non-uniform fuels, as an alternative to following paragraphs (c)(1) through (4) of this section, you may determine CO
2emissions during 
the compliance period using one of the following methods: 
(i) Units firing fuel gas may determine 
the heat input during the compliance period following the procedure under § 60.107a(d) and convert this heat input to CO
2emissions using Equation G–4 in 
appendix G to 40 CFR part 75. (ii) You may use the procedure for 
determining CO 2emissions during the 
compliance period based on the use of the Tier 3 methodology under 40 CFR 98.33(a)(3). 
(d) Consistent with § 60.5520a, you 
must determine the basis of the emissions standard that applies to your affected source in accordance with either paragraph (d)(1) or (2) of this section, as applicable: 
(1) If you operate a source subject to 
an emissions standard established on an output basis (e.g., lb CO
2per gross or net 
MWh of energy output), you must install, calibrate, maintain, and operate a sufficient number of watt meters to continuously measure and record the hourly gross electric output or net electric output, as applicable, from the affected EGU(s). These measurements must be performed using 0.2 class electricity metering instrumentation and calibration procedures as specified under ANSI No. C12.20–2010 (incorporated by reference, see § 60.17). For a combined heat and power (CHP) EGU, as defined in § 60.5580a, you must also install, calibrate, maintain, and operate meters to continuously (i.e., hour-by-hour) determine and record the total useful thermal output. For process steam applications, you will need to install, calibrate, maintain, and operate meters to continuously determine and record the hourly steam flow rate, temperature, and pressure. Your plan shall ensure that you install, calibrate, maintain, and operate meters to record each component of the determination, hour-by-hour. 
(2) If you operate a source subject to 
an emissions standard established on a heat-input basis (e.g., lb CO
2/MMBtu) 
and your affected source uses non- uniform heating value fuels as delineated under § 60.5520a(d), you must determine the total heat input for each fuel fired during the compliance period in accordance with one of the following procedures: 
(i) Appendix D to 40 CFR part 75; 
(ii) The procedures for monitoring 
heat input under § 60.107a(d); 
(iii) If you monitor CO
2emissions in 
accordance with the Tier 3 methodology 
under 40 CFR 98.33(a)(3), you may convert your CO
2emissions to heat 
input using the appropriate emission factor in table C–1 of 40 CFR part 98. If your fuel is not listed in table C–1, you must determine a fuel-specific carbon- based F-factor (Fc) in accordance with section 12.3.2 of EPA Method 19 of appendix A–7 to this part, and you must convert your CO
2emissions to heat 
input using Equation G–4 in appendix G to 40 CFR part 75. 
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(e) Consistent with § 60.5520a, 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 and/or direct mechanical energy contributed by each EGU to the electric generator. 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. You may also elect to develop, demonstrate, and provide information satisfactory to the Administrator on alternate methods to apportion the gross or net energy output. The Administrator may approve such alternate methods for apportioning the gross or net energy output whenever the demonstration ensures accurate estimation of emissions regulated under this part. 
(f) In accordance with §§ 60.13(g) and 
60.5520a, 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 you must monitor hourly CO
2 
mass emissions in accordance with one of the following procedures: 
(1) If the EGUs are subject to the same 
emissions standard in table 1 to this subpart, you may monitor the hourly CO
2mass 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 40 CFR 72.2). If you attain compliance with the applicable emissions standard in § 60.5520a at the common stack, each affected EGU sharing the stack is in compliance; or 
(2) As an alternative to the 
requirements in paragraph (f)(1) of this section, or if the EGUs are subject to different emission standards in table 1 to this subpart, you must either: 
(i) Monitor each EGU separately by 
measuring the hourly CO
2mass 
emissions prior to mixing in the common stack or 
(ii) Apportion the CO
2mass emissions 
based on the unit’s load contribution to the total load associated with the common stack and the appropriate F- factors. You may also elect to develop, demonstrate, and provide information satisfactory to the Administrator on alternate methods to apportion the CO
2 
emissions. The Administrator may approve such alternate methods for apportioning the CO
2emissions 
whenever the demonstration ensures 
accurate estimation of emissions regulated under this part. 
(g) In accordance with §§ 60.13(g) and 
60.5520a 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 CO
2mass emissions 
and the ‘‘stack operating time’’ (as defined in 40 CFR 72.2) at each stack or duct separately. In this case, you must determine compliance with the applicable emissions standard in table 1 or 2 to this subpart by summing the CO
2 
mass emissions measured at the individual stacks or ducts and dividing by the total gross or net energy output for the affected EGU. 
§ 60.5540a How do I demonstrate 
compliance with my CO 2emissions 
standard and determine excess emissions? 
(a) In accordance with § 60.5520a, if 
you are subject to an output-based 
emission standard or you burn non- uniform fuels as specified in § 60.5520a(d)(2), you must demonstrate compliance with the applicable CO
2 
emission standard in table 1 to this subpart as required in this section. For the initial and each subsequent 12- operating-month rolling average compliance period, you must follow the procedures in paragraphs (a)(1) through (8) of this section to calculate the CO
2 
mass emissions rate for your affected EGU(s) in units of the applicable emissions standard (e.g., either kg/MWh 
or kg/GJ). You must use the hourly CO
2 
mass emissions calculated under § 60.5535a(b) or (c), as applicable, and either the generating load data from § 60.5535a(d)(1) for output-based calculations or the heat input data from § 60.5535a(d)(2) for heat-input-based calculations. Combustion turbines firing non-uniform fuels that contain CO
2 
prior to combustion (e.g., blast furnace 
gas or landfill gas) may sample the fuel stream to determine the quantity of CO
2 
present in the fuel prior to combustion and exclude this portion of the CO
2 
mass emissions from compliance determinations. 
(1) Each compliance period shall 
include only ‘‘valid operating hours’’ in the compliance period, i.e., operating 
hours for which: 
(i) ‘‘Valid data’’ (as defined in 
§ 60.5580a) are obtained for all of the parameters used to determine the hourly CO
2mass emissions (kg) and, if a heat input-based standard applies, all the 
parameters used to determine total heat input for the hour are also obtained; and 
(ii) The corresponding hourly gross or 
net energy output value is also valid data (Note: For hours with no useful output, zero is considered to be a valid value). 
(2) You must exclude operating hours 
in which: 
(i) The substitute data provisions of 
part 75 of this chapter are applied for 
any of the parameters used to determine the hourly CO
2mass emissions or, if a 
heat input-based standard applies, for any parameters used to determine the hourly heat input; 
(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 CO
2mass emissions or, if applicable, to 
determine the hourly heat input; or 
(iii) The total gross or net energy 
output (P gross/net ) or, if applicable, the 
total heat input is unavailable. 
(3) For each compliance period, at 
least 95 percent of the operating hours in the compliance period must be valid operating hours, as defined in paragraph (a)(1) of this section. 
(4) You must calculate the total CO
2 
mass emissions by summing the valid hourly CO
2mass emissions values from 
§ 60.5535a 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 CO
2mass emissions, 
you must determine P gross/net (the 
corresponding hourly gross or net energy output in MWh) according to the procedures in paragraphs (a)(5)(i) and (ii) of this section, as appropriate for the type of affected EGU(s). For an operating hour in which a valid CO
2mass 
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 CO
2mass 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 P
gross/net for your affected 
EGU using the following equation. All terms in the equation must be expressed in units of MWh. To convert each 
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hourly gross or net energy output 
(consistent with § 60.5520a) value 
reported under part 75 of this chapter to MWh, multiply by the corresponding 
EGU or stack operating time. 
Equation 1 to Paragraph (a)(5)(i) Equation 1 to Paragraph (a)(5)(i) 
Where: 
Pgross/net = In accordance with § 60.5520a, 
gross or net energy output of your 
affected EGU for each valid operating hour (as defined in § 60.5540a(a)(1)) in MWh. 
(Pe)
ST= Electric energy output plus 
mechanical energy output (if any) of steam turbines in MWh. 
(Pe)
CT= Electric energy output plus 
mechanical energy output (if any) of stationary combustion turbine(s) in MWh. 
(Pe)
IE= Electric energy output plus 
mechanical energy output (if any) of your affected EGU’s integrated equipment that provides electricity or mechanical energy to the affected EGU or auxiliary equipment in MWh. 
(Pe)
FW= Electric energy used to power boiler 
feedwater pumps at steam generating 
units in MWh. Not applicable to stationary combustion turbines, IGCC 
EGUs, or EGUs complying with a net energy output based standard. 
(Pe)
A= Electric energy used for any auxiliary 
loads in MWh. Not applicable for determining P
gross. 
(Pt) PS= Useful thermal output of steam 
(measured relative to standard ambient temperature and pressure (SATP) 
conditions, as applicable) that is used for applications that do not generate additional electricity, produce mechanical energy output, or enhance the performance of the affected EGU. This is calculated using the equation specified in paragraph (a)(5)(ii) of this section in MWh. 
(Pt)
HR= Non steam useful thermal output 
(measured relative to SATP conditions, as applicable) from heat recovery that is used for applications other than steam generation or performance enhancement of the affected EGU in MWh. (Pt)
IE= Useful thermal output (relative to 
SATP conditions, as applicable) from 
any integrated equipment is used for applications that do not generate additional steam, electricity, produce mechanical energy output, or enhance the performance of the affected EGU in MWh. 
TDF = Electric Transmission and Distribution 
Factor of 0.95 for a combined heat and power affected EGU where at least on an annual basis 20.0 percent of the total gross or net energy output consists of useful thermal output on a 12-operating- month rolling average basis, or 1.0 for all other affected EGUs. 
(ii) If applicable to your affected EGU 
(for example, for combined heat and 
power), you must calculate (Pt)PS using the following equation: 
Equation 2 to Paragraph (a)(5)(ii) 
Where: 
Qm= Measured useful thermal output flow in 
kg (lb) for the operating hour. 
H = Enthalpy of the useful thermal output at 
measured temperature and pressure 
(relative to SATP conditions or the energy in the condensate return line, as applicable) in Joules per kilogram (J/kg) (or Btu/lb). 
CF = Conversion factor of 3.6 × 10
9J/MWh 
or 3.413 × 106Btu/MWh. 
(6) Sources complying with energy 
output-based standards must calculate 
the basis (i.e., denominator) of their 
actual annual emission rate in accordance with paragraph (a)(6)(i) of this section. Sources complying with heat input based standards must calculate the basis of their actual annual emission rate in accordance with paragraph (a)(6)(ii) of this section. 
(i) In accordance with § 60.5520a if 
you are subject to an output-based standard, you must calculate the total gross or net energy output for the affected EGU’s compliance period by summing the hourly gross or net energy output values for the affected EGU that you determined under paragraph (a)(5) of this section for all of the valid operating hours in the applicable compliance period. 
(ii) If you are subject to a heat input- 
based standard, you must calculate the total heat input for each fuel fired during the compliance period. The calculation of total heat input for each individual fuel must include all valid operating hours and must also be consistent with any fuel-specific procedures specified within your selected monitoring option under § 60.5535(d)(2). 
(7) If you are subject to an output- 
based standard, you must calculate the CO
2mass emissions rate for the affected 
EGU(s) (kg/MWh) by dividing the total CO
2mass emissions value calculated 
according to the procedures in paragraph (a)(4) of this section by the total gross or net energy output value calculated according to the procedures in paragraph (a)(6)(i) of this section. Round off the result to two significant figures if the calculated value is less than 1,000; round the result to three significant figures if the calculated value is greater than 1,000. If you are subject to a heat input-based standard, you must calculate the CO
2mass emissions 
rate for the affected EGU(s) (kg/GJ or lb/ MMBtu) by dividing the total CO
2mass 
emissions value calculated according to the procedures in paragraph (a)(4) of this section by the total heat input calculated according to the procedures in paragraph (a)(6)(ii) of this section. Round off the result to two significant figures. 
(8) You may exclude CO
2mass 
emissions and output generated from your affected EGU from your calculations for hours during which the affected EGU operated during a system emergency, as defined in § 60.5580a, if you can provide the information listed in § 60.5560a(i). While operating during a system emergency, your compliance determination depends on your subcategory or unit type, as listed in paragraphs (a)(8)(i) through (ii) of this section. 
(i) For affected EGUs in the 
intermediate or base load subcategory, your CO
2emission standard while 
operating during a system emergency is the applicable emission standard for low load combustion turbines. 
(ii) For affected modified steam 
generating units, your CO
2emission 
standard while operating during a system emergency is 230 lb CO
2/ 
MMBtu. 
(b) In accordance with § 60.5520a, to 
demonstrate compliance with the applicable CO
2emission standard, for 
the initial and each subsequent 12- operating-month compliance period, the CO
2mass emissions rate for your 
affected EGU must be determined 
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ER09MY24.060</GPH> ER09MY24.061</GPH>ddrumheller on DSK120RN23PROD with RULES3= (Pe)sT+(Pe)cT+(Pe)rn-(Pe)Fw-(Pe)A + [ (Pt)ps + (Pt)HR + (Pt)rn] (Eq. 2) Pgross/net TDF 
(Pt)ps = Q:;H (Eq. 3) 40042 Federal Register / Vol. 89, No. 91 / Thursday, May 9, 2024 / Rules and Regulations 
according to the procedures specified in 
paragraph (a)(1) through (8) of this section and must be less than or equal to the applicable CO
2emissions 
standard in table 1 to this subpart, or the emissions standard calculated in accordance with § 60.5525a(a)(2). 
(c) If you are the owner or operator of 
a new or reconstructed stationary combustion turbine operating in the base load subcategory, are installing add-on controls, and are unable to comply with the applicable Phase 2 CO
2 
emission standard specified in table 1 to this subpart due to circumstances beyond your control, you may request a compliance date extension of no longer than one year beyond the effective date of January 1, 2032, and may only receive an extension once. The extension request must contain a demonstration of necessity that includes the following: 
(1) A demonstration that your affected 
EGU cannot meet its compliance date due to circumstances beyond your control and you have taken all steps reasonably possible to install the controls necessary for compliance by the effective date up to the point of the delay. The demonstration shall: 
(i) Identify each affected unit for 
which you are seeking the compliance extension; 
(ii) Identify and describe the controls 
to be installed at each affected unit to comply with the applicable CO
2 
emission standard in table 1 to this subpart; 
(iii) Describe and demonstrate all 
progress towards installing the controls and that you have acted consistently with achieving timely compliance, including; 
(A) Any and all contract(s) entered 
into for the installation of the identified controls or an explanation as to why no contract is necessary or obtainable; 
(B) Any permit(s) obtained for the 
installation of the identified controls or, where a required permit has not yet been issued, a copy of the permit application submitted to the permitting authority and a statement from the permit authority identifying its anticipated timeframe for issuance of such permit(s). 
(iv) Identify the circumstances that 
are entirely beyond your control and that necessitate additional time to install the identified controls. This may include: 
(A) Information gathered from control 
technology vendors or engineering firms demonstrating that the necessary controls cannot be installed or started up by the applicable compliance date listed in table 1 to this subpart; 
(B) Documentation of any permit 
delays; or (C) Documentation of delays in 
construction or permitting of infrastructure (e.g., CO
2pipelines) that 
is necessary for implementation of the control technology; 
(v) Identify a proposed compliance 
date no later than one year after the applicable compliance date listed in table 1 to this subpart. 
(2) The Administrator is charged with 
approving or disapproving a compliance date extension request based on his or her written determination that your affected EGU has or has not made each of the necessary demonstrations and provided all of the necessary documentation according to paragraph (c)(1) of this section. The following must be included: 
(i) All documentation required as part 
of this extension must be submitted by you to the Administrator no later than 6 months prior to the applicable effective date for your affected EGU. 
(ii) You must notify the Administrator 
of the compliance date extension request at the time of the submission of the request. 
Notification, Reports, and Records 
§ 60.5550a What notifications must I 
submit and when? 
(a) You must prepare and submit the 
notifications specified in §§ 60.7(a)(1) 
and (3) and 60.19, as applicable to your affected EGU(s) (see table 3 to this subpart). 
(b) You must prepare and submit 
notifications specified in 40 CFR 75.61, as applicable, to your affected EGUs. 
§ 60.5555a 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 § 60.5525a 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 CO
2mass 
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 CO
2mass 
emissions rate for the compliance period according to the procedures in § 60.5540a. You must report the dates (month and year) of the first and twelfth operating months in each compliance period for which you performed a CO
2 
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 CO
2emission 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) of this section (i.e., the 
total number of valid operating hours (as defined in § 60.5540a(a)(1)) in that period divided by the total number of operating hours in that period, multiplied by 100 percent); 
(v) Consistent with § 60.5520a, the 
CO
2emissions standard (as identified in 
table 1 or 2 to this subpart) with which your affected EGU must comply; and 
(vi) Consistent with § 60.5520a, an 
indication whether or not the hourly gross or net energy output (P
gross/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 § 60.5520a, gross 
energy output or net energy output sold to an electric grid, as applicable to the units of your emission standard, over the four quarters of the calendar year; and 
(ii) The potential electric output of the 
EGU. 
(b) You must submit all electronic 
reports required under paragraph (a) of this section using the Emissions Collection and Monitoring Plan System (ECMPS) Client Tool provided by the Clean Air Markets Division in the Office of Atmospheric Programs of EPA. 
(c)(1) For affected EGUs under this 
subpart that are also subject to the Acid Rain Program, you must meet all applicable reporting requirements and submit reports as required under subpart G of part 75 of this chapter. 
(2) For affected EGUs under this 
subpart that are not in the Acid Rain Program, you must also meet the reporting requirements and submit 
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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 40 CFR 75.64(a), i.e., beginning with data 
recorded on and after the earlier of: 
(A) The date of provisional 
certification, as defined in 40 CFR 75.20(a)(3); or 
(B) 180 days after the date on which 
the EGU commences commercial operation (as defined in 40 CFR 72.2). 
(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 the date on which reporting is required to begin under 40 CFR 75.64(a), if that date occurs on or after May 23, 2023. 
(iii) For reconstructed or modified 
units, reporting of emissions data shall begin at the date on which the EGU becomes an affected unit under this subpart, provided that the ECMPS Client Tool is able to receive and process net energy output data on that date. Otherwise, emissions data reporting shall be on a gross energy output basis until the date that the Client Tool is first able to receive and process net energy output data. 
(4) If any required monitoring system 
has not been provisionally certified by the applicable date on which emissions data reporting is required to begin under paragraph (c)(3) of this section, the maximum (or in some cases, minimum) potential value for the parameter measured by the monitoring system shall be reported until the required certification testing is successfully completed, in accordance with 40 CFR 75.4(j), 40 CFR 75.37(b), or section 2.4 of appendix D to part 75 of this chapter (as applicable). Operating hours in which CO
2mass 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 
40 CFR 72.20; or 
(2) The person appointed as the 
Alternate Designated Representative (ADR) under 40 CFR 72.22; or 
(3) A person (or persons) authorized 
by the DR or ADR under 40 CFR 72.26 to make the required submissions. 
(e) For affected EGUs that are not 
subject to the Acid Rain Program, the owner or operator shall appoint a DR and (optionally) an ADR to submit the reports required under paragraphs (a) and (c)(2) of this section. The DR and ADR must register with the Clean Air Markets Division (CAMD) Business System. The DR may delegate the authority to make the required submissions to one or more persons. 
(f) If your affected EGU captures CO
2 
to meet the applicable emission 
standard, 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, or subpart VV, if injection occurs on-site; 
(2) Transfer the captured CO
2to a 
facility that reports in accordance with the requirements of 40 CFR part 98, subpart RR, or subpart VV, if injection occurs off-site; or 
(3) Transfer the captured CO
2to a 
facility that has received an innovative technology waiver from EPA pursuant to paragraph (g) of this section. 
(g) Any person may request the 
Administrator to issue a waiver of the requirement that captured CO
2from an 
affected EGU be transferred to a facility reporting under 40 CFR part 98, subpart RR, or subpart VV. To receive a waiver, the applicant must demonstrate to the Administrator that its technology will store captured CO
2as effectively as 
geologic sequestration, and that the proposed technology will not cause or contribute to an unreasonable risk to public health, welfare, or safety. In making this determination, the Administrator shall consider (among other factors) operating history of the technology, whether the technology will increase emissions or other releases of any pollutant other than CO
2, and 
permanence of the CO 2storage. The 
Administrator may test the system, or require the applicant to perform any tests considered by the Administrator to be necessary to show the technology’s effectiveness, safety, and ability to store captured CO
2without release. The 
Administrator may grant conditional approval of a technology, with the approval conditioned on monitoring and reporting of operations. The Administrator may also withdraw approval of the waiver on evidence of 
releases of CO
2or other pollutants. The 
Administrator will provide notice to the public of any application under this provision and provide public notice of any proposed action on a petition before the Administrator takes final action. 
§ 60.5560a 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 40 
CFR 75.53(g) and (h); 
(ii) Operating parameter records 
under 40 CFR 75.57(b)(1) through (4); 
(iii) The records under 40 CFR 
75.57(c)(2), for stack gas volumetric flow rate; 
(iv) The records under 40 CFR 
75.57(c)(3) for continuous moisture monitoring systems; 
(v) The records under 40 CFR 
75.57(e)(1), except for paragraph (e)(1)(x), for CO
2concentration 
monitoring systems or O2 monitors used to calculate CO
2concentration; 
(vi) The records under 40 CFR 
75.58(c)(1), specifically paragraphs (c)(1)(i), (ii), and (viii) through (xiv), for oil flow meters; 
(vii) The records under 40 CFR 
75.58(c)(4), specifically paragraphs (c)(4)(i), (ii), (iv), (v), and (vii) through (xi), for gas flow meters; 
(viii) The quality-assurance records 
under 40 CFR 75.59(a), specifically paragraphs (a)(1) through (12) and (15), for CEMS; 
(ix) The quality-assurance records 
under 40 CFR 75.59(a), specifically 
paragraphs (b)(1) through (4), for fuel flow meters; and 
(x) Records of data acquisition and 
handling system (DAHS) verification under 40 CFR 75.59(e). 
(c) You must keep records of the 
calculations you performed to determine the hourly and total CO
2 
mass emissions (tons) for: 
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(1) Each operating month (for all 
affected EGUs); and 
(2) Each compliance period, 
including, each 12-operating-month 
compliance period. 
(d) Consistent with § 60.5520a, 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 CO
2 
mass emission rates in each compliance period. 
(f) You must keep records of the 
calculations you performed to assess compliance with each applicable CO
2 
mass emissions standard in table 1 or 2 to 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). 
(h) For stationary combustion 
turbines, you must keep records of electric sales to determine the applicable subcategory. 
(i) You must keep the records listed 
in paragraphs (i)(1) through (3) of this section to demonstrate that your affected facility operated during a system emergency. 
(1) Documentation that the system 
emergency to which the affected EGU was responding was in effect from the entity issuing the alert and documentation of the exact duration of the system emergency; 
(2) Documentation from the entity 
issuing the alert that the system emergency included the affected source/ region where the affected facility was located; and 
(3) Documentation that the affected 
facility was instructed to increase output beyond the planned day-ahead or other near-term expected output and/ or was asked to remain in operation outside its scheduled dispatch during emergency conditions from a Reliability Coordinator, Balancing Authority, or Independent System Operator/Regional Transmission Organization. 
§ 60.5565a 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 
5 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. Records 
that are accessible from a central location by a computer or other means that instantly provide access at the site meet this requirement. You may maintain the records off site for the remaining year(s) as required by this subpart. 
Other Requirements and Information 
§ 60.5570a 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. 
§ 60.5575a 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). 
§ 60.5580a 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. Actual and potential heat input derived from non-combustion sources (e.g., solar 
thermal) are not included when calculating the annual capacity factor. Base load combustion turbine means 
a stationary combustion turbine that supplies more than 40 percent of its potential electric output as net-electric sales on both a 12-operating month and a 3-year rolling average basis. 
Base load rating means the maximum 
amount of heat input (fuel) that an EGU can combust on a steady state basis plus the maximum amount of heat input derived from non-combustion source (e.g., solar thermal), as determined by 
the physical design and characteristics of the EGU at International Organization for Standardization (ISO) conditions. For a stationary combustion turbine, base load rating includes the heat input from duct burners. 
Coal means all solid fuels classified as 
anthracite, bituminous, subbituminous, or lignite in ASTM D388–99R04 (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-fired Electric Generating Unit 
means a steam generating unit or integrated gasification combined cycle unit that combusts coal on or after the date of modification or at any point after 
December 31, 2029. 
Combined cycle unit means 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 simultaneously produces both electric (or mechanical) and useful thermal output from the same primary energy source. 
Design efficiency means the rated 
overall net efficiency (e.g., electric plus 
useful thermal output) on a higher heating value basis at the base load rating, at ISO conditions, and at the maximum useful thermal output (e.g., CHP unit with condensing steam turbines would determine the design efficiency at the maximum level of extraction and/or bypass). Design efficiency shall be determined using one of the following methods: ASME PTC 22–2014, ASME PTC 46–1996, ISO 2314:2009 (E) (all incorporated by reference, see § 60.17), or an alternative approved by the Administrator. When determining the design efficiency, the output of integrated equipment and energy storage are included. 
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Distillate oil means fuel oils that 
comply with the specifications for fuel 
oil numbers 1 and 2, as defined in ASTM D396–98 (incorporated by reference, see § 60.17); diesel fuel oil numbers 1 and 2, as defined in ASTM D975–08a (incorporated by reference, see § 60.17); kerosene, as defined in ASTM D3699–08 (incorporated by reference, see § 60.17); biodiesel as defined in ASTM D6751–11b (incorporated by reference, see § 60.17); or biodiesel blends as defined in ASTM D7467–10 (incorporated by reference, see § 60.17). 
Electric Generating units or EGU 
means any steam generating unit, IGCC unit, or stationary combustion turbine 
that is subject to this rule (i.e., meets the 
applicability criteria). 
Fossil fuel means natural gas, 
petroleum, coal, and any form of solid, liquid, or gaseous fuel derived from such material for the purpose of creating useful heat. 
Gaseous fuel means any fuel that is 
present as a gas at ISO conditions and includes, but is not limited to, natural gas, refinery fuel gas, process gas, coke- oven gas, synthetic gas, and gasified coal. 
Gross energy output means: 
(1) For stationary combustion turbines 
and IGCC, the gross electric or direct 
mechanical output from both the EGU (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander(s)) plus 100 percent of the useful thermal output. 
(2) For steam generating units, the 
gross electric or mechanical output from the affected EGU(s) (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander(s)) minus any electricity used to power the feedwater pumps plus 100 percent of the useful thermal output; 
(3) For combined heat and power 
facilities, where at least 20.0 percent of the total gross energy output consists of useful thermal output on a 12-operating- month rolling average basis, the gross electric or mechanical output from the affected EGU (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander(s)) minus any electricity used to power the feedwater pumps (the electric auxiliary load of boiler feedwater pumps is not applicable to IGCC facilities), that difference divided by 0.95, plus 100 percent of the useful thermal output. 
Heat recovery steam generating unit 
(HRSG) means an EGU in which hot exhaust gases from the combustion turbine engine are routed in order to extract heat from the gases and generate useful output. Heat recovery steam generating units can be used with or 
without duct burners. 
Integrated gasification combined 
cycle facility or IGCC means a combined 
cycle facility that is designed to burn fuels containing 50 percent (by heat input) or more solid-derived fuel not meeting the definition of natural gas, plus any integrated equipment that provides electricity or useful thermal output to the affected EGU or auxiliary equipment. The Administrator may waive the 50 percent solid-derived fuel requirement during periods of the gasification system construction, startup and commissioning, shutdown, or repair. No solid fuel is directly burned in the EGU during operation. 
Intermediate load combustion turbine 
means a stationary combustion turbine 
that supplies more than 20 percent but less than or equal to 40 percent of its potential electric output as net-electric sales on both a 12-operating month and a 3-year rolling average basis. 
ISO conditions means 288 Kelvin (15 
°C, 59 °F), 60 percent relative humidity 
and 101.3 kilopascals (14.69 psi, 1 atm) 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. 
Low load combustion turbine means a 
stationary combustion turbine that supplies 20 percent or less of its potential electric output as net-electric sales on both a 12-operating month and a 3-year rolling average basis. 
Mechanical output means the useful 
mechanical energy that is not used to operate the affected EGU(s), generate electricity and/or thermal energy, or to enhance the performance of the affected EGU. Mechanical energy measured in horsepower hour should be converted into MWh by multiplying it by 745.7 then dividing by 1,000,000. 
Natural gas means a fluid mixture of 
hydrocarbons (e.g., methane, ethane, or 
propane), composed of at least 70 percent methane by volume or that has a gross calorific value between 35 and 41 megajoules (MJ) per dry standard cubic meter (950 and 1,100 Btu per dry standard cubic foot), that maintains a gaseous state under ISO conditions. Finally, natural gas does not include the following gaseous fuels: Landfill gas, digester gas, refinery gas, sour gas, blast furnace gas, coal-derived gas, producer gas, coke oven gas, or any gaseous fuel produced in a process which might result in highly variable CO
2content or 
heating value. 
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-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 useful thermal output on a 12-operating month basis, the gross electric sales to the utility power distribution system minus the applicable percentage of purchased power of the thermal host facility or facilities. The applicable percentage of purchase power for CHP facilities is determined based on the percentage of the total thermal load of the host facility supplied to the host facility by the CHP facility. For example, if a CHP facility serves 50 percent of a thermal host’s thermal demand, the owner/operator of the CHP facility would subtract 50 percent of the thermal host’s electric purchased power when calculating net-electric sales. 
(3) Electricity supplied to other 
facilities that produce electricity to offset auxiliary loads are included when calculating net-electric sales. 
(4) Electric sales during a system 
emergency are not included when calculating net-electric sales. 
Net energy output means: 
(1) The net electric or mechanical 
output from the affected EGU plus 100 
percent of the useful thermal output; or 
(2) For combined heat and power 
facilities, where at least 20.0 percent of the total gross or net energy output consists of useful thermal output on a 12-operating-month rolling average basis, the net electric or mechanical output from the affected EGU divided by 0.95, plus 100 percent of the useful thermal output. 
Operating month means a calendar 
month during which any fuel is combusted in the affected EGU at any time. 
Petroleum means crude oil or a fuel 
derived from crude oil, including, but not limited to, distillate and residual oil. 
Potential electric output means the 
base load rating design efficiency at the maximum electric production rate (e.g., CHP units with condensing steam turbines will operate at maximum electric production) multiplied by the base load rating (expressed in MMBtu/ 
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h) of the EGU, multiplied by 106Btu/ 
MMBtu, divided by 3,413 Btu/KWh, 
divided by 1,000 kWh/MWh, and multiplied by 8,760 h/yr (e.g., a 35 
percent efficient affected EGU with a 100 MW (341 MMBtu/h) fossil fuel heat input capacity would have a 306,000 MWh 12-month potential electric output capacity). 
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. 
Standard ambient temperature and 
pressure (SATP) conditions means 298.15 Kelvin (25 °C, 77 °F) and 100.0 
kilopascals (14.504 psi, 0.987 atm) pressure. The enthalpy of water at SATP conditions is 50 Btu/lb. 
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, (e.g., onsite photovoltaics), integrated energy storage (e.g., onsite batteries), heat 
recovery system, or auxiliary equipment. Stationary means that the combustion turbine is not self-propelled or intended to be propelled while performing its function. It may, however, be mounted on a vehicle for portability. A stationary combustion turbine that burns any solid fuel directly is considered a steam generating unit. 
Steam generating unit means any 
furnace, boiler, or other device used for combusting fuel and producing steam (nuclear steam generators are not included) plus any integrated equipment that provides electricity or useful thermal output to the affected EGU(s) or auxiliary equipment. 
System emergency means periods 
when the Reliability Coordinator has declared an Energy Emergency Alert level 2 or 3 as defined by NERC Reliability Standard EOP–011–2 or its successor. 
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 40 CFR 75.20 and appendix A to 40 CFR part 75 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 40 CFR part 75 must be met and the data validation criteria in sections 2.1.5, 2.2.3, and 2.3.2 of appendix B to 40 CFR part 75. For fuel flow meters, the initial certification requirements in section 2.1.5 of appendix D to 40 CFR part 75 must be met before quality-assured data are reported under this subpart (except for qualifying commercial billing meters under section 2.1.4.2 of appendix D to 40 CFR part 75), and for on-going quality assurance, the provisions in section 2.1.6 of appendix D to 40 CFR part 75 apply (except for qualifying commercial billing meters). 
Violation means a specified averaging 
period over which the CO
2emissions 
rate is higher than the applicable emissions standard located in table 1 to this subpart. 
TABLE 1 TOSUBPART TTTT AO F PART60—CO 2EMISSION STANDARDS FOR AFFECTED STATIONARY COMBUSTION TUR-
BINES THAT COMMENCED CONSTRUCTION OR RECONSTRUCTION AFTER MAY23, 2023 (G ROSS OR NETENERGY  
OUTPUT -BASED STANDARDS APPLICABLE AS APPROVED BY THE ADMINISTRATOR ) 
[Note: Numerical values of 1,000 or greater have a minimum of 3 significant figures and numerical values of less than 1,000 have a minimum of 
2 significant figures] 
Affected EGU category CO 2emission standard 
Base load combustion turbines ........................... For 12-operating month averages beginning before January 2032, 360 to 560 kg CO 2/MWh 
(800 to 1,250 lb CO 2/MWh) of gross energy output; or 370 to 570 kg CO 2/MWh (820 to 
1,280 lb CO 2/MWh) of net energy output as determined by the procedures in § 60.5525a. 
For 12-operating month averages beginning after December 2031, 43 to 67 kg CO 2/MWh (100 
to 150 lb CO 2/MWh) of gross energy output; or 42 to 64 kg CO 2/MWh (97 to 139 lb CO 2/ 
MWh) of net energy output as determined by the procedures in § 60.5525a. 
Intermediate load combustion turbines ............... 530 to 710 kg CO 2/MWh (1,170 to 1,560 lb CO 2/MWh) of gross energy output; or 540 to 700 
kg CO 2/MWh (1,190 to 1,590 lb CO 2/MWh) of net energy output as determined by the pro-
cedures in § 60.5525a. 
Low load combustion turbines ............................ Between 50 to 69 kg CO 2/GJ (120 to 160 lb CO 2/MMBtu) of heat input as determined by the 
procedures in § 60.5525a. 
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TABLE 2 TOSUBPART TTTT AO F PART60—CO 2EMISSION STANDARDS FOR AFFECTED STEAM GENERATING UNITS OR  
IGCC T HATCOMMENCED MODIFICATION AFTER MAY23, 2023 
Affected EGU CO 2Emission standard 
Modified coal-fired steam gener-
ating unit.A unit-specific emissions standard determined by an 88.4 percent reduction in the unit’s best historical an-
nual CO 2emission rate (from 2002 to the date of the modification). 
TABLE 3 TOSUBPART TTTT AO F PART60—A PPLICABILITY OF SUBPART A OFPART60 (G ENERAL PROVISIONS ) TO 
SUBPART TTTT A 
General provisions citation Subject of citation Applies to subpart TTTTa Explanation 
§ 60.1 ................................... Applicability ........................ Yes. 
§ 60.2 ................................... Definitions .......................... Yes .................................... Additional terms defined in § 60.5580a. 
§ 60.3 ................................... Units and Abbreviations .... Yes. 
§ 60.4 ................................... Address ............................. Yes .................................... Does not apply to information reported electronically 
through ECMPS. Duplicate submittals are not re-
quired. 
§ 60.5 ................................... Determination of construc-
tion or modification.Yes. 
§ 60.6 ................................... Review of plans ................. Yes. 
§ 60.7 ................................... Notification and Record-
keeping.Yes .................................... Only the requirements to submit the notifications in 
§ 60.7(a)(1) and (3) and to keep records of malfunc-tions in § 60.7(b), if applicable. 
§ 60.8(a) ............................... Performance tests ............. No..
§ 60.8(b) ............................... Performance test method 
alternatives.Yes .................................... Administrator can approve alternate methods. 
§ 60.8(c)–(f) .......................... Conducting performance 
tests.No..
§ 60.9 ................................... Availability of Information .. Yes. 
§ 60.10 ................................. State authority ................... Yes. 
§ 60.11 ................................. Compliance with standards 
and maintenance re-quirements.No..
§ 60.12 ................................. Circumvention .................... Yes. 
§ 60.13 (a)–(h), (j) ................ Monitoring requirements .... No ...................................... All monitoring is done according to part 75. 
§ 60.13 (i) ............................. Monitoring requirements .... Yes .................................... Administrator can appr ove alternative monitoring pro-
cedures or requirements. 
§ 60.14 ................................. Modification ....................... Yes (steam generating 
units and IGCC facilities) No (stationary combus-tion turbines)..
§ 60.15 ................................. Reconstruction ................... Yes. 
§ 60.16 ................................. Priority list .......................... No..
§ 60.17 ................................. Incorporations by reference Yes. 
§ 60.18 ................................. General control device re-
quirements.No..
§ 60.19 ................................. General notification and re-
porting requirements.Yes .................................... Does not apply to notifications under § 75.61 or to in-
formation reported through ECMPS. 
Subpart UUUUa—[Reserved] 
■16. Remove and reserve subpart 
UUUUa. 
■17. Add subpart UUUUb to read as 
follows: 
Sec. 
Subpart UUUUb—Emission Guidelines for 
Greenhouse Gas Emissions for Electric Utility Generating Units 
Introduction 60.5700b What is the purpose of this 
subpart? 
60.5705b Which pollutants are regulated by 
this subpart? 
60.5710b Am I affected by this subpart? 
60.5715b What is the review and approval 
process for my State plan? 60.5720b What if I do not submit a State 
plan or my State plan is not approvable? 
60.5725b In lieu of a State plan submittal, 
are there other acceptable option(s) for a 
State to meet its CAA section 111(d) obligations? 
60.5730b Is there an approval process for a 
negative declaration letter? 
State Plan Requirements 
60.5740b What must I include in my 
federally enforceable State plan? 
60.5775b What standards of performance 
must I include in my State plan? 
60.5780b What compliance dates and 
compliance periods must I include in my 
State plan? 
60.5785b What are the timing requirements 
for submitting my State plan? 
60.5790b What is the procedure for revising 
my State plan? 60.5795b Commitment to review emission 
guidelines for coal-fired affected EGUs 
Applicability of State Plans to Affected EGUs 
60.5840b Does this subpart directly affect 
EGU owners or operators in my State? 
60.5845b What affected EGUs must I 
address in my State plan? 
60.5850b What EGUs are excluded from 
being affected EGUs? 
Recordkeeping and Reporting Requirements 60.5860b What applicable monitoring, 
recordkeeping, and reporting 
requirements do I need to include in my State plan for affected EGUs? 
60.5865b What are my recordkeeping 
requirements? 
60.5870b What are my reporting and 
notification requirements? 
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60.5875b How do I submit information 
required by these emission guidelines to 
the EPA? 
60.5876b What are the recordkeeping and 
reporting requirements for EGUs that have committed to permanently cease operations by January 1, 2032? 
Definitions 
60.5880b What definitions apply to this 
subpart? 
Subpart UUUUb—Emission Guidelines 
for Greenhouse Gas Emissions for Electric Utility Generating Units 
Introduction 
§ 60.5700b What is the purpose of this 
subpart? 
This subpart establishes emission 
guidelines and approval criteria for 
State plans that establish standards of performance limiting greenhouse gas (GHG) emissions from an affected steam generating unit. An affected steam generating unit shall, for the purposes of this subpart, be referred to as an affected EGU. These emission guidelines are developed in accordance with section 111(d) of the Clean Air Act and subpart Ba of this part. State plans under the emission guidelines in this subpart are also subject to the requirements of subpart Ba. To the extent any requirement of this subpart is inconsistent with the requirements of subparts A or Ba of this part, the requirements of this subpart shall apply. 
§ 60.5705b Which pollutants are regulated 
by this subpart? 
(a) The pollutants regulated by this 
subpart are greenhouse gases (GHG). 
The emission guidelines for greenhouse gases established in this subpart are expressed as carbon dioxide (CO
2) 
emission performance rates. 
(b) PSD and Title V Thresholds for 
Greenhouse Gases. 
(1) For the purposes of 40 
CFR 51.166(b)(49)(ii), with respect to GHG emissions from facilities regulated in the State plan, the ‘‘pollutant that is subject to the standard promulgated under section 111 of the Act’’ shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in 40 CFR 51.166(b)(48) and in any State Implementation Plan (SIP) approved by the EPA that is interpreted to incorporate, or specifically incorporates, 40 CFR 51.166(b)(48). 
(2) For the purposes of 40 
CFR 52.21(b)(50)(ii), with respect to GHG emissions from facilities regulated in the State plan, the ‘‘pollutant that is subject to the standard promulgated under section 111 of the Act’’ shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in 40 CFR 52.21(b)(49). 
(3) For the purposes of 40 CFR 70.2, 
with respect to greenhouse gas emissions from facilities regulated in the State plan, the ‘‘pollutant that is subject to any standard promulgated under section 111 of the Act’’ shall be considered to be the pollutant that otherwise is ‘‘subject to regulation’’ as defined in 40 CFR 70.2. 
(4) For the purposes of 40 CFR 71.2, 
with respect to GHG emissions from facilities regulated in the State plan, the ‘‘pollutant that is subject to any standard promulgated under section 111 of the Act’’ shall be considered to be the pollutant that otherwise is ‘‘subject to regulation’’ as defined in 40 CFR 71.2. 
§ 60.5710b Am I affected by this subpart? 
(a) If you are the Governor of a State 
in the contiguous United States with one or more affected EGUs that must be addressed in your State plan as indicated in § 60.5845b, you must submit a State plan to the U.S. Environmental Protection Agency (EPA) that implements the emission guidelines contained in this subpart. If you are the Governor of a State in the contiguous United States with no affected EGUs, or if all EGUs in your State are excluded from being affected EGUs per § 60.5850b, you must submit a negative declaration letter in place of the State plan. 
(b) If you are a coal-fired steam 
generating unit that has demonstrated that it plans to permanently cease operation prior to January 1, 2032, consistent with § 60.5740b(a)(9)(ii), and that would be an affected EGU under these emissions guidelines but for § 60.5850b(k), you must comply with § 60.5876b. 
§ 60.5715b What is the review and 
approval process for my State plan? 
(a) The EPA will determine the 
completeness of your State plan 
submission according to § 60.27a(g). The timeline for completeness determinations is provided in § 60.27a(g)(1). 
(b) The EPA will act on your State 
plan submission according to § 60.27a. The Administrator will have 12 months after the date the final State plan or State plan revision (as allowed under § 60.5790b) is found to be complete to fully approve, partially approve, conditionally approve, partially disapprove, and/or fully disapprove such State plan or revision or each portion thereof. § 60.5720b What if I do not submit a State 
plan or my State plan is not approvable? 
(a) If you do not submit an approvable 
State plan the EPA will develop a 
Federal plan for your State according to § 60.27a. The Federal plan will implement the emission guidelines contained in this subpart. Owners and operators of affected EGUs not covered by an approved State plan must comply with a Federal plan implemented by the EPA for the State. 
(b) After a Federal plan has been 
implemented in your State, it will be withdrawn when your State submits, and the EPA approves, a State plan replacing the relevant portion(s) of the Federal plan. 
§ 60.5725b In lieu of a State plan 
submittal, are there other acceptable option(s) for a State to meet its CAA section 111(d) obligations? 
A State may meet its CAA section 
111(d) obligations only by submitting a 
State plan or a negative declaration letter (if applicable). 
§ 60.5730b Is there an approval process 
for a negative declaration letter? 
No. The EPA has no formal review 
process for negative declaration letters. 
Once your negative declaration letter has been received, consistent with the electronic submission requirements in § 60.5875b, the EPA will place a copy in the public docket and publish a notice in the Federal Register. If, at a later date, an affected EGU for which construction commenced on or before January 8, 2014, reconstruction on or before June 18, 2014, or modification on or before May 23, 2023, is found in your State, you will be found to have failed to submit a State plan as required, and a Federal plan implementing the emission guidelines contained in this subpart, when promulgated by the EPA, will apply to that affected EGU until you submit, and the EPA approves, a State plan. 
State Plan Requirements 
§ 60.5740b What must I include in my 
federally enforceable State plan? 
(a) You must include the components 
described in paragraphs (a)(1) through 
(13) of this section in your State plan submittal. The final State plan must meet the requirements and include the information required under § 60.5775b and must also meet any administrative and technical completeness criteria listed in § 60.27a(g)(2) and (3) that are not otherwise specifically enumerated here. 
(1) Identification of affected EGUs. 
Consistent with § 60.25a(a), you must identify the affected EGUs covered by 
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your State plan and all affected EGUs in 
your State that meet the applicability criteria in § 60.5845b. You must also identify the subcategory into which you have classified each affected EGU. States must subcategorize affected EGUs into one of the following subcategories: 
(i) Long-term coal-fired steam 
generating units, consisting of coal-fired steam generating units that are not medium-term coal-fired steam generating units and do not plan to permanently cease operation before January 1, 2039. 
(ii) Medium-term coal-fired steam 
generating units, consisting of coal-fired steam generating units that have elected to commit to permanently cease operations by a date after December 31, 2031, and before January 1, 2039. 
(iii) Base load oil-fired steam 
generating units, consisting of oil-fired steam generating units with an annual capacity factor greater than or equal to 45 percent. 
(iv) Intermediate load oil-fired steam 
generating units, consisting of oil-fired steam generating units with an annual capacity factor greater than or equal to 8 percent and less than 45 percent. 
(v) Low load oil-fired steam 
generating units, consisting of oil-fired steam generating units with an annual capacity factor less than 8 percent. 
(vi) Base load natural gas-fired steam 
generating units, consisting of natural gas-fired steam generating units with an annual capacity factor greater than or equal to 45 percent. 
(vii) Intermediate load natural gas- 
fired steam generating units, consisting of natural gas-fired steam generating units with an annual capacity factor greater than or equal to 8 percent and less than 45 percent. 
(viii) Low load natural gas-fired steam 
generating units, consisting of natural gas-fired steam generating units with an annual capacity factor less than 8 percent. 
(2) Inventory of Data from Affected 
EGUs. You must include an inventory of 
the following data from the affected EGUs: 
(i) The nameplate capacity of the 
affected EGU, as defined in § 60.5880b. 
(ii) The base load rating of the affected 
EGU, as defined in § 60.5880b. 
(iii) The data within the continuous 5- 
year period immediately prior to May 9, 2024 including: 
(A) The sum of the CO
2emissions 
during each quarter in the 5-year period. 
(B) For affected EGUs in all 
subcategories except the low load natural gas- and oil-fired subcategories, the sum of the gross energy output during each quarter in the 5-year period; for affected EGUs in the low load natural gas- and oil-fired subcategories, 
the sum of the heat input during each quarter in the 5-year period. 
(C) The heat input for each fuel type 
combusted during each quarter in the 5- year period. 
(D) The start date and end date of the 
most representative continuous 8- quarter period used to determine the baseline of emission performance under § 60.5775b(d), the sum of the CO
2mass 
emissions during that period, the sum of 
the gross energy output or, for affected EGUs in the low load natural gas-fired subcategory or low load oil-fired subcategory, the sum of the heat input during that period, and sum of the heat input for each fuel type combusted during that period. 
(3) Standards of Performance. You 
must include all standards of performance for each affected EGU according to § 60.5775b. Standards of performance must be established at a level of performance that does not exceed the level calculated through the use of the methods described in § 60.5775b(b), unless a State establishes a standard of performance pursuant to § 60.5775b(e). 
(4) Requirements related to 
Subcategory Applicability. (i) You must include the following enforceable requirements to establish an affected EGU’s applicability for each of the following subcategories: 
(A) For medium-term coal-fired steam 
generating units, you must include a requirement to permanently cease operations by a date after December 31, 2031, and before January 1, 2039. 
(B) For steam generating units that 
meet the definition of natural gas- or oil- fired, and that either retain the capability to fire coal after May 9, 2024, that fired any coal during the 5-year period prior to that date, or that will fire any coal after that date and before January 1, 2030, you must include a requirement to remove the capability to fire coal before January 1, 2030. 
(C) For each affected EGU, you must 
also estimate coal, oil, and natural gas usage by heat input for the first 3 calendar years after January 1, 2030. 
(D) For affected EGUs that plan to 
permanently cease operation, you must include a requirement that each such affected EGU comply with applicable State and Federal requirements for permanently ceasing operation, including removal from its respective State’s air emissions inventory and amending or revoking all applicable permits to reflect the permanent shutdown status of the EGU. 
(5) Increments of Progress. You must 
include in your State plan legally enforceable increments of progress as required elements for affected EGUs in 
the long-term coal-fired steam generating unit and medium-term coal- fired steam generating unit subcategories. 
(i) For affected EGUs in the long-term 
coal-fired steam generating unit subcategory using carbon capture to meet their applicable standard of performance and affected EGUs in the 
medium-term coal-fired steam generating unit subcategory using natural gas co-firing to meet their applicable standard of performance, State plans must assign calendar-date deadlines to each of the increments of progress described in subsection (a)(5)(i) and meet the website reporting obligations of subsection (a)(5)(iii): 
(A) Submittal of a final control plan 
for the affected EGU to the appropriate air pollution control agency. The final control plan must be consistent with the subcategory declaration for each affected EGU in the State plan. 
(1) For each affected unit in the long- 
term coal-fired steam generating unit subcategory, the final control plan must include supporting analysis for the affected EGU’s control strategy, including a feasibility and/or front-end engineering and design (FEED) study. 
(2) For each affected unit in the 
medium-term coal-fired steam generating unit subcategory, the final control plan must include supporting analysis for the affected EGU’s control strategy, including the design basis for modifications at the facility, the anticipated timeline to achieve full compliance, and the benchmarks the facility anticipates along the way. 
(B) Completion of awarding of 
contracts. The owner or operator of an affected EGU can demonstrate compliance with this increment of progress by submitting sufficient evidence that the appropriate contracts have been awarded. 
(1) For each affected unit in the long- 
term coal-fired steam generating unit subcategory, awarding of contracts for emission control systems or for process modifications, or issuance of orders for the purchase of component parts to accomplish emission control or process modification. 
(2) For each affected unit in the 
medium-term coal-fired steam generating unit subcategory, awarding of contracts for boiler modifications, or issuance of orders for the purchase of component parts to accomplish boiler modifications. 
(C) Initiation of on-site construction 
or installation of emission control equipment or process change. 
(1) For each affected unit in the long- 
term coal-fired steam generating unit 
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subcategory, initiation of on-site 
construction or installation of emission control equipment or process change required to achieve 90 percent carbon capture on an annual basis. 
(2) For each affected unit in the 
medium-term coal-fired steam generating unit subcategory, initiation of on-site construction or installation of any boiler modifications necessary to enable natural gas co-firing at a level of 40 percent on an annual average basis. 
(D) Completion of on-site construction 
or installation of emission control equipment or process change. 
(1) For each affected unit in the long- 
term coal-fired steam generating unit subcategory, completion of on-site construction or installation of emission control equipment or process change 
required to achieve 90 percent carbon capture on an annual basis. 
(2) For each affected unit in the 
medium-term coal-fired steam generating unit subcategory, completion of on-site construction of any boiler modifications necessary to enable natural gas co-firing at a level of 40 percent on an annual average basis. 
(E) Commencement of permitting 
actions related to pipeline construction. The owner or operator of an affected EGU must demonstrate that they have commenced permitting actions by a date specified in the State plan. Evidence in support of the demonstration must include pipeline planning and design documentation that informed the permitting process, a complete list of pipeline-related permitting applications, including the nature of the permit sought and the authority to which each permit application was submitted, an attestation that the list of pipeline- related permits is complete with respect to the authorizations required to operate each affected unit at full compliance with the standard of performance, and a timeline to complete all pipeline permitting activities. 
(1) For affected units in the long-term 
coal-fired steam generating unit subcategory, this increment of progress applies to each affected EGU that adopts CCS to meet the standard of performance and ensure timely completion of CCS-related pipeline infrastructure. 
(2) For affected units in the medium- 
term coal-fired steam generating unit subcategory, this increment of progress applies to each affected EGU that adopts natural gas co-firing to meet the standard of performance and ensures timely completion of any pipeline infrastructure needed to transport natural gas to designated facilities. 
(F) For each affected unit in the long- 
term coal-fired steam generating unit subcategory, a report identifying the 
geographic location where CO
2will be 
injected underground, how the CO 2will 
be transported from the capture location to the storage location, and the regulatory requirements associated with the sequestration activities, as well as an anticipated timeline for completing related permitting activities. 
(G) Compliance with the standard of 
performance as follows: 
(1) For each affected unit in the 
medium-term coal-fired subcategory, by 
January 1, 2030. 
(2) For each affected unit in the long- 
term coal-fired steam generating subcategory, by January 1, 2032. 
(ii) For any affected unit in the long- 
term coal-fired steam generating unit subcategory that will meet its applicable standard of performance using a control other than CCS or in the medium-term coal-fired steam generating unit subcategory that will meet its applicable standard of performance using a control other than natural gas co-firing: 
(A) The State plan must include 
appropriate increments of progress consistent with 40 CFR 60.21a(h) specific to the affected unit’s control strategy. 
(1) The increment of progress 
corresponding to 40 CFR 60.21a(h)(1) must be assigned the earliest calendar date among the increments. 
(2) The increment of progress 
corresponding to 40 CFR 60.21a(h)(5) must be assigned calendar dates as follows: for affected EGUs in the long- term coal-fired steam generating subcategory, no later than January 1, 2032; and for affected EGUs in the medium-term coal-fired steam generating subcategory, no later than January 1, 2030. 
(iii) The owner or operator of the 
affected EGU must post within 30 business days of the State plan submittal a description of the activities or actions that constitute the increments of progress and the schedule for achieving the increments of progress on the Carbon Pollution Standards for EGUs website required by § 60.5740b(a)(10). As the calendar dates for each increment of progress occurs, the owner or operator of the affected EGU must post within 30 business days any documentation necessary to demonstrate that each increment of progress has been met on the Carbon Pollution Standards for EGUs website required by § 60.5740b(a)(10). 
(iv) You must include in your State 
plan a requirement that the owner or operator of each affected EGU shall report to the State regulatory agency any deviation from any federally enforceable State plan increment of progress within 30 business days after the owner or 
operator of the affected EGU knew or should have known of the event. This report must explain the cause or causes of the deviation and describe all measures taken or to be taken by the owner or operator of the EGU to cure the reported deviation and to prevent such deviations in the future, including the timeframes in which the owner or operator intends to cure the deviation. You must also include in your State plan a requirement that the owner or operator of the affected EGU to post a report of any deviation from any federally enforceable increment of progress on the Carbon Pollution Standards for EGUs website required by § 60.5740b(a)(10) within 30 business days. 
(6) Reporting Obligations and 
Milestones for Affected EGUs that Have Demonstrated They Plan to Permanently Cease Operations. You must include in your State plan legally enforceable reporting obligations and milestones for affected EGUs in the medium-term coal- fired steam generating unit (§ 60.5740b(a)(1)(ii)) subcategory, and for affected EGUs that invoke RULOF based on a unit’s remaining useful life according to paragraphs (a)(6)(i) through (v) of this section: 
(i) Five years before the date the 
affected EGU permanently ceases operations (either the date used to determine the applicable subcategory under these emission guidelines or the date used to invoke RULOF based on remaining useful life) or 60 days after State plan submission, whichever is later, the owner or operator of the affected EGU must submit an Initial 
Milestone Report to the applicable air pollution control agency that includes the information in paragraphs (a)(6)(i)(A) through (D) of this section: 
(A) A summary of the process steps 
required for the affected EGU to permanently cease operations by the date included in the State plan, including the approximate timing and duration of each step and any notification requirements associated with deactivation of the unit. 
(B) A list of key milestones that will 
be used to assess whether each process step has been met, and calendar day deadlines for each milestone. These milestones must include at least the initial notice to the relevant reliability authority or authorities of an EGU’s deactivation date and submittal of an official retirement filing with the EGU’s relevant reliability authority or authorities. 
(C) An analysis of how the process 
steps, milestones, and associated timelines included in the Milestone 
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Report compare to the timelines of 
similar EGUs within the State that have permanently ceased operations within the 10 years prior to the date of promulgation of these emission guidelines. 
(D) Supporting regulatory documents, 
which include those listed in paragraphs (a)(6)(i)(D)(1) through (3) of this section: 
(1) Any correspondence and official 
filings with the relevant Regional Transmission Organization (RTO), Independent System Operator, Balancing Authority, Public Utilities Commission (PUC), or other applicable authority; 
(2) Any deactivation-related reliability 
assessments conducted by the RTO or Independent System Operator; 
(3) Any filings with the United States 
Securities and Exchange Commission or notices to investors, including but not limited to, those listed in paragraphs (a)(6)(i)(D)(3)(i) through (v) of this section. 
(i) References in forms 10–K and 10– 
Q, in which the plans for the EGU are mentioned; 
(ii) Any integrated resource plans and 
PUC orders approving the EGU’s deactivation; 
(iii) Any reliability analyses 
developed by the RTO, Independent System Operator, or relevant reliability authority in response to the EGU’s deactivation notification; 
(iv) Any notification from a relevant 
reliability authority that the EGU may be needed for reliability purposes notwithstanding the EGU’s intent to deactivate; and 
(v) Any notification to or from an 
RTO, Independent System Operator, or Balancing Authority altering the timing of deactivation for the EGU. 
(ii) For each of the remaining years 
prior to the date by which an affected EGU has committed to permanently cease operations that is included in the State plan, the owner or operator of the affected EGU must submit an annual Milestone Status Report that includes the information in paragraphs (a)(6)(ii)(A) and (B) of this section: 
(A) Progress toward meeting all 
milestones identified in the Initial Milestone Report, described in § 60.5740b(a)(6)(i); and 
(B) Supporting regulatory documents 
and relevant SEC filings, including correspondence and official filings with the relevant RTO, Independent System Operator, Balancing Authority, PUC, or other applicable authority to demonstrate compliance with or progress toward all milestones. 
(iii) No later than six months from the 
date the affected EGU permanently ceases operations (either the date used to determine the applicable subcategory under these emission guidelines or the date used to invoke RULOF based on remaining useful life), the owner or operator of the affected EGU must submit a Final Milestone Status Report. This report must document any actions that the EGU has taken subsequent to ceasing operation to ensure that such cessation is permanent, including any regulatory filings with applicable authorities or decommissioning plans. 
(iv) The owner or operator of the 
affected EGU must post their Initial Milestone Report, as described in paragraph (a)(6)(i) of this section; annual Milestone Status Reports, as described in paragraph (a)(6)(ii) of this section; and Final Milestone Status Report, as described in paragraph (a)(6)(iii) of this section; including the schedule for achieving milestones and any documentation necessary to demonstrate that milestones have been achieved, on the Carbon Pollution Standards for EGUs website required by paragraph (a)(10) of this section within 30 business days of being filed. 
(v) You must include in your State 
plan a requirement that the owner or operator of each affected EGU shall report to the State regulatory agency any deviation from any federally enforceable State plan reporting milestone within 30 business days after the owner or operator of the affected EGU knew or should have known of the event. This report must explain the cause or causes of the deviation and describe all measures taken or to be taken by the owner or operator of the EGU to cure the reported deviation and to prevent such deviations in the future, including the timeframes in which the owner or operator intends to cure the deviation. You must also include in your State plan a requirement that the owner or operator of the affected EGU to post a report of any deviation from any federally enforceable reporting milestone on the Carbon Pollution Standards for EGUs website required by § 60.5740b(a)(10) within 30 business days. 
(7) Identification of applicable 
monitoring, reporting, and recordkeeping requirements for each affected EGU. You must include in your State plan all applicable monitoring, reporting and recordkeeping requirements, including initial and ongoing quality assurance and quality control procedures, for each affected EGU and the requirements must be consistent with or no less stringent than the requirements specified in § 60.5860b. (8) State reporting. You must include 
in your State plan a description of the 
process, contents, and schedule for State reporting to the EPA about State plan implementation and progress. 
(9) Specific requirements for existing 
coal-fired steam generating EGUs. Your State plan must include the requirements in paragraphs (a)(9)(i) through (iii) of this section specifically for existing coal-fired steam generating EGUs: 
(i) Your State plan must require that 
any existing coal-fired steam-generating EGU shall operate only subject to a standard of performance pursuant to § 60.5775b or under an exemption of applicability provided under § 60.5850b (including any extension of the date by which an EGU has committed to cease operating pursuant to the reliability assurance mechanism, described in paragraph (a)(13) of this section). 
(ii) You must include a list of the 
coal-fired steam generating EGUs that are existing sources at the time of State plan submission and that plan to permanently cease operation before January 1, 2032, and the calendar dates by which they have committed to cease operating. 
(iii) The State plan must provide that 
an existing coal-fired steam generating EGU operating past the date listed in the State plan pursuant to paragraph (a)(9)(ii) of this section is in violation of that State plan, except to the extent the existing coal-fired steam generating EGU has received an extension of its date for ceasing operation pursuant to the reliability assurance mechanism, described in paragraph (a)(13) of this section. 
(10) Carbon Pollution Standards for 
EGUs Websites. You must require in your State plan that owners or operators 
of affected EGUs establish a publicly accessible ‘‘Carbon Pollution Standards for EGUs Website’’ and that they post relevant documents to this website. You must require in your State plan that owners or operators of affected EGUs post their subcategory designations and compliance schedules as well as any emissions data and other information needed to demonstrate compliance with a standard of performance to this website in a timely manner. This information includes, but is not limited to, emissions data and other information relevant to determining compliance with applicable standards of performance, information relevant to the designation and determination of compliance with increments of progress and reporting obligations including milestones for affected EGUs that plan to permanently cease operations, and any extension requests made and 
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granted pursuant to the compliance date 
extension mechanism or the reliability assurance mechanism. Data should be available in a readily downloadable format. In addition, you must establish a website that displays the links to these websites for all affected EGUs in your State plan. 
(11) Compliance Date Extension. You 
may include in your State plan provisions allowing for a compliance date extension for owners or operators of affected EGU(s) that are installing add-on controls and that are unable to meet the applicable standard of performance by the compliance date specified in § 60.5740b(a)(4)(i) due to circumstances beyond the owner or 
operator’s control. Such provisions may allow an owner or operator of an affected EGU to request an extension of no longer than one year from the specified compliance date and may only allow the owner or operator to receive an extension once. The optional State plan mechanism must provide that an extension request contains a demonstration of necessity that includes the following: 
(i) A demonstration that the owner or 
operator of the affected EGU cannot meet its compliance date due to circumstances beyond the owner or operator’s control and that the owner or operator has met all relevant increments of progress and otherwise taken all steps reasonably possible to install the controls necessary for compliance by the specified compliance date up to the point of the delay. The demonstration shall: 
(A) Identify each affected unit for 
which the owner or operator is seeking the compliance extension; 
(B) Identify and describe the controls 
to be installed at each affected unit to comply with the applicable standard of performance pursuant to § 60.5775b; 
(C) Describe and demonstrate all 
progress towards installing the controls and that the owner or operator has itself acted consistent with achieving timely compliance, including: 
(1) Any and all contract(s) entered 
into for the installation of the identified controls or an explanation as to why no contract is necessary or obtainable; and 
(2) Any permit(s) obtained for the 
installation of the identified controls or, where a required permit has not yet been issued, a copy of the permit application submitted to the permitting authority and a statement from the permit authority identifying its anticipated timeframe for issuance of such permit(s). 
(D) Identify the circumstances that are 
entirely beyond the owner or operator’s control and that necessitate additional time to install the identified controls. This may include: 
(1) Information gathered from control 
technology vendors or engineering firms demonstrating that the necessary controls cannot be installed or started up by the applicable compliance date listed in § 60.5740b(a)(4)(i); 
(2) Documentation of any permit 
delays; or 
(3) Documentation of delays in 
construction or permitting of infrastructure (e.g., CO
2pipelines) that 
is necessary for implementation of the control technology; 
(E) Identify a proposed compliance 
date no later than one year after the applicable compliance date listed in § 60.5740b(a)(4)(i) and, if necessary, updated calendar dates for the increments of progress that have not yet been met. 
(ii) The State air pollution control 
agency is charged with approving or disapproving a compliance date extension request based on its written determination that the affected EGU has or has not made each of the necessary demonstrations and provided all of the necessary documentation according to paragraphs (a)(11)(i)(A) through (E) of this section. The following provisions for approval must be included in the mechanism: 
(A) All documentation required as 
part of this extension must be submitted by the owner or operator of the affected EGU to the State air pollution control agency no later than 6 months prior to the applicable compliance date for that affected EGU. 
(B) The owner or operator of the 
affected EGU must notify the relevant EPA Regional Administrator of their compliance date extension request at the time of the submission of the request. 
(C) The owner or operator of the 
affected EGU must post their application for the compliance date extension request to the Carbon Pollution Standards for EGUs website, described in § 60.5740b(a)(10), when they submit the request to the State air pollution control agency. 
(D) The owner or operator of the 
affected EGU must post the State’s determination on the compliance date extension request to the Carbon Pollution Standards for EGUs website, described in § 60.5740b(a)(10), upon receipt of the determination and, if the request is approved, update the information on the website related to the compliance date and increments of progress dates within 30 days of the receipt of the State’s approval. 
(12) Short-Term Reliability 
Mechanism. You may include in your State plan provisions for a short-term 
reliability mechanism for affected EGUs in your State that operate during a system emergency, as defined in § 60.5880b. Such a mechanism must include the components listed in paragraphs (a)(12)(i) through (vi) of this section. 
(i) A requirement that the short-term 
reliability mechanism is available only during system emergencies as defined in § 60.5880b. The State plan must identify the entity or entities that are authorized to issue system emergencies for the State. 
(ii) A provision that, for the duration 
of a documented system emergency, an impacted affected EGU may comply with an emission limitation 
corresponding to its baseline emission performance rate, as calculated under § 60.5775b(d), in lieu of its otherwise applicable standard of performance. The State plan must clearly identify the alternative emission limitation that corresponds to the affected EGU’s baseline emission rate and include it as an enforceable emission limitation that may be applied only during periods of system emergency. 
(iii) A requirement that an affected 
EGU impacted by the system emergency and complying with an alternative emission limitation must provide documentation, as part of its compliance demonstration, of the system emergency according to (a)(12)(iii)(A) through (D) of this section and that it was impacted by that system emergency. 
(A) Documentation that the system 
emergency was in effect from the entity issuing the system emergency and documentation of the exact duration of the event; 
(B) Documentation from the entity 
issuing the system emergency that the system emergency included the affected source/region where the unit was located; 
(C) Documentation that the source 
was instructed to increase output beyond the planned day-ahead or other near-term expected output and/or was asked to remain in operation outside of its scheduled dispatch during emergency conditions from a Reliability Coordinator, Balancing Authority, or Independent System Operator/RTO; and 
(D) Data collected during the event 
including the sum of the CO
2emissions, 
the sum of the gross energy output, and the resulting CO
2emissions 
performance rate. 
(iv) A requirement to document the 
hours an affected EGU operated under a system emergency and the enforceable emission limitation, whether the applicable standard of performance or 
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the alternative emission limitation, 
under which that affected EGU operated during those hours. 
(v) A provision that, for the purpose 
of demonstrating compliance with the applicable standard of performance, the affected EGU would comply with its baseline emissions rate as calculated under § 60.5775b(d) in lieu of its otherwise applicable standard of 
performance for the hours of operation that correspond to the duration of the event. 
(vi) The inclusion of provisions 
defining the short-term reliability mechanism must be part of the public comment process as part of the State plan’s development. 
(13) Reliability Assurance 
Mechanism. You may include 
provisions for a reliability assurance mechanism in your State plan. If included, such provisions would allow for one extension, not to exceed 12- months of the date by which an affected EGU has committed to permanently cease operations based on a demonstration consistent with this paragraph (a)(13) that operation of the affected EGU is necessary for electric grid reliability. 
(i) The State plan must require that 
the reliability assurance mechanism would only be appliable to the following EGUs which, for the purpose of this paragraph (a)(13), are collectively referred to as ‘‘eligible EGUs’’: 
(A) Coal-fired steam generating units 
that are exempt from these emission guidelines pursuant to § 60.5850b(k), 
(B) Affected EGUs in the medium- 
term coal-fired steam-generating subcategory that have enforceable commitments to permanently cease operation before January 1, 2039, in the State plan, and 
(C) Affected EGUs that have 
enforceable dates to permanently cease operation included in the State plan pursuant to § 60.24a(g). 
(ii)The date from which an extension 
would run is the date included in the State plan by which an eligible EGU has committed to permanently cease operation. 
(iii) The State plan must provide that 
an extension is only available to owners or operators of affected EGUs that have satisfied all applicable increments of progress and reporting obligations and milestones in paragraphs (a)(5) and (6) of this section. This includes requiring that the owner or operator of an affected EGU has posted all information relevant to such increments of progress and reporting obligations and milestones on the Carbon Pollution Standards for EGUs website, described in § 60.5740b(a)(10). (iv) The State plan must provide that 
any applicable standard of performance 
for an affected EGU must remain in place during the duration of an extension provided under this mechanism. 
(v) The State plan may provide for 
requests for an extension of up to 12 months without a State plan revision. 
(A) For an extension of 6 months or 
less, the owner or operator of the eligible EGU requesting the extension must submit the information in paragraph (a)(13)(vi) to the applicable EPA Regional Administrator to review and approve or disapprove the extension request. 
(B) For an extension of more than 6 
months and up to 12 months, the owner or operator of the eligible EGU requesting the extension must submit the information in paragraph (a)(13)(vii) to the Federal Energy Regulatory Commission (through a process and at an office of the Federal Energy Regulatory Commission’s designation) and to the applicable EPA Regional Administrator to review and approve or 
disapprove the extension request. 
(vi) The State plan must require that 
to apply for an extension for 6 months or less, described in paragraph (a)(13)(v)(A) of this section, the owner or operator of an eligible EGU must submit a complete written application that includes the information listed in paragraphs (a)(13)(vi)(A) through (D) of this section no less than 30 days prior to the cease operation date, but no earlier than 12 months prior to the cease operation date. 
(A) An analysis of the reliability risk 
that clearly demonstrates that the eligible EGU is critical to maintaining electric reliability. The analysis must include a projection of the length of time that the EGU is expected to be reliability-critical and the length of the requested extension must be no longer than this period or 6 months, whichever is shorter. In order to show an approvable reliability need, the analysis must clearly demonstrate that an eligible EGU ceasing operation by the date listed in the State plan would cause one or more of the conditions listed in paragraphs (a)(13)(vi)(A)(1) or (2) of this section. An eligible EGU that has received a Reliability Must Run designation, or equivalent from a Reliability Coordinator or Balancing Authority, would fulfill those conditions. 
(1) Result in noncompliance with at 
least one of the mandatory reliability standards approved by FERC; or 
(2) Would cause the loss of load 
expectation to increase beyond the level targeted by regional system planners as part of their established procedures for 
that particular region; specifically, this requires a clear demonstration that the eligible EGU would be needed to maintain the targeted level of resource adequacy. 
(B) Certification from the relevant 
reliability planning authority that the claims of reliability risk are accurate and that the identified reliability problem both exists and requires the specific relief requested. This certification must be accompanied by a written analysis by the relevant planning authority consistent with paragraph (a)(13)(vi)(A) of this section, confirming the asserted reliability risk if the eligible EGU was not in operation. The information from the relevant reliability planning authority must also include any related system-wide or regional analysis and a substantiation of the length of time that the eligible EGU is expected to be reliability critical. 
(C) Copies of any written comments 
from third parties regarding the extension. 
(D) Demonstration from the owner or 
operator of the eligible EGU, grid 
operator, and other relevant entities of a plan, including appropriate actions to bring on new capacity or transmission, to resolve the underlying reliability issue is leading to the need to employ this reliability assurance mechanism, including the steps and timeframes for implementing measures to rectify the underlying reliability issue. 
(E) Any other information requested 
by the applicable EPA Regional Administrator or the Federal Energy Regulatory Commission. 
(vii) The State plan must require that 
to apply for an extension longer than 6 months but up to 12 months, described in paragraph (a)(13)(v)(B) of this section, the owner or operator of an eligible EGU must submit a complete written application that includes the information listed in (a)(13)(vi)(A) through (E) of this section, except that the period of time under (a)(13)(vi)(A) would be 12 months. For requests for extensions longer than 6 months, this application must be submitted to the EPA Regional Administrator no less than 45 days prior to the date for ceasing operation listed in the State plan, but no earlier than 12 months prior to that date. 
(viii) The State plan must provide that 
extensions will only be granted for the period of time that is substantiated by the reliability need and the submitted analysis and documentation, and shall not exceed 12 months in total. 
(ix) The State plan must provide that 
the reliability assurance mechanism shall not be used more than once to 
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extend an eligible EGU’s planned cease 
operation date. 
(x) The EPA Regional Administrator 
may reject the application if the submission is incomplete with respect to the requirements listed in paragraphs (a)(13)(vi)(A) through (E) of this section or if the submission does not adequately support the asserted reliability risk or the period of time for which the eligible EGU is anticipated to be reliability critical. 
(b) [Reserved] 
§ 60.5775b What standards of performance 
must I include in my State plan? 
(a) For each affected EGU, your State 
plan must include the standard of 
performance that applies for the affected EGU. A standard of performance for an affected EGU may take the following forms: 
(1) A rate-based standard of 
performance for an individual affected EGU that does not exceed the level calculated through the use of the methods described in § 60.5775b(c) and (d). 
(2) A standard of performance in an 
alternate form, which may apply for affected EGUs in the long-term coal- fired steam generating unit subcategory or the medium-term coal-fired steam generating unit subcategory, as provided for in § 60.5775b(e). 
(b) Standard(s) of performance for 
affected EGUs included under your State plan must be demonstrated to be quantifiable, verifiable, non-duplicative, permanent, and enforceable with respect to each affected EGU. The State plan submittal must include the methods by which each standard of performance meets each of the following requirements: 
(1) An affected EGU’s standard of 
performance is quantifiable if it can be reliably measured in a manner that can be replicated. 
(2) An affected EGU’s standard of 
performance is verifiable if adequate monitoring, recordkeeping and reporting requirements are in place to enable the State and the Administrator to independently evaluate, measure, and verify compliance with the standard of performance. 
(3) An affected EGU’s standard of 
performance is non-duplicative with respect to a State plan if it is not already incorporated as an standard of performance in the State plan. 
(4) An affected EGU’s standard of 
performance is permanent if the standard of performance must be met continuously unless it is replaced by another standard of performance in an approved State plan revision. (5) An affected EGU’s standard of 
performance is enforceable if: 
(i) A technically accurate limitation or 
requirement, and the time period for the limitation or requirement, are specified; 
(ii) Compliance requirements are 
clearly defined; 
(iii) The affected EGUs are responsible 
for compliance and liable for violations identified; 
(iv) Each compliance activity or 
measure is enforceable as a practical matter, as defined by 40 CFR 49.167; and 
(v) The Administrator, the State, and 
third parties maintain the ability to enforce against violations (including if an affected EGU does not meet its standard of performance based on its emissions) and secure appropriate corrective actions: in the case of the Administrator, pursuant to CAA sections 113(a)–(h); in the case of a State, pursuant to its State plan, State law or CAA section 304, as applicable; and in the case of third parties, pursuant to CAA section 304. 
(c) Methodology for establishing 
presumptively approvable standards of performance, for affected EGUs in each subcategory. 
(1) Long-term coal-fired steam 
generating units 
(i) BSER is CCS with 90 percent 
capture of CO
2. 
(ii) Degree of emission limitation is 
88.4 percent reduction in emission rate (lb CO
2/MWh-gross). 
(iii) Presumptively approvable 
standard of performance is an emission rate limit defined by an 88.4 percent reduction in annual emission rate (lb CO
2/MWh-gross) from the unit-specific 
baseline. 
(2) Medium-term coal-fired steam 
generating units 
(i) BSER is natural gas co-firing at 40 
percent of the heat input to the unit. 
(ii) Degree of emission limitation is a 
16 percent reduction in emission rate (lb CO
2/MWh-gross). 
(iii) Presumptively approvable 
standard of performance is an emission rate limit defined by a 16 percent reduction in annual emission rate (lb CO
2/MWh-gross) from the unit-specific 
baseline. 
(iv) For units in this subcategory that 
have an amount of co-firing that is reflected in the baseline operation, States must account for such preexisting co-firing in adjusting the degree of emission limitation (e.g., for an EGU co- 
fires natural gas at a level of 10 percent of the total annual heat input during the applicable 8-quarter baseline period, the corresponding degree of emission limitation would be adjusted to 12 percent to reflect the preexisting level of natural gas co-firing). 
(3) Base load oil-fired steam 
generating units. 
(i) BSER is routine methods of 
operation and maintenance. 
(ii) Degree of emission limitation is a 
0 percent increase in emission rate (lb CO
2/MWh-gross). 
(iii) Presumptively approvable 
standard of performance is an annual emission rate limit of 1,400 lb CO
2/ 
MWh-gross. 
(4) Intermediate load oil-fired steam 
generating units. 
(i) BSER is routine methods of 
operation and maintenance. 
(ii) Degree of emission limitation is a 
0 percent increase in emission rate (lb CO
2/MWh-gross). 
(iii) Presumptively approvable 
standard of performance is an annual emission rate limit of 1,600 lb CO
2/ 
MWh-gross. 
(5) Low load oil-fired steam 
generating units. 
(i) BSER is uniform fuels. 
(ii) Degree of emission limitation is 
170 lb CO 2/MMBtu. 
(iii) Presumptively approvable 
standard of performance is an annual 
emission rate limit of 170 lb CO 2/ 
MMBtu. 
(6) Base load natural gas-fired steam 
generating units. 
(i) BSER is routine methods of 
operation and maintenance. 
(ii) Degree of emission limitation is a 
0 percent increase in emission rate (lb CO
2/MWh-gross). 
(iii) Presumptively approvable 
standard of performance is an annual emission rate limit of 1,400 lb CO
2/ 
MWh-gross. 
(7) Intermediate load natural gas-fired 
steam generating units. 
(i) BSER is routine methods of 
operation and maintenance. 
(ii) Degree of emission limitation is a 
0 percent increase in emission rate (lb CO
2/MWh-gross). 
(iii) Presumptively approvable 
standard of performance is an annual emission rate limit of 1,600 lb CO
2/ 
MWh-gross. 
(8) Low load natural gas-fired steam 
generating. 
(i) BSER is uniform fuels. 
(ii) Degree of emission limitation is 
130 lb CO 2/MMBtu. 
(iii) Presumptively approvable 
standard of performance is an annual 
emission rate limit of 130 lb CO 2/ 
MMBtu. 
(d) Methodology for establishing the 
unit-specific baseline of emission performance. 
(1) A State shall use the CO
2mass 
emissions and corresponding electricity 
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generation or, for affected EGUs in the 
low load oil- or natural gas-fired subcategory, heat input data for a given affected EGU from the most representative continuous 8-quarter period from 40 CFR part 75 reporting within the 5-year period immediately prior to May 9, 2024. 
(2) For the continuous 8 quarters of 
data, a State shall divide the total CO
2 
emissions (in the form of pounds) over that continuous time period by either the total gross electricity generation (in the form of MWh) or, for affected EGUs in the low load oil- or natural gas-fired subcategory, total heat input (in the form of MMBtu) over that same time period to calculate baseline CO
2 
emission performance in lb CO 2per 
MWh or lb CO 2per MMBtu. 
(e) Your State plan may include a 
standard of performance in an alternate form that differs from the presumptively approvable standard of performance specified in § 60.5775b(a)(1), as follows: 
(1) An aggregate rate-based standard 
of performance (lb CO
2/MWh-gross) that 
applies for a group of affected EGUs that 
share the same owner or operator, as calculated on a gross generation weighted average basis, provided the standard of performance meets the requirements of paragraph (f) of this section. 
(2) A mass-based standard of 
performance in the form of an annual limit on allowable mass CO
2emissions 
for an individual affected EGU, provided the standard of performance meets the requirements of paragraph (g) of this section. 
(3) A rate-based standard of 
performance (lb CO
2/MWh-gross) 
implemented through a rate-based emission trading program, such that an affected EGU must meet the specified lb CO
2/MWh-gross rate that applies for the 
affected EGU, and where an affected EGU may surrender compliance instruments denoted in 1 short ton of CO
2to adjust its reported lb CO 2/MWh- 
gross rate for the purpose of demonstrating compliance, provided the standard of performance meets the requirements of paragraph (h) of this section. 
(4) A mass-based standard of 
performance in the form of an annual CO
2budget implemented through a 
mass-based CO 2emission trading 
program, where an affected EGU must surrender CO
2allowances in an amount 
equal to its reported mass CO 2 
emissions, provided the standard of performance meets the requirements of paragraph (i) of this section. 
(f) Where your State plan includes a 
standard of performance in the form of an aggregate rate-based standard of performance (lb CO
2/MWh-gross) that 
applies for a group of affected EGUs that share the same owner or operator, as calculated on a gross generation weighted average basis, your State plan must include: 
(1) The presumptively approvable 
rate-based standard of performance (lb CO
2/MWh-gross) that would apply 
under paragraph (a)(1) of this section, and as determined in accordance with paragraphs (c) and (d) of this section, to each of the affected EGUs that form the group. 
(2) Documentation of any 
assumptions underlying the calculation of the aggregate rate-based standard of performance (lb CO
2/MWh-gross). 
(3) The process for calculating the 
aggregate gross generation weighted average emission rate (lb CO
2/MWh- 
gross) at the end of each compliance period, based on the reported emissions (lb CO
2) and utilization (MWh-gross) of 
each of the affected EGUs that form the group. 
(4) Measures to implement and 
enforce the annual aggregate rate-based standard of performance, including the basis for determining owner or operator compliance with the aggregate standard of performance and provisions to address any changes to owners or operators in the course of implementation. 
(5) A demonstration of how the 
application of the aggregate rate-based standard of performance will achieve equivalent or better emission reduction as would be achieved through the application of a rate-based standard of performance (lb CO
2/MWh-gross) that 
would apply pursuant to paragraph (a)(1) of this section, and as determined in accordance with paragraphs (c) and (d) of this section. 
(g) Where your State plan includes a 
standard of performance in the form of an annual limit on allowable mass CO
2 
emissions for an individual affected EGU, your State plan must include: 
(1) The presumptively approvable 
rate-based standard of performance (lb CO
2/MWh-gross) that would apply to 
the affected EGU under paragraph (a)(1) of this section, and as determined in accordance with paragraphs (c) and (d) of this section. 
(2) The utilization level used to 
calculate the mass CO
2limit, by 
multiplying the assumed utilization level (MWh-gross) by the presumptively approvable rate-based standard of performance (lb CO
2/MWh-gross), 
including the underlying data used for the calculation and documentation of any assumptions underlying this calculation. (3) Measures to implement and 
enforce the annual limit on mass CO
2 
emissions, including provisions that 
address assurance of achievement of equivalent emission performance. 
(4) A demonstration of how the 
application of the mass CO
2limit for the 
affected EGU will achieve equivalent or better emission reduction as would be achieved through the application of a rate-based standard of performance (lb CO
2/MWh-gross) that would apply 
pursuant to paragraph (a)(1) of this section, and as determined in accordance with paragraphs (c) and (d) of this section. 
(5) The backstop rate-based emission 
rate requirement (lb CO
2/MWh-gross) 
that will also be applied to the affected EGU on an annual basis. 
(6) For affected EGUs in the long-term 
coal-fired steam generating unit subcategory, in lieu of paragraphs (g)(2), (4), and (5) of this section, you may include a presumptively approvable mass CO
2limit based on the product of 
the rate-based standard of performance (lb CO
2/MWh-gross) under paragraph 
(a)(1) of this section multiplied by a 
level of utilization (MWh-gross) corresponding to an annual capacity factor of 80 percent for the individual affected EGU with a backstop rate-based emission rate requirement equivalent to a reduction in baseline emission performance of 80 percent on an annual calendar-year basis. 
(h) Where your State plan includes a 
standard of performance in the form of a rate-based standard of performance (lb CO
2/MWh-gross) implemented through 
a rate-based emission trading program, your State plan must include: 
(1) The presumptively approvable 
rate-based standard of performance (lb CO
2/MWh-gross) that applies to each of 
the affected EGUs participating in the rate-based emission trading program under paragraph (a)(1) of this section, and as determined in accordance with paragraphs (c) and (d) of this section. 
(2) Measures to implement and 
enforce the rate-based emission trading program, including the basis for awarding compliance instruments (denoted in 1 ton of CO
2) to an affected 
EGU that performs better on an annual basis than its rate-based standard of performance, and the process for demonstration of compliance that includes the surrender of such compliance instruments by an affected EGU that exceeds its rate-based standard of performance. 
(3) A demonstration of how the use of 
the rate-based emission trading program will achieve equivalent or better emission reduction as would be achieved through the application of a 
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rate-based standard of performance (lb 
CO 2/MWh-gross) that would apply 
pursuant to paragraph (a)(1) of this section, and as determined in accordance with paragraphs (c) and (d) of this section. 
(i) Where your State plan includes a 
mass-based standard of performance implemented through a mass-based CO
2 
emission trading program, where an affected EGU must surrender CO
2 
allowances in an amount equal to its reported mass CO
2emissions, your State 
plan must include: 
(1) The presumptively approvable 
rate-based standard of performance (lb CO
2/MWh-gross) that would apply to 
each affected EGU participating in the trading program under paragraph (a)(1) 
of this section, and as determined in accordance with paragraphs (c) and (d) of this section. 
(2) The calculation of the mass CO
2 
budget contribution for each participating affected EGU, determined by multiplying the assumed utilization level (MWh-gross) of the affected EGU by its presumptively approvable rate- based standard of performance (lb CO
2/ 
MWh-gross), including the underlying data used for the calculation and documentation of any assumptions underlying this calculation. 
(3) Measures to implement and 
enforce the annual budget of the mass- based CO
2emission trading program, 
including provisions that address assurance of achievement of equivalent emission performance. 
(4) A demonstration of how the 
application of the CO
2emission budget 
for the group of participating affected EGUs will achieve equivalent or better emission performance as would be achieved through the application of a rate-based standard of performance (lb CO
2/MWh-gross) that would apply to 
each participating affected EGU under paragraph (a)(1) of this section, and as determined in accordance with paragraphs (c) and (d) of this section. 
(5) The backstop rate-based emission 
rate requirement (lb CO
2/MWh-gross) 
that will also be applied to each participating affected EGU on an annual basis. 
(j) In order to use the provisions of 
§ 60.24a(e) through (h) to apply a less stringent standard of performance or longer compliance schedule to an affected EGU based on consideration of electric grid reliability, including resource adequacy, under these emission guidelines, a State must provide the following with its State plan submission: 
(1) An analysis of the reliability risk 
clearly demonstrating that the particular affected EGU is critical to maintaining electric reliability such that requiring it to comply with the applicable requirements under paragraph (c) of this section or § 60.5780b would trigger non- compliance with at least one of the mandatory reliability standards approved by the Federal Energy Regulatory Commission or would cause the loss of load expectation to increase beyond the level targeted by regional system planners as part of their established procedures for that particular region; specifically, a clear demonstration is required that the particular affected EGU would be needed to maintain the targeted level of resource adequacy. The analysis must also include a projection of the period of time for which the particular affected EGU is expected to be reliability critical and substantiate the basis for applying a less stringent standard of performance or longer compliance schedule consistent with 40 CFR 60.24a(e). 
(2) An analysis by the relevant 
reliability planning authority that corroborates the asserted reliability risk identified in the analysis under paragraph (j)(1) of this section and confirms that requiring the particular affected EGU to comply with its applicable requirements under paragraph (c) of this section or § 60.5780b would trigger non- compliance with at least one of the mandatory reliability standards approved by the Federal Energy Regulatory Commission or would cause the loss of load expectation to increase beyond the level targeted by regional system planners as part of their established procedures for that particular region, and also confirms the period of time for which the EGU is projected to be reliability critical. 
(3) A certification from the relevant 
reliability planning authority that the claims of reliability risk are accurate and that the identified reliability problem both exists and requires the specific relief requested. 
§ 60.5780b What compliance dates and 
compliance periods must I include in my State plan? 
(a) The State plan must include the 
following compliance dates: 
(1) For affected EGUs in the long-term 
coal-fired subcategory, the State plan 
must require compliance with the applicable standards of performance starting no later than January 1, 2032, unless the State has applied a later compliance date pursuant to § 60.24a(e) through (h). 
(2) For affected EGUs in the medium- 
term coal-fired subcategory, the base load oil-fired subcategory, the intermediate load oil-fired steam generating subcategory, the low load oil- fired subcategory, the base load natural gas-fired subcategory, the intermediate load natural gas-fired subcategory, and the low load natural gas-fired subcategory, the State plan must require compliance with the applicable standards of performance starting no later than January 1, 2030, unless State has applied a later compliance date pursuant to § 60.24a(e) through (h). 
(b) The State plan must require 
affected EGUs to achieve compliance with their applicable standards of performance for each compliance period as defined in § 60.5880b. 
§ 60.5785b What are the timing 
requirements for submitting my State plan? 
(a) You must submit a State plan or 
a negative declaration letter with the 
information required under § 60.5740b by May 11, 2026. 
(b) You must submit all information 
required under paragraph (a) of this section according to the electronic reporting requirements in § 60.5875b. 
§ 60.5790b What is the procedure for 
revising my State plan? 
EPA-approved State plans can be 
revised only with approval by the 
Administrator. The Administrator will approve a State plan revision if it is satisfactory with respect to the applicable requirements of this subpart and all applicable requirements of subpart Ba of this part. If one (or more) of State plan elements in § 60.5740b require revision, the State must submit a State plan revision pursuant to § 60.28a. 
§ 60.5795b Commitment to review 
emission guidelines for coal-fired affected EGUs 
EPA will review and, if appropriate, 
revise these emission guidelines as they 
apply to coal-fired steam generating affected EGUs by January 1, 2041. Notwithstanding this commitment, EPA need not review these emission guidelines if the Administrator determines that such review is not appropriate in light of readily available information on their continued appropriateness. 
Applicability of State Plans to Affected 
EGUs 
§ 60.5840b Does this subpart directly 
affect EGU owners or operators in my State? 
(a) This subpart does not directly 
affect EGU owners or operators in your 
State, except as provided in § 60.5710b(b). However, affected EGU owners or operators must comply with the State plan that a State develops to 
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implement the emission guidelines 
contained in this subpart. 
(b) If a State does not submit a State 
plan to implement and enforce the standards of performance contained in this subpart by May 11, 2026, or the EPA disapproves State plan, the EPA will implement and enforce a Federal plan, as provided in § 60.5720b, applicable to each affected EGU within the State. 
§ 60.5845b What affected EGUs must I 
address in my State plan? 
(a) The EGUs that must be addressed 
by your State plan are: 
(1) Any affected EGUs that were in 
operation or had commenced 
construction on or before January 8, 2014; 
(2) Coal-fired steam generating units 
that commenced a modification on or before May 23, 2023. 
(b) An affected EGU is a steam 
generating unit that meets the relevant applicability conditions specified in paragraphs (b)(1) through (2) of this section, as applicable, except as provided in § 60.5850b. 
(1) Serves a generator capable of 
selling greater than 25 MW to a utility power distribution system; and 
(2) Has a base load rating (i.e., design 
heat input capacity) greater than 260 GJ/ hr (250 MMBtu/hr) heat input of fossil fuel (either alone or in combination with any other fuel). 
§ 60.5850b What EGUs are excluded from 
being affected EGUs? 
EGUs that are excluded from being 
affected EGUs are: 
(a) New or reconstructed steam 
generating units that are subject to 
subpart TTTT of this part as a result of commencing construction after the subpart TTTT applicability date; 
(b) Modified natural gas- or oil-fired 
steam generating units that are subject to subpart TTTT of this part as a result of commencing modification after the subpart TTTT applicability date; 
(c) Modified coal-fired steam 
generating units that are subject to subpart TTTTa of this part as a result of commencing modification after the subpart TTTTa applicability date; 
(d) EGUs subject to a federally 
enforceable permit limiting net-electric sales to one-third or less of their potential electric output or 219,000 MWh or less on an annual basis and annual net-electric sales have never exceeded one-third or less of their potential electric output or 219,000 MWh; 
(e) Non-fossil fuel units (i.e., units 
that are capable of deriving at least 50 percent of heat input from non-fossil fuel at the base load rating) that are subject to a federally enforceable permit limiting fossil fuel use to 10 percent or less of the annual capacity factor; 
(f) CHP units that are subject to a 
federally enforceable permit limiting annual net-electric sales to no more than either 219,000 MWh or the product of the design efficiency and the potential electric output, whichever is greater; 
(g) Units that serve a generator along 
with other EGUs, where the effective generation capacity (determined based on a prorated output of the base load rating of each EGU) is 25 MW or less; 
(h) Municipal waste combustor units 
subject to 40 CFR part 60, subpart Eb; 
(i) Commercial or industrial solid 
waste incineration units that are subject to 40 CFR part 60, subpart CCCC; or 
(j) EGUs that derive greater than 50 
percent of the heat input from an industrial process that does not produce any electrical or mechanical output or useful thermal output that is used outside the affected EGU. 
(k) Existing coal-fired steam 
generating units that have demonstrated that they plan to permanently cease operations before January 1, 2032, pursuant to § 60.5740b(a)(9)(ii). 
Recordkeeping and Reporting 
Requirements 
§ 60.5860b What applicable monitoring, 
recordkeeping, and reporting requirements do I need to include in my State plan for affected EGUs? 
(a) Your State plan must include 
monitoring for affected EGUs that is no 
less stringent than what is described in (a)(1) through (9) of this section. 
(1) The owner or operator of an 
affected EGU (or group of affected EGUs that share a monitored common stack) that is required to meet standards of performance must prepare a monitoring plan in accordance with the applicable provisions in 40 CFR 75.53(g) and (h), unless such a plan is already in place under another program that requires CO
2mass emissions to be monitored 
and reported according to 40 CFR part 75. 
(2) For rate-based standards of 
performance, only ‘‘valid operating hours,’’, i.e., full or partial unit (or stack) 
operating hours for which: 
(i) ‘‘Valid data’’ (as defined in 
§ 60.5880b) are obtained for all of the parameters used to determine the hourly CO
2mass emissions (lbs). For the 
purposes of this subpart, substitute data recorded under part 75 of this chapter are not considered to be valid data; data obtained from flow monitoring bias adjustments are not considered to be valid data; and data provided or not provided from monitoring instruments that have not met the required frequency for relative accuracy audit testing are not considered to be valid data and 
(ii) The corresponding hourly gross 
energy output value is also valid data (Note: For operating hours with no useful output, zero is considered to be a valid value). 
(3) For rate-based standards of 
performance, the owner or operator of an affected EGU must measure and report the hourly CO
2mass emissions 
(lbs) from each affected unit using the procedures in paragraphs (a)(3)(i) through (vi) of this section, except as otherwise provided in paragraph (a)(4) of this section. 
(i) The owner or operator of an 
affected EGU must install, certify, operate, maintain, and calibrate a CO
2 
continuous emissions monitoring system (CEMS) to directly measure and record CO
2concentrations in the 
affected EGU exhaust gases emitted to the atmosphere and an exhaust gas flow rate monitoring system according to 40 CFR 75.10(a)(3)(i). As an alternative to direct measurement of CO
2 
concentration, provided that the affected EGU does not use carbon separation (e.g., carbon capture and 
storage (CCS)), the owner or operator of an affected EGU may use data from a certified oxygen (O
2) monitor to 
calculate hourly average CO 2 
concentrations, in accordance with 40 CFR 75.10(a)(3)(iii). However, when an O
2monitor is used this way, it only 
quantifies the combustion CO 2; 
therefore, if the EGU is equipped with emission controls that produce non- combustion CO
2(e.g., from sorbent 
injection), this additional CO 2must be 
accounted for, in accordance with section 3 of appendix G to part 75 of this chapter. If CO
2concentration is 
measured on a dry basis, the owner or operator of the affected EGU must also install, certify, operate, maintain, and calibrate a continuous moisture monitoring system, according to 40 CFR 75.11(b). Alternatively, the owner or operator of an affected EGU may either use an appropriate fuel-specific default moisture value from 40 CFR 75.11(b) or submit a petition to the Administrator under 40 CFR 75.66 for a site-specific default moisture value. 
(ii) For each ‘‘valid operating hour’’ 
(as defined in paragraph (a)(2) of this section), calculate the hourly CO
2mass 
emission rate (tons/hr), either from Equation F–11 in appendix F to 40 CFR part 75 (if CO
2concentration is 
measured on a wet basis), or by following the procedure in section 4.2 of appendix F to 40 CFR part 75 (if CO
2 
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concentration is measured on a dry 
basis). 
(iii) Next, multiply each hourly CO 2 
mass emission rate by the EGU or stack operating time in hours (as defined in 40 CFR 72.2), to convert it to tons of CO
2.Multiply the result by 2,000 lbs/ton 
to convert it to lbs. 
(iv) The hourly CO 2tons/hr values 
and EGU (or stack) operating times used to calculate CO
2mass emissions are 
required to be recorded under 40 CFR 75.57(e) and must be reported electronically under 40 CFR 75.64(a)(6), if required by a State plan. The owner or operator must use these data, or equivalent data, to calculate the hourly CO
2mass emissions. 
(v) Sum all of the hourly CO 2mass 
emissions values from paragraph (a)(3)(ii) of this section. 
(vi) For each continuous monitoring 
system used to determine the CO
2mass 
emissions from an affected EGU, the monitoring system must meet the applicable certification and quality assurance procedures in 40 CFR 75.20 and appendices A and B to 40 CFR part. 
(4) The owner or operator of an 
affected EGU that exclusively combusts liquid fuel and/or gaseous fuel may, as an alternative to complying with paragraph (a)(3) of this section, determine the hourly CO
2mass 
emissions according to paragraphs (a)(4)(i) through (a)(4)(vi) of this section. 
(i) Implement the applicable 
procedures in appendix D to part 75 of this chapter to determine hourly EGU heat input rates (MMBtu/hr), based on hourly measurements of fuel flow rate and periodic determinations of the gross calorific value (GCV) of each fuel 
combusted. The fuel flow meter(s) used to measure the hourly fuel flow rates must meet the applicable certification and quality-assurance requirements in sections 2.1.5 and 2.1.6 of appendix D to 40 CFR part 75 (except for qualifying commercial billing meters). The fuel GCV must be determined in accordance with section 2.2 or 2.3 of appendix D to 40 CFR part 75, as applicable. (ii) For each measured hourly heat 
input rate, use Equation G–4 in 
appendix G to 40 CFR part 75 to calculate the hourly CO
2mass emission 
rate (tons/hr). 
(iii) For each ‘‘valid operating hour’’ 
(as defined in paragraph (a)(2) of this section), multiply the hourly tons/hr CO
2mass emission rate from paragraph 
(a)(4)(ii) of this section by the EGU or stack operating time in hours (as defined in 40 CFR 72.2), to convert it to tons of CO
2. Then, multiply the result 
by 2,000 lbs/ton to convert it to lbs. 
(iv) The hourly CO 2tons/hr values 
and EGU (or stack) operating times used to calculate CO
2mass emissions are 
required to be recorded under 40 CFR 75.57(e) and must be reported electronically under 40 CFR 75.64(a)(6), if required by a State plan. You must use these data, or equivalent data, to calculate the hourly CO
2mass 
emissions. 
(v) Sum all of the hourly CO 2mass 
emissions values (lb) from paragraph (a)(4)(iii) of this section. 
(vi) The owner or operator of an 
affected EGU may determine site- specific carbon-based F-factors (F
c) 
using Equation F–7b in section 3.3.6 of appendix F to 40 CFR part 75 and may use these F
cvalues in the emissions 
calculations instead of using the default F
cvalues in the Equation G–4 
nomenclature. 
(5) For rate-based standards, the 
owner or operator of an affected EGU (or group of affected units that share a monitored common stack) must install, calibrate, maintain, and operate a sufficient number of watt meters to continuously measure and record on an hourly basis gross electric output. Measurements must be performed using 0.2 accuracy class electricity metering instrumentation and calibration procedures as specified under ANSI No. C12.20–2010 (incorporated by reference, see § 60.17). Further, the owner or 
operator of an affected EGU that is a combined heat and power facility must install, calibrate, maintain, and operate equipment to continuously measure and 
record on an hourly basis useful thermal output and, if applicable, mechanical output, which are used with gross electric output to determine gross energy output. The owner or operator must use the following procedures to calculate gross energy output, as appropriate for the type of affected EGU(s). 
(i) Determine P
gross/net the hourly gross 
or net energy output in MWh. For rate- based standards, perform this calculation only for valid operating hours (as defined in paragraph (a)(2) of this section). For mass-based standards, perform this calculation for all unit (or stack) operating hours, i.e., full or 
partial hours in which any fuel is combusted. 
(ii) If there is no net electrical output, 
but there is mechanical or useful thermal output, either for a particular valid operating hour (for rate-based applications), or for a particular operating hour (for mass-based applications), the owner or operator of the affected EGU must still determine the net energy output for that hour. 
(iii) For rate-based applications, if 
there is no (i.e., zero) gross electrical, 
mechanical, or useful thermal output for a particular valid operating hour, that hour must be used in the compliance 
determination. For hours or partial hours where the gross electric output is equal to or less than the auxiliary loads, net electric output shall be counted as zero for this calculation. 
(iv) Calculate P
gross/net for your affected 
EGU (or group of affected EGUs that share a monitored common stack) using the following equation. All terms in the equation must be expressed in units of MWh. To convert each hourly gross or net energy output value reported under 40 CFR part 75 to MWh, multiply by the corresponding EGU or stack operating time. 
Equation 1 to Paragraph (a)(5)(iv) 
Where: 
PGROSS/NET = Gross or net energy output of 
your affected EGU for each valid 
operating hour (as defined in 60.5860b(a)(2)) in MWh. 
(PE)
ST= Electric energy output plus 
mechanical energy output (if any) of steam turbines in MWh. 
(PE)
CT= Electric energy output plus 
mechanical energy output (if any) of stationary combustion turbine(s) in 
MWh. 
(PE) IE= Electric energy output plus 
mechanical energy output (if any) of your affected egu’s integrated equipment that provides electricity or mechanical energy to the affected EGU or auxiliary equipment in MWh. 
(PE)
A= Electric energy used for any auxiliary 
loads in MWh. (PT) PS= Useful thermal output of steam 
(measured relative to SATP conditions, as applicable) that is used for applications that do not generate additional electricity, produce mechanical energy output, or enhance the performance of the affected EGU. This is calculated using the equation specified in paragraph (a)(5)(V) of this section in MWh. 
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(PT) HR= Non-steam useful thermal output 
(measured relative to SATP conditions, 
as applicable) from heat recovery that is used for applications other than steam generation or performance enhancement of the affected EGU in MWh. 
(PT)
IE= Useful thermal output (relative to 
SATP conditions, as applicable) from 
any integrated equipment is used for applications that do not generate additional steam, electricity, produce mechanical energy output, or enhance 
the performance of the affected EGU in MWh. 
TDF = Electric transmission and distribution 
factor of 0.95 for a combined heat and power affected egu where at least on an annual basis 20.0 percent of the total gross or net energy output consists of 
electric or direct mechanical output and 20.0 percent of the total gross or net energy output consist of useful thermal output on a 12-operating month rolling 
average basis, or 1.0 for all other affected EGUs. 
(v) If applicable to your affected EGU 
(for example, for combined heat and 
power), you must calculate (Pt) PSusing 
the following equation: 
Equation 2 to Paragraph (a)(5)(v) 
Where: 
QM= Measured steam flow in kilograms (KG) 
(or pounds (LBS)) for the operating hour. 
H = Enthalpy of the steam at measured 
temperature and pressure (relative to 
SATP conditions or the energy in the condensate return line, as applicable) in joules per kilogram (J/KG) (or BTU/LB). 
CF = Conversion factor of 3.6 × 10
9J/MWH 
or 3.413 × 106BTU/MWh. 
(vi) For rate-based standards, sum all 
of the values of P gross/net for the valid 
operating hours (as defined in paragraph (a)(2) of this section). Then, divide the total CO
2mass emissions for the valid 
operating hours from paragraph (a)(3)(v) or (a)(4)(v) of this section, as applicable, by the sum of the P
gross/net values for the 
valid operating hours to determine the CO
2emissions rate (lb/gross or net 
MWh). 
(6) In accordance with § 60.13(g), if 
two or more affected EGUs 
implementing the continuous emissions monitoring provisions in paragraph (a)(3) of this section share a common exhaust gas stack and are subject to the same emissions standard, the owner or operator may monitor the hourly CO
2 
mass emissions at the common stack in lieu of monitoring each EGU separately. If an owner or operator of an affected EGU chooses this option, the hourly gross or net electric output for the common stack must be the sum of the hourly gross or net electric output of the individual affected EGUs and the operating time must be expressed as ‘‘stack operating hours’’ (as defined in 40 CFR 72.2). 
(7) In accordance with § 60.13(g), if 
the exhaust gases from an affected EGU implementing the continuous emissions monitoring provisions in paragraph (a)(3) of this section are emitted to the atmosphere through multiple stacks (or if the exhaust gases are routed to a common stack through multiple ducts and you elect to monitor in the ducts), the hourly CO
2mass emissions and the 
‘‘stack operating time’’ (as defined in 40 
CFR 72.2) at each stack or duct must be monitored separately. In this case, the owner or operator of an affected EGU must determine compliance with an applicable emissions standard by summing the CO
2mass emissions 
measured at the individual stacks or ducts and dividing by the gross or net energy output for the affected EGU. 
(8) Consistent with § 60.5775b, 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. 
(9) The owner or operator of an 
affected EGU must measure and report monthly fuel usage for each affected source subject to standards of performance with the information in paragraphs (a)(9)(i) through (iii) of this section: 
(i) The calendar month during which 
the fuel was used; 
(ii) Each type of fuel used during the 
calendar month of the compliance period; and 
(iii) Quantity of each type of fuel 
combusted in each calendar month in the compliance period with units of measure. 
(b) Your State plan must require the 
owner or operator of each affected EGU covered by your State plan to maintain the records, for at least 5 years following 
the date of each occurrence, measurement, maintenance, corrective action, report, or record. 
(1) The owner or operator of an 
affected EGU must maintain each record on site for at least 2 years after the date 
of each occurrence, measurement, maintenance, corrective action, report, or record, whichever is latest, according to § 60.7. The owner or operator of an affected EGU may maintain the records 
off site and electronically for the remaining year(s). 
(2) The owner or operator of an 
affected EGU must keep all of the following records, in a form suitable and readily available for expeditious review: 
(i) All documents, data files, and 
calculations and methods used to demonstrate compliance with an affected EGU’s standard of performance under § 60.5775b. 
(ii) Copies of all reports submitted to 
the State under paragraph (b) of this section. 
(iii) Data that are required to be 
recorded by 40 CFR part 75 subpart F. 
(c) Your State plan must require the 
owner or operator of an affected EGU covered by your State plan to include in a report submitted to you the information in paragraphs (c)(1) through (3) of this section. 
(1) Owners or operators of an affected 
EGU must include in the report all hourly CO
2emissions, for each affected 
EGU (or group of affected EGUs that share a monitored common stack). 
(2) For rate-based standards, each 
report must include: 
(i) The hourly CO
2mass emission rate 
values (tons/hr) and unit (or stack) operating times, (as monitored and reported according to part 75 of this chapter), for each valid operating hour; 
(ii) The gross or net electric output 
and the gross or net energy output (P
gross/net ) values for each valid operating 
hour; 
(iii) The calculated CO 2mass 
emissions (lb) for each valid operating hour; 
(iv) The sum of the hourly gross or net 
energy output values and the sum of the 
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hourly CO 2mass emissions values, for 
all of the valid operating hours; and 
(v) The calculated CO 2mass emission 
rate (lbs/gross or net MWh). 
(3) For each affected EGU the report 
must also include the applicable 
standard of performance and demonstration that it met the standard of performance. An owner or operator must also include in the report the affected EGU’s calculated emission performance as a CO
2emission rate in 
units of the standard of performance. 
(d) The owner or operator of an 
affected EGU must follow any additional requirements for monitoring, recordkeeping and reporting in a State plan that are required under § 60.5740b if applicable. 
(e) If an affected EGU captures CO
2to 
meet the applicable standard of 
performance, the owner or operator must report in accordance with the requirements of 40 CFR part 98 subpart PP and either: 
(1) Report in accordance with the 
requirements of 40 CFR part 98, subpart RR, or subpart VV, if injection occurs on-site; 
(2) Transfer the captured CO
2to a 
facility that reports in accordance with the requirements of 40 CFR part 98, subpart RR, or subpart VV, if injection occurs off-site; or 
(3) Transfer the captured CO
2to a 
facility that has received an innovative technology waiver from the EPA pursuant to paragraph (f) of this section. 
(f) Any person may request the 
Administrator to issue a waiver of the requirement that captured CO
2from an 
affected EGU be transferred to a facility reporting under 40 CFR part 98, subpart RR, or subpart VV. To receive a waiver, the applicant must demonstrate to the Administrator that its technology will store captured CO
2as effectively as 
geologic sequestration, and that the proposed technology will not cause or contribute to an unreasonable risk to public health, welfare, or safety. In making this determination, the Administrator shall consider (among other factors) operating history of the technology, whether the technology will increase emissions or other releases of any pollutant other than CO
2, and 
permanence of the CO 2storage. The 
Administrator may test the system or require the applicant to perform any tests considered by the Administrator to be necessary to show the technology’s effectiveness, safety, and ability to store captured CO
2without release. The 
Administrator may grant conditional approval of a technology, with the approval conditioned on monitoring and reporting of operations. The Administrator may also withdraw approval of the waiver on evidence of releases of CO
2or other pollutants. The 
Administrator will provide notice to the public of any application under this provision and provide public notice of any proposed action on a petition before the Administrator takes final action. 
§ 60.5865b What are my recordkeeping 
requirements? 
(a) You must keep records of all 
information relied upon in support of 
any demonstration of State plan components, State plan requirements, supporting documentation, and the status of meeting the State plan requirements defined in the State plan. 
(b) You must keep records of all data 
submitted by the owner or operator of each affected EGU that are used to determine compliance with each affected EGU emissions standard or requirements in an approved State plan, consistent with the affected EGU requirements listed in § 60.5860b. 
(c) If your State has a requirement for 
all hourly CO
2emissions and gross 
generation or heat input information to be used to calculate compliance with an annual emissions standard for affected EGUs, any information that is submitted by the owners or operators of affected EGUs to the EPA electronically pursuant to requirements in 40 CFR part 75 meets the recordkeeping requirement of this section and you are not required to keep records of information that would be in duplicate of paragraph (b) of this section. 
(d) You must keep records for a 
minimum of 10 years from the date the record is used to determine compliance with an emissions standard or State plan requirement. Each record must be in a form suitable and readily available for expeditious review. 
(e) If your State plan includes 
provisions for the compliance date extension, described in § 60.5740b(a)(11), you must keep records of the information required in § 60.5740b(a)(11)(i) from affected EGUs that use the compliance date extension. 
(f) If your State plan includes 
provisions for the short-term reliability mechanism, as described in § 60.5740b(a)(12), you must keep records of the information required in § 60.5740b(a)(12)(iii) from affected EGUs that use the short-term reliability mechanism. 
(g) If your State plan includes 
provisions for the reliability assurance mechanism, described in § 60.5740b(a)(13), you must keep records of the information required in § 60.5740b(a)(13)(vi) from affected EGUs that use the reliability assurance mechanism. § 60.5870b What are my reporting and 
notification requirements? 
(a) In lieu of the annual report 
required under § 60.25(e) and (f), you 
must report the information in paragraph (b) of this section. 
(b) You must submit an annual report 
to the EPA that must include the information in paragraphs (b)(1) through (10) of this section. For each calendar year reporting period the report must be submitted by March 1 of the following year. 
(1) The report must include the 
emissions performance achieved by each affected EGU during the reporting period and identification of whether each affected EGU is in compliance with its standard of performance during the compliance period, as specified in the State plan. 
(2) The report must include, for each 
affected EGU, a comparison of the CO
2 
standard of performance in the State plan versus the actual CO
2emission 
performance achieved. 
(3) The report must include, for each 
affected EGU, the sum of the CO 2 
emissions, the sum of the gross energy output, and the sum of the heat input for each fuel type. 
(4) Enforcement actions initiated 
against affected EGUs during the reporting period, under any standard of performance or compliance schedule of the State plan. 
(5) Identification of the achievement 
of any increment of progress required by the applicable State plan during the reporting period. 
(6) Identification of designated 
facilities that have ceased operation during the reporting period. 
(7) Submission of emission inventory 
data as described in paragraph (a) of this section for designated facilities that were not in operation at the time of State plan development but began operation during the reporting period. 
(8) Submission of additional data as 
necessary to update the information submitted under paragraph (a) of this section or in previous progress reports. 
(9) Submission of copies of technical 
reports on all performance testing on designated facilities conducted under paragraph (b)(2) of this section, complete with concurrently recorded process data. 
(10) The report must include all other 
required information, as specified in your State plan according to § 60.5740b. 
(c) If you include provisions for the 
compliance date extension, described in § 60.5740b(a)(11), in your State plan, you must report to the EPA the information listed in § 60.5740b(a)(11)(i). 
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(d) If you include provisions for the 
short-term reliability mechanism, 
described in § 60.5740b(a)(12), in your State plan, you must report to the EPA the following information for each event, listed in § 60.5740b(a)(12)(iii). 
(e) If you include provisions for the 
reliability assurance mechanism, 
described in § 60.5740b(a)(13) in your State plan, you must report to the EPA the information listed in § 60.5740b(a)(13)(vi). 
§ 60.5875b How do I submit information 
required by these emission guidelines to the EPA? 
(a) You must submit to the EPA the 
information required by these emission 
guidelines following the procedures in paragraphs (b) through (e) of this section. 
(b) All State plan submittals, 
supporting materials that are part of a State plan submittal, any State plan revisions, and all State reports required to be submitted to the EPA by the State plan must be reported through the EPA’s State Plan Electronic Collection System (SPeCS). SPeCS is a web accessible electronic system accessed at the EPA’s Central Data Exchange (CDX) (http://www.epa.gov/cdx/). States that claim that a State plan submittal or supporting documentation includes confidential business information (CBI) must submit that information on a compact disc, flash drive, or other commonly used electronic storage media to the EPA. The electronic media must be clearly marked as CBI and mailed to U.S. EPA/OAQPS/CORE CBI Office, Attention: State and Local Programs Group, MD C539–01, 4930 Old Page Rd., Durham, NC 27703. 
(c) Only a submittal by the Governor 
or the Governor’s designee by an electronic submission through SPeCS shall be considered an official submittal to the EPA under this subpart. If the Governor wishes to designate another responsible official the authority to submit a State plan, the EPA must be notified via letter from the Governor prior to the May 11, 2026, deadline for State plan submittal so that the official will have the ability to submit the initial or final State plan submittal in the SPeCS. If the Governor has previously delegated authority to make CAA submittals on the Governor’s behalf, a State may submit documentation of the delegation in lieu of a letter from the Governor. The letter or documentation must identify the designee to whom authority is being designated and must include the name and contact information for the designee and also identify the State plan preparers who will need access to SPeCS. A State may also submit the names of the State plan preparers via a separate letter prior to the designation letter from the Governor in order to expedite the State plan administrative process. Required contact information for the designee and preparers includes the person’s title, organization, and email address. 
(d) The submission of the information 
by the authorized official must be in a non-editable format. In addition to the non-editable version all State plan components designated as federally enforceable must also be submitted in an editable version. Following initial State plan approval, States must provide the EPA with an editable copy of any submitted revision to existing approved federally enforceable State plan components, including State plan backstop measures. The editable copy of any such submitted State plan revision must indicate the changes made at the State level, if any, to the existing approved federally enforceable State plan components, using a mechanism such as redline/strikethrough. These changes are not part of the State plan until formal approval by the EPA. 
(e) You must provide the EPA with 
non-editable and editable copies of any submitted revision to existing approved federally enforceable State plan components. The editable copy of any such submitted State plan revision must indicate the changes made at the State level, if any, to the existing approved federally enforceable State plan components, using a mechanism such as redline/strikethrough. These changes are not part of the State plan until formal approval by the EPA. 
§ 60.5876b What are the recordkeeping 
and reporting requirements for EGUs that have committed to permanently cease operations by January 1, 2032? 
(a) If you are the owner or operator of 
an EGU that has committed to 
permanently cease operations by January 1, 2032, you must maintain records for and submit the reports listed in paragraphs (a)(1) through (3) of this section according to the electronic reporting requirements in paragraph (b) of this section. 
(1) Five years before any planned date 
to permanently cease operations or by the date upon which the State plan is submitted, whichever is later, the owner or operator of the EGU must submit an initial report to the EPA that includes the information in paragraphs (a)(1)(i) and (ii) of this section. 
(i) A summary of the process steps 
required for the EGU to permanently cease operation by the date included in the State plan, including the approximate timing and duration of each step and any notification requirements associated with deactivation of the unit. These process steps may include, e.g., initial notice to 
the relevant reliability authority of the deactivation date and submittal of an official retirement filing (or equivalent filing) made to the EGU’s relevant reliability authority. 
(ii) Supporting regulatory documents, 
which include those listed in paragraphs (a)(1)(ii)(A) through (G) of this section: 
(A) Correspondence and official 
filings with the relevant regional RTO, Independent System Operator, Balancing Authority, PUC, or other applicable authority; 
(B) Any deactivation-related 
reliability assessments conducted by the RTO or Independent System Operator; 
(C) Any filings pertaining to the 
affected EGU with the SEC or notices to investors, including but not limited to references in forms 10–K and 10–Q, in which plans for the EGU are mentioned; 
(D) Any integrated resource plans and 
PUC orders approving the EGU’s deactivation; 
(E) Any reliability analyses developed 
by the RTO, Independent System Operator, or relevant reliability authority in response to the EGU’s deactivation notification; 
(F) Any notification from a relevant 
reliability authority that the EGU may be needed for reliability purposes notwithstanding the EGU’s intent to deactivate; and 
(G) Any notification to or from an 
RTO, Independent System Operator, or relevant reliability authority altering the timing of deactivation of the EGU. 
(2) For each of the remaining years 
prior to the date by which an EGU has committed to permanently cease operations, the owner or operator of the EGU must submit an annual status report to the EPA that includes the information listed in paragraphs (a)(2)(i) and (ii) of this section: 
(i) Progress on each of the identified 
process steps identified in the initial report as described in paragraph (a)(1)(i) of this section; and 
(ii) Supporting regulatory documents, 
including correspondence and official filings with the relevant RTO, Independent System Operator, Balancing Authority, PUC, or other applicable authority to demonstrate progress toward all steps described in paragraph (a)(1)(i) of this section. 
(3) The owner or operator must 
submit a final report to the EPA no later than 6 months following its committed closure date. This report must document any actions that the EGU has taken subsequent to ceasing operation to 
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ensure that such cessation is permanent, 
including any regulatory filings with applicable authorities or decommissioning plans. 
(b) Beginning November 12, 2024, if 
you are the owner or operator of an EGU that has committed to permanently cease operations by January 1, 2032, you must submit all the information required in paragraph (a) of this section in a Permanent Cessation of Operation report in PDF format following the procedures specified in paragraph (c) of this section. 
(c) If you are required to submit 
notifications or reports following the procedure specified in this paragraph (c), you must submit notifications or reports to the EPA via the Compliance and Emissions Data Reporting Interface (CEDRI), which can be accessed through the EPA’s Central Data Exchange (CDX) (https://cdx.epa.gov/). The EPA will make all the information submitted through CEDRI available to the public without further notice to you. Do not use CEDRI to submit information you claim as CBI. Although we do not expect persons to assert a claim of CBI, if you wish to assert a CBI claim for some of the information in the report or notification, you must submit a complete file in the format specified in this subpart, including information claimed to be CBI, to the EPA following the procedures in paragraphs (c)(1) and (2) of this section. Clearly mark the part or all of the information that you claim to be CBI. Information not marked as CBI may be authorized for public release without prior notice. Information marked as CBI will not be disclosed except in accordance with procedures set forth in 40 CFR part 2. All CBI claims must be asserted at the time of submission. Anything submitted using CEDRI cannot later be claimed CBI. Furthermore, under CAA section 114(c), emissions data is not entitled to confidential treatment, and the EPA is required to make emissions data available to the public. Thus, emissions data will not be protected as CBI and will be made publicly available. You must submit the same file submitted to the CBI office with the CBI omitted to the EPA via the EPA’s CDX as described earlier in this paragraph (c). 
(1) The preferred method to receive 
CBI is for it to be transmitted 
electronically using email attachments, File Transfer Protocol, or other online file sharing services. Electronic submissions must be transmitted directly to the OAQPS CBI Office at the email address oaqpscbi@epa.gov, and as described above, should include clear CBI markings and be flagged to the attention of the Emission Guidelines for Greenhouse Gas Emissions for Electric Utility Generating Units Sector Lead. If assistance is needed with submitting large electronic files that exceed the file size limit for email attachments, and if you do not have your own file sharing service, please email oaqpscbi@epa.gov to request a file transfer link. 
(2) If you cannot transmit the file 
electronically, you may send CBI information through the postal service to the following address: U.S. EPA Attn: OAQPS Document Control Officer, Mail Drop: C404–02, 109 T.W. Alexander Drive P.O. Box 12055, RTP, NC 27711. All other files should also be sent to the attention of the Greenhouse Gas Emissions for Electric Utility Generating Units Sector Lead. The mailed CBI material should be double wrapped and clearly marked. Any CBI markings should not show through the outer envelope. 
(d) Any records required to be 
maintained by this subpart that are submitted electronically via the EPA’s CEDRI may be maintained in electronic format. This ability to maintain electronic copies does not affect the requirement for facilities to make records, data, and reports available upon request to a delegated air agency or the EPA as part of an on-site compliance evaluation. 
(e) If you are required to electronically 
submit a report through CEDRI in the EPA’s CDX, you may assert a claim of EPA system outage for failure to timely comply with that reporting requirement. To assert a claim of EPA system outage, you must meet the requirements outlined in paragraphs (e)(1) through (7) of this section. 
(1) You must have been or will be 
precluded from accessing CEDRI and submitting a required report within the time prescribed due to an outage of either the EPA’s CEDRI or CDX systems. 
(2) The outage must have occurred 
within the period of time beginning five business days prior to the date that the submission is due. 
(3) The outage may be planned or 
unplanned. 
(4) You must submit notification to 
the Administrator in writing as soon as possible following the date you first knew, or through due diligence should have known, that the event may cause or has caused a delay in reporting. 
(5) You must provide to the 
Administrator a written description identifying: 
(i) The date(s) and time(s) when CDX 
or CEDRI was accessed and the system was unavailable; 
(ii) A rationale for attributing the 
delay in reporting beyond the regulatory deadline to EPA system outage; (iii) A description of measures taken 
or to be taken to minimize the delay in reporting; and 
(iv) The date by which you propose to 
report, or if you have already met the reporting requirement at the time of the notification, the date you reported. 
(6) The decision to accept the claim 
of EPA system outage and allow an extension to the reporting deadline is solely within the discretion of the Administrator. 
(7) In any circumstance, the report 
must be submitted electronically as soon as possible after the outage is resolved. 
(f) If you are required to electronically 
submit a report through CEDRI in the EPA’s CDX, you may assert a claim of force majeure for failure to timely comply with that reporting requirement. To assert a claim of force majeure, you must meet the requirements outlined in paragraphs(f)(1) through (5) of this section. 
(1) You may submit a claim if a force 
majeure event is about to occur, occurs, 
or has occurred or there are lingering effects from such an event within the period of time beginning five business days prior to the date the submission is due. For the purposes of this section, a force majeure event is defined as an event that will be or has been caused by circumstances beyond the control of the affected facility, its contractors, or any entity controlled by the affected facility that prevents you from complying with the requirement to submit a report electronically within the time period prescribed. Examples of such events are acts of nature (e.g., hurricanes, 
earthquakes, or floods), acts of war or terrorism, or equipment failure or safety hazard beyond the control of the affected facility (e.g., large scale power 
outage). 
(2) You must submit notification to 
the Administrator in writing as soon as possible following the date you first knew, or through due diligence should have known, that the event may cause or has caused a delay in reporting. 
(3) You must provide to the 
Administrator: 
(i) A written description of the force 
majeure event; 
(ii) A rationale for attributing the 
delay in reporting beyond the regulatory deadline to the force majeure event; 
(iii) A description of measures taken 
or to be taken to minimize the delay in reporting; and 
(iv) The date by which you propose to 
report, or if you have already met the reporting requirement at the time of the notification, the date you reported. 
(4) The decision to accept the claim 
of force majeure and allow an extension 
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to the reporting deadline is solely 
within the discretion of the Administrator. 
(5) In any circumstance, the reporting 
must occur as soon as possible after the force majeure event occurs. 
(g) Alternatives to any electronic 
reporting required by this subpart must be approved by the Administrator. 
Definitions 
§ 60.5880b What definitions apply to this 
subpart? 
As used in this subpart, all terms not 
defined herein will have the meaning 
given them in the Clean Air Act and in subparts A, Ba, TTTT, and TTTTa, of this part. 
Affected electric generating unit or 
Affected EGU means a steam generating unit that meets the relevant applicability conditions in section § 60.5845b. 
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, as defined below. For a stationary combustion turbine or IGCC, base load rating includes the heat input from duct burners. 
Coal-fired steam generating unit 
means an electric utility steam generating unit or IGCC unit that meets the definition of ‘‘fossil fuel-fired’’ and that burns coal for more than 10.0 percent of the average annual heat input during any continuous 3-calendar-year period after December 31, 2029, or for more than 15.0 percent of the annual heat input during any one calendar year after December 31, 2029, or that retains the capability to fire coal after December 31, 2029. 
Combined cycle unit means a 
stationary combustion turbine from which the heat from the turbine exhaust gases is recovered by a heat recovery steam generating unit to generate additional electricity. 
Combined heat and power unit or 
CHP unit, (also known as ‘‘cogeneration’’) means an electric generating unit that uses a steam- generating unit or stationary combustion turbine to simultaneously produce both electric (or mechanical) and useful thermal output from the same primary energy source. 
Compliance period means an annual 
(calendar year) period for an affected EGU to comply with a standard of 
performance. 
Derate means a decrease in the 
available capacity of an electric generating unit, due to a system or equipment modification or to discounting a portion of a generating unit’s capacity for planning purposes. 
Fossil fuel means natural gas, 
petroleum, coal, and any form of solid fuel, liquid fuel, or gaseous fuel derived from such material for the purpose of creating useful heat. 
Gross energy output means: 
(1) For stationary combustion turbines 
and IGCC, the gross electric or direct 
mechanical output from both the EGU (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander(s)) plus 100 percent of the useful thermal output. 
(2) For steam generating units, the 
gross electric or mechanical output from 
the affected EGU(s) (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander(s)) minus any electricity used to power the feedwater pumps plus 100 percent of the useful thermal output; 
(3) For combined heat and power 
facilities where at least 20.0 percent of the total gross energy output consists of useful thermal output on a 12-operating- month rolling average basis, the gross electric or mechanical output from the affected EGU (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander(s)) minus any electricity used to power the feedwater pumps (the electric auxiliary load of boiler feedwater pumps is not applicable to IGCC facilities), that difference divided by 0.95, plus 100 percent of the useful thermal output. 
Heat recovery steam generating unit 
(HRSG) means a unit in which hot exhaust gases from the combustion turbine engine are routed in order to extract heat from the gases and generate useful output. Heat recovery steam generating units can be used with or without duct burners. 
Integrated gasification combined 
cycle facility or IGCC means a combined 
cycle facility that is designed to burn fuels containing 50 percent (by heat input) or more solid-derived fuel not meeting the definition of natural gas plus any integrated equipment that provides electricity or useful thermal output to either the affected facility or auxiliary equipment. The Administrator may waive the 50 percent solid-derived fuel requirement during periods of the gasification system construction, startup and commissioning, shutdown, or repair. No solid fuel is directly burned in the unit during operation. ISO conditions means 288 Kelvin (15 
°C, 59 °F), 60 percent relative humidity 
and 101.3 kilopascals (14.69 psi, 1 atm) pressure. 
Mechanical output means the useful 
mechanical energy that is not used to operate the affected facility, generate electricity and/or thermal output, or to enhance the performance of the affected facility. Mechanical energy measured in horsepower hour must be converted into MWh by multiplying it by 745.7 then dividing by 1,000,000. 
Nameplate capacity means, starting 
from the initial installation, the maximum electrical generating output that a generator, prime mover, or other electric power production equipment under specific conditions designated by the manufacturer is capable of producing (in MWe, rounded to the nearest tenth) on a steady-state basis and during continuous operation (when not restricted by seasonal or other deratings) as of such installation as specified by the manufacturer of the equipment, or starting from the completion of any subsequent physical change resulting in an increase in the maximum electrical generating output that the equipment is capable of producing on a steady-state basis and during continuous operation (when not restricted by seasonal or other deratings), such increased maximum amount (in MWe, rounded to the nearest tenth) as of such completion as specified by the person conducting the physical change. 
Natural gas means a fluid mixture of 
hydrocarbons (e.g., methane, ethane, or 
propane), composed of at least 70 percent methane by volume or that has a gross calorific value between 35 and 41 megajoules (MJ) per dry standard cubic meter (950 and 1,100 Btu per dry standard cubic foot), that maintains a gaseous state under ISO conditions. 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 CO
2content or 
heating value. 
Natural gas-fired steam generating 
unit means an electric utility steam 
generating unit meeting the definition of ‘‘fossil fuel-fired,’’ that is not a coal- fired or oil-fired steam generating unit, that no longer retains the capability to fire coal after December 31, 2029, and that burns natural gas for more than 10.0 percent of the average annual heat input during any continuous 3-calendar-year period after December 31, 2029, or for more than 15.0 percent of the annual 
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heat input during any calendar year 
after December 31, 2029. 
Net electric output means the amount 
of gross generation the generator(s) produce (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander(s)), as measured at the generator terminals, less the electricity used to operate the plant (i.e., auxiliary 
loads); such uses include fuel handling equipment, pumps, fans, pollution control equipment, other electricity needs, and transformer losses as measured at the transmission side of the step up transformer (e.g., the point of 
sale). 
Net energy output means: 
(1) The net electric or mechanical 
output from the affected facility, plus 
100 percent of the useful thermal output measured relative to standard ambient temperature and pressure conditions that is not used to generate additional electric or mechanical output or to enhance the performance of the unit (e.g., steam delivered to an industrial 
process for a heating application). 
(2) For combined heat and power 
facilities where at least 20.0 percent of the total gross or net energy output consists of electric or direct mechanical output and at least 20.0 percent of the total gross or net energy output consists of useful thermal output on a 12- operating month rolling average basis, the net electric or mechanical output from the affected EGU divided by 0.95, plus 100 percent of the useful thermal output; (e.g., steam delivered to an 
industrial process for a heating application). 
Oil-fired steam generating unit means 
an electric utility steam generating unit meeting the definition of ‘‘fossil fuel- fired’’ that is not a coal-fired steam generating unit, that no longer retains the capability to fire coal after December 31, 2029, and that burns oil for more than 10.0 percent of the average annual heat input during any continuous 3- calendar-year period after December 31, 2029, or for more than 15.0 percent of the annual heat input during any one calendar year after December 31, 2029. 
Standard ambient temperature and 
pressure (SATP) conditions means 
298.15 Kelvin (25 °C, 77 °F) and 100.0 
kilopascals (14.504 psi, 0.987 atm) pressure. The enthalpy of water at SATP conditions is 50 Btu/lb. 
State agent means an entity acting on 
behalf of the State, with the legal authority of the State. 
Stationary combustion turbine means 
all equipment including, but not limited to, the turbine engine, the fuel, air, lubrication and exhaust gas systems, control systems (except emissions control equipment), heat recovery system, fuel compressor, heater, and/or pump, post-combustion emission control technology, and any ancillary components and sub-components comprising any simple cycle stationary combustion turbine, any combined cycle combustion turbine, and any combined heat and power combustion turbine based system plus any integrated equipment that provides electricity or useful thermal output to the combustion turbine engine, heat recovery system, or auxiliary equipment. Stationary means that the combustion turbine is not self-propelled or intended to be propelled while performing its function. It may, however, be mounted on a vehicle for portability. A stationary combustion turbine that burns any solid fuel directly is considered a steam generating unit. 
Steam generating unit means any 
furnace, boiler, or other device used for combusting fuel and producing steam (nuclear steam generators are not included) plus any integrated equipment that provides electricity or useful thermal output to the affected facility or auxiliary equipment. 
System Emergency means periods 
when the Reliability Coordinator has declared an Energy Emergency Alert level 2 or 3 as defined by NERC Reliability Standard EOP–011–2, or its successor. 
Uprate means an increase in available 
electric generating unit power capacity due to a system or equipment modification. 
Useful thermal output means the 
thermal energy made available for use in any heating application (e.g., steam 
delivered to an industrial process for a heating application, including thermal cooling applications) that is not used for electric generation, mechanical output at the affected EGU, to directly enhance the performance of the affected EGU (e.g., economizer output is not useful 
thermal output, but thermal energy used to reduce fuel moisture is considered useful thermal output), or to supply energy to a pollution control device at the affected EGU. Useful thermal output for affected EGU(s) with no condensate return (or other thermal energy input to the affected EGU(s)) or where measuring the energy in the condensate (or other thermal energy input to the affected EGU(s)) would not meaningfully impact the emission rate calculation is measured against the energy in the thermal output at SATP conditions. Affected EGU(s) with meaningful energy in the condensate return (or other thermal energy input to the affected EGU) must measure the energy in the condensate and subtract that energy relative to SATP conditions from the measured thermal output. 
Valid data means quality-assured data 
generated by continuous monitoring systems that are installed, operated, and maintained according to 40 CFR part 75. For CEMS, the initial certification requirements in 40 CFR 75.20 and appendix A to 40 CFR part 75 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 40 CFR part 75 must be met and the data validation criteria in sections 2.1.4, 2.2.3, and 2.3.2 of appendix B to 40 CFR part 75 apply. For fuel flow meters, the initial certification requirements in section 2.1.5 of appendix D to 40 CFR part 75 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 40 CFR part 75 apply (except for qualifying commercial billing meters). 
Waste-to-Energy means a process or 
unit (e.g., solid waste incineration unit) 
that recovers energy from the conversion or combustion of waste stream materials, such as municipal solid waste, to generate electricity and/ or heat. 
[FR Doc. 2024–09233 Filed 5–8–24; 8:45 am] 
BILLING CODE 6560–50–P 
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