6560-50-P
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 60
[EPA-HQ-OAR-2023-0072; FRL-XXXX]
RIN 2060-AV09 and 2060-AV10
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: Proposed rule.
SUMMARY: The Environmental Protection Agency (EPA) is proposing amendments to the new source performance standards (NSPS) for greenhouse gas (GHG) emissions from new fossil fuel-fired stationary combustion turbine electric generating units (EGUs) based upon the eight-year review required by the Clean Air Act (CAA). The EPA is also proposing to repeal the Affordable Clean Energy rule (ACE Rule) and is proposing new 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fuel-fired steam generating EGUs, which include both coal-fired and oil/gas-fired steam generating EGUs, to replace the repealed ACE Rule.
DATES: Comments. Comments must be received on or before [INSERT DATE 60 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]. Comments on the information collection provisions submitted to the Office of Management and Budget (OMB) under the Paperwork Reduction Act (PRA) are best assured of consideration by OMB if OMB receives a copy of your comments on or before [INSERT DATE 30 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER].
Public Hearing. The EPA will hold a virtual public hearing on [INSERT DATE 15 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER] and [INSERT DATE 16 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]. See SUPPLEMENTARY INFORMATION for information on registering for a public hearing.
ADDRESSES: You may send comments, identified by Docket ID No. EPA-HQ-OAR-2023-0072, by any of the following methods:
 Federal eRulemaking Portal: https://www.regulations.gov (our preferred method). Follow the online instructions for submitting comments.
 Email<EMAIL_ADDRESS>Include Docket ID No. EPA-HQ-OAR-2023-0072 in the subject line of the message.
 Fax:<PHONE_NUMBER>. Attention Docket ID No. EPA-HQ-OAR-2023-0072.
 Mail: U.S. Environmental Protection Agency, EPA Docket Center, Docket ID No. EPA-HQ-OAR-2023-0072, Mail Code 28221T, 1200 Pennsylvania Avenue, NW, Washington, DC 20460.
 Hand/Courier Delivery: EPA Docket Center, WJC West Building, Room 3334, 1301 Constitution Avenue, NW, Washington, DC 20004. The Docket Center's hours of operation are 8:30 a.m. - 4:30 p.m., Monday - Friday (except Federal holidays).
Instructions: All submissions received must include the Docket ID No. for this rulemaking. Comments received may be posted without change to https://www.regulations.gov, including any personal information provided. For detailed instructions on sending comments and additional information on the rulemaking process, see the SUPPLEMENTARY INFORMATION section of this document.
FOR FURTHER INFORMATION CONTACT: For questions about this proposed action, contact Mr. Christian Fellner, Sector Policies and Programs Division (D243-02), Office of Air Quality Planning and Standards, U.S. Environmental Protection Agency, Research Triangle Park, North Carolina 27711; telephone number:<PHONE_NUMBER>; and email address<EMAIL_ADDRESS>and Ms. Lisa Thompson, Sector Policies and Programs Division (D243-02), Office of Air Quality Planning and Standards, U.S. Environmental Protection Agency, Research Triangle Park, North Carolina 27711; telephone number:<PHONE_NUMBER>; and email address<EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION:
Participation in virtual public hearing. The public hearing will be held via virtual platform on [INSERT DATE 15 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER] and [INSERT DATE 16 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER] and will convene at 11:00 a.m. Eastern Time (ET) and conclude at 7:00 p.m. ET each day. If the EPA receives a high volume of registrations for the public hearing, the EPA may continue the public hearing on [INSERT DATE 17 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]. On each hearing day, the EPA may close a session 15 minutes after the last pre-registered speaker has testified if there are no additional speakers. The EPA will announce further details at https://www.epa.gov/stationary-sources-air-pollution/clean-air-act-standards-and-guidelines-electric-utilities.
The EPA will begin pre-registering speakers for the hearing no later than 1 business day following the publication of this document in the Federal Register. The EPA will accept registrations on an individual basis. To register to speak at the virtual hearing, please use the online registration form available at https://www.epa.gov/stationary-sources-air-pollution/clean-air-act-standards-and-guidelines-electric-utilities or contact the public hearing team at<PHONE_NUMBER> or by email at<EMAIL_ADDRESS>The last day to pre-register to speak at the hearing will be [INSERT DATE 12 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]. Prior to the hearing, the EPA will post a general agenda that will list pre-registered speakers in approximate order at: https://www.epa.gov/stationary-sources-air-pollution/clean-air-act-standards-and-guidelines-electric-utilities.
The EPA will make every effort to follow the schedule as closely as possible on the day of the hearing; however, please plan for the hearings to run either ahead of schedule or behind schedule.
Each commenter will have 4 minutes to provide oral testimony. The EPA encourages commenters to provide the EPA with a copy of their oral testimony by submitting the text of your oral testimony as written comments to the rulemaking docket.
The EPA may ask clarifying questions during the oral presentations but will not respond to the presentations at that time. Written statements and supporting information submitted during the comment period will be considered with the same weight as oral testimony and supporting information presented at the public hearing.
Please note that any updates made to any aspect of the hearing will be posted online at https://www.epa.gov/stationary-sources-air-pollution/clean-air-act-standards-and-guidelines-electric-utilities. While the EPA expects the hearing to go forward as described in this section, please monitor our website or contact the public hearing team at<PHONE_NUMBER> or by email at<EMAIL_ADDRESS>to determine if there are any updates. The EPA does not intend to publish a document in the Federal Register announcing updates.
If you require the services of an interpreter or a special accommodation such as audio description, please pre-register for the hearing with the public hearing team and describe your needs by [INSERT DATE 7 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]. The EPA may not be able to arrange accommodations without advanced notice.
Docket. The EPA has established a docket for these rulemakings under Docket ID No. EPA-HQ-OAR-2023-0072. All documents in the docket are listed in the Regulations.gov index. Although listed in the index, 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.
Written Comments. Direct your comments to Docket ID No. EPA-HQ-OAR-2023-0072 at https://www.regulations.gov (our preferred method), or the other methods identified in the ADDRESSES section. Once submitted, comments cannot be edited or removed from the docket. The EPA may publish any comment received to its public docket. Do not submit to the EPA's docket at https://www.regulations.gov any information you consider to be Confidential Business Information (CBI) or other information whose disclosure is restricted by statute. This type of information should be submitted as discussed in the Submitting CBI section of this document.
Multimedia submissions (audio, video, etc.) must be accompanied by a written comment. The written comment is considered the official comment and should include discussion of all points you wish to make. The EPA will generally not consider comments or comment contents located outside of the primary submission (i.e., on the Web, cloud, or other file sharing system). Please visit https://www.epa.gov/dockets/commenting-epa-dockets for additional submission methods; the full EPA public comment policy; information about CBI or multimedia submissions; and general guidance on making effective comments.
The https://www.regulations.gov website allows you to submit your comment anonymously, which means the EPA will not know your identity or contact information unless you provide it in the body of your comment. If you send an email comment directly to the EPA without going through https://www.regulations.gov, your email address will be automatically captured and included as part of the comment that is placed in the public docket and made available on the Internet. If you submit an electronic comment, the EPA recommends that you include your name and other contact information in the body of your comment and with any digital storage media you submit. If the EPA cannot read your comment due to technical difficulties and cannot contact you for clarification, the EPA may not be able to consider your comment. Electronic files should not include special characters or any form of encryption and should be free of any defects or viruses.
Submitting CBI. Do not submit information containing CBI to the EPA through https://www.regulations.gov. Clearly mark the part or all of the information that you claim to be CBI. For CBI information on any digital storage media that you mail to the EPA, note the docket ID, mark the outside of the digital storage media as CBI, and identify electronically within the digital storage media the specific information that is claimed as CBI. In addition to one complete version of the comments that includes information claimed as CBI, you must submit a copy of the comments that does not contain the information claimed as CBI directly to the public docket through the procedures outlined in Written Comments section of this document. If you submit any digital storage media that does not contain CBI, mark the outside of the digital storage media clearly that it does not contain CBI and note the docket ID. Information not marked as CBI will be included in the public docket and the EPA's electronic public docket without prior notice. Information marked as CBI will not be disclosed except in accordance with procedures set forth in 40 Code of Federal Regulations (CFR) part 2.
Our preferred method to receive CBI is for it to be transmitted electronically using email attachments, File Transfer Protocol (FTP), or other online file sharing services (e.g., Dropbox, OneDrive, Google Drive). Electronic submissions must be transmitted directly to the OAQPS CBI Office at the email address<EMAIL_ADDRESS>and, as described above, should include clear CBI markings and note the docket ID. 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<EMAIL_ADDRESS>to request a file transfer link. If sending CBI information through the postal service, please send it to the following address: OAQPS Document Control Officer (C404-02), OAQPS, U.S. Environmental Protection Agency, Research Triangle Park, North Carolina 27711, Attention Docket ID No. EPA-HQ-OAR-2023-0072. The mailed CBI material should be double wrapped and clearly marked. Any CBI markings should not show through the outer envelope.
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
BACT		best available control technology
BSER 		best system of emissions reduction
Btu		British thermal unit
CAA 		Clean Air Act
CBI		Confidential Business Information
CCS		carbon capture and storage
CCUS		carbon capture, utilization, and storage
CFR 		Code of Federal Regulations
CHP		combined heat and power
CO2		carbon dioxide
CO2e		carbon dioxide equivalent
CPP		Clean Power Plan
CSAPR	Cross-State Air Pollution Rule
DOE		Department of Energy
DOI		Department of the Interior
DOT		Department of Transportation
EGU		electric generating unit
EIA		Energy Information Administration
EJ		environmental justice
EO		Executive Order
EOR		enhanced oil recovery
EPA 		Environmental Protection Agency
FEED		front-end engineering and design
FGD		flue gas desulfurization
FR		Federal Register
FrEDI		Framework for Evaluating Damages and Impacts
GHG		greenhouse gas
GHGRP	Greenhouse Gas Reporting Program
GW		gigawatt
HHV		higher heating value
HRSG		heat recovery steam generator
IBR	incorporate by reference
ICR	information collection request
IGCC		integrated gasification combined cycle
IIJA		Infrastructure Investment and Jobs Act
IPCC		Intergovernmental Panel on Climate Change
IRC		Internal Revenue Code
IRP		integrated resource plan
kg		kilogram
kWh		kilowatt-hour
LCOE		levelized cost of electricity
LHV		lower heating value
LNG		liquefied natural gas
MMBtu/hr	million British thermal units per hour
MMst		million short tons
MMT CO2e	million metric tons of carbon dioxide equivalent
MW		megawatt
MWh		megawatt-hour
NAAQS	National Ambient Air Quality Standards
NAICS	North American Industry Classification System
NCA4		2017 - 2018 Fourth National Climate Assessment
NETL		National Energy Technology Laboratory
NGCC		natural gas combined cycle
NOx		nitrogen oxides
NREL		National Renewable Energy Laboratory
NSPS 		new source performance standards
NSR		New Source Review
OMB 		Office of Management and Budget
PM		particulate matter
PSD		Prevention of Significant Deterioration
PUC		public utilities commission
RIA		regulatory impact analysis
RPS		renewable portfolio standard
SCR		selective catalytic reduction
SIP		state implementation plan
U.S.		United States
U.S.C.		United States Code

Organization of this document. The information in this preamble is organized as follows:

I. Executive Summary
A. Climate Change and the Power Sector
B. State of the Power Sector
C. Overview of the Proposals
II. General Information
A. Action Applicability
B. Where to Get a Copy of This Document and Other Related Information
C. Organization and Approach for These Proposed Rules
III. Climate Change and Its Impacts
IV. State of the Electric Power Sector
A. Introduction
B. Background
C. Recent Changes in the Power Sector
D. GHG Emissions from Fossil Fuel-fired EGUs
E. Drivers for Ongoing Change
F. 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
VI. Stakeholder Engagement
VII. Proposed Requirements for New and Reconstructed Stationary Combustion Turbine EGUs and Rationale for Proposed 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. Proposed 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. Summary of Other Solicitations of Comment and Proposed Requirements
N. Compliance Dates
VIII. Requirements for New, Modified, and Reconstructed Fossil Fuel-fired Steam Generating Units
A. Overview
B. Eight-year Review of NSPS for Fossil Fuel-fired Steam Generating Units
C. Projects Under Development
IX. Proposed ACE Repeal
A. Imprecise BSER and Degree of Emission Limitation
B. Inappropriately Low Level Of Emission Reductions From Longer-term Sources;
C. Inside-the-Fenceline Interpretation for BSER and Compliance Flexibilities
D. No Benefits to Implementing ACE Rule on an Interim Basis
X. Proposed Regulatory Approach for Existing Fossil Fuel-fired Steam Generating Units
A. Overview
B. Applicability Requirements for Existing Fossil Fuel-fired Steam Generating Units
C. Subcategorization of Fossil Fuel-fired Steam Generating Units
D. Determination of BSER for Coal-fired Steam Generating Units
E. Natural Gas-fired and Oil-fired Steam Generating Units
XI. State Plans for Proposed Emission Guidelines for Existing Fossil Fuel-fired EGUs
A. Overview
B. Compliance Deadlines
C. Requirement for State Plans to Maintain Stringency of the EPA's BSER Determination
D. Establishing Standards of Performance
E. Compliance Flexibilities
F. State Plan Components and Submission
XII. Solicitation of Comments on the BSER for Existing Gas Combustion Turbines
XIII. Outreach and Engagement with Environmental Justice Communities
XIV. Implications for Other EPA Programs and Rules
A. Implications for New Source Review (NSR) Program
B. Implications for Title V Program
C. EPA Partnership Programs
XV. Impacts of Proposed Actions
A. Air Quality Impacts
B. Compliance Cost Impacts
C. Economic Impacts
D. Benefits
E. Environmental Justice Analysis
F. Reliable Electricity
XVI. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and Executive Order 13563: Improving Regulation and Regulatory Review
B. Paperwork Reduction Act (PRA)
C. Regulatory Flexibility Act (RFA)
D. Unfunded Mandates Reform Act 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

Executive Summary
In 2009, the EPA concluded that GHG emissions endanger our nation's public health and welfare. In 2015, the EPA further concluded that fossil fuel-fired EGUs  -  which at that time were the nation's largest source of GHG emissions, and in 2020 represented 25 percent of total emissions  -  significantly contribute to that endangerment. 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.
In these actions, the EPA is proposing requirements to reduce emissions from new and reconstructed fossil fuel-fired stationary combustion turbine EGUs (primarily natural gas-fired turbines) and existing fossil fuel-fired steam generating EGUs (primarily coal-fired utility boilers). The EPA is also soliciting comment on options to address GHGs from existing fossil fuel-fired stationary combustion turbine EGUs (primarily natural gas-fired). These proposed requirements focus on technologies, such as carbon capture and storage (CCS), hydrogen co-firing, and natural gas co-firing, that can be applied directly to the sources in question.
These proposed requirements are informed by recent market and policy developments that are driving rapid changes in overall generating capacity and patterns of utilization for new and existing fossil fuel-fired EGUs. A number of factors are leading to significant changes in the way electricity is generated in this country that are changing the economics of both coal- and gas-fired generation. The power sector has innovated, developing new tools to reduce GHG emissions from its sources, and states have implemented a range of different programs to reduce GHGs from the power sector. Congress has also acted in significant ways affecting the power sector, providing funding and other incentives to spur the deployment of low GHG technologies and encourage reductions in GHG emissions. These significant trends have played an important role in the EPA's understanding of the economics of the control technologies that were evaluated to design these proposals, as well as the impacts of the proposed standards on this sector.
These proposals address the statutory command of section 111 of the Clean Air Act (CAA) -- to establish standards of performance for emissions of air pollutants that reflect application of the best system of emissions reduction (BSER) -- by leveraging adequately demonstrated GHG control technologies to significantly reduce emissions of dangerous pollution from fossil fuel-fired EGUs, taking into account costs, energy requirements, and other statutory factors. The EPA is proposing to update and establish more protective NSPS for GHG emissions from new and reconstructed fossil fuel-fired stationary combustion turbine EGUs to take advantage of advancements in efficiency, hydrogen co-firing, and CCS. The EPA is also proposing to repeal the ACE Rule and is proposing new emission guidelines to replace the repealed ACE Rule. The EPA is proposing emission guidelines for GHG emissions from existing fossil fuel-fired steam generating EGUs, taking advantage of advancements in CCS and the availability of natural gas co-firing, and paying due attention to the real-world changes that are underway for those EGUs as they age and face significant economic competition from other electricity generating technologies. The EPA is also soliciting comment on how the Agency should approach its legal obligation to establish emission guidelines for existing fossil fuel-fired combustion turbine EGUs.
In all of these efforts, the EPA seeks to ensure that EGUs reduce their GHG emissions in a cost-effective and achievable way to address the danger posed by those emissions, mindful of the guidance the EPA has received from the courts. These proposed standards and emission guidelines, if finalized, would significantly decrease the GHG emissions from fossil fuel-fired EGUs and the associated harms to human health and welfare. The EPA has designed these proposed standards and emission guidelines in a way that is compatible with the nation's overall need for a reliable supply of electricity.
Climate Change and the Power Sector
These proposals focus on reducing the emissions of GHGs from the power sector. 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 threatens human welfare.
The power sector in the United States (U.S.) is both a key contributor to the cause of climate change and a key component of the solution to the climate challenge. In 2020, the power sector was the largest stationary source of GHGs, emitting 25 percent of the overall domestic emissions. These emissions are almost entirely the result of the combustion of fossil fuels in the EGUs that are the subjects of these proposals.
The power sector possesses many opportunities to contribute to solutions to the climate challenge. Particularly relevant to these proposals are several key technologies (co-firing of low-GHG fuels and CCS) that can allow steam generating EGUs and stationary combustion turbines (the focus of these proposals) to provide power while emitting significantly less GHG emissions. Moreover, with the increased drive to electrify other GHG-emitting sectors of the economy, such as personal vehicles, heavy-duty trucks, and the heating and cooling of buildings, a power sector with lower GHG emissions can also help reduce pollution coming from other sectors of the economy.
State of the Power Sector
These proposals occur at a time of great and accelerating change in the power sector. As the existing fossil fuel-fired fleet ages (as of late 2021, the average age of the coal-fired fleet was 45 years old), Federal and state legislation, technology advancements, market forces, and consumer demand are pushing the industry toward increased use of new lower-emitting generation sources and away from the higher-emitting fossil fuel-fired units that are the subjects of these proposals. Between 2010 and 2021, fossil fuel-fired generation declined from approximately 70 percent of total net generation to approximately 60 percent, with coal generation dropping most precipitously, from 46 percent to 23 percent of net generation during the period. The economics of the power sector have shifted dramatically and technological innovations have increasingly made low- and zero-emitting sources more competitive with fossil fuel-derived power generating sources.
Many utilities and power generating companies have already announced GHG reduction commitments as they further analyze and consider the incentives of the recently enacted Inflation Reduction Act (IRA), which is discussed in greater detail later in this preamble. These utilities and companies have also announced their intention to retire a significant number of their remaining coal-fired EGUs. Some are replacing those coal-fired units with natural gas-fired combustion turbines while others are replacing those units with alternatives such as renewable generating sources and energy storage. Some companies are planning to install combustion turbines with advanced technologies to limit GHG emissions, including CCS and hydrogen co-firing (with a number of companies having announced plans to ultimately move to 100 percent hydrogen firing) and advanced energy storage technologies that either have longer storage capacity than lithium-ion batteries and/or use more common materials and are lower cost. Others are exploring the use of advanced technologies such as distributed generation through the use of virtual power plants and small modular nuclear reactors. As more renewables come online and as these technologies become more widely deployed, many experts have projected that utilization of natural gas-fired combustion turbine EGUs will significantly decrease. Indeed, the Post-IRA 2022 reference case modeling for this proposal projects lower utilization relative to current levels of stationary combustion turbines even without consideration of advanced energy storage, virtual power plants, and small modular nuclear reactors (see section IV.F. of this preamble).
The power sector's trajectory has also been greatly influenced by the actions of state governments that are interested in limiting GHG pollution for the benefit of their citizens. More than two-thirds of states have enacted policies to require utilities to increase the amount of electricity generated from sources that emit no GHGs. Other states have recently enacted significant legislation requiring the decarbonization of their utility fleets, using devices such as carbon markets, low-GHG emission standards, carbon capture and storage mandates, utility planning, or mandatory retirement schedules.
During this time of dynamic change, Congress enacted historic investments in GHG reductions. Through the Infrastructure Investment and Jobs Act (IIJA), Congress infused more than $65 billion of infrastructural investments and upgrades that will provide needed transmission capacity, pipelines, and low-carbon fuels (such as low-GHG hydrogen) for the power sector. In addition, 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 will provide additional low-cost options for power companies to reduce overall GHG emissions.
Perhaps the most significant effects for the power sector will result from the IRA, which was signed into law on August 16, 2022. With billions of dollars in investments in the transition to clean energy, the IRA promises to promote industrial investment toward low- and non-GHG emitting generation at a much faster pace. The IRA's provisions represent a cross-sectoral drive to push the power sector away from GHG-emitting sources through a broad array of tax credits, loan guarantees, and public investment programs. These provisions are not only aimed at creating incentives for new cleaner generating assets that are not subject to this proposal, but also at limiting GHG emissions from the fossil fuel-fired generating sources that are the subjects of these proposals, with tax credits for use of CCS and for hydrogen production and use that provide pathways for the use of fossil fuels as part of a low-carbon electricity grid.
These proposals focus on just such "measures that improve the pollution performance of individual sources." While the legislative programs described are considered in the regulatory impact analysis (RIA) as part of the Agency's overall assessment of the costs, benefits, and power sector impacts of these proposals, the EPA has not considered shifts in generation (either among different fossil generation technologies or to non-fossil technologies) in determining the BSER. As described in more detail below, the EPA has also designated subcategories of fossil fuel-fired EGUs that correspond with the power sector's ongoing and rapid transition, and take account of how recent legislative, policy, and market developments affect the emission reductions, costs, and feasibility of GHG control technologies for improving the pollution performance of the specific types of EGUs for which the EPA is proposing standards of performance and emission guidelines in this rulemaking. While the EPA has focused on ensuring that sources that have the potential to emit large amounts of GHGs and that will be providing power over a long time horizon install technologies that address these emissions, the EPA has also analyzed the cost reasonableness of installing such equipment at sources that may be retiring in the shorter term and has designed this proposal to avoid the need to install highly capital-intensive control equipment at those sites.
The EPA also recognizes that these proposals are not the only recent regulatory actions impacting these sources and is attempting, consistent with its statutory obligations under CAA section 111, to establish NSPS and emission guidelines that are well-aligned with other known regulatory obligations. This will enable owners and operators of EGUs to make informed investment decisions moving forward. Finally, given the pace of the projected transition within the power sector, the EPA understands that careful planning is needed to ensure that compliance with the provisions of these proposals does not result in any generation deficiencies that will undercut the delivery of reliable power to customers. With that in mind, the EPA has included in these proposals the flexibility operators need to achieve critical reductions of GHGs from these sources while ensuring grid reliability. These proposals consider each of these factors.
Overview of the Proposals
These actions include proposed BSER determinations and accompanying standards of performance for GHG emissions from new and reconstructed fossil fuel-fired stationary combustion turbines, proposed BSER determinations and proposed emission guidelines for existing fossil fuel-fired steam generating units, and solicitation for comment on potential BSER options and emission guidelines for existing fossil fuel-fired stationary combustion turbines.
For new and reconstructed fossil fuel-fired combustion turbines, the EPA is proposing to create three subcategories based on the function the combustion turbine serves: a low load ("peaking units") subcategory that consists of combustion turbines with a capacity factor of less than 20 percent; an intermediate load subcategory for combustion turbines with a capacity factor that ranges between 20 percent and a source-specific upper bound that is based on the design efficiency of the combustion turbine; and a base load subcategory for combustion turbines that operate above the upper-bound threshold for intermediate load turbines. This subcategorization approach is similar to the current NSPS for these sources, which includes separate subcategories for base load and non-base load units.
For the low load subcategory, the EPA is proposing that the BSER is the use of clean fuels (e.g., natural gas and distillate oil) with standards of performance ranging from 120 lb CO2/MMBtu to 160 lb CO2/MMBtu, depending on the type of fuel combusted. For the intermediate load and base load subcategories, the EPA is proposing an approach in which the BSER has two components -- (1) highly efficient generation; and (2) depending on the subcategory, use of CCS or co-firing low-GHG hydrogen.
These components form the basis of a standard of performance that applies in two phases. That is, affected facilities  -  which are facilities that commence construction or reconstruction after the date of publication in the Federal Register of this proposed rulemaking  -  must meet the first phase of the standard of performance, based on application of the first component of the BSER, highly efficient generation, by the date the rule is promulgated. They must also meet the second and more stringent phase of the standard of performance, which is based on application of both the first component and the second component of the BSER, which is the use of CCS or co-firing low-GHG hydrogen, by 2035. It should be noted that although the first phase of the standard of performance is based on only the application of the first component of the BSER, the second phase is based on the application of both components. Indeed, utilization of highly efficient generation is a logical complement to both CCS and co-firing of low-GHG hydrogen because, from both an economic and emissions perspective, that configuration will provide the greatest reductions at the lowest cost. This approach reflects the EPA's view that the BSER for the intermediate load and base load subcategories should reflect the deeper reductions in GHG emissions that can be achieved by implementing CCS and co-firing low-GHG hydrogen with the most efficient stationary combustion turbine configuration available, but, is proposing compliance begin in 2035, recognizes that building the infrastructure required to support wider spread use of CCS and qualified low-GHG hydrogen in the power sector will take place on a multi-year time scale.
More specifically, with respect to the first phase of the standards of performance, the EPA is proposing that the BSER for both the intermediate load and base load subcategories includes highly efficient generating technology (i.e., the most efficient available turbines). For the intermediate load subcategory, the EPA is proposing that the BSER includes highly efficient simple cycle turbine technology with an associated first phase standard of 1,150 lb CO2/MWh-gross. For the base load subcategory, the EPA is proposing that the BSER includes highly efficient combined cycle technology with an associated first phase standard of 770 lb CO2/MWh-gross for larger combustion turbine EGUs with a base load rating of 2,000 MMBtu/h or more. For smaller base load combustion turbines (with a base load rate less than 2,000 MMBtu/h), the proposed associated standard would range from 770 to 900 lb CO2/MWh-gross depending on the specific base load rating of the combustion turbine. These standards would apply immediately upon the effective date of the final rule.
With respect to the second phase of the standards of performance, compliance with which would be required in 2035, for the intermediate load subcategory, the EPA is proposing that the BSER includes co-firing 30 percent low-GHG hydrogen with an associated standard of 1,000 lb CO2/MWh. For the base load subcategory, the EPA is proposing to subcategorize further into base load units that are not combusting at least 10 percent hydrogen, and base load units that are combusting at least 10 percent hydrogen. For the subcategory of base load units that are not combusting at least 10 percent hydrogen, the EPA is proposing that the BSER includes the use of CCS with 90 percent capture of CO2 with an associated standard of 90 lb CO2/MWh. For the subcategory of base load units that are combusting at least 10 percent hydrogen, the EPA is proposing that the BSER includes co-firing 30 percent low-GHG hydrogen with an associated standard of 680 lb CO2/MWh.
This preamble also announces the Agency's intention to rescind a 2018 proposal to amend the NSPS for new, reconstructed, and modified coal-fired steam generating units. Additionally, the EPA is also proposing to repeal the existing ACE Rule emission guidelines.
For the emission guidelines for existing coal-fired steam generating units, the EPA is proposing to create four subcategories based on the operating horizon of the units. The EPA recognizes that the coal-fired steam generating EGU fleet is aging and that many owners and operators are considering or have already announced plans to cease operation of their units between now and 2040. Therefore, the EPA is proposing that, for the subcategory of coal-fired steam generating units with the longest operating horizons, i.e., those that plan to operate past December 31, 2039, the BSER is the use of CCS with 90 percent capture of CO2 with an associated degree of emission limitation of an 88.4 percent reduction in emission rate (lb CO2/MWh-gross basis). For coal-fired steam generating units with medium-term operating horizons, i.e., those that operate after December 31, 2031 and that choose to adopt federally enforceable commitments to permanently cease operations before January 1, 2040 and that do not meet the definition of near-term units, the EPA is proposing that the BSER is co-firing 40 percent natural gas on a heat input basis with an associated degree of emission limitation of a 16 percent reduction in emission rate (lb CO2/MWh-gross basis). For units with operating horizons that are imminent-term, i.e., those that choose to adopt federally enforceable commitments to permanently cease operations before January 1, 2032, or near-term, i.e., those that choose to adopt a federally enforceable commitment to permanently cease operations after January1, 2035 and that choose to adopt a federally enforceable annual capacity factor limit of 20 percent, the EPA is proposing that the BSER is routine methods of operation and maintenance with associated degrees of emission limitation of no increase in emission rate (lb CO2/MWh-gross basis). Finally, for the emission guidelines for existing natural gas-fired and oil-fired steam generating units, the EPA is, in general, also proposing that the BSER is routine methods of operation and maintenance with an associated degree of emission limitation of no increase in emission rate (lb CO2/MWh-gross).
For the emission guidelines for existing steam generating units, the EPA is also proposing state plan requirements, including submittal timelines for state plans and methodologies for determining presumptively approvable standards of performance consistent with BSER. This proposal also addresses how states can implement the remaining useful life and other factors (RULOF) provision of CAA section 111(d) and how states can conduct meaningful engagement with impacted stakeholders. Finally, this proposal discusses considerations related to the appropriateness of including emission trading or averaging in state plans.
Finally, the EPA is soliciting comment on a number of variations to the subcategories, BSER determinations, degrees of emission limitation, and standards of performance summarized above, as well as a BSER determination and degrees of emission limitation for existing fossil fuel-fired stationary combustion turbines.
General Information
Action Applicability
The source category that is the subject of these actions is comprised of the fossil fuel-fired electric utility generating units regulated under CAA section 111. 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 proposed actions are likely to affect.
The proposed amendments to 40 CFR part 60, subpart TTTT, once promulgated, will be directly applicable to affected facilities that began construction after January 8, 2014 and affected facilities that began reconstruction or modification after June 18, 2014. The proposed NSPS, proposed to be codified in 40 CFR part 60, subpart TTTTa, once promulgated, will be directly applicable to affected facilities that begin construction or reconstruction after the date of publication of the proposed standards in the Federal Register. Federal, state, local, and tribal government entities that own and/or operate EGUs subject to 40 CFR part 60, subparts TTTT or TTTTa would be affected by these proposed amendments and standards.
The proposed emission guidelines for GHG emissions from fossil fuel-fired EGUs proposed to be codified in 40 CFR part 60, subpart UUUUb, once promulgated, will be applicable to states in the development and submittal of state plans pursuant to CAA section 111(d). After the EPA promulgates a final emission guideline, each state that has one or more designated facilities must develop, adopt, and submit to the EPA a state plan under CAA section 111(d). The 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). If a state fails to submit a plan or the EPA determines that a state plan is not satisfactory, the EPA has the authority to establish a Federal CAA section 111(d) plan in such instances.
Under the Tribal Authority Rule adopted by the EPA, tribes may seek authority 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 an emission guideline. 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. 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 a TIP applicable to those facilities.
Where to Get a Copy of This Document and Other Related Information
In addition to being available in the docket, an electronic copy of this action is available on the Internet at https://www.epa.gov/stationary-sources-air-pollution/clean-air-act-standards-and-guidelines-electric-utilities. Following publication in the Federal Register, the EPA will post the Federal Register version of the proposals and key technical documents at this same website.
Memoranda showing the edits that would be necessary to incorporate the changes to 40 CFR part 60, subpart TTTT and new 40 CFR part 60, subparts TTTTa and UUUUb proposed in these actions are available in the docket (Docket ID No. EPA-HQ-OAR-2023-0072). Following signature by the EPA Administrator, the EPA also will post a copy of the documents at https://www.epa.gov/stationary-sources-air-pollution/clean-air-act-standards-and-guidelines-electric-utilities.
Organization and Approach for These Proposed Rules
These actions present the EPA's proposed amendments to the Standards of Performance for Greenhouse Gas Emissions From New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units (80 FR 64510; October 23, 2015) (2015 NSPS) and proposed requirements for GHG emissions from new and reconstructed fossil fuel-fired stationary combustion turbine EGUs. These actions also propose to repeal the ACE Rule (84 FR 32523; July 8, 2019) and propose new emission guidelines for states in developing plans to reduce GHG emissions from existing fossil fuel-fired steam generating EGUs, which include both coal-fired and oil/gas-fired steam generating EGUs, to replace the repealed ACE Rule. The EPA is also soliciting comment on how the Agency should approach the creation of emission guidelines for existing fossil fuel-fired stationary combustion turbines.
Section III of this preamble provides updated information on the impacts of climate change. In section IV, the EPA provides a summary of the current state of the power sector, including changes and trends, GHG emissions, and GHG reduction goals and commitments, and the impacts of recent legislation on these. Section V presents a summary of the statutory background and regulatory history. In section VI, the EPA summarizes stakeholder outreach efforts. In section VII, the EPA describes the proposed BSERs, standards of performance, and associated requirements for new and reconstructed fossil fuel-fired stationary combustion turbine EGUs. In section VIII, the EPA presents proposed amendments to the applicability requirements for new, reconstructed, and modified fossil fuel-fired steam generating units. In section IX, the EPA provides a summary of the ACE Rule and proposes its repeal. In section X, the EPA presents the proposed BSERs, degree of emission limitation, and related requirements for the emission guidelines for existing fossil fuel-fired steam generating EGUs. Section XI presents the requirements for state plan development. In section XII, the EPA solicits comment on the creation of emission guidelines for existing natural gas-fired combustion turbines. In section XIII, the EPA describes the implications for these proposals and other EPA programs and rules. Section XIV describes the impacts of these proposals. Finally, in section XV, the EPA provides the statutory and executive order reviews.
Climate Change and Its Impacts
Elevated concentrations of GHGs are and have been warming the planet, leading to changes in the Earth's climate including changes in the frequency and intensity of heat waves, precipitation, and extreme weather events; rising seas; and retreating snow and ice. The changes taking place in the atmosphere as a result of the well-documented buildup of GHGs due to human activities are transforming the climate at a pace and scale that threatens human health, society, and the natural environment. Human-induced GHGs, largely derived from our reliance on fossil fuels, are causing serious and life-threatening environmental and health impacts.
Extensive additional 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 GHGs Under section 202(a) of the CAA (74 FR 66496; December 15, 2009). In the 2009 Endangerment Findings, the Administrator found under section 202(a) of the CAA that elevated atmospheric concentrations of six key well-mixed GHGs -- carbon dioxide (CO2), methane (CH4), nitrous oxide (N2O), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulfur hexafluoride (SF6) -- "may reasonably be anticipated to endanger the public health and welfare of current and future generations" (74 FR 66523; December 15, 2009), and the science and observed changes have confirmed and strengthened the understanding and concerns regarding the climate risks considered in the Finding. The 2009 Endangerment Findings, 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 Findings further explained that compared to 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 Findings also documented, together with the extensive scientific and technical evidence in the supporting record, that climate change touches nearly every aspect of public welfare in the U.S. including changes in water supply and quality due to increased frequency of 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; predominantly negative consequences for biodiversity and the provisioning of ecosystem goods and services; 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 similarly issued Endangerment and Cause or Contribute Findings for GHG emissions from aircraft under section 231(a)(2)(A) of the CAA (81 FR 54422; August 15, 2016). In the 2016 Endangerment Findings, the Administrator found that the body of scientific evidence amassed in the record for the 2009 Endangerment Findings 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 the 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 Findings, the climate has continued to change, with new records being set for several climate indicators such as global average surface temperatures, GHG concentrations, and sea level rise. Moreover, heavy precipitation events have increased in the eastern U.S. while agricultural and ecological drought has increased in the western U.S. along with more intense and larger wildfires. These and other trends are examples of the risks discussed in the 2009 and 2016 Endangerment Findings that have already been experienced. Additionally, major scientific assessments continue to demonstrate advances in our understanding of the climate system and the impacts that GHGs have on public health and welfare both for current and future generations. These updated observations and projections document the rapid rate of current and future climate change both globally and in the U.S. These assessments include:
 U.S. Global Change Research Program's (USGCRP) 2016 Climate and Health Assessment and 2017 - 2018 Fourth National Climate Assessment (NCA4).
 Intergovernmental Panel on Climate Change (IPCC) 2018 Global Warming of 1.5 °C, 2019 Climate Change and Land, and the 2019 Ocean and Cryosphere in a Changing Climate assessments, as well as the 2021 IPCC Sixth Assessment Report (AR6).
 The National Academy of Sciences (NAS) 2016 Attribution of Extreme Weather Events in the Context of Climate Change, 2017 Valuing Climate Damages: Updating Estimation of the Social Cost of Carbon Dioxide, and 2019 Climate Change and Ecosystems assessments.
 National Oceanic and Atmospheric Administration's (NOAA) annual State of the Climate reports published by the Bulletin of the American Meteorological Society, most recently in August of 2022.
 EPA Climate Change and Social Vulnerability in the United States: A Focus on Six Impacts (2021).
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 as a result of both historic 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, the annual global average atmospheric concentrations of one of these GHGs, CO2, measured at Mauna Loa in Hawaii and at other sites around the world reached 415 parts per million (ppm) in 2020 (nearly 50 percent higher than pre-industrial levels) and has continued to rise at a rapid rate. Global average temperature has increased by about 1.1 degrees Celsius (°C) (2.0 degrees Fahrenheit (°F)) in the 2011 - 2020 decade relative to 1850 - 1900. The years 2015 - 2021 were the warmest 7 years in the 1880 - 2020 record according to six different global surface temperature datasets. The IPCC determined (with medium confidence) that this past decade was warmer than any multi-century period in at least the past 100,000 years. Global 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. The rate of sea level rise during the 20[th] Century was higher than in any other century in at least the last 2,800 years. Higher CO2 concentrations have led to acidification of the surface ocean in recent decades to an extent unusual in the past 2 million years, with negative impacts on marine organisms that use calcium carbonate to build shells or skeletons. Arctic 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. Human-induced climate change has led to heatwaves and heavy precipitation becoming more frequent and more intense, along with increases in agricultural and ecological droughts in many regions.
The assessment literature demonstrates that modest additional amounts of warming may lead to a climate different from anything humans have ever experienced. The present-day CO2 concentration of 415 ppm is already higher than at any time in the last 2 million years. If concentrations exceed 450 ppm, they would likely be higher than at any time in the past 23 million years: At the current rate of increase of more than 2 ppm per year, this will occur in about 15 years. While buildup of GHGs is not the only factor that controls climate, it is illustrative that 3 million years ago (the last time CO2 concentrations were this high) 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 to melt substantially, for example, sea levels would rise dramatically, with potentially severe consequences for coastal cities and infrastructure. The IPCC estimated that during the next 2,000 years, sea level will rise by 7 to 10 feet even if warming is limited to 1.5 °C (2.7 °F), from 7 to 20 feet if limited to 2 °C (3.6 °F), and by 60 to 70 feet if warming is allowed to reach 5 °C (9 °F) above preindustrial levels. For context, almost all of the city of Miami is less than 25 feet above sea level, and the NCA4 stated that 13 million Americans would be at risk of migration due to 6 feet of sea level rise. Moreover, the CO2 being absorbed by the ocean has resulted in changes in ocean chemistry due to acidification of a magnitude not seen in 65 million years, putting many marine species -- particularly calcifying species -- at risk.
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. Coral 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. The 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 and 62 million more people to frequent exceptional heatwaves (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 a hundred 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). 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, while the movement speed has decreased, and elevated sea levels have increased coastal flooding, all of which make these tropical cyclones more damaging.
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. The 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. 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, leading to salt water intrusion into coastal aquifers and groundwater, flooding streets, increasing storm surge damages, and threatening coastal property and ecosystems, requiring costly adaptive measures such as installation of pump stations, beach nourishment, property elevation, and shoreline armoring. 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, but also 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.
Some GHGs also have impacts beyond those mediated through climate change. For example, elevated concentrations of CO2 stimulate 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) and cause ocean acidification. Nitrous oxide depletes the levels of protective stratospheric ozone. The tropospheric ozone produced by the reaction of methane in the atmosphere has harmful effects for human health and plant growth in addition to its climate effects.
Ongoing EPA modeling efforts can shed further light on the distribution of climate change damages expected to occur within the U.S. Based on methods from over 30 peer-reviewed climate change impact studies, the EPA's Framework for Evaluating Damages and Impacts (FrEDI) model has developed estimates of the relationship between future temperature changes and physical and economic climate-driven damages occuring in specific U.S. regions across 20 impact categories, which span a large number of sectors of the U.S. economy. Recent applications of FrEDI have advanced the collective understanding about how future climate change impacts in these 20 sectors are expected to be substantial and distributed unevenly across U.S. regions. Using this framework, the EPA estimates that under a global emission scenario with no additional mitigation, relative to a world with no additional warming since the baseline period (1986 - 2005), damages accruing to these 20 sectors in the contiguous U.S. occur mainly through increased deaths due to increasing temperatures, as well as climate-driven changes in air quality, transportation impacts due to coastal flooding resulting from sea level rise, increased mortality from wildfire emission exposure and response costs for fire suppression, and reduced labor hours worked in outdoor settings and buildings without air conditioning. The relative damages from long-term climate driven changes in these sectors are also projected vary from region to region: for example, the Southeast is projected to see some of the largest damages from sea level rise, the West Coast will see higher damages from wildfire smoke than other parts of the country, and the Northern Plains states are projected to see a higher proportion of damages to rail and road infrastructure. While the FrEDI framework currently quantifies damages for 20 sectors within the U.S., it is important to note that it is still a preliminary and partial assessment of climate impacts relevant to U.S. interests in a number of ways. For example, FrEDI does 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 occuring abroad have spillover effects in different regions of the U.S. See the FrEDI Technical Documentation for more details.
These scientific assessments, 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.
State of the Electric Power Sector
Introduction
The electric power sector is experiencing a prolonged period of transition and structural change. As noted earlier in the Executive Summary (section I.B), since the generation of electricity from coal-fired power plants peaked nearly two decades ago, the power sector has undergone a dynamic transformation -- and continues to change at a rapid pace. Today, natural gas-fired power plants provide the largest share of net generation, and as new technologies enter the marketplace, power producers continue to replace aging assets with more efficient and lower cost alternatives. This transition has been a driving force in sustained GHG emissions reductions across the sector.
This section of the preamble discusses recent trends in the electric power sector, beginning with background information on how electricity is generated and the role of EGUs in supplying electricity to consumers. This is followed with general information about the different types of EGUs providing power to the grid and the overall trends in generation with a focus on the coal- and natural gas-fired units that are the subject of these proposed rulemakings.
This section also includes a summary of the provisions and incentives included in recent Federal legislation that will impact the power sector as well as state actions and commitments by power producers to reduce GHG emissions. The section concludes with projections of future trends in power sector generation.
Background
Electric Power Sector
Electricity in the U.S. is generated by a range of technologies, and while the sector is rapidly evolving, the stationary combustion turbines and steam generating EGUs that are the subject of these proposed regulations still provide more than half of the electricity generated in the U.S. These EGUs fill many roles that are important to maintaining a reliable supply of electricity. For example, certain EGUs generate base load power to meet daily and seasonal demand while others provide backup generating capacity in the event of unexpected changes in demand or unexpected changes in the availability of other generators. Some EGUs also facilitate the regulation of the frequency and voltage of the grid system, and other units, often referred to as "peaking units", only operate during the periods of highest (peak) demand or constrained supply.
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 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.
      Generated electricity must be transmitted over networks of 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; in others, individual utilities coordinate the operations of their generation, transmission, and distribution systems to balance the system across their respective service territories. Distribution of electricity involves networks of lower voltage lines and substations that take the higher voltage power from the transmission system and step it down to lower voltage levels to match the needs of customers.
During the past few decades, several jurisdictions in the U.S. began restructuring the power industry to separate transmission and distribution from generation, ownership, and operation. Historically, vertically integrated utilities established much of the existing transmission infrastructure. However, as parts of the country have restructured the industry, transmission infrastructure has also been developed by transmission utilities, electric cooperatives, and merchant transmission companies, among others. Distribution, also historically developed by vertically integrated utilities, is now often managed by multiple utilities that purchase and sell electricity but do not generate it. Power sector restructuring has focused primarily on efforts to reorganize the industry to encourage competition in the generation segment of the industry, including ensuring open access of generation to the transmission and distribution services needed to deliver power to consumers. The resulting wholesale energy, capacity, and ancillary products markets are regulated by the Federal Energy Regulatory Commission (FERC).
Types of EGUs
In 2021, approximately 61 percent of net electricity was generated from the combustion of fossil fuels with natural gas providing 38 percent, coal providing 22 percent, and petroleum products such as fuel oil providing an additional 1 percent. Fossil fuel-fired EGUs include the steam generating units and stationary combustion turbines that are the subject of these proposed regulations.
There are two forms of fossil fuel-fired electric utility steam generating units: utility boilers and those that use gasification technology (i.e., integrated gasification combined cycle (IGCC) units). Fossil fuel-fired utility boilers include those that burn natural gas, oil, or coal; however, coal is the most common fuel for these types of EGUs. An IGCC unit gasifies fuel -- typically coal or petroleum coke -- to form a synthetic gas (or syngas) composed of carbon monoxide (CO) and hydrogen (H2), which can be combusted in a combined cycle system to generate power. 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 combustion 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 high capacity factors to provide base load power. An EGU's capacity factor indicates a power plant's electricity output as a percentage of its total generation capacity. Simple cycle combustion 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 add reliability to the grid during periods of peak demand or to support increased generation from intermittent energy sources.
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 government policies and declining costs, the capacity of these renewable technologies is growing, and when considered with existing nuclear energy, accounted for nearly 40 percent of the overall net electricity supply in 2021. Many projections show this share growing over time. For example, the EPA's Power Sector Modeling Platform v6 Using the Integrated Planning Model Post-IRA 2022 Reference Case (i.e., the EPA's projections of the power sector, which includes representation of the IRA absent further regulation) shows zero-emitting sources reaching 76 percent of electricity generation by 2040. (See section IV.F of this preamble and the accompanying Regulatory Impact Analysis for additional discussion of projections for the power sector).
Recent Changes in the Power Sector
Overview
For more than a decade, the utility power sector has experienced 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; changes in electricity demand across the broader economy; growth and regional changes in the U.S. population; technological improvements in electricity generation from both existing and new EGUs; changes in the prices and availability of different fuels; state policy preferences; 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, the existing fleet of coal-fired EGUs continues to age and become more costly to maintain and operate. At the same time, the supply and availability of natural gas has increased significantly, and its price has held relatively low. For the first time, in April 2015, natural gas surpassed coal in monthly net electricity generation and has maintained its position as the primary fossil fuel for base load energy generation, for peaking applications, and for balancing renewable generation. Additionally, there has been increased generation from investments in non-fossil fuel-based energy technologies spurred by technological advancements, declining costs, state and Federal policies, and most recently, the Infrastructure Investment and Jobs Act (IIJA) and the IRA. For example, the IRA provides investments in projects to help commercialize technologies such as small modular nuclear reactors, long-duration energy storage, advanced geothermal systems, and advanced distributed energy resources (DER) as well as more traditional wind and solar resources. Particularly relevant to this proposal, the incentives in the IRA, which are discussed in detail later in this section of the preamble, support the expansion of technologies, such as carbon capture and storage (CCS) and hydrogen technologies, that reduce GHG emissions from fossil-fired units.
The ongoing transition of the power sector is illustrated by a comparison of data between 2010 and 2021. In 2010, approximately 70 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 2021, fossil fuel net generation was approximately 60 percent, less than the share in 2010 despite an increase in total electricity demand. Moreover, the share of fossil generation supplied by coal-fired EGUs fell from 46 percent in 2010 to 23 percent in 2021 while the share supplied by natural gas-fired EGUs rose from 23 to 37 percent during the same period. In absolute terms, coal-fired generation declined by 51 percent while natural gas-fired generation increased by 64 percent. This reflects both the increase in natural gas capacity as well as an increase in the utilization of new and existing gas-fired EGUs. The combination of wind and solar generation also grew from 2 percent of the electric power sector mix in 2010 to 12 percent in 2021.
The broad trends throughout the power sector can also be seen in the number of commitments and announced plans of many EGU owners and operators across the industry to decarbonize -- spanning all types of companies in all locations. Moreover, state governments, which traditionally regulate investment decisions regarding electricity generation, have implemented their own policies to reduce GHG emissions from power generation.
Additional analysis of the utility power sector, including projections of future power sector behavior and the impacts of these proposed rules, is discussed in more detail in section XIV of this preamble, in the accompanying RIA, and in the technical support document (TSD), titled Power Sector Trends. The latter two documents are available in the rulemaking docket. Consistent with analyses done by other energy modelers, the RIA and TSD demonstrate that the sector trend of moving away from coal-fired generation is likely to continue and that non-emitting technologies may eventually displace certain natural gas-fired combustion turbines.
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. 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. The peak capacity addition was 14 GW, which was added in 1980. These coal-fired steam generating units operated as base load units for decades, providing the portion of electricity loads that are continually present and typically operate throughout all hours of the year. 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 and/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. And with no new coal-fired steam generating units commencing construction in more than a decade, 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 2010, the power sector's total installed capacity has increased by 144 GW (14 percent), while coal-fired steam generating unit capacity has declined by 107 GW. This reduction in coal-fired steam generating unit capacity was offset by an increase in total installed wind capacity of 93 GW, natural gas capacity of 84 GW, and an increase in solar capacity of 60 GW during the same period. Additionally, significant amounts of DER solar (33 GW) were also added. These trends accelerated during the shorter 2015 - 2021 period when the power sector's total capacity (1,183 GW) increased by 10 percent (109 GW). The largest change in capacity was driven by a reduction of 70 GW of coal capacity. This was offset by a net increase of 60 GW of wind capacity, 52 GW of natural gas capacity, and 47 GW of solar capacity. Additionally, 23 GW of DER solar were also added from 2015 to 2021.
      At the end of 2021, there were approximately 212 GW of coal-fired capacity remaining in the U.S. Although much of the fleet of coal-fired steam generating units has historically operated as base load, there can be notable differences 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. Moreover, average annual capacity factors for coal-fired steam generating units have declined from 67 to 49 percent since 2010, indicating that a larger share of units are operating in non-base load fashion, which requires increased cycling and can lead to less efficient fuel use, increased emission rates, and increased operation and maintenance costs.
      Older power plants also tend to become uneconomic over time as they become more costly to maintain and operate, especially when competing for dispatch against newer and more efficient generating technologies that have lower operating costs. These competing technologies are often encouraged through Federal and state policies, such as subsidies and mandates that can further reduce their costs relative to coal. The average coal-fired power plant that retired between 2015 and 2021 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. To further illustrate this trend, the existing coal-fired steam generating units older than 40 years represent 71 percent (154 GW) of the total remaining capacity. In fact, more than half (118 GW) of the coal-fired steam generating units still operating have already announced retirement dates prior to 2040. As discussed further in this section, the IRA will accelerate this trend.
      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 1,200 million short tons (MMst) followed by sharp declines in 2015 and 2020. In 2015, less than 800 MMst were produced, and in 2020, the total dropped to 535 MMst, the lowest output since 1965.
Trends in 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, naptha, synthetic gas, biogases, liquified natural gas (LNG), and hydrogen.
      Natural gas consists primarily of methane and can be derived from multiple sources. After the raw gas is extracted from the ground, it is processed to remove impurities and to separate methane from other gases and natural gas liquids to produce pipeline quality gas. This gas is sent to intermediate storage facilities prior to being piped through transmission feeder lines to a distribution network on its path to storage facilities or end users. During 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.
      According to the U.S. Energy Information Administration (EIA), annual natural gas marketed production in the U.S. remained consistent at approximately 20 trillion cubic feet (Tcf) from the 1970s to the early 2000s. However, since 2005, annual natural gas marketed production has steadily increased and approached 35 Tcf in 2021, which is an average of approximately 94.6 billion cubic feet per day. Thirty-four states produce natural gas with Texas (24.6 percent), Pennsylvania (21.8 percent), Louisiana (9.9 percent), West Virginia (7.4 percent), and Oklahoma (6.7 percent) accounting for approximately 70 percent of total production. Natural gas production exceeded consumption in the U.S. for the first time in 2017.
      As the production of natural gas has increased, the annual average price has declined during the same period. In 2008, U.S. natural gas prices peaked at $13.39 per million British thermal units ($/MMBtu) for residential customers. By 2020, the price was $10.45/MMBtu. The decrease in average annual natural gas prices can also been seen in city gate prices (i.e., a point or measuring station where natural gas is transferred from long-distance pipelines to a local distribution company), which peaked in 2008 at $8.85/MMBtu. By 2020, city gate prices were $3.30/MMBtu. An equivalent $/MMBtu basis is a common way to compare natural gas and coal fuel prices. For example, the price of Henry Hub natural gas in July 2022 was $7.39/MMBtu while the spot price of Central Appalachian coal was $7.25/MMBtu for the same month. However, this method of fuel price comparison based on equivalent energy content does not reflect differences in energy conversion efficiency (i.e., heat rate) and other factors among different types of generators. Because natural gas-fired combustion turbines are more efficient than coal-fired steam units, any fuel cost comparison should include an efficiency basis (dollar per megawatt-hour) to the equivalent energy content. For illustrative purposes, an EIA comparison based on this method showed that the Henry Hub natural gas price in July 2022 was $59.18/MWh and the price for Central Appalachian coal was $78.25/MWh for the same month.
      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 renewable 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. Of this total, approximately 147 GW (70 percent) were combined cycle capacity and 65 GW were simple cycle capacity. From 2007 to 2021, more than 125 GW of capacity were constructed and approximately 78 percent of that total were combined cycle EGUs. This figure represents an average of almost 4.2 GW of new combustion turbine generation capacity per year. In 2021, the net summer capacity of combustion turbine EGUs totaled 413 GW, with 281 GW being combined cycle generation and 132 GW being simple cycle generation.
      This trend away from coal to natural gas is also reflected in comparisons of annual capacity factors, sizes, and ages of affected EGUs. For example, the annual average capacity factors for natural gas-fired units increased from 28 to 37 percent between 2010 and 2021. 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.
      As explained in greater detail later in this preamble and in the accompanying RIA, future capacity 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 most projections show that the total installed capacities of natural gas-fired combustion turbines are likely to decline after 2030 in response to increased generation from renewables, energy storage, and other technologies. For example, nearly 80 percent of capacity additions in 2022 were from non-emitting generation resources including solar, wind, nuclear, and energy storage. The IRA is likely to accelerate this trend.
Trends in Renewable Generation
Renewable sources of electric generation--especially solar and wind--have expanded in the U.S. during the past decade. This growth has coincided with a reduction in the costs of the technologies, supportive state and Federal policies, and increased consumer demand for low-GHG electricity. In 2021, renewable energy sources produced approximately 20 percent of the nation's net generation, led by wind (9.2 percent), hydroelectric (6.3 percent), solar (2.8 percent), and other sources such as geothermal and biomass (1.7 percent).
The costs of renewable energy sources have steadily fallen over time due to technological advances, improvements in performance, increased demand for clean energy, as well as local, state, and Federal incentives and tax credits. For example, the unsubsidized average levelized cost of wind energy from 1988 to 1999 was $106/MWh and has since declined to $32/MWh in 2021. The average levelized cost of energy for utility-scale solar photovoltaics has fallen from $227/MWh in 2010 to $33/MWh in 2021. And the National Renewable Energy Laboratory (NREL) has documented cost decreases of 64, 69, and 82 percent, respectively, for residential-, commercial-, and utility-scale solar installations since 2010.
During the past 15 years, more than 122 GW of wind (primarily onshore) and 61 GW of solar capacity have been constructed, which represent a tripling of wind capacity and a 20-fold increase in solar capacity. Prior to 2007, no more than 2.6 GW of new wind capacity was built in any year, and the wind capacity added from 2000 to 2006 averaged 1.2 GW per year. In 2007, the nation added 5.3 GW of total wind capacity and the annual average was 7.2 GW through 2019. Wind capacity additions peaked in the past 2 years at a total of nearly 29 GW. For solar, the pattern of expansion is similar. For example, from 2000 to 2006, a total of 11 MW of new solar capacity was constructed, and from 2007 to 2011, total capacity additions increased to 1.2 GW. However, from 2012 to 2019, more than 36 GW of solar capacity was built (an average of 4.5 GW per year). And in 2020 and 2021, new solar capacity totaled of 24 GW. In terms of the net operating share of summer capacity in 2021, wind produced 46 percent of all renewable energy while solar generated 21 percent. The remaining electricity generated from renewables included 28 percent from hydroelectric and 5 percent from other sources that include geothermal systems, biogases/biomethane from landfills, woody materials and other biomass, and municipal solid waste.
There are also emerging technologies that have demonstrated the ability to further support the development and integration of renewable energy. At the end of 2021, there were 331 large-scale battery storage systems operating in the U.S. with a combined capacity of 4.8 GW (10.7 GWh). In terms of small-scale battery storage, there were 781 MW of reported capacity in 2021, mostly in California. Energy storage costs have declined 72 percent since 2015, and in 2019, the capital costs were $589/kWh. Declining costs have led to additional capacity being installed at each facility, and this increases the duration of each system when operating at maximum output. With 20.8 GW of grid storage already announced for 2023 - 2025, EIA expects that capacity will more than triple from 7.8 GW in late 2022 to approximately 30 GW by the end of 2025.
Trends in Nuclear Generation
The U.S. power sector continues to rely on nuclear sources of energy for a consistent portion of net generation. Since 1990, nuclear energy has provided about 20 percent of the nation's electricity, and 92 reactors were operating at 54 nuclear power plants in 28 states in 2022.
It should be noted that despite the consistent output from nuclear power plants over time, the number of operating reactors is beginning to decline. The average retirement age for a nuclear reactor is 42 years and the average age of the remaining nuclear fleet is currently 40 years, although age is only one consideration for determining when a nuclear plant may retire. For example, nuclear generating units at Florida Power & Light's Turkey Point, Constellation Energy's Peach Bottom, and Dominion Energy's Surry plants, among others, have applied to the Nuclear Regulatory Commission (NRC) for a second 20-year license renewal. If granted, the extension would enable those nuclear plants to operate for an additional 20-year interval, extending the life of many existing units well past the 40-year average.
There is also interest in the next generation of nuclear technologies. Small modular nuclear reactors, which can provide both firm dispatchable power and load-following capabilities to balance greater volumes of intermittent renewable generation, could play a role in future energy generation. In February 2023, the NRC issued a final rule certifying the first small modular reactor design. Expectations with respect to output from advanced nuclear generation vary, from negligible on the low end to as high as between 1,400 and 3,600 terawatt-hours per year (TWh/yr) by 2050. According to one survey by the Nuclear Energy Institute, utilities are considering building more than 90 GW of small modular nuclear reactors.
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 CO2, CH4, N2O, HFCs, PFCs, and SF6. Of these, CO2 is the most abundant, accounting for 80 percent of all GHGs present in the atmosphere. This abundance of CO2 is largely due to the combustion of fossil fuels by the transportation, electricity, and industrial sectors.
The amount of CO2 emitted from fossil fuel-fired EGUs depends on the carbon content of the fuel and the size and efficiency of the EGU. Different fuels emit different amounts of CO2 in relation to the energy they produce when combusted. The amount of CO2 produced when a fuel is burned is a function of the carbon content of the fuel. 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 CO2 emitted per million British thermal units of energy produced, when combusted, natural gas is the lowest compared to other fossil fuels at 117 lb CO2/MMBtu.  The average for coal is 216 lb CO2/MMBtu, but varies between 206 to 229 lb CO2/MMBtu by type (e.g., anthracite, lignite, subbituminous, and bituminous). The value for petroleum products such as diesel fuel and heating oil is 161 lb CO2/MMBtu.
The EPA prepares the official U.S. Inventory of Greenhouse Gas Emissions and Sinks (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 of GHGs, including CO2 emissions, for the years 1990 - 2020.
According to the latest inventory, in 2020, total U.S. GHG emissions were 5,981 million metric tons of carbon dioxide equivalent (MMT CO2e). The transportation sector (27.2 percent) was the largest contributor to total U.S. GHG emissions, followed by the power sector (24.8 percent) and industrial sources (23.8 percent). In terms of annual CO2 emissions, the power sector was responsible for 30.5 percent (1,439 MMT CO2e) of the nation's 2020 total.
CO2 emissions from the power sector have declined by 40 percent since 2005 (when the power sector reached annual emissions of 2,400 MMT CO2, its historical peak to date). The reduction in CO2 emissions can be attributed to the power sector's ongoing trends away from carbon-intensive coal-fired generation and toward more natural gas-fired and renewable sources. In 2005, CO2 emissions from coal-fired EGUs alone measured 1,983 MMT. This total dropped to 1,351 MMT in 2015 and reached 974 MMT in 2019, the first time since 1978 that coal-fired CO2 emissions were below 1,000 MMT. In 2020, emissions of CO2 from coal-fired EGUs measured 788 MMT before rebounding in 2021 to 909 MMT due to increased demand. By contrast, CO2 emissions from natural gas-fired generation have almost doubled since 2005, increasing from 319 MMT to 613 MMT in 2021, and CO2 emissions 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.
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 CO2 emissions to 1,632 MMT by 2030, or 32 percent below 2005 levels (2,400 MMT). Instead, even in the absence of Federal regulations for existing EGUs, annual CO2 emissions 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 CO2 emission levels of 1,900 MMT, or approximately 21 percent below 2005 levels. These trends have continued and demonstrate that states and utilities will continue to achieve additional CO2 reductions. These changes have been influenced by both market pressures and policy reasons. For example, in addition to state GHG reduction programs there are renewable portfolio standards (RPS) and federal and state tax incentives. However, progress in emission reductions is not uniform across all states and so federal policies play an essential role. As discussed earlier in this section, the power sector remains a leading emitter of CO2 in the U.S., and, despite the emission reductions since 2005, current CO2 levels continue to endanger human health and welfare. Further, as sources in other sectors of the economy turn to electrification to decarbonize, future CO2 reductions from fossil fuel-fired EGUs have the potential to take on added significance and increased benefits.
Drivers for Ongoing Change
Recent Legislation Impacting the Power Sector
On November 15, 2021, President Biden signed the Infrastructure Investment and Jobs Act (IIJA) (also known as the Bipartisan Infrastructure Law), which allocated more than $70 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-carbon fuels. Some of the IIJA programs that will impact the utility power sector include: $16.5 billion to build and upgrade thousands of miles of electricity transmission lines; $6 billion in financial support for existing nuclear reactors that are at risk of closing and being replaced by high-emitting resources; and more than $700 million for upgrades to the existing hydroelectric fleet. 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. Other clean energy technologies with IIJA funding include carbon capture, grid-scale energy storage, and advanced nuclear reactors. States, tribes, local communities, utilities, and others are eligible to receive funding.
The IRA, which President Biden signed on August 16, 2022, has the potential for even greater impacts on the electric power sector. With an estimated $369 billion in Energy Security and Climate Change programs over the next 10 years, covering grant funding and tax incentives, the IRA provides investment toward non GHG-emitting generation and away from the fossil fuel-fired units that are the subjects of these proposed regulations. 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 a cross-sectoral drive to push the power sector away from GHG emissions through a broad array of additional tax credits, loan guarantees, and public investment programs. These provisions are aimed at reducing emissions of GHGs from new and existing generating assets, with tax credits for carbon capture, utilization, and storage (CCUS) and clean hydrogen production providing a pathway for the use of coal and natural gas as part of a low-carbon electricity grid. Finally, with provisions such as the Methane Emissions Reduction Program, Congress demonstrated a focus on the importance of actions to address methane emissions from petroleum and natural gas systems.
To assist states and utilities in their decarbonizing efforts, and most germane to this proposed rulemaking, the IRA increased the tax credit incentives for capturing and storing CO2, including from coal-fired steam generating units and natural gas-fired stationary combustion turbines. The increase in credit values, found in section 13104 (which revises Internal Revenue Code (IRC) section 45Q), is 70 percent, equaling $85/metric ton for CO2 captured and securely stored in geologic formations and $60/metric ton for CO2 captured and utilized or securely stored in conjunction with enhanced oil recovery (EOR). The CCS incentives include 12 years of credits that can be claimed at the higher credit value beginning in 2023 for qualifying projects. Certain tax-exempt entities, such as tax-exempt co-ops, may use direct pay options for the full 12 years of the credit stream. Direct-pay options enhance the tax credits by enabling developers to monetize the credits directly as cash refunds rather than through cumbersome and costly tax equity markets. Entities that are not tax-exempt may transfer credits to unrelated taxpayers, enabling direct monetization of the credits again without depending on tax equity markets. These entities are eligible for direct pay for the initial 5 years of the project. 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 CO2 capture design capacity of not less than 75 percent of the baseline CO2 production of the unit and that construction must begin before January 1, 2033.
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 from well-to-gate. The credits range from $3/kg H2 for 0.0 to 0.45 kilograms of CO2-equivalent emitted per kilogram of low-GHG hydrogen produced (kg CO2e/kg H2) down to $0.6/kg H2 for 2.5 to 4.0 kg CO2e/kg H2 (assuming wage and apprenticeship requirements are met). Projects with GHG emissions greater than 4.0 kg CO2e/kg H2 are not eligible. According to the DOE, current costs for hydrogen produced from renewable energy range between $4 and $5/kg H2.
The clean hydrogen production tax credit is expected to incentivize the production of low-GHG hydrogen and ultimately exert downward pressure on costs. Low-cost and widely available low-GHG hydrogen has the potential to become a material decarbonization lever in the power sector as the use of low-GHG hydrogen in stationary combustion turbines reduces direct GHG emissions as hydrogen releases no CO2 when combusted. The tiered eligibility requirements for the clean hydrogen production tax credit also incentivize the lowest-GHG emissions production processes. These provisions allow direct pay options for all entities (taxpayers as well as non-taxable entities).
The production tax credit is not the only provision in the IRA designed to incentivize low-GHG hydrogen. Projects may also access the investment tax credit (ITC) under IRC section 48 and may apply under IRC section 48C as energy storage property. Projects may not, however, combine credits from IRC section 45V with credits in IRC sections 45Q, 45, or 45C. Hydrogen production tax credits became available in January 2023 for eligible new projects. Entities that commence construction between 2023 and 2032 can claim credits for the first 10 years of production.
The magnitude of this incentive -- combined with those in the IIJA such as the $8 billion for regional hydrogen hubs and $1 billion for electrolyzer advancement -- should accelerate the production of low-GHG hydrogen for use in a broad range of applications across many sectors, including the utility power sector.
Many of the IRA tax credit incentives are directed toward non-fossil fuel-based electric generation. They are designed to lower costs and market barriers to bring new zero-emitting generation and energy storage capacity online, to retain existing zero-emitting generators, and the energy efficiency tax credits are designed to reduce electricity demand. These financial tools have been used historically and shown to be a principal driver, buttressed by state renewable and clean energy standards, for incentivizing renewable deployment.
For example, the IRA expanded and extended the existing section 13101 (IRC section 45) production tax credits for new solar, wind, geothermal, and other eligible renewable or low-GHG emissions energy sources through 2024. The production tax credit (PTC) provides credits in a 10-year stream for each MWh of clean energy produced. The IRA indexed the PTC on inflation, increasing the credit amount to $27.50/MWh. For context, the energy price in the nation's largest wholesale energy market, PJM, is typically between $20/MWh and $90/MWh depending on timing, load, and transmission congestion.
In parallel, the existing investment tax credits in section 13101 (IRC section 48) were also expanded and extended in the IRA. Taxpayers must elect between the ITC and the PTC for each applicable project. The ITC enables taxpayers to recoup up to 30 percent of project costs for technologies such as solar, geothermal, fiberoptic solar, fuel cells, microturbines, small wind, offshore wind, combined heat and power (CHP), and waste energy recovery. The IRA expanded eligibility to include storage technologies like batteries or hydrogen production-related property, which is considered a form of energy storage, as well as some non-storage technologies.
Following state practices, Congress also included a zero-emission nuclear power production credit in the IRA to ensure existing in-service nuclear generators are retained for their contribution to base load zero-carbon emitting electricity. When labor and apprenticeship requirements are met, the credit price is $15/MWh. The credit amount declines when power prices rise above $25/MWh. The program begins in 2024 with credit streams available for nine years. This PTC is in addition to the $6 billion for nuclear advancements the IIJA authorized and appropriated to the Department of Energy (DOE). New nuclear plants would be eligible for the Clean Electricity Production Credit (IRC section 45Y).
In the evaluation of these proposed actions, many of the technologies that receive investment under recent Federal legislation are not directly considered, as the EPA has not evaluated new generation technologies entities could employ in its assessment of the BSER. As the discussion of that assessment will make clear later in this preamble, the EPA's inquiry has focused on "measures that improve the pollution performance of individual sources." It is important to understand, however, that many utilities and other power producers may opt to move from higher cost and higher emitting generating assets to technologies that are both lower cost and lower emitting both for business reasons and as a response to the requirements in these proposed rulemakings.
The following section (section IV.E.2.) includes a review of integrated resource plans (IRPs) filed by public utilities that prioritize GHG reductions. These IRPs demonstrate that most power companies intend to meet their GHG reduction targets by 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. Many IRPs further demonstrate the realization of power companies that to meet their GHG reduction targets, their natural gas-fired assets will need to occupy a much smaller GHG footprint through a combination of hydrogen, CCS, and reduced utilization. The IRA is designed to encourage this trend. For example, in addition to the provisions outlined above, including the 10 percent bonus value applied in `energy communities' that include fossil-related properties, the IRA created grant and loan funding sources for hard-to-abate energy assets. Section 2204 of the IRA authorizes $9.7 billion in financing for rural electric co-operatives and providers to invest in cleaner technologies to achieve GHG reductions across rural electric systems while buttressing resilience and reliability. Additionally, Section 50144 of the IRA, known as the Energy Infrastructure Reinvestment Financing provision, provides $5 billion for backing $250 billion in low-cost loans for utilities to repurpose existing infrastructure, decarbonize, and reduce debt. The financing in this provision enables a utility to repurpose an existing fossil site, such as a retiring coal-fired power plant, and retain community jobs while reducing GHG emissions.
Commitments by Utilities to Reduce GHG Emissions
The broad trends away from coal-fired generation and toward lower-emitting generation are reflected in the recent actions and announced plans of many utilities across the industry. As highlighted later in this section, through planning documents, IRPs, filings with state and local public utility commissions, and news releases, many utilities have made public commitments to move toward cleaner energy generation. Many utilities and other power generators have announced plans to increase their renewable energy holdings and continue reducing GHG emissions, regardless of any potential Federal regulatory requirements. For example, 50 power producers that are members of the Edison Electric Institute (EEI) have announced CO2 reduction goals, two-thirds of which include net-zero carbon emissions by 2050. This trend is not unique to the largest owner-operators of coal-fired EGUs; smaller utilities, public power cooperatives, and municipal entities are also contributing to these changes.
Some of the largest electric utilities that have publicly announced near- and long-term GHG reduction commitments, many with emission reduction targets of at least 80 percent (relative to 2005 levels unless otherwise noted), include:
 Xcel Energy: 80 percent reduction in CO2 emissions by 2030 and 100 percent carbon-free by 2050. This includes a commitment to close or repower all remaining coal-fired EGUs by 2030.
 DTE Energy: 65 percent reduction in CO2 emissions by 2028, 90 percent reduction by 2040, and net-zero carbon emissions by 2050.
 Ameren Energy: 60 percent reduction in CO2 by 2030, 85 percent reduction by 2040, and net-zero carbon emissions by 2045.
 Consumers Energy: 60 percent reduction in CO2 by 2025 and net-zero carbon emissions by 2040. This includes the retirement of all coal-fired units by 2025.
 Southern Company: 50 percent reduction in CO2 by 2030 (relative to 2007 levels) and net-zero carbon emissions by 2050.
 Duke Energy: 70 percent reduction in CO2 by 2030 and net-zero carbon emissions by 2050. All coal-fired units will retire by 2035.
 Minnesota Power (Allete Inc.): 70 percent renewable energy by 2030, 80 percent reduction in CO2 and coal-free by 2035, and 100 percent carbon-free by 2050.
 First Energy: 30 percent reduction in CO2 (relative to 2019 levels) and net-zero carbon emissions by 2050.
 American Electric Power: 80 percent reduction in CO2 by 2030 and net-zero carbon emissions by 2045.
 Alliant Energy: 50 percent reduction in CO2 by 2030 and net-zero carbon emissions by 2050; will retire final coal-fired EGU by 2040.
 Tennessee Valley Authority: 70 percent reduction in CO2 by 2030, 80 percent reduction by 2035, and net-zero carbon emissions by 2050.
 NextEra Energy: 70 percent reduction in CO2 by 2025, 82 percent reduction by 2030, 87 percent reduction by 2035, 94 percent reduction by 2040, and carbon-free by 2045.
The geographic footprint of zero or net-zero carbon commitments made by utilities, their parent companies, or in response to a state clean energy requirement, covers portions of 47 states. These statements are often made as part of long-term planning processes with considerable stakeholder involvement, including regulators.
State Actions to Reduce Power Sector GHG Emissions
States across the country have taken the lead in efforts to reduce GHG emissions and accelerate the power sector's trend away from fossil fuel-fired generation. These actions include commitments that require utilities to expand renewable and clean energy production through the adoption of renewable portfolio standards (RPS) and clean energy standards (CES), as well as other measures tailored to decarbonize state power systems enacted in specific legislation.
As of 2023, 30 states and the District of Columbia have enforceable RPS. RPS require a certain 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. Fifteen states have RPS targets that are at or well above 50 percent. Eight of these states -- California, Illinois, Massachusetts, Maryland, Minnesota, New Jersey, Nevada, and Oregon -- have targets ranging from 50 percent to just below 70 percent. Four states -- Maine, New Mexico, New York, and Vermont -- have RPS targets greater than or equal to 70 percent but below 100 percent, and three states -- Hawaii, Rhode Island, and Virginia plus the District of Columbia -- have 100 percent RPS requirements. Most of these ambitious targets fall during the next decade. Ten states and the District of Columbia have final targets that mature between 2025 and 2033, while the remaining five states impose peak requirements between 2040 and 2050. Resources that are eligible under an RPS vary by state and are determined by the state's existing energy production and possibility for renewable energy development. For example, Colorado's RPS includes a range of resources such as solar, wind, emissions-neutral coal mine methane and other sources as qualifying renewable energy sources. Hawaii's includes, but is not limited to, solar, wind, and energy produced from falling water, ocean water, waves, and water currents. RFS in some other states include landfill gas, animal wastes, CHP, and energy efficiency.
States are also shifting their generating fleets away from fossil fuel generating resources through the adoption of CES. A CES requires a certain 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. Twenty-one states have adopted some form of clean energy requirement or goal with 17 of those states setting 100 percent targets. In nearly all cases, the CES applies in addition to the state's other RPS requirements. Seven states, including California, Colorado, Minnesota, New York, Washington, Oregon, and Arizona, have a zero or net-zero carbon emissions requirement with most target dates falling in 2040, 2045, or 2050. Two states -- New Mexico and Massachusetts -- have 80 percent clean energy requirements that must be met in 2045 and 2050, respectively. Ten additional states, including Connecticut, New Jersey, Nevada, Wisconsin, Illinois, Maine, North Carolina, Nebraska, Louisiana, and Michigan, have 100 percent clean energy goals with target dates falling in either 2040 or 2050. Like an RPS, CES resource eligibility can vary from state to state. One key difference between an RPS and a CES is the extent to which a CES can allow for resources like nuclear and CCS-enabled coal and natural gas, which are not renewable but have low or zero direct GHG emission attributes that make them CES eligible.
In addition, states across the U.S. have announced specific legislation aimed at reducing GHG emissions. In California, Senate Bill 32, passed in 2016, was a landmark legislation that requires California to reduce its overall GHG emissions to 1990 levels by 2020, 40 percent below 1990 levels by 2030, and 80 percent below 1990 levels by 2050. Senate Bill 100, passed in 2018, requires California to procure 60 percent of all electricity from renewable sources by 2030 and 100 percent from carbon-free sources by 2045. Senate Bills 605 and 1383, passed in 2016, require a reduction in emissions of short-lived climate pollutants like methane by 40 to 50 percent below 2013 levels by 2030.
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.
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.
In addition to the prevalence of state RPS and CES programs outlined above, several states developed regulatory programs to retain nuclear power plants to preserve the significant amount of zero-emission output the plants provide, especially as many merchant nuclear plants face downward economic pressures resulting from ultra-low natural gas spot prices combined with increasing NGCC capacity. Between 2016 and 2021, New York, New Jersey, Connecticut, and Illinois took action to retain their nuclear power stations by providing state-level financial incentives. Retention of nuclear power plants is another strategy that leading states have used to ensure an increasing market share for zero-emission electricity generation. As discussed earlier, the IRA included a zero-emission nuclear power production credit in section 13105, also referred to as IRC section 45U.
In the past two years, state actions have generally increased their decarbonization ambitions. For example, legislation in Illinois and North Carolina requires a transition away from GHG-emitting generation. Illinois' Climate and Equitable Jobs Act, which became law on September 25, 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. On October 13, 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%) reduction in emissions of carbon dioxide (CO2) 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."
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 Modeling Platform v6 Using the Integrated Planning Model Post-IRA 2022 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.
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  and participated in public events exploring modeling assumptions for the IRA. The EPA plans to continue collaborating with stakeholders, conducting external engagements, and using information gathered to refine modeling of the IRA. As such, the EPA is soliciting comment on power sector modeling of the IRA, including the assumptions and potential impacts, including assumptions about growth in electric demand, rates at which renewable generation can be built, and cost and performance assumptions about all relevant technologies, including carbon capture, renewables, energy storage and other generation technologies.
While much of the discussion below focuses on the EPA's post-IRA 2022 reference case, many other analyses show similar trends, and 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.
Projections for Coal-fired Generation
In the post-IRA 2022 reference case, coal-fired steam generating unit capacity is projected to fall from 210 GW in 2021 to 44 GW in 2035. Generation from coal-fired steam generating units also falls from 898 thousand GWh in 2021 to 120 thousand GWh by 2035. This change in generation reflects the 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 41 percent in 2021 to 15 percent in 2035. By 2050, coal-fired steam generating unit capacity is projected to diminish further, with only 10 GW, or less than 5 percent of 2021 capacity (and approximately 3 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.
In 2020, there was a total of 1,439 million metric tonnes of CO2 from the power sector with coal-fired sources contributing to over half of those emissions. In the post-IRA 2022 reference case, power sector related CO2 emission are projected to fall to 608 million metric tonnes by 2035, of which 8 percent is projected to come from coal-fired sources in 2035.
Projections for Natural Gas-fired Generation
According to the post-IRA 2022 reference case, natural gas-fired capacity is expected to continue to buildout during the next decade with 61 GW of new capacity projected to come online by 2035 and 309 GW of new capacity by 2050. By 2035, the new natural gas capacity is comprised of 24 GW of simple cycle combustion turbines and 37 GW of combined cycle combustion turbines. By 2050, most of the incremental new capacity is projected to come just from simple cycle combustion turbines. This also represents a higher rate of new simple cycle combustion turbine builds compared to the reference periods (i.e., 2000 - 2006 and 2007 - 2021) discussed previously in this section. Some of the reasons for this continued growth in natural gas-fired capacity include sustained lower fuel costs and the flexibility offered by combustion turbines. Simple cycle combustion turbines operate at lower efficiencies but offer fast startup times to meet peaking load demands. In addition, combustion turbines, along with energy storage technologies, support the expansion of renewable electricity by meeting demand during peak periods and providing flexibility around the variability of renewable generation and electricity demand.
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 falls from 1,579 thousand GWh in 2021 to 1,402 thousand GWh by 2035. Power sector related CO2 emissions from natural gas-fired EGUs are projected to reach 527 million metric tons in 2035, 93 percent of which comes from NGCC sources.