Document ID: EPA-HQ-OAR-2023-0072-0142
Agency: epa
Document Type: Supporting & Related Material
Title: 
Posted Date: 2023-07-07T04:00Z

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fuel-fired steam generating EGUs, which include both coal-fired and oil/gas-fired steam generating EGUs, to replace the repealed ACE Rule.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: a-and-r-docket@epa.gov. Include Docket ID No. EPA-HQ-OAR-2023-0072 in the subject line of the message.
 Fax: (202) 566-9744. 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: (919) 541-4003; and email address: fellner.christian@epa.gov 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: (919) 541-9775; and email address: thompson.lisa@epa.gov. 
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 (888) 372-8699 or by email at SPPDpublichearing@epa.gov. 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 (888) 372-8699 or by email at SPPDpublichearing@epa.gov 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 oaqpscbi@epa.gov 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 oaqpscbi@epa.gov 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. 
The decline in generation and emissions is driven by a projected decline in NGCC capacity factors. In model projections, NGCC units have a capacity factor early in the projection period of 64 percent, but by 2035, capacity factor projections fall to 50 percent as many of these units switch from base load operation to more intermediate load operation to support the integration of variable renewable energy resources. Natural gas simple cycle combustion turbine capacity factors also fall, although since they are used primarily as a peaking resource and their capacity factors are already below 10 percent annually, their impact on generation and emissions changes are less notable.
Some of the reasons for this continued growth in natural gas-fired capacity include sustained lower fuel costs and the greater efficiency and 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. In the longer term, as renewables and battery storage grow, they outcompete the need for natural gas-fired generation and the overall utilization of natural gas-fired capacity declines.
Projections for Renewable Generation 
The EIA's Short-Term Energy Outlook (STEO) suggests that the U.S. will continue its expansion of wind and solar renewable capacity with most of the growth in electricity capacity additions in the next 2 years to come from renewable energy sources. The EIA projected solar capacity to grow by approximately 21 GW in 2022 and by 25 GW in 2023 and wind generating capacity to grow by 7 GW in 2022 and by 4 GW in 2023. These increases in new renewable capacity will continue to reduce the demand for fossil fuel-fired generation. 
In the post-IRA 2022 reference case projections, renewable capacity shows that this short-term trend is expected to continue. Non-hydroelectric utility-scale renewable capacity is projected to increase from 209 GW in 2021 to 668 GW by 2035 and then to 1,293 GW by 2050. This capacity growth is comprised mostly of wind and solar. The post-IRA 2022 reference case shows projections of 399 GW of wind capacity by 2035 and 748 GW by 2050. Utility-scale solar capacity has a similar trajectory with 263 GW by 2035 and 539 GW by 2050 and small-scale or distributed solar capacity (e.g., rooftop solar) similarly increases from 33 GW in 2021 to 198 GW in 2050. In total, non-hydroelectric utility-scale renewable generation is projected to produce 45 percent of electricity generation by 2035 in the post-IRA 2022 reference case.
Projections for Energy Storage
According to EIA, the capacity of energy storage is expected to increase by 10 times between 2019 and 2023, and more than 6 GW of additional battery storage capacity is planned to be co-located with solar generation. The benefit of co-locating energy storage systems with solar capacity is that the batteries can recharge throughout the middle of the day when surplus energy is available. Then this stored energy can be discharged later in the day during peak evening hours, displacing fossil fuel-fired generation. This also reduces curtailment of renewable energy when generation exceeds demand. 
The build out of energy storage is projected to continue in the long-term, enabling renewable technologies to operate more flexibly with lower emission consequences. The post-IRA 2022 reference case shows projections of 97 GW of energy storage to be available on the grid by 2035 and 152 GW by 2050. 
Projections for Nuclear Energy
The post-IRA 2022 reference case shows a steady decline in nuclear generating capacity, dropping from 96 GW in 2021 to 84 GW or by 12 percent by 2035. In the short-term, capacity reductions are expected to be delayed in part due to programs passed as part of the IIJA and IRA. These acts, along with several state programs, support the continued use of existing nuclear facilities by providing payments that will likely keep reactors in affected regions profitable for the next 5 - 10 years. After 2035, the EPA projects nuclear capacity retirements to occur as EGUs begin to age out of operation, and by 2050, the nuclear fleet is projected to reduce by more than half, to 45 GW. However, breakthrough technologies like small modular reactors, if successful, could result in higher levels of nuclear capacity than discussed here. For example, output from advanced nuclear generation could range from negligible to as high as 3,600 terawatt-hours per year (TWh/yr) by 2050.
Statutory Background and Regulatory History for CAA Section 111
Statutory Authority to Regulate GHGs from EGUs under CAA Section 111
The EPA's authority for and obligation to issue these proposed rules is CAA section 111, which establishes mechanisms for controlling emissions of air pollutants from new and existing stationary sources. CAA section 111(b)(1)(A) requires the EPA Administrator to promulgate a list of categories of stationary sources that the Administrator, in his or her judgment, finds "causes, or contributes significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare." The EPA has the authority to define the scope of the source categories, determine the pollutants for which standards should be developed, and distinguish among classes, types, and sizes within categories in establishing the standards. 
Regulation of Emissions From New Sources
Once the EPA lists a source category, the EPA must, under CAA section 111(b)(1)(B), establish "standards of performance" for emissions of air pollutants from new sources (including modified and reconstructed sources) in the source category. Under CAA section 111(a)(2), a "new source" is defined as "any stationary source, the construction or modification of which is commenced after the publication of regulations (or, if earlier, proposed regulations) prescribing a standard of performance under this section, which will be applicable to such source." Under CAA section 111(a)(3), a "stationary source" is defined as "any building, structure, facility, or installation which emits or may emit any air pollutant." Under CAA section 111(a)(4), "modification" means any physical change in, or change in the method of operation of, a stationary source which increases the amount of any air pollutant emitted by such source or which results in the emission of any air pollutant not previously emitted. While this provision treats modified sources as new sources, EPA regulations also treat a source that undergoes "reconstruction" as a new source. Under the provisions in 40 CFR 60.15, "reconstruction" means the replacement of components of an existing facility such that: (1) the fixed capital cost of the new components exceeds 50 percent of the fixed capital cost that would be required to construct a comparable entirely new facility; and (2) it is technologically and economically feasible to meet the applicable standards. Pursuant to CAA section 111(b)(1)(B), the standards of performance or revisions thereof shall become effective upon promulgation.
The standards of performance for new sources are referred to as new source performance standards, or NSPS. The NSPS are national requirements that apply directly to the sources subject to them. 
In setting or revising a performance standard, CAA section 111(a)(1) provides that performance standards are to reflect "the degree of emission limitation achievable through the application of the best system of emission reduction which (taking into account the cost of achieving such reduction and any nonair quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated." The term "standard of performance" in CAA 111(a)(1) makes clear that the EPA is to determine both the "best system of emission reduction ... adequately demonstrated" (BSER) for the regulated sources in the source category and the "degree of emission limitation achievable through the application of the [BSER]." West Virginia v. EPA, 142 S. Ct. 2587, 2601 (2022). To determine the BSER, the EPA first identifies the "system[s] of emission reduction" that are "adequately demonstrated," and then determines the "best" of those systems, "taking into account" factors including "cost," "nonair quality health and environmental impact," and "energy requirements." The EPA then derives from that system an "achievable" "degree of emission limitation." The EPA must then, under CAA section 111(b)(1)(B), promulgate "standard[s] for emissions" -- the NSPS -- that reflect that level of stringency. CAA section 111(b)(5) precludes the EPA from prescribing a particular technological system that must be used to comply with a standard of performance. Rather, sources may select any measure or combination of measures that will achieve the standard.
Regulation of Emissions From Existing Sources
When the EPA establishes a standard for emissions of an air pollutant from new sources within a category, it must also, under CAA section 111(d), regulate emissions of that pollutant from existing sources within the same category, unless the pollutant is regulated under the National Ambient Air Quality Standards (NAAQS) program, under CAA sections 108 - 110, or the National Emission Standards for Hazardous Air Pollutants (NESHAP) program, under CAA section 112. See CAA section 111(d)(1)(A)(i) and (ii); American Lung Ass'n v. EPA, 985 F.3d 914, 988 (D.C. Cir. 2021).
CAA section 111(d) establishes a framework of "cooperative federalism for the regulation of existing sources." American Lung Ass'n, 985 F.3d at 931. CAA sections 111(d)(1)(A)-(B) require "[t]he Administrator ... to prescribe regulations" that require "[e]ach state ... to submit to [EPA] a plan ... which establishes standards of performance for any existing stationary source for" the air pollutant at issue, and which "provides for the implementation and enforcement of such standards of performance." CAA section 111(a)(6) defines an "existing source" as "any stationary source other than a new source."
To meet these requirements, the EPA promulgates "emission guidelines" that identify the BSER and the degree of emission limitation achievable through the application of the BSER. Each state must then establish standards of performance for its sources that reflect that level of stringency. However, the states need not compel regulated sources to adopt the particular components of the BSER itself. The EPA's emission guidelines must also permit a state, "in applying a standard of performance to any particular source," to "take into consideration, among other factors, the remaining useful life of the existing source to which such standard applies." 42 U.S.C. 7411(d)(1). Once a state receives the EPA's approval of its plan, the provisions in the plan become federally enforceable against the source, in the same manner as the provisions of an approved state implementation plan (SIP) under the Act. If a state elects not to submit a plan or submits a plan that the EPA does not find "satisfactory," the EPA must promulgate a plan that establishes Federal standards of performance for the state's existing sources. CAA section 111(d)(2)(A). 
EPA Review of Requirements
CAA section 111(b)(1)(B) requires the EPA to "at least every 8 years, review and, if appropriate, revise" new source performance standards. However, the Administrator need not review any such standard if the "Administrator determines that such review is not appropriate in light of readily available information on the efficacy" of the standard. When conducting a review of an NSPS, the EPA has the discretion and authority to add emission limits for pollutants or emission sources not currently regulated for that source category. CAA section 111 does not by its terms require the EPA to review emission guidelines for existing sources, but the EPA retains the authority to do so.
History of EPA Regulation of Greenhouse Gases From Electricity Generating Units Under CAA Section 111 and Caselaw
The EPA has listed more than 60 stationary source categories under CAA section 111(b)(1)(A). See 40 CFR part 60, subparts Cb - OOOO. In 1971, the EPA listed fossil fuel-fired EGUs (which includes natural gas, petroleum, and coal) that use steam-generating boilers in a category under CAA section 111(b)(1)(A). See 36 FR 5931 (March 31, 1971) (listing "fossil fuel-fired steam generators of more than 250 million Btu per hour heat input"). In 1977, the EPA listed fossil fuel-fired combustion turbines, which can be used in EGUs, in a category under CAA section 111(b)(1)(A). See 42 FR 53657 (October 3, 1977) (listing "stationary gas turbines"). 
In 2015, the EPA promulgated two rules that addressed CO2 emissions from fossil fuel-fired EGUs. The first promulgated standards of performance for new fossil fuel-fired EGUs. "Standards of Performance for Greenhouse Gas Emissions From New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units; Final Rule," (80 FR 64510; October 23, 2015) (2015 NSPS). The second promulgated emission guidelines for existing sources. "Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units; Final Rule," (80 FR 64662; October 23, 2015) (Clean Power Plan, or CPP).
2015 NSPS
In 2015, the EPA promulgated an NSPS to limit emissions of GHGs, manifested as CO2, from newly constructed, modified, and reconstructed fossil fuel-fired electric utility steam generating units, i.e., utility boilers and IGCC EGUs, and newly constructed and reconstructed stationary combustion turbine EGUs. These final standards are codified in 40 CFR part 60, subpart TTTT.
In promulgating the NSPS for newly constructed fossil fuel-fired steam generating units, the EPA determined the BSER to be a new, highly efficient, supercritical pulverized coal (SCPC) EGU that implements post-combustion partial CCS technology. The EPA concluded that CCS was adequately demonstrated (including being technically feasible) and widely available and could be implemented at reasonable cost. The EPA identified natural gas co-firing and IGCC technology (either with natural gas co-firing or implementing partial CCS) as alternative methods of compliance.
The 2015 NSPS included standards of performance for steam generating units that undergo a "reconstruction" as well as units that implement "large modifications," (i.e., modifications resulting in an increase in hourly CO2 emissions of more than 10 percent). The 2015 NSPS did not establish standards of performance for steam generating units that undertake "small modifications" (i.e., modifications resulting in an increase in hourly CO2 emissions of less than or equal to 10 percent), due to the limited information available to inform the analysis of a BSER and corresponding standard of performance.
The 2015 NSPS also finalized standards of performance for newly constructed and reconstructed stationary combustion turbine EGUs. For newly constructed and reconstructed base load natural gas-fired stationary combustion turbines, the EPA finalized a standard based on efficient NGCC technology as the BSER. For newly constructed and reconstructed non-base load natural gas-fired stationary combustion turbines and for both base load and non-base load multi-fuel-fired stationary combustion turbines, the EPA finalized a heat input-based clean fuels standard. The EPA did not promulgate final standards of performance for modified stationary combustion turbines due to lack of information. These standards remain in effect today.
The EPA received six petitions for reconsideration of the 2015 NSPS. On May 6, 2016 (81 FR 27442), the EPA denied five of the petitions on the basis they did not satisfy the statutory conditions for reconsideration under CAA section 307(d)(7)(B), and deferred action on one petition that raised the issue of the treatment of biomass. 
Multiple parties also filed petitions for judicial review of the 2015 NSPS in the D.C. Circuit. After briefing, the court granted the EPA's motion to hold the cases in abeyance while the Agency reviews the rule and considers whether to propose revisions to it.
In the 2015 NSPS, the EPA noted that it was authorized to regulate GHGs from the fossil fuel-fired EGU source categories because it had listed those source categories under CAA section 111(b)(1)(A). The EPA added that CAA section 111 did not require it to make a determination that GHGs from EGUs contribute significantly to dangerous air pollution (a pollutant-specific significant contribution finding), but in the alternative, the EPA did make that finding. It explained that "[greenhouse gas] air pollution may reasonably be anticipated to endanger public health or welfare," id. at 64,530 and emphasized that power plants are "by far the largest emitters" of greenhouse gases among stationary sources in the U.S. Id. at 64,522. In American Lung Ass'n v. EPA, 985 F.3d 977 (D.C. Cir. 2021), the court held that even if the EPA were required to determine that CO2 from fossil fuel-fired EGUs contributes significantly to dangerous air pollution -- and the court emphasized that it was not deciding that the EPA was required to make such a pollutant-specific determination -- the determination in the alternative that the EPA made in the 2015 NSPS was not arbitrary and capricious and, accordingly, the EPA had a sufficient basis to regulate greenhouse gases from EGUs under CAA section 111(d) in the ACE Rule. The EPA is not reopening or soliciting comment on any of those determinations in the 2015 NSPS concerning its rational basis to regulate GHG emissions from EGUs or its alternative finding that GHG emissions from EGUs contribute significantly to dangerous air pollution.
2018 Proposal to Revise the 2015 NSPS
In 2018, the EPA proposed to revise the NSPS for new, modified, and reconstructed fossil fuel-fired steam generating units and IGCC units. "Review of Standards of Performance for Greenhouse Gas Emissions From New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units; Proposed Rule," (83 FR 65424; December 20, 2018). The EPA proposed to revise the NSPS for newly constructed units, based on a revised BSER of a highly efficient SCPC, without partial CCS. The EPA also proposed to revise the NSPS for modified and reconstructed units. The EPA never took further action to finalize that proposed rule, is not soliciting further comment on it in this proposal, and intends to withdraw it through a separate notice.
Clean Power Plan
With the promulgation of the 2015 NSPS, the EPA also incurred a statutory obligation under CAA section 111(d) to issue emission guidelines for GHG emissions from existing fossil fuel-fired steam generating EGUs and stationary combustion turbine EGUs, which the EPA initially fulfilled with the promulgation of the CPP. See 80 FR 64662 (October 23, 2015). The EPA first determined that the BSER included three types of measures: (1) improving heat rate (i.e., the amount of fuel that must be burned to generate a unit of electricity) at coal-fired steam plants; (2) substituting increased generation from lower-emitting NGCC plants for generation from higher-emitting steam plants (which are primarily coal-fired); and (3) substituting increased generation from new renewable energy sources for generation from fossil fuel-fired steam plants and combustion turbines. See 80 FR 64667 (October 23, 2015). The latter two measures are known as "generation shifting" because they involve shifting electricity generation from higher-emitting sources to lower-emitting ones. See 80 FR 64728 - 29 (October 23, 2015). 
The EPA based this BSER determination on a technical record that evaluated generation-shifting, including its cost-effectiveness, against the relevant statutory criteria for BSER and on a legal interpretation that the term "system" in CAA section 111(a)(1) is sufficiently broad to encompass shifting of generation from higher-emitting to lower-emitting sources. See 80 FR 64720 (October 23, 2015). The EPA then determined the "degree of emission limitation achievable through the application of the [BSER]," CAA section 111(a)(1), expressed as emission performance rates. See 80 FR 64667 (October 23, 2015). The EPA explained that a state would "have to ensure, through its plan, that the emission standards it establishes for its sources individually, in the aggregate, or in combination with other measures undertaken by the [S]tate, represent the equivalent of" those performance rates (80 FR 64667; October 23, 2015). Neither states nor sources were required to apply the specific measures identified in the BSER (80 FR 64667; October 23, 2015), and states could include trading or averaging programs in their state plans for compliance. See 80 FR 64840 (October 23, 2015). 
Numerous states and private parties petitioned for review of the CPP before the D.C. Circuit. On February 9, 2016, the U.S. Supreme Court stayed the rule pending review, West Virginia v. EPA, 577 U.S. 1126 (2016), and the D.C. Circuit held the litigation in abeyance, and ultimately dismissed it, as the EPA reassessed its position. American Lung Ass'n, 985 F.3d at 937.
The CPP Repeal and Affordable Clean Energy Rule
In 2019, the EPA repealed the CPP and replaced it with the ACE Rule. In contrast to its interpretation of CAA section 111 in the CPP, the EPA determined that the statutory "text and reasonable inferences from it" make "clear" that a "system" of emission reduction under CAA section 111(a)(1) "is limited to measures that can be applied to and at the level of the individual source," (84 FR 32529; July 8, 2019); that is, the system must be limited to control measures that could be applied "inside the fenceline" of each source to reduce emissions at each source. See 84 FR 32523 - 24 (July 8, 2019). Specifically, the ACE Rule argued that the requirements in CAA sections 111(d)(1), (a)(3), and (a)(6), that each state establish a standard of performance "for" "any existing source," defined, in general, as any "building ... [or] facility," and the requirement in CAA section 111(a)(1) that the degree of emission limitation must be "achievable" through the "application" of the BSER, by their terms, impose this limitation. The EPA concluded that generation shifting is not such a control measure . See 84 FR 32546 (July 8, 2019). Based on its view that the CPP was a "major rule," the EPA further determined that, absent "a clear statement from Congress," the term "`system of emission reduction'" should not be read to encompass "generation-shifting measures." See 84 FR 32529 (July 8, 2019). The EPA acknowledged, however, that "[m]arket-based forces ha[d] already led to significant generation shifting in the power sector," (84 FR 32532; July 8, 2019), and that there was "likely to be no difference between a world where the CPP is implemented and one where it is not." See 84 FR 32561 (July 8, 2019); the Regulatory Impact Analysis for the Repeal of the Clean Power Plan, and the Emission Guidelines for Greenhouse Gas Emissions from Existing Electric Utility Generating Units, 2-1 to 2-5.
Second, the EPA promulgated in the ACE Rule a new set of emission guidelines for existing coal-fired steam-generating EGUs. See 84 FR 32532 (July 8, 2019). In light of "the legal interpretation adopted in the repeal of the CPP," (84 FR 32532; July 8, 2019) -- which "limit[ed] `standards of performance' to systems that can be applied at and to a stationary source," (84 FR 32534; July 8, 2019) -- the EPA found the BSER to be heat rate improvements alone. See 84 FR 32535 (July 8, 2019). The EPA listed various technologies that could improve heat rate (84 FR 32536; July 8, 2019), and identified the "degree of emission limitation achievable" by "providing ranges of expected [emission] reductions associated with each of the technologies." See 84 FR 32537 - 38 (July 8, 2019).
The EPA also stated that, under the ACE Rule, compliance measures that the state plans could authorize the sources to implement "should correspond with the approach used to set the standard in the first place," (84 FR 32556; July 8, 2019), and therefore must "apply at and to an individual source and reduce emissions from that source." See 84 FR 32555 - 56 (July 8, 2019). The EPA concluded that various measures besides generation shifting -- including averaging (i.e., allowing multiple sources to average their emissions to meet an emission-reduction goal), and trading (i.e., allowing sources to exchange emission credits or allowances) -- did not meet that requirement. The EPA therefore barred states from using such measures in their plans. See 84 FR 32556 (July 8, 2019).
D.C. Circuit Decision in American Lung Ass'n v. EPA Concerning the CPP Repeal and ACE Rule
Numerous states and private parties petitioned for review of the CPP Repeal and ACE Rule. In 2021, the D.C. Circuit vacated the ACE Rule, including the CPP Repeal. American Lung Ass'n v. EPA, 985 F.3d 914 (D.C. Cir. 2021). The court held, among other things, that CAA section 111(d) does not limit the EPA, in determining the BSER, to inside-the-fenceline measures. The court noted that "the sole ground on which the EPA defends its abandonment of the [CPP] in favor of the ACE Rule is that the text of [CAA section 111] is clear and unambiguous in constraining the EPA to use only improvements at and to existing sources in its [BSER]." 985 F.3d at 944. The court found "nothing in the text, structure, history, or purpose of [CAA section 111] that compels the reading the EPA adopted." 985 F.3d at 957. The court explained that contrary to the ACE Rule, the above-noted requirements in CAA section 111 that each state must establish a standard of performance "for" any existing "building ... [or] facility," mean that the state must establish standards applicable to each regulated stationary source; and the requirements that the degree of emission limitation must be achievable through the "application" of the BSER could be read to mean that the sources must be able to apply the system to reduce emissions across the source category. None of these requirements, the court further explained, can be read to mandate that the BSER is limited to some measure that each source can apply to its own facility to reduce its own emissions in a specified amount. 985 F.3d at 944 - 51. The court likewise rejected the view that the CPP's use of generation-shifting implicated a "major question" requiring unambiguous authorization by Congress. 985 F.3d at 958 - 68.
Having rejected the CPP Repeal Rule's view, also reflected in the ACE Rule, that CAA section 111 unambiguously requires that the BSER be "one that can be applied to and at the individual source," the court also "reject[ed] the ACE Rule's exclusion from [CAA section 111(d)] of compliance measures" that do not meet that requirement. 985 F.3d at 957. Thus, the court held that CAA section 111 does not preclude states from allowing trading or averaging. The court explained that the ACE Rule's premise for its view that compliance measures are limited to inside-the-fenceline is that BSER measures are so limited, but the court further stated that this premise was invalid. The court added that in any event, CAA section 111(d) says nothing about the type of compliance measures states may adopt, regardless of what the EPA identifies as the BSER. Id. at 957 - 58.
The D.C. Circuit concluded that, because the EPA had relied on an "erroneous legal premise," both the CPP Repeal Rule and the ACE Rule should be vacated. 985 F.3d 995. The court did not decide, however, "whether the approach of the ACE Rule is a permissible reading of the statute as a matter of agency discretion," 985 F.3d 944, and instead "remanded to the EPA so that the Agency may `consider the question afresh,'" 985 F.3d 995 (citations omitted). The court also rejected the arguments that the EPA cannot regulate CO2 emissions from coal-fired power plants under CAA section 111(d) at all because it had already regulated mercury emissions from coal-fired power plants under CAA section 112. 985 F.3d 988. 
Because the D.C. Circuit vacated the ACE Rule on the grounds noted above, it did not address the numerous other challenges to the ACE Rule, including the arguments by Petitioners that the heat rate improvement BSER was inadequate because of the limited amount of reductions it achieved and because the ACE Rule failed to include an appropriately specific degree of emission limitation. 
Upon a motion from the EPA, the D.C. Circuit agreed to stay its mandate with respect to vacatur of the CPP Repeal, American Lung Assn v. EPA, No. 19-1140, Order (February 22, 2021), so that the CPP remained repealed. The EPA explained that the CPP should remain repealed because the deadline for states to submit their plans under the CPP had long since passed. In addition, and most importantly, because of ongoing changes in electricity generation -- in particular, retirements of coal-fired electricity generation -- the emissions reductions that the CPP was projected to achieve had already been achieved by 2021. American Lung Assn v. EPA, No. 19-1140, Respondents' Motion for a Partial Stay of Issuance of the Mandate (February 12, 2021). Therefore, following the D.C. Circuit's decision, no EPA rule under CAA section 111 to reduce GHGs from existing fossil fuel-fired EGUs remained in place, and the EPA proceeded with this new rulemaking.
U.S. Supreme Court Decision in West Virginia v. EPA Concerning the CPP
In 2022, the U.S. Supreme Court reversed the D.C. Circuit's vacatur of the ACE Rule's embedded repeal of the CPP. West Virginia v. EPA, 142 S. Ct. 2587 (2022). The Supreme Court made clear that CAA section 111 authorizes the EPA to determine the BSER and the degree of emission limitation that state plans must achieve. Id. at 2601 - 02. However, the Supreme Court invalidated the CPP's generation-shifting BSER under the major questions doctrine. The Court characterized the generation-shifting BSER as "restructuring the Nation's overall mix of electricity generation," and stated that the EPA's claim that CAA section 111 authorized it to promulgate generation shifting as the BSER was "not only unprecedented; it also effected a fundamental revision of the statute, changing it from one sort of scheme of regulation into an entirely different kind." Id. at 2612 (internal quotation marks, brackets, and citation omitted). The Court explained that the EPA, in prior rules under CAA section 111, had set emissions limits based on "measures that would reduce pollution by causing the regulated source to operate more cleanly." Id. at 2610. The Court noted with approval those "more traditional air pollution control measures," and gave as examples "fuel-switching" and "add-on controls," which, the Court observed, the EPA had considered in the CPP. Id. at 2611 (internal quotations marks and citation omitted). In contrast, the Court continued, generation-shifting was "unprecedented" because "[r]ather than focus on improving the performance of individual sources, it would improve the overall power system by lowering the carbon intensity of power generation. And it would do that by forcing a shift throughout the power grid from one type of energy source to another." Id. at 2611-12 (internal quotation marks, emphasis, and citation omitted). The Court also emphasized that the adoption of generation shifting was based on a "very different kind of policy judgment [than prior CAA section 111 rules]: that it would be `best' if coal made up a much smaller share of national electricity generation." Id. at 2612. The Court recognized that a rule based on traditional measures "may end up causing an incidental loss of coal's market share," but emphasized that the CPP was "obvious[ly] differen[t]" because, with its generation-shifting BSER, it "simply announc[ed] what the market share of coal, natural gas, wind, and solar must be, and then require[ed] plants to reduce operations or subsidize their competitors to get there." Id. at 2613 n. 4. Beyond highlighting the novelty of generation shifting, the Court also emphasized "the magnitude and consequence" of the CPP. Id. at 2616. It noted "the magnitude of this unprecedented power over American industry," id. at 2612 (internal quotation marks and citation omitted), and added that the EPA's adoption of generation shifting "represent[ed] a transformative expansion in its regulatory authority." Id. at 2610 (internal quotation marks and citation omitted). The Court also viewed the CPP as promulgating "a program that ... Congress had considered and rejected multiple times." Id. at 2614 (internal quotation marks and citation omitted). The Court explained that "[a]t bottom, the [CPP] essentially adopted a cap-and-trade scheme, or set of state cap-and-trade schemes, for carbon," and that Congress "has consistently rejected proposals to amend the Clean Air Act to create such a program." Id.
For these and related reasons, the Court viewed the CPP as raising a major question, and therefore, under the major questions doctrine, required "clear congressional authorization" as a basis. Id. (internal quotation marks and citation omitted). The EPA had defended generation shifting as qualifying as a "system of emission reduction" under CAA section 111(a)(1), but the Court found that the term "system" is "a vague statutory grant [that] is not close to the sort of clear authorization required" under the doctrine, id., and, on that basis, invalidated the CPP.
The Court declined to address the D.C. Circuit's decision that the text of CAA section 111 did not limit the type of "system" the EPA could consider as the BSER to inside-the-fenceline measures. See id. at 2615 ("We have no occasion to decide whether the statutory phrase "system of emission reduction" refers exclusively to measures that improve the pollution performance of individual sources, such that all other actions are ineligible to qualify as the BSER." (emphasis in original)). Nor did the Court address the scope of the states' compliance flexibilities. 
D.C. Circuit Order to Reinstate the ACE Rule
On October 27, 2022, the D.C. Circuit responded to the U.S. Supreme Court's reversal by recalling its mandate for the vacatur of the ACE Rule. American Lung Ass'n v. EPA, No. 19-1140, Order (October 27, 2022). Accordingly, at that time, the ACE Rule came back into effect. The court also revised its judgment to deny petitions for review challenging the CPP Repeal Rule, consistent with the West Virginia decision, so that the CPP remains repealed. The court took further action denying several of the petitions for review unaffected by the Supreme Court's decision in West Virginia, which means that certain parts of its 2021 decision in American Lung Ass'n remain valid. These parts include the holding that the EPA's prior regulation of mercury emissions from coal-fired electric power plants under CAA section 112 does not preclude the Agency from regulating CO2 from coal-fired electric power plants under CAA section 111, and the holding, discussed above, that the 2015 NSPS included a valid significant contribution determination and therefore provided a sufficient basis for a CAA section 111(d) rule regulating greenhouse gases from existing fossil fuel-fired EGUs. The court's holding to invalidate amendments to the implementing regulations applicable to emission guidelines under CAA section 111(d) that extended the preexisting schedules for state and federal actions and sources' compliance, also remains valid. Based on the EPA's stated intention to replace the ACE Rule, the court stayed further proceedings with respect to the ACE Rule, including the various challenges that its BSER was flawed because it did not achieve sufficient emission reductions and failed to specify an appropriately specific degree of emission limitation. 
Detailed Discussion of CAA Section 111 Requirements
This section discusses in more detail the key requirements of CAA section 111 for both new and existing sources that are relevant for these rulemakings. 
Approach to the Source Category and Subcategorizing
CAA section 111 requires the EPA first to list stationary source categories that cause or contribute to air pollution which may reasonably be anticipated to endanger public health or welfare and then to regulate new sources within each such source category. CAA section 111(b)(2) grants the EPA discretion whether to "distinguish among classes, types, and sizes within categories of new sources for the purpose of establishing [new source] standards," which we refer to as "subcategorizing." The D.C. Circuit has stated that whether and how to subcategorize is a decision for which the EPA is entitled to a "high degree of deference" because it entails "scientific judgement." Lignite Energy Council v. EPA, 198 F3d 930, 933 (D.C. Cir. 1999); see Sierra Cub, v. Costle, 657 F.2d 298, 318-19 (D.C. Cir. 1981).
CAA section 111(d)(1) is silent as to whether the EPA may subcategorize. The EPA interprets this provision to authorize the Agency to exercise discretion as to whether and, if so, how to subcategorize, for the following reasons. CAA section 111(d)(1) provides a broad grant of authority to the EPA, directing it to "prescribe regulations which shall establish a procedure...under which each State shall submit to the Administrator a plan [with standards of performance for existing sources.]" The EPA promulgates emission guidelines under this provision directing the states to regulate existing sources. The Supreme Court has recognized the breadth of authority that CAA section 111(d) grants the EPA:
      Although the States set the actual rules governing existing power plants, EPA itself still retains the primary regulatory role in Section 111(d). The Agency, not the States, decides the amount of pollution reduction that must ultimately be achieved. It does so by again determining, as when setting the new source rules, "the best system of emission reduction ... that has been adequately demonstrated for [existing covered] facilities." [citations omitted]

West Virginia v. EPA, 142 S. Ct. at 2601 - 02. That this broad authority under CAA section 111(d) includes subcategorization follows from the fact that these provisions authorize the EPA to determine the BSER. Subcategorizing is a mechanism for determining different controls to be the BSER for different sets of sources. This is clear from CAA section 111(b)(2) itself, which authorizes the EPA to subcategorize new sources "for the purpose of establishing ... standards." In addition, the EPA's longstanding implementing regulations under CAA section 111(d) provide that the Administrator will specify different emission guidelines or compliance times or both "for different sizes, types, and classes of designated facilities when costs of control, physical limitations, geographical location, or similar factors make subcategorization appropriate." 
The EPA's authority to "distinguish among classes, types, and sizes within categories," as provided under CAA section 111(b)(2), generally allows the Agency to place types of sources into subcategories when they have characteristics that are relevant to the controls they can apply to reduce their emissions. This is consistent with the commonly understood meaning of the term "type" in CAA section 111(b)(2): "a particular kind, class, or group," or "qualities common to a number of individuals that distinguish them as an identifiable class." See https://www.merriam-webster.com/dictionary/type. That is, subcategorization is appropriate for a set of sources that have qualities in common that are relevant for determining what controls are appropriate for those sources. And where the qualities in common are not relevant for determining what controls are appropriate, subcategorization is not allowed. This view is consistent with the D.C. Circuit's interpretation of CAA section 112(d)(1), which is a subcategorization provision that is identical to CAA section 111(b)(2). In NRDC v. EPA, 489 F.3d 1364, 1375 - 76 (D.C. Cir. 2007), the court upheld the EPA's decision under CAA section 112(d)(1) not to subcategorize sources subject to control requirements under CAA section 112(d)(3), known as the maximum achievable control technology (MACT) floor, on the basis of costs. That was because the EPA is not authorized to consider costs in setting the MACT floor. See Chem. Mfrs. Ass'n v. NRDC, 470 U.S. 116, 131 (1985) (Court interprets similar provision under the Clean Water Act to grant the EPA broad discretion). 
The EPA has developed subcategories in numerous rulemakings under CAA section 111 since it began promulgating them in the 1970s. These rulemakings have included subcategories on the basis of the size of the sources, see 40 CFR 60.40b(b)(1)-(2) (subcategorizing certain coal-fired steam generating units on the basis of heat input capacity); the types of fuel combusted, see Sierra Cub, v. EPA, 657 F.2d 298, 318-19 (D.C. Cir. 1981) (upholding a rulemaking that established different NSPS "for utility plants that burn coal of varying sulfur content"), 2015 NSPS, 80 FR 64510, 64602 (table 15) (October 23, 2015) (subdividing new combustion turbines on the basis of type of fuel combusted); the types of equipment used to produce products, see 81 FR 35824 (June 3, 2016) (promulgating separate NSPS for many types of oil and gas sources, such as centrifugal compressors, pneumatic controllers, and well sites); types of manufacturing processes used to produce product, see 42 FR 12022 (March 1, 1977) (announcing availability of final guideline document for control of atmospheric fluoride emissions from existing phosphate fertilizer plants) and "Final Guideline Document: Control of Fluoride Emissions From Existing Phosphate Fertilizer Plants, EPA-450/2-77-005 1-7 to 1-9, including table 1-2 (applying different control requirements for different manufacturing operations for phosphate fertilizer); levels of utilization of the sources, see 2015 NSPS, 80 FR 64510, 64602 (table 15) (October 23, 2015) (dividing new natural gas-fired combustion turbines into the subcategories of base load and non-base load); and geographic location of the sources, see 71 FR 38482 (July 6, 2006) (SO2 NSPS for stationary combustion turbines subcategories turbines on the basis of whether they are located in, for example, a continental area, a noncontinental area, the part of Alaska north of the Arctic Circle, and the rest of Alaska), see also Sierra Club v. Costle, 657 F.2d 298, 330 (D.C. Cir. 1981) (stating that the EPA could create different subcategories for sources in the eastern and western U.S. for requirements that depend on water-intensive controls). As these references indicate, the EPA has subcategorized many times in rulemaking under CAA sections 111(b) and 111(d) and based on a wide variety of physical, locational, and operational characteristics. 
Regardless of whether the EPA subcategorizes within a source category for purposes of determining the BSER and the emission performance level for the emission guideline, a state retains certain flexibility in assigning standards of performance to its affected EGUs. The statutory framework for CAA section 111(d) emission guidelines, and the flexibilities available to states within that framework, are discussed below. 
Key Elements of Determining a Standard of Performance
Congress first included the definition of "standard of performance" when enacting CAA section 111 in the 1970 Clean Air Act Amendments (CAAA), amended it in the 1977 CAAA, and then amended it again in the 1990 CAAA to largely restore the definition as it read in the 1970 CAAA. The current text reads: "The term `standard of performance' means a standard for emission of air pollutants which reflects the degree of emission limitation achievable through the application of the best system of emission reduction which (taking into account the cost of achieving such reduction and any non-air quality health and environmental impact and energy requirements) the Administrator determines has been adequately demonstrated." The D.C. Circuit has reviewed CAA section 111 rulemakings on numerous occasions since 1973, and has developed a body of case law that interprets the term "standard of performance," as discussed throughout this preamble. 
The basis for standards of performance, whether promulgated by the EPA under CAA section 111(b) or established by the states under CAA section 111(d), is that the EPA determines the "degree of emission limitation" that is "achievable" by the sources by application of a "system of emission reduction" that the EPA determines is "adequately demonstrated," "taking into account" the factors of "cost ... nonair quality health and environmental impact and energy requirements," and that the EPA determines to be the "best." The D.C. Circuit has stated that in determining the "best" system, the EPA must also take into account "the amount of air pollution" reduced and the role of "technological innovation." The court has emphasized that the EPA has discretion in weighing those various factors. 
Our overall approach to determining the BSER and degree of emission limitation achievable, which incorporates the various elements, is as follows: First, we identify "system[s] of emission reduction" that have been "adequately demonstrated" for a particular source category. Second, we determine the "best" of these systems after evaluating the amount of reductions, costs, any nonair health and environmental impacts, and energy requirements. And third, we determine an achievable emission limit based on application of the BSER. For a CAA section 111(b) rule, we determine the emissions standard -- that is, the standard of performance -- that reflects the achievable emission limit. For a CAA section 111(d) rule, the states have the obligation of establishing standards of performance for the affected sources that reflect the degree of emission limitation that the EPA has determined. 
The remainder of this subsection discusses the various elements in our general analytical approach.
System of Emission Reduction
The CAA does not define the phrase "system of emission reduction." In American Lung Ass'n v. EPA, the D.C. Circuit stated that "[t]he ordinary meaning of the[] term[]" reflect[s] an intentional effort to confer the flexibility necessary for effective regulation appropriate to the context," 985 F.3d at 947 (internal quotation marks omitted), although the court further noted that other requirements "significantly rein[] in" the controls the EPA may select, and the court cited the requirements, discussed below, to consider "cost," "nonair quality health and environmental impact," and "energy requirements," and to ensure that the system is "adequately demonstrated." Id. at 962. In West Virginia v. EPA, the Supreme Court applied the major questions doctrine and held that the term "system" does not provide the requisite clear authorization to support the CPP's BSER, which the Court described as "carbon emissions caps based on a generation shifting approach." 142 S. Ct. at 2614. 
"Adequately Demonstrated" 
Under CAA section 111(a)(1), in order for a "system of emission reduction" to serve as the basis for an "achievable" emission limitation, the Administrator must determine that the system is "adequately demonstrated." This means, according to the D.C. Circuit, that the system is "one which has been shown to be reasonably reliable, reasonably efficient, and which can reasonably be expected to serve the interests of pollution control without becoming exorbitantly costly in an economic or environmental way." It does not mean that the system "must be in actual routine use somewhere." Rather, the court has said, "[t]he Administrator may make a projection based on existing technology, though that projection is subject to the restraints of reasonableness and cannot be based on `crystal ball' inquiry." Similarly, the EPA may "hold the industry to a standard of improved design and operational advances, so long as there is substantial evidence that such improvements are feasible." Ultimately, the analysis "is partially dependent on `lead time,'" that is, "the time in which the technology will have to be available." It should be emphasized that the EPA may treat a set of control measures as "adequately demonstrated" regardless of whether the measures are in widespread commercial use. For example, the D.C. Circuit upheld the EPA's determination that selective catalytic reduction (SCR) was adequately demonstrated to reduce NOx emissions from coal-fired industrial boilers, even though it was a "new technology." The court explained that "section 111 `looks toward what may fairly be projected for the regulated future, rather than the state of the art at present.'" Lignite Energy Council v. EPA, 198 F.3d 930, 934 (D.C. Cir. 1999), (citing Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 391 (D.C. Cir. 1973)). The Court added that the EPA may determine that control measures are "adequately demonstrated" through a "reasonable extrapolation of [control measure's] performance in other industries." Id. 
Costs
Under CAA section 111(a)(1), the EPA is required to take into account "the cost of achieving" the required emission reductions. As described in the January 2014 proposal for the 2015 NSPS, in several cases the D.C. Circuit has elaborated on this cost factor and formulated the cost standard in various ways, stating that the EPA may not adopt a standard the cost of which would be "exorbitant," "greater than the industry could bear and survive," "excessive," or "unreasonable." These formulations appear to be synonymous, and for convenience, in these rulemakings, we will use reasonableness as the standard, so that a control technology may be considered the "best system of emission reduction ... adequately demonstrated" if its costs are reasonable, but cannot be considered the best system if its costs are unreasonable.
The D.C. Circuit has repeatedly upheld the EPA's consideration of cost in reviewing standards of performance. In several cases, the court upheld standards that entailed significant costs, consistent with Congress's view that "the costs of applying best practicable control technology be considered by the owner of a large new source of pollution as a normal and proper expense of doing business." See Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427, 440 (D.C. Cir. 1973); Portland Cement Association v. Ruckelshaus, 486 F.2d 375, 387 - 88 (D.C. Cir. 1973); Sierra Club v. Costle, 657 F.2d 298, 313 (D.C. Cir. 1981) (upholding standard imposing controls on SO2 emissions from coal-fired power plants when the "cost of the new controls ... is substantial"). 
Non-air Quality Health and Environmental Impact and Energy Requirements
Under CAA section 111(a)(1), the EPA is required to take into account "any nonair quality health and environmental impact and energy requirements" in determining the BSER. Non-air quality health and environmental impacts may include the impacts of the disposal of byproducts of the air pollution controls, or requirements of the air pollution control equipment for water. Portland Cement Ass'n v. Ruckelshaus, 465 F.2d 375, 387 - 88 (D.C. Cir. 1973), cert. denied, 417 U.S. 921 (1974). Energy requirements may include the impact, if any, of the air pollution controls on the source's own energy needs. 
Sector or Nationwide Component of Factors In Determining the BSER
Another component of the D.C. Circuit's interpretations of CAA section 111 is that the EPA may consider the various factors it is required to consider on a national or regional level and over time, and not only on a plant-specific level at the time of the rulemaking. The D.C. Circuit based this interpretation -- which it made in the 1981 Sierra Club v. Costle case regarding the NSPS for new power plants -- on a review of the legislative history, stating, 
      [T]he Reports from both Houses on the Senate and House bills illustrate very clearly that Congress itself was using a long-term lens with a broad focus on future costs, environmental and energy effects of different technological systems when it discussed section 111.
The court has upheld EPA rules that the EPA "justified ... in terms of the policies of the Act," including balancing long-term national and regional impacts:
      The standard reflects a balance in environmental, economic, and energy consideration by being sufficiently stringent to bring about substantial reductions in SO2 emissions (3 million tons in 1995) yet does so at reasonable costs without significant energy penalties.... By achieving a balanced coal demand within the utility sector and by promoting the development of less expensive SO2 control technology, the final standard will expand environmentally acceptable energy supplies to existing power plants and industrial sources.
      
      By substantially reducing SO2 emissions, the standard will enhance the potential for long term economic growth at both the national and regional levels.
      
The EPA interprets this caselaw to authorize it to assess the impacts of the controls it is considering as the BSER, including their costs and implications for the energy system, on a sector-wide, regional, or national basis, as appropriate. For example, the EPA may assess whether controls it is considering would create risks to the reliability of the electricity system in a particular area or nationwide and, if they would, to reject those controls as the BSER.
"Best" 
In determining which adequately demonstrated system of emission reduction is the "best," the D.C. Circuit has made clear that the EPA has broad discretion. Specifically, in Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. 1981), the court explained that "section 111(a) explicitly instructs the EPA to balance multiple concerns when promulgating a NSPS," and emphasized that "[t]he text gives the EPA broad discretion to weigh different factors in setting the standard." In Lignite Energy Council v. EPA, 198 F.3d 930 (D.C. Cir. 1999), the court reiterated:
      Because section 111 does not set forth the weight that should be assigned to each of these factors, we have granted the agency a great degree of discretion in balancing them.... EPA's choice [of the `best system'] will be sustained unless the environmental or economic costs of using the technology are exorbitant.... EPA [has] considerable discretion under section 111.
      
Moreover, the D.C. Circuit has also read "best" to authorize the EPA to consider factors in addition to the ones enumerated in CAA section 111(a)(1), that further the goals of the statute. 
See Portland Cement Ass'n v. Ruckelshaus 486 F.2d 375, 385 & n.42 (D.C. Cir. 1973) (prior to enactment of the 1977 CAA Amendments that added a reference to non-air quality environmental impacts, court states that the EPA must consider "counter-productive environmental effects" in determining BSER); Sierra Club v. Costle, 657 F.2d 298, 326, 346-47 (D.C. Cir. 1981) (EPA should consider the amount of emission reductions and technology advancement in determining BSER). 
Amount of Emissions Reductions
Although the definition of "standard of performance" does not by its terms identify the amount of emissions from the category of sources or the amount of emission reductions achieved as factors the EPA must consider in determining the "best system of emission reduction," that consideration is implicit in the plain language -- the EPA must choose the best system of emission reduction. Indeed, consistent with this plain language and the purpose of CAA section 111, the D.C. Circuit has stated that the EPA must consider the quantity of emissions at issue. See Sierra Club v. Costle, 657 F.2d 298, 326 (D.C. Cir. 1981) ("we can think of no sensible interpretation of the statutory words "best ... system" which would not incorporate the amount of air pollution as a relevant factor to be weighed when determining the optimal standard for controlling ... emissions"). The fact that the purpose of a "system of emission reduction" is to reduce emissions, and that the term itself explicitly incorporates the concept of reducing emissions, supports the court's view that in determining whether a "system of emission reduction" is the "best," the EPA must consider the amount of emission reductions that the system would yield. Even if the EPA were not required to consider the amount of emission reductions, the EPA has the discretion to do so, on grounds that either the term "system of emission reduction" or the term "best" may reasonably be read to allow that discretion.
Expanded Use and Development of Technology
The D.C. Circuit has long held that Congress intended for CAA section 111 to create incentives for new technology and therefore that the EPA is required to consider technological innovation as one of the factors in determining the "best system of emission reduction." See Sierra Club v. Costle, 657 F.2d at 346 - 47. The court has grounded its reading in the statutory text. In addition, the court's interpretation finds firm support in the legislative history. The legislative history identifies three different ways that Congress designed CAA section 111 to authorize standards of performance that promote technological improvement: (i) the development of technology that may be treated as the "best system of emission reduction ... adequately demonstrated;" under CAA section 111(a)(1); (ii) the expanded use of the best demonstrated technology; and (iii) the development of emerging technology. Even if the EPA were not required to consider technological innovation as part of its determination of the BSER, it would be reasonable for the EPA to consider it because technological innovation may be considered an element of the term "best," particularly in light of Congress's emphasis on technological innovation. 
Achievability of the Degree of Emission Limitation
For new sources, CAA section 111(b)(1)(B) and (a)(1) provides that the EPA must establish "standards of performance," which are standards for emissions that reflect the degree of emission limitation that is "achievable" through the application of the BSER. According to the D.C. Circuit, a standard of performance is "achievable" if a technology can reasonably be projected to be available to an individual source at the time it is constructed that will allow it to meet the standard. Moreover, according to the court, "[a]n achievable standard is one which is within the realm of the adequately demonstrated system's efficiency and which, while not at a level that is purely theoretical or experimental, need not necessarily be routinely achieved within the industry prior to its adoption." To be achievable, a standard "must be capable of being met under most adverse conditions which can reasonably be expected to recur and which are not or cannot be taken into account in determining the `costs' of compliance." To show a standard is achievable, the EPA must "(1) identify variable conditions that might contribute to the amount of expected emissions, and (2) establish that the test data relied on by the agency are representative of potential industry-wide performance, given the range of variables that affect the achievability of the standard."
Although the D.C. Circuit established these standards for achievability in cases concerning CAA section 111(b) new source standards of performance, the same standards for achievability should apply under CAA section 111(d). For existing sources, CAA section 111(d)(1) requires the EPA to establish requirements for state plans that, in turn, must include "standards of performance." As the Supreme Court has recognized, this provision requires the EPA to promulgate emission guidelines that determine the BSER for a source category and that identify the degree of emission limitation achievable by application of the BSER. See West Virginia v. EPA, 142 S. Ct. 2587, 2601-02 (2022).
The EPA has promulgated emission guidelines on the basis that the existing sources can achieve the degree of emission limitation described herein, even though the state retains discretion to apply standards of performance to individual sources that are more or less stringent. Note further that this requirement that the emission limitation be "achievable" based on the "best system of emission reduction ... adequately demonstrated" indicates that the technology or other measures that the EPA identifies as the BSER must be technically feasible. 
EPA Promulgation of Emission Guidelines for States to Establish Standards of Performance
CAA section 111(d)(1) directs the EPA to promulgate regulations establishing a CAA section 110-like procedure under which states submit state plans that establish "standards of performance" for emissions of certain air pollutants from sources which, if they were new sources, would be regulated under CAA section 111(b), and that implement and enforce those standards of performance. The term "standard of performance" is defined under CAA section 111(a)(1), quoted above. Thus, CAA sections 111(a)(1) and (d)(1) collectively require the EPA to determine the BSER for the existing sources and, based on the BSER, to establish emission guidelines that identify the minimum amount of emission limitation that a state, in its state plan, must impose on its existing sources through standards of performance. Consistent with these CAA requirements, the EPA's regulations require that the EPA's guidelines reflect--
      the degree of emission limitation achievable through the application of the best system of emission reduction which (taking into account the cost of such reduction and any non-air quality health and environmental impact and energy requirements) the Administrator has determined has been adequately demonstrated from designated facilities.

Following the EPA's promulgation of emission guidelines, each state must determine the standards of performance for its existing sources, which the EPA's regulations call "designated facilities." While the EPA specifies in emission guidelines the degree of emission limitation achievable through application of the best system of emission reduction, which it may express as a presumptive standard of performance, a state retains discretion in applying such a presumptive standard of performance to any particular designated facility. CAA section 111(d)(1) requires the EPA's regulations to "permit the State in applying a standard of performance to any particular source ... to take into consideration, among other factors, the remaining useful life of the ... source...." Consistent with this statutory direction, the EPA's regulations provide requirements for states that wish to apply standards of performance that deviate from an emission guideline. In December 2022, the EPA proposed to clarify these requirements, including the three circumstances under which states can invoke a particular source's remaining useful life and other factors (RULOF), to apply a less stringent standard of performance. These proposed clarifications provided:
      The State may apply a standard of performance to a particular source that is less stringent than otherwise required by an applicable emission guideline, taking into consideration remaining useful life and other factors, provided that the State demonstrates with respect to each such facility (or class of such facilities) that it cannot reasonably apply the best system of emission reduction to achieve the degree of emission limitation determined by the EPA, based on:
 Unreasonable cost of control resulting from plant age, location, or basic process design;
 Physical impossibility or technical infeasibility of installing necessary control equipment; or
 Other circumstances specific to the facilities (or class of facilities) that are fundamentally different from the information considered in the determination of the best system of emission reduction in the emission guidelines.

87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-2021-0527-0002 (proposed 40 CFR 60.24a(e)). In addition, under CAA sections 111(d) and 116, the state is authorized to establish a standard of performance for any particular source that is more stringent than the presumptive standards contained in the EPA's emission guidelines. Thus, for any particular source, a state may apply a standard of performance that is either more stringent or less stringent than the presumptive standards of performance in the emission guidelines. The state must include the standards of performance in their state plans and submit the plans to the EPA for review. Under CAA section 111(d)(2)(A), the EPA approves state plans that are determined to be "satisfactory." 
Stakeholder Engagement
Prior to proposing these actions, the EPA conducted outreach to a broad range of stakeholders. The EPA also opened a non-regulatory pre-proposal docket to solicit public input on the Agency's efforts to reduce GHG emissions from new and existing EGUs. For additional details on stakeholder engagement, see the memorandum in the docket titled Stakeholder Outreach.
The EPA conducted two rounds of outreach to gather input for these proposals. In the first round of outreach, in early 2022, the EPA sought input in a variety of formats and settings from states, tribal nations, and a broad range of stakeholders on the state of the power sector and how the Agency's regulatory actions affect those trends. This outreach included state energy and environmental regulators; tribal air regulators; power companies and trade associations representing investor-owned utilities, rural electric cooperatives, and municipal power agencies; environmental justice and community organizations; and labor, environmental, and public health organizations. A second round of outreach took place in August and September 2022, and focused on seeking input specific to this rulemaking. The EPA asked to hear perspectives, priorities, and feedback around five guiding questions, and encouraged public input to the nonregulatory docket (Docket ID No. EPA-HQ-OAR-2022-0723) on these questions as well. 
The EPA also regularly interacts with other Federal agencies and departments whose activities intersect with the power sector, and in the course of developing these proposed rules the Agency conducted multiple discussions with these agencies to benefit from their expertise and to explore the potential interaction of these proposed rules with their independent missions and initiatives. Among other things, these discussions focused on the impacts of proposed investments in energy technology by the Department of Energy and Department of Treasury on the technical and economic analyses underlying this proposal. In addition, the EPA evaluated structures in these proposals to address reliability considerations with the Department of Energy and Federal Energy Regulatory Commission.
Proposed Requirements for New and Reconstructed Stationary Combustion Turbine EGUs and Rationale for Proposed Requirements
Overview
This section discusses and proposes requirements for new and reconstructed stationary combustion turbine EGUs. The EPA is proposing that those requirements will be part of a new 40 CFR part 60, subpart TTTTa. The EPA explains in section VII.B the two basic turbine technologies in use in the power sector and covered by 40 CFR part 60, subpart TTTT, simple cycle turbines and combined cycle turbines. It further explains how these technologies are used in the three general categories of low load turbines, intermediate load turbines, and base load turbines. Section VII.C provides an overview of how stationary combustion turbine EGUs have been previously regulated and how the EPA recently took comment on a proposed whitepaper on GHG mitigation options for stationary combustion turbines. Section VII.D discusses the EPA's decision to revisit the standards for turbines as part of the statutorily required 8-year review. Section VII.E discusses changes that the EPA is proposing in both applicability and subcategories in the new proposed 40 CFR part 60, subpart TTTTa as compared to those codified in 40 CFR part 60, subpart TTTT. Most notably, for natural gas-fired combustion turbines, the EPA is proposing three subcategories, a low load subcategory, an intermediate load subcategory, and a base load subcategory. 
Section VII.F discusses the EPA's determination of the BSER for each of the subcategories of turbines. For low load combustion turbines, the EPA continues to believe that use of clean fuels is the appropriate BSER. For intermediate load turbines, the EPA believes that co-firing low-GHG hydrogen is an appropriate component of the BSER beginning in 2035, when the EPA projects there will be enough low-GHG hydrogen at a reasonable price to supply all of the combustion turbines that would need to use it. For this reason, the EPA is proposing a two-component BSER for intermediate load combustion turbines, and a two-phase standard of performance, in which the first phase is based on highly efficient generation (based on the performance of a highly efficient simple cycle turbine) and the second phase is based on co-firing 30 percent (by volume) low-GHG hydrogen, along with continued use of highly efficient generation. 
For base load turbines, while the EPA believes CCS is available and of reasonable cost today, the EPA proposes that a two-component BSER and a two-phase standard of performance is also appropriate based on consideration of the manufacturing and installation capabilities within the larger EGU category and other industries and considerations of projected operation of combustion turbines in the future. For base load turbines, the EPA is proposing that the first phase is based on highly efficient generation (based on the performance of a highly efficient combined cycle unit) and the second phase is based on the use of either CCS with 90 percent CO2 capture or co-firing with 30 percent (by volume) low-GHG hydrogen, depending on the subcategory, along with continued use of highly efficient generation. For both intermediate load and base load turbines, the standards corresponding to both components of the BSER would apply to all new and reconstructed sources that commence construction or reconstruction after the publication date of this proposal. The EPA occasionally refers to these standards of performance as the phase-1 or phase-2 standards.
Combustion Turbine Technology
For purposes of 40 CFR part 60, subparts TTTT and TTTTa, stationary combustion turbines include both simple cycle and combined cycle EGUs. Simple cycle turbines operate in the Brayton thermodynamic cycle and include three primary components: a multistage compressor, a combustion chamber (i.e., combustor), and a turbine. The compressor is used to supply large volumes of high-pressure air to the combustion chamber. The combustion chamber converts fuel to heat and expands the now heated, compressed air to create shaft work. The shaft work drives an electric generator to produce electricity. Combustion turbines that recover their high-temperature exhaust -- instead of venting it directly to the atmosphere -- are combined cycle EGUs and can obtain additional useful electric output. A combined cycle EGU includes a heat recovery steam generator (HRSG) operating in the Rankine thermodynamic cycle. The HRSG receives the high-temperature exhaust and converts the heat to mechanical energy by producing steam that is then fed into a steam turbine that, in turn, drives a second electric generator. As the thermal efficiency of a stationary combustion turbine EGU is increased, less fuel is burned to produce the same amount of electricity, with a corresponding decrease in fuel costs and lower emissions of CO2 and, generally, of other air pollutants. The greater the output of electric energy for a given amount of fuel energy input, the higher the efficiency of the electric generation process. 
Combustion turbines serve various roles in the power sector. Some combustion turbines operate at low annual capacity factors and are available to provide temporary power during periods of high load demand. These turbines are often referred to as "peaking units." Some combustion turbines operate at intermediate annual capacity factors and are often referred to as cycling or load-following units. Other combustion turbines operate at high annual capacity factors to serve base load demand and are often referred to as base load units. In this proposal, the EPA refers to these types of combustion turbines as low load, intermediate load, and base load, respectively.
Low load combustion turbines provide reserve capacity, support grid reliability, and generally provide power during periods of peak electric demand. As such, the units may operate at or near their full capacity, but only for short periods, as needed. Because these units only operate occasionally, capital expenses are a major factor in the cost of electricity, and often, the lowest capital cost (and generally least efficient) simple cycle EGUs are used only during periods of peak electric demand. This is because even though their capital cost is low they are inefficient and require more fuel per MWh produced and, thus, their operating costs tend to be higher. Because of the higher operating costs, they are generally some of the last units in the dispatch order. Important characteristics for low load combustion turbines include their low capital costs, their ability to start and quickly ramp to full load, and their ability to operate at partial loads while maintaining acceptable emission rates and efficiencies. The ability to start and quickly attain full load is important to maximize revenue during periods of peak electric prices and to meet sudden shifts in demand. Simple cycle combustion turbines typically fill this role even though they are less efficient and have higher fuel costs per kilowatt hour (kWh) than combined cycle EGUs, which due to their higher efficiencies, often operate at higher capacity factors, including at base load. 
Highly efficient simple cycle turbines and fast-start combined cycle turbines both offer different advantages and disadvantages when operating at intermediate loads. One of the roles of these intermediate, or load-following, EGUs is to provide dispatchable backup power to support intermittent renewable generating sources. A developer's decision of whether to build a simple cycle combustion turbine or a combined cycle combustion turbine to serve intermediate load demand would be based on several factors related to the intended operation of the unit. These factors include how frequently the unit is expected to cycle between starts and stops, the predominant load level at which the unit is expected to operate, and whether this level of operation is expected to remain consistent or is expected to vary over the lifetime of the unit. While the owner/operator of an individual combustion turbine controls whether and how that unit will operate over time, they do not necessarily control the precise timing of dispatch for the unit in any given day or hour. Such short-term dispatch decisions are often made by regional grid operators that determine, on a moment-to-moment basis, which available individual units should operate to balance supply and demand and other requirements in an optimal manner. However, operating permits for simple cycle turbines often contain restrictions on the annual hours of operation which owners/operators incorporate into longer term operating plans. 
Intermediate load combustion turbines vary their generation, especially during transition periods between low and high electric demand. Both high-efficiency simple cycle combustion turbines and fast-start combined cycle combustion turbines can fill this cycling role. While the ability to start and quickly ramp is important, efficiency is also an important characteristic. These combustion turbines have higher capital costs than low load combustion turbines but are less expensive to operate.
Base load combustion turbines are designed to operate for extended periods at high loads with infrequent starts and stops. Quick start capability and low capital costs are less important than low operating costs. High-efficiency combined cycle combustion turbines typically fill the role of base load combustion turbines.
The increase in generation from intermittent renewable energy sources during the past decade has impacted the way in which firm dispatchable generating resources operate. For example, the electric output from wind and solar generating sources fluctuates daily and seasonally due to increases and decreases in the wind speed or solar intensity. Due to this intermittent nature of wind and solar, firm dispatchable electric generating units need to be available to ensure the reliability of the electric grid. This requires technologies such as dispatchable power plants to start and stop and change load more frequently than was previously needed. Important characteristics of combustion turbines that provide firm backup capacity are the ability to start and stop quickly and the ability to quickly change loads. Natural gas-fired combustion turbines are much more flexible than coal-fired utility boilers in this regard and have played an important role in maintaining grid reliability during the past decade. 
As discussed in section IV.F.2 of this preamble and in the accompanying RIA, the post-IRA 2022 reference case projects that natural gas-fired combustion turbines will continue to play an important role in maintaining grid reliability. However, that role is projected to evolve as additional renewable generation and energy storage technologies are added to the grid. Energy storage technologies would have a greater ability to store energy during periods when generation from renewable resources is high relative to demand and provide electricity to the grid during other periods. This could reduce the need for firm dispatchable power plants to start and stop as frequently. Consequently, in the future, naturual gas-fired stationary combustion turbine EGUs may run at more stable operation and, thus, more efficiently (i.e., at higher duty cycles and for longer periods of operation per start). The EPA is soliciting comment on whether this a likely scenario. 
Overview of Regulation of Stationary Combustion Turbines for GHGs
As explained earlier in this preamble, the EPA originally regulated stationary combustion turbine EGUs for emissions of GHGs in 2015 under 40 CFR part 60, subpart TTTT. In 40 CFR part 60, subpart TTTT, the EPA created three subcategories, two for natural gas-fired combustion turbines and one for multi-fuel-fired combustion turbines. For natural gas-fired turbines, the EPA created a subcategory for base load turbines and a separate subcategory for non-base load turbines. Base load turbines were defined as combustion turbines with electric sales greater than a site-specific electric sales threshold that is based on the design efficiency of the combustion turbine. Non-base load turbines were defined as combustion turbines with a capacity factor less than or equal to the site-specific electric sales threshold. For base load turbines, the EPA set a standard of 1,000 lb CO2/MWh-gross based on efficient combined cycle turbine technology and for non-base load and multi-fuel-fired turbines, the EPA set a standard based on the use of clean fuels that varied from 120 lb CO2/MMBtu to 160 lb CO2/MMBtu depending upon whether the turbine burned primarily natural gas or other clean fuels.
On April 21, 2022, the EPA issued an informational draft white paper, titled Available and Emerging Technologies for Reducing Greenhouse Gas Emissions from Combustion Turbine Electric Generating Units. The draft document included discussion of the basic types of available stationary combustion turbines as well as factors that influence GHG emission rates from these sources. The technology discussion in the draft white paper included information on an array of new and existing control technologies and potential reduction measures for GHG emissions. These reduction measures included: the GHG reduction potential of various efficiency improvements; technologies capable of firing or co-firing alternative fuels such as hydrogen; the ongoing advancement of CCS projects with NGCC units; and, the co-location of technologies that do not emit onsite GHG emissions with EGUs, such as onsite renewables or short-duration energy storage.
The EPA provided an opportunity for the public to comment on this white paper to inform its approach to this proposed rulemaking. More than 30 groups or individuals provided public comments on the topics and technologies discussed in the draft white paper. Commenters included representatives from utilities, technology providers, trade associations, states, regulatory agencies, environmental groups, and public health advocates. The information provided in the public comments was beneficial in enabling the EPA to review the current NSPS for new stationary combustion turbines and to develop the proposed revisions described in this preamble. 
Eight-Year Review of NSPS
CAA section 111(b)(1)(B) requires the Administrator to "at least every 8 years, review and, if appropriate, revise [the NSPS] ..." The provision further provides that "the Administrator need not review any such standard if the Administrator determines that such review is not appropriate in light of readily available information on the efficacy of such [NSPS]." 
The EPA promulgated the NSPS for GHG emissions for stationary combustion turbines in 2015. Announcements and modeling projections show companies are building new fossil fuel-fired combustion turbines and plan to continue building additional capacity. Because the emissions from this capacity have the potential to be large and these units are likely to have long lives (25 years or more), the EPA believes it is important to consider options to reduce emissions from these new units. In addition, the EPA is aware of developments concerning the types of control measures that may be available to reduce GHG emissions from new stationary combustion turbines. Accordingly, the EPA is proceeding to review and is proposing updated NSPS for newly constructed and reconstructed fossil fuel-fired stationary combustion turbines.
Applicability Requirements and Subcategorization
This section describes the proposed amendments to the specific applicability criteria for non-fossil fuel-fired combustion turbines, industrial combustion turbines, CHP combustion turbines, and combustion turbines not connected to a natural gas pipeline and the proposed amendments to the subcategories based on the level of electric sales. The EPA is also proposing certain changes to the applicability requirements for stationary combustion turbines affected by this proposal as compared to those for sources affected by the 2015 NSPS. The proposed changes are described below and include the elimination of the multi-fuel-fired subcategory, further binning non-base load combustion turbines into low and intermediate load subcategories, and lowering the electric sales threshold for base load combustion turbines.
Applicability Requirements
In general, the EPA refers to fossil fuel-fired EGUs that would be subject to a CAA section 111 NSPS as "affected" EGUs or units. An EGU is any fossil fuel-fired electric utility steam generating unit (i.e., a utility boiler or IGCC unit) or stationary combustion turbine (in either simple cycle or combined cycle configuration). To be considered an affected EGU under the current NSPS at 40 CFR part 60, subpart TTTT, the unit must meet the following applicability criteria: The unit must: (i) be capable of combusting more than 250 million British thermal units per hour (MMBtu/h) (260 gigajoules per hour (GJ/h)) of heat input of fossil fuel (either alone or in combination with any other fuel); and (ii) serve a generator capable of supplying more than 25 MW net to a utility distribution system (i.e., for sale to the grid). However, 40 CFR part 60, subpart TTTT includes applicability exemptions for certain EGUs, including: (1) non-fossil fuel-fired units subject to a federally enforceable permit that limits the use of fossil fuels to 10 percent or less of their heat input capacity on an annual basis; (2) CHP units that are subject to a federally enforceable permit limiting annual net electric sales to no more than either the unit's design efficiency multiplied by its potential electric output, or 219,000 megawatt-hours (MWh), whichever is greater; (3) stationary combustion turbines that are not physically capable of combusting natural gas (e.g., those that are not connected to a natural gas pipeline); (4) utility boilers and IGCC units that have always been subject to a federally enforceable permit limiting annual net electric sales to one-third or less of their potential electric output (e.g., limiting hours of operation to less than 2,920 hours annually) or limiting annual electric sales to 219,000 MWh or less; (5) municipal waste combustors that are subject to 40 CFR part 60, subpart Eb; (6) commercial or industrial solid waste incineration units subject to 40 CFR part 60, subpart CCCC; and (7) certain projects under development, as discussed below.
Revisions to 40 CFR Part 60, Subpart TTTT
The EPA is proposing to amend 40 CFR 60.5508 and 60.5509 to reflect that 40 CFR part 60, subpart TTTT will remain applicable to steam generating EGUs and IGCC units constructed after January 8, 2014 or reconstructed after June 18, 2014. The EPA is also proposing that stationary combustion turbines that commenced construction after January 8, 2014 or reconstruction after June 18, 2014 and before [INSERT DATE OF PUBLICATION IN FEDERAL REGISTER] that meet the relevant applicability criteria would be subject to 40 CFR part 60, subpart TTTT. Upon promulgation of 40 CFR part 60, subpart TTTTa, stationary combustion turbines that commence construction or reconstruction after [INSERT DATE OF PUBLICATION IN FEDERAL REGISTER] and meet the relevant applicability criteria will be subject to 40 CFR part 60, subpart TTTTa.
Revisions to 40 CFR Part 60, Subpart TTTT that would also be included in 40 CFR Part 60, Subpart TTTTa
 The EPA is proposing that 40 CFR part 60, subpart TTTT and 40 CFR part 60, subpart TTTTa use similar regulatory text except where specifically stated. This section describes proposed amendments that would be included in both subparts.
Applicability to Non-fossil Fuel-fired EGUs
The current non-fossil applicability exemption in 40 CFR part 60, subpart TTTT is based strictly on the combustion of non-fossil fuels (e.g., biomass). To be considered a non-fossil fuel-fired EGU, the EGU must both (1) be capable of combusting more than 50 percent non-fossil fuel and (2) be subject to a federally enforceable permit condition limiting the annual capacity factor for all fossil fuels combined of 10 percent (0.10) or less. The current language does not take heat input from non-combustion sources (e.g., solar thermal) into account. Certain solar thermal installations have natural gas backup burners larger than 250 MMBtu/h. As currently written, these solar thermal installations would not be eligible to be considered non-fossil units because they are not capable of deriving more than 50 percent of their heat input from the combustion of non-fossil fuels. Therefore, solar thermal installations that include backup burners could meet the applicability criteria of 40 CFR part 60, subpart TTTT even if the burners are limited to an annual capacity factor of 10 percent or less. These EGUs would readily comply with the emissions standard, but the reporting and recordkeeping would increase costs for these EGUs.
The EPA is proposing several amendments to align the applicability criteria with the original intent to cover only fossil fuel-fired EGUs. This would ensure that solar thermal EGUs with natural gas backup burners, like other types of non-fossil fuel-fired units in which most of their energy is derived from non-fossil fuel sources, are not subject to the requirements of 40 CFR part 60, subparts TTTT or TTTTa. Amending the applicability language to include heat input derived from non-combustion sources would allow these facilities to avoid the requirements of 40 CFR part 60, subparts TTTT or TTTTa by limiting the use of the natural gas burners to less than 10 percent of the capacity factor of the backup burners. Specifically, the EPA is proposing to amend the definition of non-fossil fuel-fired EGUs from EGUs capable of "combusting 50 percent or more non-fossil fuel" to EGUs capable of "deriving 50 percent or more of the heat input from non-fossil fuel at the base load rating." (emphasis added). The definition of base load rating would also be amended to include the heat input from non-combustion sources (e.g., solar thermal). 
The proposed amended non-fossil fuel applicability language changing "combusting" to "deriving" will ensure that 40 CFR part 60, subparts TTTT and TTTTa cover the fossil fuel-fired EGUs, properly understood, that the original rule was intended to cover, while minimizing unnecessary costs to EGUs fueled primarily by steam generated without combustion (e.g., through the use of solar thermal). The corresponding change in the base load rating to include the heat input from non-combustion sources is necessary to determine the relative heat input from fossil fuel and non-fossil fuel sources.
Industrial EGUs
Applicability to Industrial EGUs
In simple terms, the current applicability provisions in 40 CFR part 60, subpart TTTT require that an EGU be capable of combusting more than 250 MMBtu/h of fossil fuel and be capable of selling 25 MW to a utility distribution system to be subject to 40 CFR part 60, subpart TTTT. These applicability provisions exclude industrial EGUs. However, the definition of an EGU also includes "integrated equipment that provides electricity or useful thermal output." This language facilitates the integration of non-emitting generation and avoids energy inputs from non-affected facilities being used in the emission calculation without also considering the emissions of those facilities (e.g., an auxiliary boiler providing steam to a primary boiler). This language could result in certain large processes being included as part of the EGU and meeting the applicability criteria. For example, the high-temperature exhaust from an industrial process (e.g., calcining kilns, dryer, metals processing, or carbon black production facilities) that consumes fossil fuel could be sent to a HRSG to produce electricity. If the industrial process is more than 250 MMBtu/h heat input and the electric sales exceed the applicability criteria, then the unit could be subject to 40 CFR part 60, subparts TTTT or TTTTa. This is potentially problematic for multiple reasons. First, it is difficult to determine the useful output of the EGU (i.e., HRSG) since part of the useful output is included in the industrial process. In addition, the fossil fuel that is combusted might have a relatively high CO2 emissions rate on a lb/MMBtu basis, making it problematic to meet the emissions standard. Finally, the compliance costs associated with 40 CFR part 60, subparts TTTT or TTTTa could discourage the development of environmentally beneficial projects.
To avoid these outcomes, the EPA is proposing to amend the applicability provision that exempts EGUs where greater than 50 percent of the heat input is derived from an industrial process that does not produce any electrical or mechanical output or useful thermal output that is used outside the affected EGU. Projects of this type provide significant environmental benefit with little if any additional emissions. Including these types of projects would result in regulatory burden without any associated environmental benefit and would discourage project development, leading to overall increases in GHG emissions.
Industrial EGUs Electric Sales Threshold Permit Requirement
The current electric sales applicability exemption in 40 CFR part 60, subpart TTTT for non-CHP steam generating units includes the provision that EGUs have "always been subject to a federally enforceable permit limiting annual net electric sales to one-third or less of their potential electric output (e.g., limiting hours of operation to less than 2,920 hours annually) or limiting annual electric sales to 219,000 MWh or less" (emphasis added). The justification for this restriction includes that the 40 CFR part 60, subpart Da applicability language includes "constructed for the purpose of ..." and the Agency concluded that the intent was defined by permit conditions (80 FR 64544; October 23, 2015). This applicability criterion is important for determining applicability with both the new source CAA section 111(b) requirements and if existing steam generating units are subject to the existing source CAA section 111(d) requirements. For steam generating units that commenced construction after September 18, 1978, the applicability of 40 CFR part 60, subpart Da, would be relatively clear by what criteria pollutant NSPS is applicable to the facility. However, for steam generating units that commenced construction prior to September 18, 1978, or where the owner/operator determined that criteria pollutant NSPS applicability was not critical to the project (e.g., emission controls were sufficient to comply with either the EGU or industrial boiler criteria pollutant NSPS), owners/operators might not have requested an electric sales permit restriction be included in the operating permit. Under the current applicability language, some onsite EGUs could be covered by the existing source CAA section 111(d) requirements even if they have never sold electricity to the grid. To avoid covering these industrial EGUs, the EPA is proposing to amend the electric sales exemption in 40 CFR part 60, subparts TTTT and TTTTa to read, "annual net-electric sales have never exceeded one-third of its potential electric output or 219,000 MWh, whichever is greater, and is" (the "always been" would be deleted) subject to a federally enforceable permit limiting annual net electric sales to one-third or less of their potential electric output (e.g., limiting hours of operation to less than 2,920 hours annually) or limiting annual electric sales to 219,000 MWh or less" (emphasis added). EGUs that reduce current generation would continue to be covered as long as they sold more than one-third of their potential electric output at some time in the past. The proposed revisions would simply make it possible for an owner/operator of an existing industrial EGU to provide evidence to the Administrator that the facility has never sold electricity in excess of the electricity sales threshold and to modify their permit to limit sales in the future. Without the amendment, owners/operators of any non-CHP industrial EGU capable of selling 25 MW would be subject to the existing source CAA section 111(d) requirements even if they have never sold any electricity. Therefore, the EPA is proposing the exemption to eliminate the requirement that existing industrial EGUs must have always been subject to a permit restriction limiting net electric sales.
Determination of the Design Efficiency 
The design efficiency (i.e., the efficiency of converting thermal energy to useful energy output) of a combustion turbine is used to determine the electric sales applicability threshold and is relevant to both new and existing EGUs. The sales criteria are based in part on the individual EGU design efficiency. Three methods for determining the design efficiency are currently provided in 40 CFR part 60, subpart TTTT. Since the 2015 NSPS was finalized, the EPA has become aware that owners/operators of certain existing EGUs do not have records of the original design efficiency. These units are not able to readily determine whether they meet the applicability criteria and are therefore subject to the CAA section 111(d) requirements for existing sources in the same way that 111(b) sources would be able to determine if the facility meets the applicability criteria. Many of these EGUs are CHP units and it is likely they do not meet the applicability criteria. However, the language in the 2015 NSPS would require them to conduct additional testing to demonstrate this. The requirement would result in burden to the regulated community without any environmental benefit. The electricity generating market has changed, in some cases dramatically, during the lifetime of existing EGUs, especially concerning ownership. As a result of acquisitions and mergers, original EGU design efficiency documentation as well as performance guarantee results that affirmed the design efficiency, may no longer exist. Moreover, such documentation and results may not be relevant for current EGU efficiencies, as changes to original EGU configurations, upon which the original design efficiencies were based, render those original design efficiencies moot, meaning that there would be little reason to maintain former design efficiency documentation since it would not comport with the efficiency associated with current EGU configurations. As the three specified methods would rely on documentation from the original EGU configuration performance guarantee testing, and results from that documentation may no longer exist or be relevant, it is only appropriate to allow other means to demonstrate EGU design efficiency. To reduce compliance burden, the EPA is proposing in 40 CFR part 60, subparts TTTT and TTTTa to allow alternative methods as approved by the Administrator on a case-by-case basis. Owners/operators of EGUs would petition the Administrator in writing to use an alternate method to determine the design efficiency. The Administrator's discretion is intentionally left broad and could extend to other American Society of Mechanical Engineers (ASME) or International Organization for Standardization (ISO) methods as well as to operating data to demonstrate the design efficiency of the EGU. The EPA is also proposing to change the applicability of paragraph 60.8(b) in table 3 of 40 CFR part 60, subpart TTTT from "no" to "yes" and that the applicability of paragraph 60.8(b) in table 3 of 40 CFR part 60, subpart TTTTa is "yes." This would allow the Administrator to approve alternatives to the test methods specified in 40 CFR part 60, subparts TTTT and TTTTa.
Applicability for 40 CFR Part 60, subpart TTTTa
This section describes proposed amendments that would only be incorporated into 40 CFR part 60, subpart TTTTa and would differ from the requirements in 40 CFR part 60, subpart TTTT.
Proposed Applicability
	Section 111 of the CAA defines a new or modified source for purposes of a given NSPS as any stationary source that commences construction or modification after the publication of the proposed regulation. Thus, any standards of performance the Agency finalizes as part of this rulemaking will apply to EGUs that commence construction or reconstruction after the date of this proposal. (EGUs that commenced construction after the date of the proposal for the 2015 NSPS and by the date of this proposal will remain subject to the standards of performance promulgated in the 2015 NSPS). A modification is any physical change in, or change in the method of operation of, an existing source that increases the amount of any air pollutant emitted to which a standard applies. The NSPS General Provisions (40 CFR part 60, subpart A) provide that an existing source is considered a new source if it undertakes a reconstruction.
The EPA is proposing the same applicability requirements in 40 CFR part 60, subpart TTTTa as the applicability requirements in 40 CFR part 60, subpart TTTT. The stationary combustion turbine must meet the following applicability criteria: The stationary combustion turbine must: (i) be capable of combusting more than 250 million British thermal units per hour (MMBtu/h) (260 gigajoules per hour (GJ/h)) of heat input of fossil fuel (either alone or in combination with any other fuel); and (ii) serve a generator capable of supplying more than 25 MW net to a utility distribution system (i.e., for sale to the grid). In addition, the EPA is proposing in 40 CFR part 60, subpart TTTTa to include applicability exemptions for stationary combustion turbines that are: (1) capable of deriving 50 percent or more of the heat input from non-fossil fuel at the base load rating and subject to a federally enforceable permit condition limiting the annual capacity factor for all fossil fuels combined of 10 percent (0.10) or less; (2) combined heat and power units subject to a federally enforceable permit condition limiting annual net-electric sales to no more than 219,000 MWh or the product of the design efficiency and the potential electric output, whichever is greater; (3) serving a generator along with other steam generating unit(s), IGCC, or stationary combustion turbine(s) where the effective generation capacity is 25 MW or less; (4) municipal waste combustors that are subject to 40 CFR part 60, subpart Eb; (5) commercial or industrial solid waste incineration units subject to 40 CFR part 60, subpart CCCC; and (6) deriving greater than 50 percent of heat input from an industrial process that does not produce any electrical or mechanical output that is used outside the affected stationary combustion turbine. 
The EPA is proposing to apply the same requirements to combustion turbines in non-continental areas (i.e., Hawaii, the Virgin Islands, Guam, American Samoa, the Commonwealth of Puerto Rico, and the Northern Mariana Islands) and non-contiguous areas (non-continental areas and Alaska) as the EPA is proposing for comparable units in the contiguous 48 states. However, new units in non-continental and non-contiguous areas may operate on small, isolated electric grids, may operate differently from units in the contiguous 48 states, and may have limited access to certain components of the proposed BSER due to their uniquely isolated geography or infrastructure. Therefore, the EPA is soliciting comment on whether combustion turbines in non-continental and non-contiguous areas should be subject to different requirements.
Applicability to CHP units 
For 40 CFR part 60, subpart TTTT, owner/operators of CHP units calculate net electric sales and net energy output using an approach that includes "at least 20.0 percent of the total gross or net energy output consists of electric or direct mechanical output." It is unlikely that a CHP unit with a relatively low electric output (i.e., less than 20.0 percent) would meet the applicability criteria. However, if a CHP unit with less than 20.0 percent of the total output consisting of electricity were to meet the applicability criteria, the net electric sales and net energy output would be calculated the same as for a traditional non-CHP EGU. Even so, it is not clear that these CHP units would have less environmental benefit per unit of electricity produced than more traditional CHP units. For 40 CFR part 60, subpart TTTTa, the EPA is proposing to eliminate the restriction that CHP units produce at least 20.0 percent electrical or mechanical output to qualify for the CHP-specific method for calculating net electric sales and net energy output.
      In the 2015 NSPS, the EPA did not issue standards of performance for certain types of sources -- including industrial CHP units and CHPs that are subject to a federally enforceable permit limiting annual net electric sales to no more than the unit's design efficiency multiplied by its potential electric output, or 219,000 MWh or less, whichever is greater. For CHP units, the approach in 40 CFR part 60, subpart TTTT for determining net electric sales for applicability purposes allows the owner/operator to subtract the purchased power of the thermal host facility. The intent of the approach is to determine applicability similarly for third-party developers and CHP units owned by the thermal host facility. However, as written in 40 CFR part 60, subpart TTTT, each third-party CHP unit would subtract the entire electricity use of the thermal host facility when determining its net electric sales. It is clearly not the intent of the provision to allow multiple third-party developers that serve the same thermal host to all subtract the purchased power of the thermal host facility when determining net electric sales. This would result in counting the purchased power multiple times. In addition, it is not the intent of the provision to allow a CHP developer to provide a trivial amount of useful thermal output to multiple thermal hosts and then subtract all the thermal hosts' purchased power when determining net electric sales for applicability purposes. The proposed approach in 40 CFR part 60, subpart TTTTa would set a limit to the amount of thermal host purchased power that a third-party CHP developer can subtract for electric sales when determining net electric sales equivalent to the percentage of useful thermal output provided to the host facility by the specific CHP unit. This approach would eliminate both circumvention of the intended applicability by sales of trivial amounts of useful thermal output and double counting of thermal host-purchased power. 
      Finally, to avoid potential double counting of electric sales, the EPA is proposing that for CHP units determining net electric sales, purchased power of the host facility would be determined based on the percentage of thermal power provided to the host facility by the specific CHP facility.
Non-natural Gas Stationary Combustion Turbines
There is currently an exemption in 40 CFR part 60, subpart TTTT for stationary combustion turbines that are not physically capable of combusting natural gas (e.g., those that are not connected to a natural gas pipeline). While combustion turbines not connected to a natural gas pipeline meet the general applicability of 40 CFR part 60, subpart TTTT, these units are not subject to any of the requirements. The EPA is proposing requirements for new and reconstructed combustion turbines that are not capable of combusting natural gas. As described in the standards of performance section, the Agency is proposing that owners/operators of combustion turbines burning fuels with a higher heat input emission rate than natural gas would adjust the natural gas-fired emissions rate by the ratio of the heat input-based emission rates. The overall result is that new stationary combustion turbines combusting fuels with higher GHG emissions rates than natural gas on a lb CO2/MMBtu basis would have to maintain the same efficiency compared to a natural gas-fired combustion turbine and comply with an emissions standard based on the identified BSER. Therefore, the EPA is not including in 40 CFR part 60, subpart TTTTa, the exemption for stationary combustion turbines that are not physically capable of combusting natural gas.
Subcategories
Stationary combustion turbines are defined in the 2015 NSPS to include both simple cycle and combined cycle EGUs. In addition, 40 CFR part 60, subpart TTTT includes three subcategories for combustion turbines -- natural gas-fired base load EGUs, natural gas-fired non-base load EGUs, and multi-fuel-fired EGUs. Base load EGUs are those that sell electricity in excess of the site-specific electric sales threshold to an electric distribution network on both a 12-operating-month and 3-year rolling average basis. Non-base load EGUs are those that sell electricity at or less than the site-specific electric sales threshold to an electric distribution network on both a 12-operating-month and 3-year rolling average basis. Multi-fuel-fired EGUs combust 10 percent or more (by heat input) of fuels not meeting the definition of natural gas on a 12-operating-month rolling average basis. 
Legal Basis for Subcategorization
As noted in section V.C.1., CAA section 111(b)(2) provides that the EPA "may distinguish among classes, types, and sizes within categories of new sources for the purpose of establishing ... standards [of performance]." The D.C. Circuit has held that the EPA has broad discretion in determining whether and how to subcategorize under CAA section 111(b)(2). Lignite Energy Council v. EPA, 198 F3d 930, 933 (D.C. Cir. 1999). As also noted in section V.C.1., in prior CAA section 111 rules, the EPA has subcategorized on numerous bases, including, among other things, fuel type and extent of utilization. 
Electric Sales Subcategorization (Low, Intermediate, and Base Load Combustion Turbines)
As noted earlier, in the 2015 NSPS, the EPA established separate standards for natural gas-fired base load and non-base load stationary combustion turbines. The electric sales threshold distinguishing the two subcategories is based on the design efficiency of individual combustion turbines. A stationary combustion turbine qualifies as a non-base load turbine, and is thus subject to a less stringent standard of performance, if it has net electric sales equal to or less than the design efficiency of the turbine (not to exceed 50 percent) multiplied by the potential electric output (80 FR 64601; October 23, 2015). If the net electric sales exceed that level, then the combustion turbine is in the base load combustion subcategory and is subject to a more stringent standard of performance. For additional discussion on this approach, see the 2015 NSPS (80 FR 64609 - 12; October 23, 2015). The 2015 NSPS non-base load subcategory is broad and includes combustion turbines that assure grid reliability by providing electricity during periods of peak electric demand. These peaking turbines tend to have low annual capacity factors and sell a small amount of their potential electric output. The non-base load subcategory in the 2015 NSPS also includes combustion turbines that operate at intermediate annual capacity factors but are not considered base load EGUs. These intermediate load EGUs provide a variety of services, including providing dispatchable power to support intermittent generation from renewable sources of electricity. The need for this service has been expanding as the amount of electricity from renewable sources continues to grow. In the 2015 NSPS, the EPA determined the BSER for the non-base load subcategory to be the use of clean fuels (e.g., natural gas and Nos. 1 and 2 fuel oils). In 2015, the EPA explained that efficient generation did not qualify as the BSER due in part to the challenge of determining an achievable output-based CO2 emissions rate for all combustion turbines in this subcategory.
In this action, the EPA is proposing changes to the subcategories in 40 CFR part 60, subpart TTTTa that will be applicable to sources that commence construction or reconstruction after the date of this proposed rulemaking. First, the Agency is proposing the definition of design efficiency so that the heat input calculation of an EGU is based on the higher heating value (HHV) of the fuel instead of the lower heating value (LHV), as explained immediately below. It is important to note that this would have the effect of lowering the electric sales threshold. In addition, the EPA is proposing to further divide the non-base load subcategory into separate intermediate and low load subcategories.
Higher Heating Value as the Basis for Calculation of the Design Efficiency
The heat rate is the amount of energy used by an EGU to generate one kWh of electricity and is often provided in units of Btu/kWh. As the thermal efficiency of a combustion turbine EGU is increased, less fuel is burned per kWh generated and there is a corresponding decrease in emissions of CO2 and other air pollutants. The electric energy output as a fraction of the fuel energy input expressed as a percentage is a common practice for reporting the unit's efficiency. The greater the output of electric energy for a given amount of fuel energy input, the higher the efficiency of the electric generation process. Lower heat rates are associated with more efficient power generating plants.
Efficiency can be calculated using the HHV or the LHV of the fuel. The HHV is the heating value directly determined by calorimetric measurement of the fuel in the laboratory. The LHV is calculated using a formula to account for the moisture in the combustion gas (i.e., subtracting the energy required to vaporize the water in the flue gas) and is a lower value than the HHV. Consequently, the HHV efficiency for a given EGU is always lower than the corresponding LHV efficiency because the reported heat input for the HHV is larger. For U.S. pipeline natural gas, the HHV heating value is approximately 10 percent higher than the corresponding LHV heating value and varies slightly based on the actual constituent composition of the natural gas. While the EPA default is to reference all technologies on a HHV basis, manufacturers of combustion turbines typically use the LHV to express the efficiency of combustion turbines.
Similarly, the electric energy output for an EGU can be expressed as either of two measured values. One value relates to the amount of total electric power generated by the EGU, or gross output. However, a portion of this electricity must be used by the EGU facility to operate the unit, including compressors, pumps, fans, electric motors, and pollution control equipment. This within-facility electrical demand, often referred to as the parasitic load or auxiliary load, reduces the amount of power that can be delivered to the transmission grid for distribution and sale to customers. Consequently, electric energy output may also be expressed in terms of net output, which reflects the EGU gross output minus its parasitic load. 
When using efficiency to compare the effectiveness of different combustion turbine EGU configurations and the applicable GHG emissions control technologies, it is important to ensure that all efficiencies are calculated using the same type of heating value (i.e., HHV or LHV) and the same basis of electric energy output (i.e., MWh-gross or MWh-net). Most emissions data are available on a gross output basis and the EPA is proposing output-based standards based on gross output. However, to recognize the superior environmental benefit of minimizing auxiliary loads, the Agency is proposing to include optional equivalent standards on a net output basis. 
Lowering the Threshold Between the Base Load and Non-Base Load Subcategories
The subpart TTTT distinction between a base load and non-base load combustion turbine is determined by the unit's actual electric sales relative to its potential electric sales, assuming the EGU is operated continuously (i.e., percent electric sales). Specifically, stationary combustion turbines qualify as non-base load, and thus for a less stringent standard of performance, if they have net electric sales equal to or less than their design efficiency (not to exceed 50 percent) multiplied by their potential electric output (80 FR 64601; October 23, 2015). Because the electric sales threshold is based in part on the design efficiency of the EGU, more efficient combustion turbine EGUs can sell a higher percentage of their potential electric output while remaining in the non-base load subcategory. This approach both recognizes the environmental benefit of combustion turbines with higher design efficiencies and provides flexibility to the regulated community. In the 2015 NSPS, it was unclear how often high-efficiency simple cycle EGUs would be called upon to support increased generation from intermittent renewable generating resources. Therefore, the Agency determined it was appropriate to provide maximum flexibility to the regulated community. To do this, the Agency based the numeric value of the design efficiency, which is used to calculate the electric sales threshold, on the LHV efficiency. This had the impact of allowing combustion turbines to sell a greater share of their potential electric output while remaining in the non-base load subcategory. 
For the reasons noted below, the EPA is proposing in 40 CFR part 60, subpart TTTTa that the design efficiency to be based on the HHV efficiency instead of LHV efficiency. The EPA is also proposing to eliminate the restriction of 50 percent limit on the design efficiency used to determine the electric sales threshold. By basing the electric sales threshold on the HHV design efficiency, the restriction is no longer necessary. If this restriction were maintained, it would reduce the regulatory incentive for manufacturers to invest in programs to develop higher efficiency combustion turbines. The EPA is also proposing to eliminate the 33 percent minimum design efficiency in the calculation of the potential electric output. The EPA is unaware of any new combustion turbines with design efficiencies of less than 33 percent; and this will likely have no cost or emissions impact. However, this provides assurance that new combustion turbines will maximize design efficiencies. Because of this relationship between the electric sales threshold and the design efficiency of an individual EGU, the proposed definition of design efficiency would have the effect of lowering the electric sales threshold between the base load and non-base load subcategories. For combined cycle EGUs, the current base load electric sales threshold is 55 percent. Proposing the definition of the design efficiency to be based on HHV would make the base load electric sales threshold for combined cycle EGUs between 46 and 55 percent. The current electric sales threshold for simple cycle turbines (i.e., non-base load) peaks in a range of 40 to 49 percent of potential electric sales. Under the proposed definition, simple cycle turbines would be able to sell no more than between 33 and 40 percent of their potential electric output without moving into the base load subcategory. A design efficiency definition based on the HHV will have the effect of decreasing the electric sales threshold in relative terms by 19 percent and absolute terms by 7 to 9 percent. The EPA is soliciting comment on whether the intermediate/base load electric sales threshold should be reduced further. The EPA is considering a range that would lower the base load electric sales threshold for simple cycle combustion turbines to between 29 to 35 percent (depending on the design efficiency) and to between 40 to 49 percent for combined cycle combustion turbines (depending on the design efficiency). This would be equivalent to reducing the design efficiency by 6 percent (e.g., multiplying by 0.94) when determining the electric sales threshold.
The EPA determined that proposing to lower the electric sales threshold is appropriate for new combustion turbines because, as will be discussed later, the first component of BSER for both intermediate load and base load turbines is based on highly efficient generation. Combined cycle units are significantly more efficient than simple cycle turbines; and therefore, in general, the EPA should be focusing its determination of the BSER for base load units on that more efficient technology. In the 2015 NSPS, the EPA used a higher sales threshold because of the argument that less efficient simple cycle turbine technology served a unique role that could not be served by more efficient combined cycle technology. At the time, the EPA determined that a BSER based exclusively on that more efficient technology could exclude the building of simple cycle turbines that are needed to maintain electric reliability. With improvements to the ramp rates for combined cycle units and with integrated renewable/energy storage projects becoming more common, these less efficient simple cycle turbines are no longer the only technology that can serve this purpose. Further, as EGUs operate more, they have more hours of steady state operation relative to hours of startup/cycling. Amending the electric sales threshold would result in GHG reductions by assuring that the most efficient generating and lowest emitting combustion turbine technology is used for each subcategory. Therefore, the proposed change to calculate the design efficiency on a HHV basis will result in additional emission reductions at reasonable costs.
Based on EIA 2022 model plants, combined cycle EGUs have a lower levelized cost of electricity (LCOE) at capacity factors above approximately 40 percent compared to simple cycle EGUs operating at the same capacity factors. This supports the proposed base load electric threshold of 40 percent for simple cycle turbines because it would be cost effective for owners/operators of simple cycle turbines to add heat recovery if they elected to operate their unit as a base load unit.. Furthermore, based on an analysis of monthly emission rates, recently constructed combined cycle EGUs maintain a 12-operating-month emissions rates at 12-operating-month capacity factors of less than 55 percent (the base load electric sales threshold in subpart TTTT) relative to operation at higher capacity factors. Therefore, the base load subcategory operating range could be expanded in subpart TTTTa without impacting the stringency of the numeric standard. However, at 12-operating-month capacity factors of less than approximately 50 percent, emission rates of combined cycle EGUs increase relative to operation at a higher capacity factor. It takes longer for a HRSG to begin producing steam that can be used to generate additional electricity than the time it takes a combustion engine to reach full power. Under operating conditions with a significant number of starts and stops, typical of intermediate and especially low load combustion turbines, there may not be enough time for the HRSG to generate steam that can be used for additional electrical generation. To maximize overall efficiency, combined cycle EGUs often use combustion turbine engines that are less efficient than the most efficient simple cycle combustion turbine engines. Under operating conditions with frequent starts and stops where the HRSG does not have sufficient time to begin generating additional electricity, a combined cycle EGU may be no more efficient than a highly efficient simple cycle EGU. Above capacity factors of approximately 40 percent, the average run time per start for combined cycle EGUs tends to increase significantly and the HRSG would be available to contribute additional electric generation. For more information on the impact of capacity factors on the emission rates of combined cycle EGUs see the TSD titled Efficient Generation at Combustion Turbine Electric Generating Units.
After the 2015 NSPS was finalized, some stakeholders expressed concerns about the approach for distinguishing between base load and non-base load turbines. They posited a scenario in which increased utilization of wind and solar resources, combined with low natural gas prices, would create the need for certain types of simple cycle turbines to operate for longer time periods than had been contemplated when the 2015 NSPS was being developed. Specifically, stakeholders have claimed that in some regional electricity markets with large amounts of intermittent renewable generation, some of the most efficient new simple cycle turbines -- aeroderivative turbines -- could be called on to operate at capacity factors greater than their design efficiency. However, if those new simple cycle turbines were to operate at those higher capacity factors, they would become subject to the more stringent standard of performance for base load turbines. As a result, according to these stakeholders, the new aeroderivative turbines would have to curtail their generation and instead, less-efficient existing turbines would be called upon to run by the regional grid operators, which would result in overall higher emissions. The EPA evaluated the operation of simple cycle turbines in areas of the country with relatively large amounts of intermittent renewable generation and did not find a strong correlation between the percentage of generation from the renewable sources and the 12-operating-month capacity factors of simple cycle turbines. In addition, the vast majority of simple cycle turbines that commenced operation between 2010 and 2016 (the most recent simple cycle combustion turbines not subject to 40 CFR part 60, subpart TTTT) have operated well below the base load electric sales threshold in 40 CRF part 60, subpart TTTT. Therefore, the Agency does not believe that the concerns expressed by stakeholders necessitates any revisions to the regulatory scheme. In fact, as noted above, the EPA is proposing that the electric sales threshold can be lowered without impairing the availability of simple cycle turbines where needed, including to support the integration of intermittent generation. The EPA believes that the proposed threshold is not overly restrictive since a simple cycle turbine could operate on average for more than 8 hours a day,
Low and Intermediate Load Subcategories
The EPA is proposing in 40 CFR part 60, subpart TTTTa to create a low load subcategory to include combustion turbines that operate only during periods of peak electric demand (i.e., peaking units), to assure grid reliability, which would be separate from the intermediate load subcategory. The EPA evaluated the operation of recently constructed simple cycle turbines to understand how they operate and to determine at what electric sales level or capacity factor their emissions rate is relatively steady. (Note that for purposes of this discussion, we use the terms "electric sales" and "capacity factor" interchangeably.) Peaking units only operate for short periods of time and potentially at relatively low duty cycles. This type of operation reduces the efficiency and increases the emissions rate, regardless of the design efficiency of the combustion turbine or how it is maintained. For this reason, it is difficult to establish a reasonable output-based emissions standard for peaking units. 
To determine the electric sales threshold -- that is, to distinguish between the intermediate load and low load subcategories -- the EPA evaluated capacity factor electric sales thresholds of 10 percent, 15 percent, 20 percent, and 25 percent. The EPA found the 10 percent level problematic for two reasons. First, simple cycle combustion turbines operating at that level or lower have highly variable emission rates, and therefore it would be difficult for the EPA to establish a meaningful output-based emissions standard. In addition, only one-third of simple cycle turbines that have commenced operation since 2015 have maintained 12-operating-month capacity factors of less than 10 percent. Therefore, setting the threshold at this level would bring most new simple cycle turbines into the intermediate load subcategory, which would subject them to a more stringent emission rate which is only achievable for simple cycle combustion turbines operating at higher capacity factors. This could create a situation where simple cycle turbines might not be able to comply with the intermediate load emissions standard while operating at the low end of the intermediate load capacity factor subcategorization criteria. 
Importantly, based on the EPA's review of hourly emissions data, above a 15 percent capacity factor, GHG emission rates begin to stabilize, see the TSD titled Simple Cycle Stationary Combustion Turbine EGUs, which is available in the rulemaking docket. At higher capacity factors, more time is typically spent at steady state operation rather than ramping up and down; and, emission rates tend to be lower while in steady state operation. Approximately 60 percent of recently constructed simple cycle turbines have maintained 12-operating-month capacity factors of 15 percent or less while two-thirds of recently constructed simple cycle turbines have operated at capacity factors of 20 percent or less; and, the emission rates clearly stabilize for simple cycle turbines operating at capacity factors of greater than 20 percent. Nearly 80 percent of recently constructed simple cycle turbines maintain maximum 12-operating-month capacity factors of 25 percent or less. Based on this information, the EPA is proposing the low load electric sales threshold -- again, the dividing line to distinguish between the intermediate- and low-load subcategories -- to be 20 percent and is soliciting comment on a range of 15 to 25 percent. The EPA is also soliciting comment on whether the low load electric sales threshold should be determined by a site-specific threshold based on three quarters of the design efficiency of the combustion turbine. Under this approach, simple cycle combustion turbines selling less than 18 to 22 percent of their potential electric output (depending on the design efficiency) would still be considered low load combustion turbines. This "sliding scale" electric sales threshold approach is similar to the approach the EPA used in the 2015 NSPS to recognize the environmental benefit of installing the most efficient combustion turbines for low load applications. Using this approach, combined cycle EGUs would be able to sell between 26 to 31 percent of their potential electric output while still being considered low load combustion turbines.
Placing low load and intermediate load combustion turbines into separate subcategories is consistent with how these units are operated and how emissions from these units can be quantified and controlled. Consistent with the 2015 NSPS, the BSER analysis for base load combustion turbine EGUs assumes the use of combined cycle technology and the BSER analysis for intermediate and low load combustion turbine EGUs assumes the use of simple cycle technology. However, the Agency notes that combined cycle EGUs can elect to operate at lower levels of electric sales and be classified as intermediate or peaking EGUs. In this case, owners/operators of combined cycle EGUs would be required to comply with the emission standards for intermediate or peaking EGUs. 
Multi-fuel-fired Combustion Turbines
40 CFR part 60, subpart TTTT subcategorizes multi-fuel-fired combustion turbines as EGUs that combust 10 percent or more of fuels not meeting the definition of natural gas on a 12-operating-month rolling average basis. The BSER for this subcategory is the use of clean fuels with a corresponding heat input-based standard of performance of 120 to 160 lb CO2/MMBtu, depending on the fuel, for newly constructed and reconstructed multi-fuel-fired stationary combustion turbines. Clean fuels for these units include natural gas, ethylene, propane, naphtha, jet fuel kerosene, Nos. 1 and 2 fuel oils, biodiesel, and landfill gas. The definition of natural gas in 40 CFR part 60, subpart TTTT includes fuel that maintains a gaseous state at ISO conditions, is composed of 70 percent by volume or more methane, and has a heating value of between 35 and 41 megajoules (MJ) per dry standard cubic meter (dscm, m[3]) (950 and 1,100 British thermal units (Btu) per dry standard cubic foot). Natural gas typically contains 95 percent methane and has a heating value of 1,050 Btu/lb. A potential issue with the multi-fuel subcategory is that owners/operators of simple cycle turbines can elect to burn 10 percent non-natural gas fuels, such as Nos. 1 or 2 fuel oil, and thereby remain in that subcategory, regardless of their electric sales. As a result, they would remain subject to the less stringent standard that applies to multi-fuel-fired sources, the clean fuels standard. This could allow less efficient combustion turbine designs to operate as base load units without having to improve efficiency and could allow EGUs to avoid the need for efficient design or best operating and maintenance practices. These potential circumventions would result in higher GHG emissions. 
To avoid these concerns, the EPA is proposing to eliminate the multi-fuel subcategory for low, intermediate, and base load combustion turbines in 40 CFR part 60, subpart TTTTa. This would mean that new multi-fuel-fired turbines that commence construction or reconstruction after the date of this proposal will fall within a particular subcategory depending on their level of electric sales. The EPA also proposes that the performance standards for each subcategory be adjusted appropriately for multi-fuel-fired turbines to reflect the application of the BSER for the subcategories to turbines burning fuels with higher GHG emission rates than natural gas. To be consistent with the definition of clean fuels in the 2015 Rule, the maximum allowable heat input-based emissions rate would be 160 lb CO2/MMBtu. For example, an emissions standard based on efficient generation would be 33 percent higher for a fuel oil-fired combustion turbine compared to a natural gas-fired combustion turbine. This would assure that the BSER, in this case efficient generation, is applied, while at the same time accounting for the use of multiple fuels. As explained in section VII.F, in the second phase of the NSPS, the EPA is proposing to further subcategorize base load combustion turbines based on whether the combustion turbine is combusting hydrogen. During the first phase of the NSPS, all base load combustion turbines would be in a single subcategory. Table 1 summarizes the proposed electric sales subcategories for combustion turbines.
Table 1 -- Proposed Sales Thresholds for Subcategories of Combustion Turbine EGUs
Subcategory
Electric Sales Threshold
(Percent of potential electric sales)
Low Load
<= 20 percent 
Intermediate Load
> 20 percent and <= site-specific value determined based on the design efficiency of the affected facility
 Between ~ 33 to 40 percent for simple cycle combustion turbines
 Between ~ 45 to 55 percent for combined cycle combustion turbines
Base Load
> Site-specific value determined based on the design efficiency of the affected facility
 Between ~ 33 to 40 percent for simple cycle combustion turbines
 Between ~ 45 to 55 percent for combined cycle combustion turbines
Determination of the Best System of Emission Reduction (BSER) for New and Reconstructed Stationary Combustion Turbines
In this section, the EPA describes the controls it is proposing for the BSER for each of the subcategories of new and reconstructed combustion turbines that commence construction after the date of this proposal, and explains its basis for proposing those controls, and not others, as the BSER. The controls that the EPA is evaluating primarily include combusting non-hydrogen clean fuels (e.g., natural gas and distillate oil), using highly efficient generation, using CCS, and co-firing with low-GHG hydrogen. For the low-load subcategory, the EPA is proposing the use of clean fuels as the BSER. For the intermediate load and base load subcategories, the EPA is proposing an approach under which the BSER is a set of controls that apply in two components, and that form the basis of standards of performance that apply in two phases. That is, affected facilities -- which are facilities that commence construction or modification after the date of this proposed rulemaking -- must meet the first phase of the standard of performance, which is based on the application of the first component of the BSER, highly efficient generation, by the date the rule is finalized; and then meet the second and more stringent phase of the standard of performance, which is based on application of the second component of the BSER, CCS or co-firing low-GHG hydrogen, along with continued application highly efficient generation, by 2035. 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, but recognizes that building the infrastructure required to support wider spread use of CCS and low-GHG hydrogen in the power sector will take place on a multi-year time scale. Accordingly, newly constructed or reconstructed facilities must be aware of their need to ramp towards a more stringent phase of the standards, which reflects application of the more stringent controls in the BSER, by 2035. 
Specifically, with respect to the first phase of the standards of performance, for both the intermediate load and base load subcategories, the EPA is proposing that the BSER includes constructing highly efficient generating technology -- combined cycle technology for the base load subcategories and simple cycle technology for the intermediate load subcategory -- as well as operating and maintaining it efficiently. The EPA sometimes refers to highly efficient generating technology in combination with the best operating and maintenance practices as highly efficient generation.
The affected sources must meet standards based on this efficient generating technology upon the effective date of the final rule. With respect to the second phase of the standards of performance, for base load combustion turbines not combusting at least 10 percent hydrogen by heat input, the BSER includes the use of CCS. Therefore, these sources would be required to meet emission standards by 2035 that reflect application of both components of the BSER  -  highly efficient generation and CCS  -  and thus are more stringent. For base load combustion turbines combusting at least 10 percent hydrogen and for intermediate load combustion turbines, the BSER includes co-firing 30 percent by volume (12 percent by heat input) low-GHG hydrogen. Therefore, these sources would be required to meet standards by 2035 that reflect the application of both components of the BSER  -  in this case, highly efficient generation and co-firing 30 percent low-GHG hydrogen  -  and, that are, again, are more stringent. Table 2 summarizes the proposed BSER for combustion turbine EGUs that commence construction or reconstruction after publication of this proposal.
              Table 2 -- Proposed BSER for Combustion Turbine EGUs
                                  Subcategory
                                     Fuel
                             1[st] Component BSER
                             2[nd] Component BSER
                                   Low Load
                                   All Fuels
                                  Clean Fuels
                                  Clean Fuels
                               Intermediate Load
                                   All Fuels
                          Highly Efficient Generation
                          Low-GHG Hydrogen Co-firing
                                   Base Load
                  Not combusting at least 10 percent hydrogen
                          Highly Efficient Generation
                                      CCS
                                       
                    Combusting at least 10 percent hydrogen
                                       
                          Low-GHG Hydrogen Co-firing
                                       
The EPA is also proposing standards of performance based on those BSER for each subcategory, as discussed in section VII.G.
BSER for Low Load Subcategory
      This section describes the proposed BSER for the low load (i.e., peaking) subcategory, which is the use of clean fuels. For this proposed rule, the Agency proposes to determine that the use of clean fuels, which the EPA determined to be the BSER for the non-base load subcategory in the 2015 NSPS, is the BSER for this subcategory in both phases of the standards of performance proposed in this action. As explained above, the EPA is proposing to narrow the definition of the low load subcategory by lowering the electric sales threshold (as compared to the electric sales threshold for non-base load combustion turbines in the 2015 NSPS), so that turbines with higher electric sales would be placed in the proposed intermediate load subcategory and therefore be subject to a more stringent standards based on the more stringent component of the BSER.
Background: The Non-base Load Subcategory in the 2015 NSPS
The 2015 NSPS defined non-base load natural gas-fired EGUs as stationary combustion turbines that (1) burn more than 90 percent natural gas and (2) have net electric sales equal to or less than their design efficiency (not to exceed 50 percent) multiplied by their potential electric output (80 FR 64601; October 23, 2015). These are calculated on 12-operating-month and 3-year rolling average bases. The EPA also determined in the 2015 NSPS that the BSER for newly constructed and reconstructed non-base load natural gas-fired stationary combustion turbines is the use of clean fuels. Id. at 64515. These clean fuels are primarily natural gas with a small allowance for distillate oil (i.e., Nos. 1 and 2 fuel oils), which have been widely used in stationary combustion turbine EGUs for decades. 
The EPA also determined in the 2015 NSPS that the standard of performance for sources in this subcategory is a heat input-based standard of 120 lb CO2/MMBtu. The EPA established this clean-fuels BSER for this subcategory because the variability in the operation in non-base load combustion turbines and the challenges involved in determining a uniform output-based standard that all new and reconstructed non-base load units could achieve. 
Specifically, in the 2015 NSPS, the EPA recognized that a BSER for the non-base load subcategory based on clean fuels results in limited GHG reductions, but further recognized that an output-based emissions standard could not reasonably be applied to the subcategory. The EPA explained that a combustion turbine operating at a low capacity factor could operate with multiple starts and stops, and that its emission rate would be highly dependent on how it was operated and not its design efficiency. Moreover, combustion turbines with low annual capacity factors typically operated differently from each other, and therefore had different emission rates. The EPA recognized that, as a result, it would not be possible to determine a standard of performance that could reasonably apply to all combustion turbines in the subcategory. For that reason, the EPA further recognized, efficient design and operation would not qualify as the BSER; rather, the BSER should be clean fuels and the associated standard of performance should be based on heat input. Since the 2015 NSPS, all newly constructed simple cycle turbines have been non-base load units and thus have become subject to this standard of performance.
Proposed BSER
      Consistent with the rationale of the 2015 NSPS, the EPA proposes that the use of clean fuels meets the BSER requirements for the low load subcategory. Use of clean fuels is technically feasible for combustion turbines. Natural gas comprises the majority of the heat input for simple cycle turbines and is the lowest cost fossil fuel. In the 2015 NSPS, the EPA determined that natural gas comprised 96 percent of the heat input for simple cycle turbines. See 80 FR 64616 (October 23, 2015). Therefore, a BSER based on the use of natural gas and/or distillate oil would have minimal, if any, costs to regulated entities. The use of clean fuels would not have any significant adverse energy requirements or non-air quality or environmental impacts, as the EPA determined in the 2015 NSPS. Id. at 64616. In addition, the use of clean fuels would result in some emission reductions by limiting the use of fuels with higher carbon content, such as residual oil, as the EPA also explained in the 2015 NSPS. Id. Although the use of clean fuels would not advance technology, in light of the other reasons described here, the EPA proposes that the use of natural gas, Nos. 1 and 2 fuel oils, and other fuels currently specified in 40 CFR part 60, subpart TTTT, qualify as the BSER for new and reconstructed combustion turbine EGUs in the low load subcategory. The EPA is also proposing to add hydrogen to the list of clean fuels in subpart TTTT and low-GHG hydrogen to the list of clean fuels in subpart TTTTa. The addition of hydrogen (and fuels derived from hydrogen) to subpart TTTT will simplify the recordkeeping and reporting requirements for non-base load combustion turbines that elect to burn hydrogen regardless of how it is derived. In contrast, the EPA would add a definition of low-GHG hydrogen in subpart TTTTa. As described in section VII.F, a component of the BSER for certain subcategories in subpart TTTTa is based on the use of low-GHG hydrogen. An owner/operator of a subpart TTTTa affected combustion turbine that combusts hydrogen not meeting the definition of low-GHG hydrogen would be in violation of the subpart TTTTa requirements.
      For the reasons discussed in the 2015 NSPS and noted above, efficient design and operation cannot qualify as the BSER for the low load subcategory. The EPA is not proposing high-efficiency simple cycle or combined cycle turbine design and operation as the BSER for the low load subcategory because they are not cost-effective and would not necessarily result in emission reductions. High efficiency combustion turbines have higher initial costs compared to lower efficiency combustion turbines. The cost of combustion turbine engines is dependent upon many factors, but the EPA estimates that the capital cost of a high efficiency simple cycle turbine is 5 percent more than that for a comparable lower efficiency simple cycle turbine. Assuming all other costs are the same and that the high efficiency simple cycle turbine uses 6 percent less fuel, it would not be cost-effective to use a high efficiency simple cycle turbine until the combustion turbine is operated at a 12-operating month capacity factor of approximately 20 percent. At lower capacity factors, the CO2 abatement costs on both a $/ton and $/MW basis increase rapidly. Further, the emission rate of a low load combustion turbines is highly dependent upon the way the combustion turbine is operated. If the combustion turbine is frequently operated at part load conditions with frequent starts and stops, a combustion turbine with a high design efficiency, which is determined at full load steady state conditions, would not necessarily emit at a lower GHG rate than a combustion turbine with a lower design efficiency. 
      The EPA expects that units in the low-load subcategory will be simple cycle turbines. The capital cost of a combined cycle EGU is approximately 250 percent that of a comparable sized simple cycle EGU and would not be recovered by reduced fuel costs if operated as low load units. Furthermore, low load combustion turbines start and stop so frequently that there might not be sufficient periods of continuous operation for the HRSG to begin generating steam to operate the steam turbine enough to significantly lower the emissions rate of the EGU. 
      The EPA is not proposing the use of CCS or hydrogen co-firing as the BSER (or as a component of the BSER) for low load combustion turbines. As described in the section discussing the second component of BSER for the intermediate load subcategory, the EPA is not determining that CCS is the BSER for simple cycle combustion turbines, based on the Agency's assessment that CCS is not cost-effective for such combustion turbines when operated at intermediate load. This rationale is even more applicable for low load combustion turbines, for that reason the Agency proposes to conclude that CCS does not qualify as the BSER for this subcategory of sources. The EPA is not proposing hydrogen co-firing as the BSER for low load combustion turbines because not all new combustion turbines can necessarily co-fire higher percentages of hydrogen and limiting the models that are available for new low load combustion turbine installations could result in increased cost to the regulated community. In addition, at the relatively infrequent levels of utilization that characterize the low load subcategory, a hydrogen co-firing BSER would not result in significant GHG reductions. Based on simple cycle turbines that recently commenced operation, the average 12-operating month capacity factor of low load combustion turbines would be less than 8 percent. Further, the majority of fuel use, and potential GHG reduction, from simple cycle combustion turbines would be from intermediate load combustion turbines.
BSER for Base Load and Intermediate Load Subcategories -- First Component
This section describes the first component of the EPA's proposed BSER for newly constructed and reconstructed combustion turbines in the base load and intermediate load subcategories. For combustion turbines in the intermediate load subcategory, this first component of the BSER is the use of high-efficiency simple cycle turbine technology in combination with the best operating and maintenance practices. For combustion turbines in the base load subcategory, the first component of the BSER is the use of high-efficiency combined cycle technology in combination with the best operating and maintenance practices. 
Clean Fuels
      The EPA is not proposing clean fuels as the BSER for intermediate load or base load EGUs because it would achieve few emission reductions, compared to highly efficient generation. 
Highly Efficient Generation
The use of highly efficient generating technology in combination with the best operating and maintenance practices has been demonstrated by multiple facilities for decades. Notably, over time, as technologies have improved, what is considered highly efficient has changed as well. Highly efficient generating technology is available and offered by multiple vendors for both simple cycle and combined cycle combustion turbines. Both types of turbines can also employ best operating and maintenance practices, which include routine operating and maintenance practices that minimize fuel use. 
For simple cycle combustion turbines, manufacturers continue to improve the efficiency by increasing firing temperature, increasing pressure ratios, using intercooling on the air compressor, and adopting other measures. These improved designs allow for improved operating efficiencies and reduced emission rates. Design efficiencies of simple cycle combustion turbines range from 33 to 40 percent. Best operating practices for simple cycle combustion turbines include proper maintenance of the combustion turbine flow path components and the use of inlet air cooling to reduce efficiency losses during periods of high ambient temperatures. 
For combined cycle turbines, high efficiency technology uses a highly efficient combustion turbine engine matched with a high-efficiency HRSG. The most efficient combined cycle EGUs use HRSG with three different steam pressures and incorporate a steam reheat cycle to maximize the efficiency of the Rankine cycle. It is not necessarily practical for owner/operators of combined cycle facilities using a turbine engine with an exhaust temperature below 593 [o]C or a steam turbine engine smaller than 60 MW to incorporate a steam reheat cycle. Smaller combustion turbine engines, less than those rated at approximately 2,000 MMBtu/h, tend to have lower exhaust temperatures and are paired with steam turbines of 60 MW or less. These smaller combined cycle units are limited to using triple-pressure steam without a reheat cycle. This reduces the overall efficiency of the combined cycle unit by approximately 2 percent. Therefore the EPA is proposing less stringent emission standards for smaller combined cycle EGUs with base load ratings of less than 2,000 MMBtu/h relative to those for larger combined cycle combustion turbine EGUs . High efficiency also includes, but is not limited to, the use of the most efficient steam turbine and minimizing energy losses using insulation and blowdown heat recovery. Best operating and maintenance practices include, but are not limited to, minimizing steam leaks, minimizing air infiltration, and cleaning and maintaining heat transfer surfaces.
New technologies are available for new simple and combined cycle EGUs that could reduce emissions beyond what is currently being achieved by the best performing EGUs. For example, pressure gain combustion in the turbine engine would increase the efficiency of both simple and combined cycle EGUs. For combined cycle EGUs, the HRSG could be designed to utilize supercritical steam conditions or to utilize supercritical CO2 as the working fluid instead of water; useful thermal output could be recovered from a compressor intercooler and boiler blowdown; and fuel preheating could be implemented. For additional information on these and other technologies that could reduce the emissions rate of new combustion turbines, see the TSD titled Efficient Generation at Combustion Turbine Electric Generating Units, which is available in the rulemaking docket. The EPA is soliciting comment on whether these technologies should be incorporated into a standard of performance based on an efficient generation BSER. To the extent commenters support the inclusion of emission reductions from the use of these technologies, the EPA requests that cost information and potential emission reductions be included.
Adequately Demonstrated
The EPA proposes that highly efficient simple cycle and combined cycle designs are adequately demonstrated because highly efficient simple cycle EGUs and highly efficient combined cycle EGUs have been demonstrated by multiple facilities for decades, the efficiency improvements of the most efficient designs are incremental in nature and do not change in any significant way that the combustion turbine is operated or maintained, and the levels of efficiency that the EPA is proposing have been achieved by many recently constructed turbines. Approximately 14 percent of simple cycle and combined cycle combustion turbines that have commenced operation since 2015 have maintained emission rates below the proposed standards, demonstrating that the efficient generation technology described in this BSER is commercially available and that the emission standards the EPA is proposing are achievable. 
Costs
      In general, advanced generation technologies enhance operational efficiency compared to lower efficiency designs. Such technologies present little incremental capital cost compared to other types of technologies that may be considered for new and reconstructed sources. In addition, more efficient designs have lower fuel costs that offset at least a portion of the increase in capital costs. 
      For the intermediate load subcategory, the EPA proposes that the costs of high-efficiency simple cycle combustion turbines are reasonable. As described in the subcategory section, the cost of combustion turbine engines is dependent upon many factors, but the EPA estimates that that the capital cost of a high efficiency simple cycle turbine is 5 percent more than a comparable lower efficiency simple cycle turbine. Assuming all other costs are the same and that the high efficiency simple cycle turbine uses 6 percent less fuel, high efficiency simple cycle combustion turbines have a lower LCOE compared to standard efficiency simple cycle combustion turbine at 12-operating month capacity factor of approximately 20 percent. Therefore, a BSER based on the use of high efficiency simple cycle combustion turbines for intermediate load combustion turbines would have minimal, if any, overall compliance costs since the capital costs would be recovered through reduced fuel costs. The EPA considered, but is not proposing combined cycle unit design for combustion turbines in the intermediate subcategory because the capital cost of a combined cycle EGU is approximately 250 percent that of a comparable sized simple cycle EGU and because the amount of GHG reductions that could be achieved by operating combined cycle EGUs as intermediate-load EGUs is unclear. The higher capital costs of these units would not be recovered by reduced fuel costs if operated as non-base load units. Furthermore, intermediate load combustion turbines start and stop so frequently that there might not be sufficient periods of continuous operation where the HRSG would have sufficient time to generate steam to operate the steam turbine enough to significantly lower the emissions rate of the EGU.
      For the base load subcategory, the EPA proposes that the cost of high-efficiency combined cycle EGUs is reasonable. While the capital costs of a higher efficiency combined cycle EGUs are 1.9 percent higher than standard efficiency combined cycle EGUs, fuel use is 2.6 percent lower. The reduction in fuel costs outweigh the capital costs at capacity factors of 40 percent or greater. Therefore, a BSER based on the use of high efficiency combined cycle combustion turbines for base load combustion turbines would have minimal, if any, overall compliance costs since the capital costs would be recovered through reduced fuel costs. For additional information on costs see the TSD Efficient Generation at Combustion Turbine Electric Generating Units, which is available in the rulemaking docket.
Non-air Quality Health and Environmental Impact and Energy Requirements
Use of highly efficient simple cycle and combined cycle generation reduces all non-air quality health and environmental impacts and energy requirements as compared to use of less efficient generation. Even when operating at the same input-based emissions rate, the more efficient a unit is, the less fuel is required to produce the same level of output; and, as a result, emissions are reduced for all pollutants. The use of highly efficient simple cycle turbines, compared to the use of less efficient simple cycle turbines, reduces all pollutants. Similarly, the use of high efficiency combined combustion turbines, compared to the use of less efficient combine cycle turbines, reduces all pollutants. By the same token, because improved efficiency allows for more electricity generation from the same amount of fuel, it will not have any adverse effects on energy requirements.
Designating highly efficient generation as part of the BSER for new and reconstructed base load and intermediate load combustion turbines will not have significant impacts on the nationwide supply of electricity, electricity prices, or the structure of the electric power sector. On a nationwide basis, the additional costs of the use of highly efficient generation will be small because the technology does not add significant costs and at least some of those costs are offset by reduced fuel costs. In addition, at least some of these new combustion turbines would be expected to incorporate highly efficient generation technology in any event.
Extent of Reductions in CO2 Emissions
The EPA estimated the potential emission reductions associated with a standard that reflects the application of highly efficient generation as BSER for the intermediate load and base load subcategories. As discussed in section VII.G., the EPA determined that the standards of performance reflecting this BSER are 1,150 lb CO2/MWh-gross for intermediate load and 770 lb CO2/MWh-gross for large base load combustion turbines. 
For the intermediate load subcategory, the EPA determined that the average achievable emissions rate of recently constructed high-efficiency simple cycle turbines operating at intermediate load is 1,230 lb CO2/MWh-gross. This is 6.5 percent higher than the proposed intermediate load standard of 1,150 lb CO2/MWh-gross. Therefore, the EPA estimates that the proposed standard of performance based on the application of the proposed BSER for intermediate load combustion turbines would reduce the GHG emissions from those sources by 6.5 percent.
For the base load subcategory, the average achievable emissions rate of large (base load ratings of 2,000 MMBtu/h or more) NGCC combustion turbines that commenced operation since 2015 was 810 lb CO2/MWh-gross. This is 5 percent higher than the proposed standard of 770 lb CO2/MWh-gross for large base load combustion turbines. The only small, combined cycle combustion turbine (base load rating of less than 2,000 MMBtu/h) reporting emissions that commenced operation since 2015 had a reported annual emissions rate of 870 lb CO2/MWh-gross, 4 percent higher than the proposed standard for small base load combustion turbines. Therefore, the EPA estimates that the proposed standards would require owners/operators to construct and maintain highly efficient combined cycle combustion turbines that would result in reductions in emissions of approximately 5 percent for new large stationary combustion EGUs and 4 percent for new small stationary combustion EGUs.
Promotion of the Development and Implementation of Technology
      The EPA also considered the potential impact of selecting highly efficient generation technology as the BSER in promoting the development and implementation of improved control technology. This technology is more efficient than the average new generation technology and determining it to be a component of the BSER will advance its penetration throughout the industry. Accordingly, consideration of this factor supports the EPA's proposal to determine this technology to be the first component of the BSER. 
Low-GHG Hydrogen and CCS
      For reasons discussed in section VII.F.3.b.v. (CCS) and VII.F.3.c.vi, the EPA is not proposing either co-firing low-GHG hydrogen or CCS as the first component of the BSER for intermediate load or base load EGUs.
Proposed BSER
The EPA proposes that highly efficient generating technology in combination with the best operating and maintenance practices is the first component BSER for base load and intermediate load combustion turbines and the phase 1 standards of performance are based on the application of that technology. Specifically, the use of highly efficient simple cycle technology in combination with the best operating and maintenance practices is the first component of the BSER for intermediate load combustion turbines. The use of highly efficient combined cycle technology in combination with best operating and maintenance practices is the first component of the BSER for base load combustion turbines. 
Highly efficient generation qualifies as a component of the BSER because it is adequately demonstrated, it can be implemented at reasonable cost, it achieves emission reductions, and it does not have significant adverse non-air quality health or environmental impacts or significant adverse energy requirements. The fact that it promotes greater use of advanced technology provides additional support; however, the EPA would consider highly efficient generation to be a component of the BSER for base load and intermediate load combustion turbines even without taking this factor into account. 
BSER for Base Load And Intermediate Load Subcategories -- Second Component
This section describes the proposed second component of the BSER for base load and intermediate load combustion turbines, which would be reflected in the second phase standards of performance that apply beginning in 2035. The proposed second component of the BSER for base load combustion turbines that are not combusting at least 10 percent hydrogen is the use of CCS. The second component of the BSER for base load combustion turbines that are combusting at least 10 percent hydrogen and for intermediate load combustion turbines is co-firing 30 percent by volume low-GHG hydrogen.
Authority to Promulgate a Two-part BSER and Standard of Performance
	The EPA's proposed approach of promulgating standards of performance that apply in two phases, based on determining the BSER to be a set of controls with two components, is consistent with CAA section 111(b). That provision authorizes the EPA to promulgate "standards of performance," CAA section 111(b)(1)(B), defined, in the singular, as "a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the [BSER]." CAA section 111(a)(1). The provision further provides, "[s]tandards of performance ... shall become effective upon promulgation." In this rulemaking, the EPA is proposing to determine that the BSER is a set of controls that, depending on the subcategory, include either highly efficient generation and use of CCS or highly efficient generation and co-firing low-GHG hydrogen. The EPA is further proposing that affected sources can apply the first component of the BSER (highly efficient generation) by the effective date of the final rule and can apply both the first and second components of the BSER (highly efficient generation in combination with either CCS or co-firing low GHG hydrogen) beginning in 2035. Accordingly, the EPA is proposing a standard of performance that reflects the application of this two-component BSER and that takes the form of emission standards that affected sources must comply with in two phases. Affected sources must comply with the first phase standards that are based on the application of the first component of the BSER (highly efficient generation) upon initial startup of the facility. The second phase (more stringent) standards are based on the application of both the first and second components of the BSER (highly efficient generation in combination with either use of CCS or co-firing low-GHG hydrogen) by 2035.. In this manner, this two-phase standard of performance "become[s] effective upon promulgation," CAA section 111(b)(1)(B), although, as just noted, sources are not required to comply with the second and more stringent phase until 2035.
D.C. Circuit caselaw supports the proposition that CAA section 111(b) authorizes the EPA to determine that controls qualify as the BSER -- including meeting the "adequately demonstrated" criterion -- even if the controls require some amount of "lead time," defined as "the time in which the technology will have to be available." Consistent with this caselaw, the phased implementation of the standards of performance in this rule is intended to ensure facilities have sufficient lead time for planning and implementation of the use of CCS or low GHG-hydrogen-based controls necessary to comply with the second phase of the standards, and are therefore achievable.
The EPA has promulgated several prior rulemakings under CAA section 111(b) that have similarly provided the regulated sector with lead time to accommodate the availability of technology, which also serve as precedent for the two-phase implementation approach proposed in this rule. See 81 FR 59332 (August 29, 2016) (establishing standards for municipal solid waste landfills with 30-month compliance timeframe for installation of control device, with interim milestones); 80 FR 13672, 13676 (March 16, 2015) (establishing stepped compliance approach to wood heaters standards to permit manufacturers lead time to develop, test, field evaluate and certify current technologies to meet Step 2 emission limits); 78 FR 58416, 58420 (September 23, 2013) (establishing multi-phased compliance deadlines for revised storage vessel standards to permit sufficient time for production of necessary supply of control devices and for trained personnel to perform installation); 70 FR 28606, 28617 (March 18, 2005) (establishing two-phase caps for mercury emission standards from new and existing coal-fired electric utility steam generating units based on timeframe when additional control technologies were projected to be adequately demonstrated). Cf. 80 FR 64662, 64743 (October 23, 2015) (establishing interim compliance period to phase in final power sector GHG standards to allow time for planning and investment necessary for implementation activities). In each action, the standards and compliance timelines were effective upon the final rule, with affected facilities required to comply consistent with the phased compliance deadline specified in each action. 
It should be noted that the two-phased implementation of the standards of performance that the EPA is proposing in this rule, like the delayed or multi-phased standards in prior rules just described, is distinct from the promulgation of revised standards of performance under the 8-year review provision of CAA section 111(b)(1)(B). As discussed in section VII.F, the EPA has determined that the proposed BSER -- highly efficient generation and use of CCS or highly efficient generation and co-firing low-GHG hydrogen -- meet all of the statutory criteria and are adequately demonstrated for the compliance timeframes being proposed. Thus, the second phase of the standard of performance, if finalized, would apply to affected facilities that commence construction after the date of this proposal. In contrast, when the EPA later reviews and (if appropriate) revises a standard of performance under the 8-year review provision, then affected sources that commence construction after the date of that proposal of the revised standard of performance would be subject to that standard, but not sources that commenced construction earlier.
Similarly, the two-phased implementation of the standard of performance that the EPA is proposing in this rule is also distinct from the promulgation of emission guidelines for existing sources under CAA section 111(d). Emission guidelines only apply to existing sources, which are defined in CAA section 111(a)(6) as "any stationary source other than a new source." Because new sources are defined relative to the proposal of standards pursuant to CAA section 111(b)(1)(B), standards of performance adopted pursuant to emission guidelines will only apply to sources constructed before the date of these proposed standards of performance for new sources.
BSER for Base Load Subcategory Not Combusting At Least 10 percent Hydrogen -- Second Component
This section describes the second component of the BSER for the base load subcategory not combusting at least 10 percent (by heat input) hydrogen. This subcategory is expected to include highly efficient combined cycle combustion turbines that primarily combust fossil fuels, and therefore have high levels of CO2 in the exhaust.
The EPA is proposing the use of CCS as the second component of the BSER for these combustion turbines. A detailed discussion of CCS follows. It should be noted that the EPA is also proposing use of CCS as the BSER for existing long-term coal-fired steam generating units (i.e., coal-fired utility boilers), as discussed in section X.D of this preamble. Many aspects of CCS and considerations are common to both new combined cycle combustion turbines and existing long-term steam generating units, and the following discussion details those common aspects and considerations. 
Clean Fuels
      The EPA is not proposing clean fuels as the second component of the BSER for base load combustion turbines not combusting at least 10 percent hydrogen because it would achieve few emission reductions, compared to highly efficient generation in combination with the use of CCS. 
Highly Efficient Generation
For the reasons described above, the EPA is proposing that highly efficient generation technology in combination with best operating and maintenance practices continues to be a component of the BSER in that is reflected in the second phase of the standards of performance for base load combustion turbine EGUs not combusting at least 10 percent hydrogen. Highly efficient generation reduces fuel use and the amount of CO2 that must be captured by a CCS system. Since less flue gas needs to be treated, smaller carbon capture equipment may be used -- potentially reducing capital, fixed, and operating costs.
CCS
In this section of the preamble, the EPA provides a description of the components of CCS and evaluates it against the criteria to qualify as the BSER. CCS has three major components: CO2 capture, transportation, and sequestration/storage. Post-combustion capture processes remove CO2 from the exhaust gas of a combustion system, such as a combustion turbine or a utility boiler. This technology is referred to as "post-combustion capture" because CO2 is a product of the combustion of the primary fuel and the capture takes place after the combustion of that fuel. The exhaust gases from most combustion processes are at atmospheric pressure and are moved through the flue gas duct system by fans. The concentration of CO2 in most fossil fuel combustion flue gas streams is somewhat dilute. Most post-combustion capture systems utilize liquid solvents -- most commonly amine-based solvents -- that separate the CO2 from the flue gas in CO2 scrubber systems through the use of chemical absorption (or chemisorption). In a chemisorption-based separation process, the flue gas is processed through the CO2 scrubber and the CO2 is absorbed by the liquid solvent. The CO2-rich solvent is then regenerated by heating the solvent to release the captured CO2. The high purity CO2 is then compressed and transported, generally through pipelines, to a site for geologic sequestration (i.e., the long-term containment of CO2 in subsurface geologic formations). These sequestration sites are widely available across the nation, and the EPA has developed a comprehensive regulatory structure to oversee geological sequestration projects and assure their safety and effectiveness. See 80 FR 64549 (October 23, 2015).
Adequately Demonstrated
For new base load combustion turbines, the EPA proposes that CCS with a 90 percent capture rate, beginning in 2035, meets the BSER criteria. This amount of CCS is feasible and has been adequately demonstrated. The use of CCS at this level can be implemented at reasonable cost because it allows affected sources to maximize the benefits of the IRC section 45Q tax credit, and sources can maintain it over time by capturing a higher percentage at certain times in order to offset a lower capture rate at other times due to, for example, the need to undertake maintenance or due to unplanned capture system outages.
The EPA previously determined "partial CCS" to be a component of the BSER (in combination with the use of a highly efficient supercritical utility boiler) for new coal-fired steam generating units as part of the 2015 NSPS (80 FR 64538; October 23, 2015). As described in that action, numerous projects demonstrate the feasibility and effectiveness of CCS technology. Additional projects since publication of that rule provide confirmation.
In the 2015 NSPS, the EPA considered coal-fired industrial projects that had installed at least some components of CCS technology. In doing so, the EPA recognized that some of those projects had received assistance in the form of grants, loan guarantees, and federal tax credits for investment in "clean coal technology," under provisions of the Energy Policy Act of 2005 ("EPAct05"). See 80 FR 64541 - 42 (October 23, 2015). (The EPA refers to projects that received assistance under that legislation as "EPAct05-assisted projects.") The EPA further recognized that the EPAct05 included provisions that constrained how the EPA could rely on EPAct05 projects in determining whether technology is adequately demonstrated for the purposes of CAA section 111. The EPA went on to provide a legal interpretation of those constraints. Under that legal interpretation, "these provisions [in the EPAct05] ... preclude the EPA from relying solely on the experience of facilities that received [EPAct05] assistance, but [do] not ... preclude the EPA from relying on the experience of such facilities in conjunction with other information." Id. at 64541 - 42. In the present action, the EPA is applying the same legal interpretation and is not reopening it for comment.
CO2 Capture Technology
The EPA is proposing that the CO2 capture component of CCS has been adequately demonstrated and is technically feasible based on the demonstration of the technology at existing coal-fired steam generating units and industrial sources in addition to combustion turbines. While the EPA would propose that the CO2 capture component of CCS is adequately demonstrated on those bases alone, this determination is further corroborated by EPAct05-assisted projects.
Various technologies may be used to capture CO2, the details of which are described in the TSD titled GHG Mitigation Measures  -  111(d), which is available in the rulemaking docket. For post-combustion capture, these technologies include solvent-based methods (e.g., amines, chilled ammonia), solid sorbent-based methods, membrane filtration, pressure-swing adsorption, and cryogenic methods. Lastly, oxy-combustion uses a purified oxygen stream from an air separation unit (often diluted with recycled CO2 to control the flame temperature) to combust the fuel and produce a higher concentration of CO2 in the flue gas, as opposed to combustion with oxygen in air which contains 80 percent nitrogen. The CO2 can then be separated by the aforementioned CO2 capture methods. Of the available capture technologies, solvent-based processes have been the most widely demonstrated at commercial scale for post-combustion capture, and are applicable to use with either combustion turbines or steam generating units.
Solvent-based capture processes usually use an amine (e.g., monoethanolamine, MEA). Carbon capture occurs by reactive absorption of the CO2 from the flue gas into the amine solution in an absorption column. The amine reacts with the CO2 but will also react with potential contaminants in the flue gas, including SO2. After absorption, the CO2-rich amine solution passes to the solvent regeneration column, while the treated gas passes through a water wash column to limit emission of amines or other byproducts. In the solvent regeneration column, the solution is heated (using steam) to release the absorbed CO2. The released CO2 is then compressed and transported offsite by pipeline. The amine solution from the regenerating column is cooled and sent back to the absorption column, and any spent solvent is replenished with new solvent.
Capture Demonstrations at Coal-fired Steam Generating Units and Industrial Processes 
The function, design, and operation of post-combustion CO2 capture equipment is similar, although not identical, for both steam generating units and combustion turbines. As a result, application of CO2 capture at existing coal-fired steam generating units helps demonstrate the adequacy of the CO2 capture component of CCS.
SaskPower's Boundary Dam Unit 3, a 110 MW lignite-fired unit in Saskatchewan, Canada, has demonstrated CO2 capture rates of 90 percent using an amine-based post-combustion capture system retrofitted to the existing steam generating unit. The capture plant, which began operation in 2014, was the first full-scale CO2 capture system retrofit on an existing coal-fired power plant. It uses the amine-based Shell CANSOLV process, with integrated heat and power from the steam generating unit. While successfully demonstrating the commercial-scale feasibility of 90 percent capture rates, the plant has also provided valuable lessons learned for the next generation of capture plants. A feasibility study for SaskPower's Shand Power Station indicated achievable capture rates of 97 percent, even at lower loads.
For all industrial processes, operational availability (the percent of time a unit operates relative to its planned operation) is usually less than 100 percent due to unplanned maintenance and other factors. As a first-of-a-kind commercial-scale project, Boundary Dam Unit 3 experienced some additional challenges with availability during its initial years of operation, due to the fouling of heat exchangers and issues with its CO2 compressor. However, identifying and correcting those problems has improved the operational availability of the capture system. The facility has reported greater than 90 percent capture system availability in the second and third quarters of 2022. Currently, newly constructed and retrofit CO2 capture systems are anticipated to have operational availability of around 90 percent, on the same order of that is expected at coal-fired steam generating units. The EPA is soliciting comment on information relevant to the expected operational availability of new and retrofit CO2 capture systems.
Several other projects have successfully demonstrated the capture component of CCS at electricity generating plants and other industrial facilities, some of which were previously noted in the discussion in the 2015 NSPS (80 FR 64548 - 54; October 23, 2015). Amine-based carbon capture has been demonstrated at AES's Warrior Run (Cumberland, Maryland) and Shady Point (Panama, Oklahoma) coal-fired power plants, with the captured CO2 being sold for use in the food processing industry. At the 180-MW Warrior Run plant, approximately 10 percent of the plant's CO2 emissions (about 110,000 metric tons of CO2 per year) has been captured since 2000 and sold to the food and beverage industry. AES's 320-MW coal-fired Shady Point plant captured CO2 from an approximate 5 percent slipstream (about 66,000 metric tons of CO2 per year) from 2001 through around 2019. These facilities, which have operated for multiple years, clearly show the technical feasibility of post-combustion carbon capture.
The capture component of CCS has also been demonstrated at other industrial processes. Since 1978, the Searles Valley Minerals soda ash plant in Trona, California, has used an amine-based system to capture approximately 270,000 metric tons of CO2 per year from the flue gas of a coal-fired industrial power plant that generates steam and power for onsite use. The captured CO2 is used for the carbonation of brine in the process of producing soda ash.
The Quest CO2 capture facility in Alberta, Canada, uses amine-based CO2 capture retrofitted to three existing steam methane reformers at the Scotford Upgrader facility (operated by Shell Canada Energy) to capture and sequester approximately 80 percent of the CO2 in the produced syngas. The Quest facility has been operating since 2015 and captures approximately 1 million metric tons of CO2 per year.
Capture Demonstrations at Combustion Turbines
While most demonstrations of CCS have been for applications other than combustion turbines, CCS has been successfully applied to an existing combined cycle EGU and several other projects are in development. Examples of the use of CCS on combined cycle EGUs include the Bellingham Energy Center in south central Massachusetts and the proposed Peterhead Power Station in Scotland. The Bellingham plant used Fluor's Econamine FG Plus[SM] capture system and demonstrated the commercial viability of carbon capture on a combined cycle combustion turbine EGU using first-generation technology. The 40-MW slipstream capture facility operated from 1991 to 2005 and captured 85 to 95 percent of the CO2 in the slipstream for use in the food industry. In Scotland, the proposed 900-MW Peterhead Power Station combined cycle EGU with CCS is in the planning stages of development. It is anticipated that the power plant will be operational by the end of the 2020s and will have the potential to capture 90 percent of the CO2 emitting from the combined cycle facility and sequester up to 1.5 million tonnes of CO2 annually. A storage site being developed 62 miles off the Scottish North Sea coast might serve as a destination for the captured CO2. Moreover, an 1,800-MW NGCC EGU that will be constructed in West Virginia and will utilize CCS has been announced. The project is planned to begin operation later this decade, and its feasibility was partially credited to the expanded IRC section 45Q tax credit for sequestered CO2 provided through the IRA. 
In addition, there are several planned projects using the NET Power Cycle. The NET Power Cycle is a proprietary process for producing electricity that combusts a fuel with purified oxygen and uses supercritical CO2 as the working fluid instead of water/steam. This cycle is designed to achieve thermal efficiencies of up to 59 percent. Potential advantages of this cycle are that it emits no NOX and produces a stream of high-purity CO2 that can be delivered by pipeline to a storage or sequestration site without extensive processing. A 50-MW (thermal) test facility in La Porte, Texas was completed in 2018 and was synchronized to the grid in 2021. There are several announced commercial projects proposing to use the NET Power Cycle. These include the 280-MW Broadwing Clean Energy Complex in Illinois, the 280-MW Coyote Clean Power Project on the Southern Ute Indian Reservation in Colorado, a 300-MW project located near Occidental's Permian Basin operations close to Odessa, Texas, and several international projects. Commercial operation of the facility near Odessa, Texas is expected in 2026.
Currently available post-combustion amine-based carbon capture systems require that the flue gas be cooled prior to entering the carbon capture equipment. This holds true for the exhaust from a combustion turbine. The most energy efficient way to do this is to use a HSRG -- which, as explained above, is an integral component of a combined cycle turbine system -- to generate additional useful output. Because simple cycle combustion turbines do not incorporate a HRSG, the Agency is limiting consideration of the use of CCS as a potential component of the BSER only to combined cycle combustion turbine EGUs. 
EPAct05-assisted CO2 Capture Projects
While the EPA is proposing that the capture component of CCS is adequately demonstrated based solely on the other demonstrations of CO2 capture discussed in this preamble, adequate demonstration of CO2 capture technology is further corroborated by CO2 capture projects assisted by grants, loan guarantees, and Federal tax credits for "clean coal technology" authorized by the EPAct05. 80 FR 64541 - 42 (October 23, 2015).
Petra Nova is a 240 MW-equivalent capture facility that is the first at-scale application of carbon capture at a coal-fired power plant in the U.S. The system is located at the W.A. Parish Generating Station in Thompsons, Texas, and began operation in 2017, successfully capturing and sequestering CO2 for several years. Although the system was put into reserve shutdown (i.e., idled) in May 2020, citing the poor economics of utilizing captured CO2 for enhanced oil recovery (EOR) at that time, there are reports of plans to restart the capture system. A final report from National Energy Technology (NETL) details the success of the project and what was learned from this first-of-a-kind demonstration at scale. The project used Mitsubishi Heavy Industry's proprietary KM-CDR Process(R), a process that is similar to an amine-based solvent process but that uses a proprietary solvent and is optimized for CO2 capture from a coal-fired generator's flue gas. During its operation, the project successfully captured 92.4 percent of the CO2 from the slip stream of flue gas processed with 99.08 percent of the captured CO2 sequestered by EOR. Plant Barry in Mobile, Alabama, began using the KM-CDR Process(R) in 2011 for a fully integrated 25-MW CCS project with a capture rate of 90 percent. The CCS project at Plant Barry captured approximately 165,000 tons of CO2 annually, which is then transported via pipeline and sequestered underground in geologic formations. See 80 FR 64552 (October 23, 2015). 
CO2 Transport
The majority of CO2 transported in the U.S. is transported through pipelines. Pipeline transport of CO2 has been occurring for nearly 60 years, and over this time, the design, construction, and operational requirements for CO2 pipelines have been demonstrated. Moreover, the U.S. CO2 pipeline network has steadily expanded, and appears primed to continue to do so. The Pipeline and Hazardous Materials Safety Administration (PHMSA) reported that 5,339 miles of CO2 pipelines were in operation in 2021, a 13 percent increase in CO2 pipeline miles since 2011. Moreover, several major projects have recently been announced to expand the CO2 pipeline network across the U.S. For example, the Midwest Carbon Express and Heartland Greenway have proposed to add more than a combined 1,600 miles of dedicated CO2 pipeline in Iowa, Nebraska, North Dakota, South Dakota, Minnesota, and Illinois. The Midwest Carbon Express is projected to begin operations in 2024 and the Heartland Greenway is projected to start its initial system commissioning in the second quarter of 2025.  The proximity to existing or planned CO2 pipelines and geologic sequestration sites can be a factor to consider in the construction of stationary combustion turbines, and pipeline expansion, when needed, has been proven to be feasible.  
Existing and new CO2 pipeline safety is comprehensively regulated by PHMSA. These regulations include standards related to pipeline operations and maintenance, operator reporting requirements, operator qualifications, corrosion control and pipeline integrity management, incident reporting and response, and public awareness and communications. PHMSA has regulatory authority to conduct inspections of CO2 pipeline operations and issue notices to operators in the event of operator noncompliance with regulatory requirements. Furthermore, PHMSA initiated a rulemaking in 2022 to develop and implement new measures to strengthen its safety oversight of CO2 pipelines following investigation into a CO2 pipeline failure in Satartia, Mississippi in 2020. Following that incident, PHMSA also issued a notice of probable violation and proposed civil penalties on the operator for probable violations of Federal pipeline safety regulations, issued an updated nationwide advisory bulletin to all pipeline operators, and solicited research proposals to strengthen CO2 pipeline safety. These CO2 pipeline controls ensure that captured CO2 will be securely conveyed to a sequestration site.
Transportation of CO2 via pipeline is the most viable and cost-effective method at the scale needed for sequestration of captured EGU CO2 emissions. However, CO2 can also be liquified and transported via ship, road tanker, or rail tank cars when pipelines are not available. Liquefied natural gas and liquefied petroleum gases are already routinely transported via ship at a large scale, and the properties of liquified CO2 are not significantly different. In fact, the food and beverage as well as specialty gas industries already have experience transporting CO2 by rail. Road tankers and rail can transport smaller quantities of CO2 and can be used in tandem with other modes of transportation to move CO2 captured from an EGU. 
Geologic Sequestration of CO2 
Security of Sequestration
Geologic sequestration, which is the long-term containment of a CO2 stream in subsurface geologic formations, is well proven and broadly available throughout the U.S. Geologic sequestration is based on a demonstrated understanding of the processes that affect the fate of CO2 in the subsurface. These processes can vary regionally based on differences in subsurface geology. There have been numerous instances of geologic sequestration in the U.S. and overseas, and the U.S. has developed a detailed set of regulatory requirements to ensure the security of sequestered CO2.
Demonstration of Geologic Sequestration
Existing project and regulatory experience, along with other information, indicate that geologic sequestration is a viable long-term CO2 sequestration option. The effectiveness of long-term trapping of CO2 has been demonstrated by natural analogues in a range of geologic settings where CO2 has remained trapped for millions of years. For example, CO2 has been trapped for more than 65 million years in the Jackson Dome, located near Jackson, Mississippi. Other examples of natural CO2 sources include the Bravo Dome and the McElmo Dome in New Mexico and Colorado, respectively. These naturally occurring sequestration sites demonstrate the feasibility of containing the large volumes of CO2 that may be captured from fossil fuel-fired EGUs, as these sites have held volumes of CO2 that are much larger than the volume of CO2 expected to be captured from a fossil fuel-fired EGU over the course of its useful life. In 2010, the DOE estimated CO2 reserves of 594 million metric tons at Jackson Dome, 424 million metric tons at Bravo Dome, and 530 million metric tons at McElmo Dome.
Numerous additional saline facilities are under development across the United States. The EPA is currently reviewing Underground Injection Control (UIC) Class VI geologic sequestration well permit applications for proposed sequestration sites in at least seven states.[,]  States with UIC Class VI primacy are also processing injection permits for potential saline sequestration projects. In Wyoming, Class VI permit applications have been filed for a proposed saline sequestration facility located in southwestern Wyoming. At full capacity, the facility will permanently store up to 5 million metric tons of CO2 annually from industrial facilities in the Nugget saline sandstone reservoir.
Geologic sequestration has been proven to be successful and safe in projects internationally. Several facilities have geologically sequestered CO2 for over ten years. In Norway, facilities conduct offshore sequestration under the Norwegian continental shelf. In addition, the Sleipner CO2 Storage facility in the North Sea, which began operations in 1996, injects around 1 million metric tons of CO2 per year from natural gas processing. The Snohvit CO2 Storage facility in the Barents Sea, which began operations in 2008, injects around 0.7 million metric tons of CO2 per year from natural gas processing. The SaskPower carbon capture and storage facility at Boundary Dam Power Station in Saskatchewan, Canada had, as of mid-2022, captured 4.6 million tons of CO2 since it began operating in 2014. Other international sequestration facilities in operation include Glacier Gas Plant MCCS (Canada), Quest (Canada), and Qatar LNG CCS (Qatar).
EPAct05-Assisted Geologic Sequestration Projects
While the EPA is proposing that the sequestration component of CCS is adequately demonstrated based solely on the other demonstrations of geologic sequestration discussed in this preamble, adequate demonstration of geologic sequestration is further corroborated by geologic sequestration currently operational and planned projects assisted by grants, loan guarantees, and Federal tax credits for "clean coal technology" authorized by the EPAct05. 80 FR 64541-42 (October 23, 2015).
Two saline sequestration facilities are currently in operation in the U.S. and several are under development. The Illinois Industrial Carbon Capture and Storage Project began injecting CO2 from ethanol production into the Mount Simon Sandstone in April 2017. The project has the potential to store up to 5.5 million metric tons of CO2, and, according to the facility's report to the EPA's GHGRP, as of 2021, 2.5 million metric tons of CO2 had been injected into the saline reservoir. The Red Trail Energy CCS facility in North Dakota, which is the first saline sequestration facility in the U.S. to operate under a state-led regulatory authority for carbon storage, began injecting CO2 from ethanol production in 2022. This project is expected to inject a total of 3.7 million tons of CO2 over its lifetime.
There are additional planned geologic sequestration facilities across the United States. Project Tundra, a saline sequestration project planned at the lignite-fired Milton R. Young Station in North Dakotais projected to capture 4 million metric tons of CO2 annually. The Great Plains Synfuel Plant currently captures 2 million metric tons of CO2 per year, which is used for enhanced oil recovery (EOR). A planned addition of saline sequestration for this facility is expected to increase the amount captured and sequestered (through both geologic sequestration and EOR) to 3.5 million metric tons of CO2 per year. 
Security of Geologic Sequestration
Regulatory oversight of geologic sequestration is built upon an understanding of the proven mechanisms by which CO2 is retained in geologic formations. These mechanisms include (1) structural and stratigraphic trapping (generally trapping below a low permeability confining layer); (2) residual CO2 trapping (retention as an immobile phase trapped in the pore spaces of the geologic formation); (3) solubility trapping (dissolution in the in situ formation fluids); (4) mineral trapping (reaction with the minerals in the geologic formation and confining layer to produce carbonate minerals); and (5) preferential adsorption trapping (adsorption onto organic matter in coal and shale).
Based on the understanding developed from natural analogs and existing projects, the security of sequestered CO2 is expected to increase after injection ceases. This is due to drilling post-closure injection wells that decrease pressure and to trapping mechanisms that reduce CO2 mobility over time, e.g., physical CO2 trapping by a low-permeability geologic seal or chemical trapping by conversion or adsorption. In addition, site characterization, site operations, and monitoring strategies as required through the Underground Injection Control (UIC) Program and the GHGRP, discussed below, work in combination to ensure security and transparency.
The UIC Program, the GHGRP and other regulatory requirements comprise a detailed regulatory framework for facilitating geologic sequestration in the U.S., according to a 2021 report from the Council on Environmental Quality (CEQ). This framework is already in place and capable of reviewing and permitting CCS activities. 
This regulatory framework includes the UIC Class VI well regulations, promulgated under the authority of the Safe Drinking Water Act (SDWA); and the GHGRP, promulgated under the authority of the CAA. The requirements of the UIC and GHGRP programs work together to ensure that sequestered CO2 will remain securely stored underground. The UIC regulations facilitate the injection of CO2 for geologic sequestration while protecting human health and the environment by ensuring the protection of underground sources of drinking water (USDW). These regulations are built upon decades of Federal experience regulating underground injection wells, and many additional years of state UIC program expertise.
To complement the UIC regulations, the EPA included in the GHGRP air-side monitoring and reporting requirements for CO2 capture, underground injection, and geologic sequestration. These requirements are included in 40 CFR part 98, subpart RR, also referred to as "GHGRP subpart RR." 
The GHGRP subpart RR requirements provide the monitoring mechanisms to identify, quantify, and address potential leakage. The EPA designed them to complement and build on UIC monitoring and testing requirements. Although the regulations for the UIC program are designed to ensure protection of USDWs from endangerment, the practical effect of these GHGRP subpart RR requirements is that they also prevent releases of CO2 to the atmosphere. 
Major components to be included in UIC Class VI permits are site characterization, area of review, corrective action, well construction and operation, testing and monitoring, financial responsibility, post-injection site care, well plugging, emergency and remedial response, and site closure. Reporting under GHGRP subpart RR is required for, but not limited to, all facilities that have received a UIC Class VI permit for injection of CO2. GHGRP subpart RR requires facilities meeting the source category definition (40 CFR 98.440) for any well or group of wells to report basic information on the mass of CO2 received for injection; develop and implement an EPA-approved monitoring, reporting, and verification (MRV) plan; report the mass of CO2 sequestered using a mass balance approach; and report annual monitoring activities.    Although deep subsurface monitoring is required for UIC Class VI wells at 40 CFR 146.90 and is the primary means of determining if there are any leaks to a USDW, and is generally effective in doing so, the surface air and soil gas monitoring employed under a GHGRP subpart RR MRV Plan can be utilized in addition to subsurface monitoring required under 40 CFR 146.90, if required by the UIC Program Director under 40 CFR 146.90(h), to further ensure protection of USDWs. The MRV plan includes five major components: a delineation of monitoring areas based on the CO2 plume location; an identification and evaluation of the potential surface leakage pathways and an assessment of the likelihood, magnitude, and timing, of surface leakage of CO2 through these pathways; a strategy for detecting and quantifying any surface leakage of CO2 in the event leakage occurs; an approach for establishing the expected baselines for monitoring CO2 surface leakage; and, a summary of considerations made to calculate site-specific variables for the mass balance equation. 
Broad Availability of Sequestration
Geologic sequestration potential for CO2 is widespread and available throughout the U.S. Nearly every state in the U.S. has or is in close proximity to formations with geologic sequestration potential, including areas offshore. These areas include deep saline formation, unmineable coal seams, and oil and gas reservoirs. Moreover, the amount of storage capacity can readily accommodate the amount of CO2 for which sequestration could be required under this proposed rule. 
The DOE and the United States Geological Survey (USGS) have independently conducted preliminary analyses of the availability and potential CO2 sequestration capacity in the U.S. The DOE estimates are compiled in the DOE's National Carbon Sequestration Database and Geographic Information System (NATCARB) using volumetric models and are published in its Carbon Utilization and Sequestration Atlas (NETL Atlas). The DOE estimates that areas of the U.S. with appropriate geology have a sequestration potential of at least 2,400 billion to over 21,000 billion metric tons of CO2 in deep saline formations, unmineable coal seams, and oil and gas reservoirs. The USGS assessment estimates a mean of 3,000 billion metric tons of subsurface CO2 sequestration potential across the U.S. 
With respect to deep saline formations, the DOE estimates a sequestration potential of at least 2,200 billion metric tons of CO2 in these formations in the U.S. At least 37 states have geologic characteristics that are amenable to deep saline sequestration, and an additional 6 states are within 100 kilometers of potentially amenable deep saline formations in either onshore or offshore locations.  
Unmineable coal seams offer another potential option for geologic sequestration of CO2. Enhanced coalbed methane recovery is the process of injecting and storing CO2 in unmineable coal seams to enhance methane recovery. These operations take advantage of the preferential chemical affinity of coal for CO2 relative to the methane that is naturally found on the surfaces of coal. When CO2 is injected, it is adsorbed to the coal surface and releases methane that can then be captured and produced. This process effectively "locks" the CO2 to the coal, where it remains stored. States with the potential for sequestration in unmineable coal seams include Iowa and Missouri, which have little to no saline sequestration potential and have existing coal-fired EGUs. Unmineable coal seams have a sequestration potential of 54 billion metric tons of CO2, or 2 percent of total potential in the U.S., and are located in 22 states.
The potential for CO2 sequestration in unmineable coal seams has been demonstrated in small-scale demonstration projects, including the Allison Unit pilot project in New Mexico, which injected a total of 270,000 tons of CO2 over a six-year period (1995 - 2001). Further, DOE Regional Carbon Sequestration Partnership projects have injected CO2 volumes in unmineable coal seams ranging from 90 tons to 16,700 tons. DOE has judged unmineable coal seams worthy of inclusion in the NETL Atlas. 
Although the large-scale injection of CO2 in coal seams can lead to swelling of coal, the literature also suggests that there are available technologies and techniques to compensate for the resulting reduction in injectivity. Further, the reduced injectivity can be anticipated and accommodated in sizing and characterizing prospective sequestration sites.
There is sufficient technical basis and scientific evidence that depleted oil and gas reservoirs represent another option for geologic storage. The reservoir characteristics of older fields are well known as a result of exploration and many years of hydrocarbon production and in many areas infrastructure already exists for CO2 transportation and storage. Other types of geologic formations such as organic rich shale and basalt may also have the ability to store CO2, and DOE is continuing to evaluate their potential sequestration capacity and efficacy.
The EPA performed a geographic availability analysis in which the Agency examined areas of the country with sequestration potential in deep saline formations, unmineable coal seams, and oil and gas reservoirs; information on existing and probable, planned or under study CO2 pipelines; and areas within a 100-kilometer (km) (62-mile) area of locations with sequestration potential. The distance of 100 km is consistent with the assumptions underlying the NETL cost estimates for transporting CO2 by pipeline. Overall, the EPA found that there are 43 states with access to or within 100 km from onshore or offshore storage in deep saline formations, unmineable coal seams, and depleted oil and gas reservoirs.
As described in the 2015 NSPS, electricity demand in states that may not have geologic sequestration sites may be served by new generation, including new base load combustion turbines, built in nearby areas with geologic sequestration, and this electricity can be delivered through transmission lines. This approach has long been used in the electricity sector because siting an EGU away from a load center and transmitting the generation long distances to the load area can be less expensive and easier to permit than siting the EGU near the load area.
In many of the areas without access to geologic sequestration, utilities, electric cooperatives, and municipalities have a history of joint ownership of electricity generation outside the region or contracting with electricity generation in outside areas to meet demand. Some of the areas are in RTOs, which engage in planning as well as balancing supply and demand in real time throughout the RTO's territory. Accordingly, generating resources in one part of the RTO can serve load in other parts of the RTO, as well as load outside of the RTO. For example, the Prairie State Generating Plant, a 1,600-MW coal-fired EGU in Illinois that is currently considering retrofitting with CCS, serves load in eight different states from the midwest to the mid-Atlantic. The Intermountain Power Project, a coal-fired plant located in Delta, Utah, that is converting to burn hydrogen and natural gas, serves customers in both Utah and California.
Costs
The EPA has evaluated the costs of CCS for new combined cycle units, including the cost of installing and operating CO2 capture equipment as well as the costs of transport and storage, and is proposing that these costs are reasonable. Certain elements of the transport and storage costs are similar for new combustion turbines and existing steam generating units. In this section, we outline these costs and identify the considerations specific to new combustion turbines. These costs are significantly reduced by the IRC section 45Q tax credit. For additional details on the EPA's CCS costing analysis see the TSD titled GHG Mitigation Measures  -  111(d), which is available in the rulemaking docket.
Capture costs
According to the NETL Fossil Energy Baseline Report (October 2022 revision), before accounting for the IRC section 45Q tax credit for sequestered CO2, using a 90 percent capture amine-based post-combustion CO2 capture system increases the capital costs of a new combined cycle EGU by 115 percent on a $/kW basis, increases the heat rate by 13 percent, increases incremental operating costs by 35 percent, and derates the unit (i.e., decreases the capacity available to generate useful output) by 11 percent. For a base load combustion turbine, carbon capture increases the LCOE by 61 percent (an increase of 27 $/MWh) and has an estimated cost of $81/ton ($89/tonne) of onsite CO2 reduction. The NETL costs are based on the use of a second generation amine-based capture system without exhaust gas recirculation (EGR) and does not take into account further cost reductions that can be expected to occur as post-combustion capture systems are more widely deployed. 
      The flue gas from NGCC EGUs differs from that of a coal-fired EGUs in several ways that impact the cost of CO2 capture. These include that the CO2 concentration is approximately one-third, the volumetric flow rate on a per MW basis is larger, and the oxygen concentration is approximately 3 times that of a coal-fired EGU. The higher amount of excess oxygen has the potential to reduce the efficiency of amine-based solvents that are susceptible to oxidation. Other important factors include that the lower concentrations of CO2 reduce the efficiency of the capture process and that the larger volumetric flow rates require a larger CO2 absorber, which increases the capital cost of the capture process. EGR, also referred to as flue gas recirculation (FGR), is a process that addresses all of these issues. EGR diverts some of the combustion turbine exhaust gas back into the inlet stream for the combustion turbine. Doing so increases the CO2 concentration and decreases the O2 concentration in the exhaust stream and decreases the flow rate, producing more favorable conditions for CCS. One study found that EGR can decrease the capital costs of a combined cycle EGU with CCS by 6.4 percent, decrease the heat rate by 2.5 percent, decrease the LCOE by 3.4 percent, and decrease the overall CO2 capture costs by 11 percent relative to a combined cycle EGU without EGR. 
Furthermore, the EPA expects that the costs of capture systems will also decrease over the rest of this decade and continue to decrease afterwards. As part of the plan to reduce the costs of CO2 capture, the DOE is funding multiple projects to advance CCS technology. These include projects falling under carbon capture research and development, engineering-scale testing of carbon capture technologies, and engineering design studies for carbon capture systems. The projects will aim to capture CO2 from various point sources, including NGCC units, cement manufacturing plants, and iron and steel plants. The general aim is to reach 95 percent capture of CO2, to lower the costs of the technologies, and to prove feasible scalability at the industrial scale. Some projects are designed solely to develop new carbon capture technologies, while others are designed to apply existing technologies at the industrial scale. Some of the notable DOE-funded projects related to NGCC units are as follows:    
 General Electric (GE) (Bucks, Alabama) was awarded $5,771,670 to retrofit an NGCC facility with CCS technology to capture 95 percent of CO2, and is targeting commercial deployment by 2030.
 Wood Environmental & Infrastructure Solutions (Blue Bell, Pennsylvania) was awarded $4,000,000 to complete an engineering design study for CO2 capture at the Shell Chemicals Complex. The aim is to reduce CO2 emissions by 95 percent using post-combustion technology to capture CO2 from several plants, including an onsite natural gas CHP plant.
 General Electric Company, GE Research (Niskayuna, New York) was awarded $1,499,992 to develop a design to capture 95 percent of CO2 from NGCC flue gas with the potential to reduce electricity costs by at least 15 percent.
 SRI International (Menlo Park, California) was awarded $1,499,759 to design, build, and test a technology that can capture at least 95 percent of CO2 while demonstrating a 20 percent cost reduction compared to existing NGCC carbon capture.
 CORMETECH, Inc. (Charlotte, North Carolina) was awarded $2,500,000 to further develop, optimize, and test a new, lower cost technology to capture CO2 from NGCC flue gas and improve scalability to large NGCC plants.
 TDA Research, Inc. (Wheat Ridge, Colorado) was awarded $2,500,000 to build and test a post-combustion capture process to improve the performance of NGCC flue gas CO2 capture.
 GE Gas Power (Schenectady, New York) was awarded $5,771,670 to perform an engineering design study to incorporate a 95 percent CO2 capture solution for an existing NGCC site while providing lower costs and scalability to other sites. 
 Electric Power Research Institute (EPRI) (Palo Alto, California) was awarded $5,842,517 to complete a study to retrofit a 700-Mwe NGCC with a carbon capture system to capture 95 percent of CO2.
 Gas Technology Institute (Des Plaines, Illinois) was awarded $1,000,000 to develop membrane technology capable of capturing more than 97 percent of NGCC CO2 flue gas and demonstrate upwards of 40 percent reduction in costs.
 RTI International (Research Triangle Park, North Carolina) was awarded $1,000,000 to test a novel non-aqueous solvent technology aimed at demonstrating 97 percent capture efficiency from simulated NGCC flue gas.
 Tampa Electric Company (Tampa, Florida) was awarded $5,588,173 to conduct a study retrofitting Polk Power Station with post-combustion CO2 capture technology aiming to achieve a 95 percent capture rate.
Although current post-combustion CO2 capture projects have primarily been based on amine capture systems, there are multiple alternate capture technologies in development -- many of which are funded through industry research programs -- that could have reductions in capital, operating, and auxiliary power requirements and could reduce the cost of capture significantly or improve performance. More specifically, post combustion carbon capture systems generally fall into one of several categories: solvents, sorbents, membranes, cryogenic, and molten carbonate fuel cells systems. It is expected that as CCS infrastructure increases, technologies from each of these categories will become more economically competitive. For example, advancements in solvents, that are potentially direct substitutes for current amine-solvents, will reduce auxiliary energy requirements and reduce both operating and capital costs, and thereby, increasing the economic competitiveness of CCS. Planned large-scale projects, pilot plants, and research initiatives will also decrease the capital and operating costs of future CCS technologies.
In general, CCS costs have been declining as carbon capture technology advances. While the cost of capture has been largely dependent on the concentration of CO2 in the gas stream, advancements in varying individual CCS technologies tend to drive down the cost of capture for other CCS technologies. The increase in CCS investment is already driving down the costs of near-future CCS technologies. For example, the capture costs at the Petra Nova CCS project in Thompsons, Texas, were 35 percent lower than the capture costs at the Boundary Dam Power Station in Saskatchewan, Canada, which was built only a few years earlier. IEA suggests this trend will continue in the future as technology advancements "spill over" into other projects to reduce costs. 
CO2 Transport and Sequestration Costs
NETL's "Quality Guidelines for Energy System Studies; Carbon Dioxide Transport and Sequestration Costs in NETL Studies" provides an estimation of transport costs based on the CO2 Transport Cost Model. The CO2 Transport Cost Model estimates costs for a single point-to-point pipeline. Estimated costs reflect pipeline capital costs, related capital expenditures, and operations and maintenance costs.
NETL's Quality Guidelines also provide an estimate of sequestration costs. These costs reflect the cost of site screening and evaluation, permitting and construction costs, the cost of injection wells, the cost of injection equipment, operation and maintenance costs, pore volume acquisition expense, and long-term liability protection. Permitting and construction costs also reflect the regulatory requirements of the UIC Class VI program and GHGRP subpart RR for geologic sequestration of CO2 in deep saline formations. NETL calculates these sequestration costs on the basis of generic plant locations in the Midwest, Texas, North Dakota, and Montana, as described in the NETL energy system studies that utilize the coal found in Illinois, East Texas, Williston, and Powder River basins. 
There are two primary cost drivers for a CO2 sequestration project: the rate of injection of the CO2 into the reservoir and the areal extent of the CO2 plume in the reservoir. The rate of injection depends, in part, on the thickness of the reservoir and its permeability. Thick, permeable reservoirs provide for better injection and fewer injection wells. The areal extent of the CO2 plume depends on the sequestration capacity of the reservoir. Thick, porous reservoirs with a good sequestration coefficient will present a small areal extent for the CO2 plume and have lower testing and monitoring costs.
NETL's Quality Guidelines model costs for a given cumulative storage potential. At a storage potential of 25 gigatons of CO2, costs range between $7.54/ton ($8.32/metric ton) sequestered (in the Illinois Basin) to $18.00/ton ($19.84/metric ton) sequestered (in the Powder River Basin). 
In addition, provisions in the BIL and IRA are expected to significantly increase the CO2 pipeline infrastructure and development of sequestration sites, which, in turn, are expected to result in further cost reductions for the application of CCS at a new combined cycle EGUs. The BIL establishes a new Carbon Dioxide Transportation Infrastructure Finance and Innovation program to provide direct loans, loan guarantees, and grants to CO2 infrastructure projects, such as pipelines, rail transport, ships and barges. The IRA increases and extends the IRC section 45Q tax credit, as noted above.
IRC Section 45Q Tax Credit
In determining the cost of CCS, the EPA is taking into account the tax credit provided under IRC section 45Q, as revised by the IRA. The tax credit is available at $85/tonne ($77/ton) and offsets a significant portion of the capture, transport, and sequestration costs, as noted above. 
It is reasonable to take the tax credit into account because it reduces the cost of the controls to the source, which has a significant effect on the actual cost of installing and operating CCS. In addition, all sources that install CCS to meet the requirements of these proposals are eligible for the tax credit. The legislative history of the IRA makes clear that Congress was well aware that the EPA may promulgate rulemaking under CAA section 111 based on CCS and explicitly stated that the EPA should consider the tax credit to reduce the costs of CCUS (i.e., CCS). Rep. Frank Pallone, the chair of the House Energy & Commerce Committee, included a statement in the Congressional Record when the House adopted the IRA in which he explained: "The tax credit[] for CCUS ... included in this Act may also figure into CAA Section 111 GHG regulations for new and existing industrial sources[.] ... Congress anticipates that EPA may consider CCUS ... as [a] candidate[] for BSER for electric generating plants .... Further, Congress anticipates that EPA may consider the impact of the CCUS ... tax credit[] in lowering the costs of [that] measure[]." 168 Cong. Rec. E879 (August 26, 2022) (statement of Rep. Frank Pallone).
In the 2015 NSPS, in which the EPA determined partial CCS to be the BSER for GHGs from new coal-fired steam generating EGUs, the EPA recognized that the IRC section 45Q tax credit or other tax incentives factored into the cost of the controls to the sources. Specifically, the EPA calculated the cost of partial CCS on the basis of cost calculations from NETL, which included "a range of assumptions including the projected capital costs, the cost of financing the project, the fixed and variable O&M costs, the projected fuel costs, and incorporation of any incentives such as tax credits or favorable financing that may be available to the project developer." 80 FR 64570 (October 23, 2015).
Similarly, in the 2015 NSPS, the EPA also recognized that revenues from utilizing captured CO2 for EOR would reduce the cost of CCS to the sources, although the EPA did not account for potential EOR revenues for purposes of determining the BSER. Id. At 64563 - 64. In other rules, the EPA has considered revenues from sale of the by-products of emission controls to affect the costs of the emission controls. For example, in the 2016 Oil & Gas methane rule, the EPA determined that certain control requirements would reduce natural gas leaks and therefore result in the collection of recovered natural gas that could be sold; and the EPA further determined that revenues from the sale of the recovered natural gas reduces the cost of controls. See 81 FR 38824 (June 14, 2016). In a 2011 action concerning a regional haze SIP, the EPA recognized that a NOX control would alter the chemical composition of fly ash that the source had previously sold, so that it could no longer be sold; and as a result, the EPA further determined that the cost of the NOX control should include the foregone revenues from the fly ash sales. 76 FR 58570, 58603 (September 21, 2011). 
The amount of the IRC section 45Q tax credit that the EPA is taking into account is $85/metric ton for CO2 that is captured and stored. This amount is available to the affected source as long as it meets the prevailing wage and apprenticeship requirements of IRC section 45Q(h)(3) - (4). The legislative history to the IRA specifically stated that when the EPA considers CCS as the BSER for GHG emissions from industrial sources in CAA section 111 rulemaking, the EPA should determine the cost of CCS by assuming that the sources would meet those prevailing wage and apprenticeship requirements. 168 Cong. Rec. E879 (August 26, 2022) (statement of Rep. Frank Pallone).
Total Costs of CCS
In a typical NSPS analysis, the EPA amortizes costs over the expected life of the affected facility and assumes constant revenue and expenses over that period of time. This analysis is different because the IRC section 45Q tax credits for the sequestration of CO2 are only available for combustion turbines that commence construction by the end 2032 and are available for 12 years. The construction timeframe is within the NSPS review cycle, and the EPA has determined that it is appropriate to include the credits as part of the CCS costing analysis. Since the duration of the tax credit is less than the expected life of a new base load combustion turbine, the EPA conducted the costing analysis assuming a 30-year useful life and a separate analysis assuming the capital costs are amortized over a 12-year period. For the 30-year analysis, the EPA used a discount rate of 3.8 percent for the 45Q tax credits to get an effective 30-year value of $41/ton.
Even considering that the IRC section 45Q tax credits are currently available for only 12 years and would, therefore, only offset costs for a portion of a new NGCC turbine's expected operating life, the current overall CO2 abatement costs of CCS of a 90 percent capture amine-based post combustion capture system, accounting for the tax credit, are $44/ton ($49/tonne) and the increase in the LCOE is $15/MWh. These costs assume a stable 30-year operating life and do not include any revenues from sale of the CO2 following the 12-year period when the IRC section 45Q tax credit is available. An alternate costing approach is to assume all capital costs are amortized during the 12-year period when tax credits are available. These tax credits are a significant source of revenue and would lower the incremental generating costs of the unit. Therefore, under the 12-year costing approach the EPA increased the assumed annual capacity factor from 65 to 75 percent. The 12-year CO2 abatement costs are $19/ton ($21/tonne) and the increase in the LCOE is $6/MWh. These costs are for a combined cycle unit with a base load rating of 4,600 MMBtu/h with an output of approximately 700 MW. These costs could be higher for small units and lower for larger units. For additional details on the CCS costing analysis see the TSD titled GHG Mitigation Measures  -  111(b), which is available in the rulemaking docket.
Comparison to Costs of Controls on EGUs for Other Pollutants
In assessing cost reasonableness for the BSER determination for this rule, the EPA compares the costs of GHG control measures to costs that EGUs have incurred to install controls that reduce other air pollutants, such as SO2. At different times, many coal-fired steam generating units have been required to install and operate flue gas desulfurization (FGD) equipment -- that is, wet or dry scrubbers -- to reduce their SO2 emissions. These control costs are compared across technologies -- steam generating units and combustion turbines -- because these costs are indicative of what is reasonable for the power sector in general. The fact that many EGUs have installed and operated these controls is evidence that these costs are reasonable, and as a result, the cost of these controls provides a benchmark to assess the reasonableness of the costs in this preamble. In the 2011 Cross-State Air Pollution Rule (CSAPR) (76 FR 48208; August 8, 2011), the EPA estimated the annualized costs to install and operate wet FGD retrofits on coal-fired steam generating units. Using those same cost equations and assumptions (i.e., a 63 percent annual capacity factor  -  the average value in 2011) for a representative 300 to 700 MW coal-fired steam generating unit results in annualized costs of $15.00 to $18.50/MWh of generation. In comparison, the cost for CCS applied to a representative new base load stationary combustion turbine EGU are comparable, ranging from $6 to $15/MWh (depending on the amortization period). Therefore, the EPA is proposing that the costs for CCS for those units are reasonable. 
Non-air Quality Health and Environmental Impact and Energy Requirements
In this section of the preamble, the EPA evaluates the non-air quality health and environmental impact and energy requirements of CCS specific to combined cycle combustion turbines. In particular, the Agency has considered non-GHG emissions impacts and water use impacts, as well as energy requirements, resulting from the capture, transport and sequestration of CO2. Use of CCS is not expected to have unreasonable adverse consequences related to non-air quality health and environmental impacts or energy requirements. 
Including a 90 percent carbon capture system in the design of a new NGCC will increase the parasitic/auxiliary energy demand and reduce its net power output. A utility that wants to construct an NGCC unit to provide 500 MWe-net of power could build a 500 MWe-net plant knowing that it will be essentially de-rated by 11 percent (to a 444 MWe-net plant) with the installation and operation of CCS. In the alternative, the project developer could build a larger 563 MWe-net NGCC plant knowing that, with the installation of the carbon capture system, the unit will still be able to provide 500 MWe-net of power to the grid. The 563 MWe plant will, as a consequence of its larger size, have the potential to emit more air pollutants than the smaller 500 MWe plant. However, in either scenario, the installation of CCS does not impact the unit's potential-to-emit any of the criteria or hazardous air pollutants. In other words, a new base load stationary combustion turbine EGU constructed using highly efficient generation (the first component of the BSER) would not see an increase in emissions of criteria or hazardous air pollutants as a consequence of installing and using 90 percent CO2 capture CCS to meet the second phase standard of performance.
Due to their relatively high efficiency, combined cycle EGUs have relatively small cooling requirements compared to other base load EGUs. According to NETL, a combined cycle EGU without CCS requires 190 gallons of cooling water per MWh of electricity. CCS increases the cooling water requirements due both to the decreased efficiency and the cooling requirements for the CCS process to 290 gallons per MWh, an increase of about 50 percent. However, because NGCC units require limited amounts of cooling water, the absolute amount of increase in cooling water required due to use of CCS does not present unsurmountable concerns. In addition, many combined cycle EGUs currently use dry cooling technologies and the use of dry or hybrid cooling technologies for the CO2 capture process would reduce the need for additional cooling water. Therefore, the EPA is proposing that the additional cooling water requirements from CCS are reasonable. 
As noted in section VII.F.3 of this preamble, PHMSA oversight of CO2 pipeline safety protects against environmental release during transport and UIC Class VI regulations under the SDWA in tandem with GHGRP requirements ensure the protection of USDWs and the security of geologic sequestration. 
Impacts on the Energy Sector
The EPA expects that several new NGCC units will install CCS because, as discussed earlier in section VII.F.3.iii.(A) of this preamble, a few have already announced that they will. However, the Agency does not expect a large number of new NGCC units to install CCS. This is because as more renewable generation and energy storage are built, the need for base load generating capacity is likely to fall. This reduction in utilization of combined cycle combustion turbine capacity can be seen in the EPA's reference case modeling (post-IRA 2022 reference case, see section IV.F of the preamble). Further, a number of companies have recently announced plans to move away from new NGCC projects in favor of more renewables, battery storage, and low load combustion turbines. For example, Xcel took this approach with regards to a proposed combined cycle plant to replace the retiring Sherco coal-fired plant. 
Extent of Reductions in CO2 Emissions 
Designating CCS as a component of the BSER for certain base load combustion turbine EGUs prevents large amounts of CO2 emissions. For example, a new base load combined cycle EGU without CCS could be expected to emit 45 million tons of CO2 over its operating life. Use of CCS would avoid the release of nearly 41 million tons of CO2 over the operating life of the combined cycle EGU. However, due to the auxiliary/parasitic energy requirements of the carbon capture system, capturing 90 percent of the CO2 does not result in a corresponding 90 percent reduction in CO2 emissions. According to the NETL baseline report, adding a 90 percent CO2 capture system increases the EGU's gross heat rate by 7 percent and the unit's net heat rate by 13 percent. Since more fuel would be consumed in the CCS case, the gross and net emissions rates are reduced by 89.3 percent and 88.7 percent respectively. 
Promotion of the Development and Implementation of Technology
The EPA also considered whether determining CCS to be a component of the BSER for long term coal-fired steam generating units and for new base load combustion turbines will advance the technological development of CCS, and concluded that this factor supports our BSER determination. An emission standard based on highly efficient generation in combination with the use of CCS -- combined with the availability of 45Q tax credits -- should incentivize additional use of CCS which should incentivize cost reductions through the development and use of better performing solvents or sorbents. While solvent-based CO2 capture has been adequately demonstrated at the commercial scale, a determination that a component of the BSER for new base load stationary combustion turbine (and long term coal-fired steam generating units) is the use of CCS will also likely incentivize the deployment of alternative CO2 capture techniques at scale. Moreover, as noted above, the cost of CCS has fallen in recent years and is expected to continue to fall; and further implementation of the technology can be expected to lead to additional cost reductions, due to added experience and cost efficiencies through scaling. 
The experience gained by utilizing CCS with stationary combustion turbine EGUs, with their lower CO2 flue gas concentration relative to other industrial sources such as coal-fired EGUs, will advance capture technology with other lower CO2 concentration sources. The EIA 2022 Annual Energy Outlook projects that almost 1,400 billion kWh of electricity will be generated from natural gas-fired sources in 2040. Much of that generation is projected to come from existing combined cycle EGUs and further development of carbon capture technologies could facilitate increased retrofitting of those EGUs. 
Proposed BSER
The Agency proposes that for new natural gas-fired base load combustion turbines, an efficient stationary combustion combined cycle turbine utilizing CCS at a capture rate of 90 percent, beginning in 2035, qualifies as the BSER because it is adequately demonstrated; it is of reasonable cost taking account of the IRC section 45Q tax credit, it achieves significant emission reductions, and it does not have significant adverse non-air quality health or environmental impacts or significant adverse energy requirements, including on a nationwide basis. The fact that it promotes useful technology provides additional, although not essential, support for this proposal. 
Low-GHG hydrogen 
As discussed later in section VII.F.3.c, the EPA is also proposing that beginning in 2035, the second component of BSER for base load combustion turbines combusting at least 10 percent (by heat input) hydrogen is co-firing 30 percent low-GHG hydrogen. However, co-firing low-GHG hydrogen does not qualify as the BSER for base load combustion turbines not combusting at least 10 percent (by heat input) hydrogen because it achieves lower GHG reductions than through the use of CCS.
Why the EPA is Proposing a Second Component of BSER, Based on CCS, in 2035
When considering whether a technology should be BSER, the EPA must consider both unit level and nationwide questions. At the unit level, the EPA must ask whether the technology is proven, can be implemented at reasonable cost, and achieves emission reductions without causing other significant environmental or energy issues. With regards to CCS at the unit level, the EPA believes there is ample evidence to conclude that it is available and cost reasonable (with the 45Q tax credits) today. When looking at the technology from a nationwide basis, the EPA must take larger system-wide impacts into consideration. For CCS this includes questions about infrastructure for transportation and storage, as well as considerations relating to the lead time needed to scale-up manufacturing and installation of carbon capture equipment to meet the amount of capacity potentially subject to this proposed BSER (in addition to meeting IRA-driven demand for CCS in other sectors).
When considering these larger geographic questions, the EPA is also mindful of requirements on other sources within the larger EGU category. As discussed later in this preamble, the EPA is also proposing a determination that the BSER for existing coal-fired EGUs with long operating horizons is CCS, with a requirement that sources meet the associated standard of performance by January 1, 2030. The EPA believes that, if there are limited resources available to install CCS, priority should go to installation on existing coal-fired steam generating units which emit significantly more CO2 than new baseload stationary combustion turbines (well over twice as much CO2 on a lb per MWh basis).
The EPA's modeling projects that 12 GW of existing coal-fired steam generating units will install retrofit CCS and that more than 30 GW of new NGCC EGUs will be built by 2030. If all those new NGCC units were required to install CCS at the time of construction, that would result in the construction of more than 40 GW of CCS by 2030. This does not include construction of CCS systems that are likely to be installed in other industries incentivized by the IRA. The EPA believes there are multiple reasons to delay the second phase of the standard of performance that is based on application of highly efficient generation and use of CCS until 2035. First, new combined cycle combustion turbines have inherently lower uncontrolled GHG emission rates than many of the other types of units that are likely to install CCS in the 2030  -  2035 timeframe. The EPA also recognizes that a number of companies are planning to build NGCC units to replace retiring coal-fired units. If there are supply chain delays or other delays such as shortages in engineering services, specialty labor, etc. critical to installing CCS, providing lower emitting NGCCs flexibility to delay installation allows higher emitting coal-fired units with plans to permanently cease operations to do so on the schedules chosen by owners and operators. Second, the EPA does not believe that all of the combustion turbine units that are likely to install CCS will choose to to delay the installation. As discussed above, there are some technologies (e.g., the NET Power Cycle) that are fully integrated into the combined cycle unit such that, if a company wishes to use this technology, it will be easier to install and integrate the CCS system when the unit is first constructed. Third, the EPA is aware that many companies are considering building combined cycle units to meet near term demand as coal-fired steam generating units cease operations and are planning to eventually convert the combined cycle units to hydrogen-fired (or co-fired) units that will operate more in an intermediate load fashion as more renewables and energy storage options are built and as a low-GHG hydrogen network is developed. Providing these units a delayed date to meet a second phase standard of performance that is based, in part, on the implementation of CCS will allow them to make more informed long term decisions. The EPA is proposing CCS as adequately demonstrated and cost reasonable for base load combustion turbines, and delaying deployment of CCS for the affected combustion turbines will provide the additional benefit of greater operational experience and potentially lower costs to install CCS or take advantage of a more fully developed low-GHG hydrogen infrastructure. By 2030 project developers are likely to have a much better picture with regards to the cost and performance of small modular nuclear reactors, advanced battery technology, and advances in renewables and distributed generation that are likely to make the long term path for combined cycle units much clearer. Companies will have a better understanding of the expected longer term operation of the combined cycle unit and whether it will continue to operate as a base load combustion turbine with CCS or with low-GHG hydrogen co-firing or whether it will operate as an intermediate load combustion turbine. 
The EPA considered establishing the start of phase 2 of the standard of performance as early as 2030 on the assumption that projects that commence construction in the period immediately following this rulemaking will need at least that amount of time to implement the BSER. However, the EPA is also proposing to determine that the BSER for long-term coal-fired steam generating units (those that will be in operation beyond 2040) is the use of 90 percent capture CCS and that the associated standard of performance for those units is effective beginning in 2030. The EPA is also aware that a significant number of new base load combined cycle stationary combustion turbines are projected to be constructed by 2030, and that there are other, non-power sector industries that will also be pursuing implement of CCS in that timeframe. The EPA believes that the deployment of CCS infrastructure, including the demand for the manufacturing and installation of CCS equipment and the demand for constructing the CO2 pipeline infrastructure and to conducting sequestration site characterization and permitting, should be prioritized for the higher GHG emitting fleet of existing long-term coal-fired steam generating units. The EPA also understands that many utilities and power generating companies are trying to assess their near term and long term base load generating needs and may have useful information to provide to the record that would help to assess the demand for CCS. So, considering all those factors, the EPA is proposing that phase 2 of the standard of performance begin in 2035 to ensure achievability of the standard. The EPA also recognizes that commenters may have more information about implementing CCS on a broader scale that would help to assess whether 2030 or 2035 (or somewhere in between) would be an appropriate start date for phase 2 of the standards of performance that are based, in part, on the use of CCS. For this reason, the EPA solicits comment on whether the compliance date for phase 2 of the standards of performance should begin earlier than 2035, including as early as 2030.
BSER for Base Load Subcategory Combusting At Least 10 percent Hydrogen and for Intermediate Load Subcategories  -  Second Component 
This section describes the second component of the EPA's proposed BSER for the subcategory of base load combustion turbines that co-fire at least 10 percent (by heat input) hydrogen and for combustion turbines in the intermediate load subcategory. For both subcategories, the EPA is proposing that the second component of the BSER is co-firing 30 percent by volume low-GHG hydrogen, beginning in 2035. The first part of this section is a background discussion concerning several key aspects of the hydrogen industry as it is currently developing. At the outset, the EPA summarizes the activities of some power producers and turbine manufacturers to develop and demonstrate hydrogen co-firing as a viable decarbonization technology for the power sector. The EPA then discuss the GHG emissions performance of stationary combustion turbines when hydrogen is used as a fuel. This discussion includes the different methods of production and the associated GHG emissions for each. The second part of this section describes the proposed second component of the BSER, which is co-firing 30 percent by volume low-GHG hydrogen. The EPA is also proposing a definition of low-GHG hydrogen. The EPA is proposing that hydrogen qualifies as low-GHG hydrogen if it is produced through a process that results in a GHG emission rate of less than 0.45 kilograms of CO2 equivalent per kilogram of hydrogen produced (kg CO2e/kg H2). Hydrogen produced by electrolysis (splitting water into hydrogen and oxygen) using electricity produced through low-GHG energy -- may be a type of hydrogen that could qualify as low-GHG hydrogen for the purposes of this proposed BSER. However, the EPA is also soliciting comment on whether a specific definition of low-GHG hydrogen should even be included in the final rule. The third part of this section explains why the EPA proposes that co-firing 30 percent by volume low-GHG hydrogen qualifies as a component of the BSER. Co-firing 30 percent hydrogen is technically feasible and well-demonstrated in new combustion turbines; it will be supported by an adequate supply by 2035; it will be of reasonable cost; it will ensure reductions of GHG emissions; and, it will be consistent with the other BSER factors. The EPA also includes in this section an explanation of why the Agency thinks that highly efficient generating technology combined with co-firing low-GHG hydrogen (as opposed to any hydrogen) is the "best" system of emission reduction taking into account the statutory considerations.
Clean Fuels
      The EPA is not proposing clean fuels as the second component of BSER for intermediate load or base load turbines combusting 10 percent or more hydrogen because it would achieve few emission reductions, compared to co-firing low-GHG hydrogen. 
Highly Efficient Generation
For the reasons described above,, the EPA is proposing that highly efficient generation technology in combination with best operating and maintenance practices continues to be a component of the BSER that is reflected in the second phase of the standards of performance for base load turbines combusting 10 percent or more hydrogen and intermediate load combustion turbines. Highly efficient generation reduces fuel use and the absolute amount, and cost, of low-GHG hydrogen that would be required to comply with the second phase standards.
CCS
The EPA is not proposing the use of CCS as a component of the BSER for the intermediate load subcategory or the base load subcategory for combustion turbines combusting 10 percent or more hydrogen. As described previously, simple cycle technology is the likely combustion turbine technology applicable to the intermediate load subcategory and the Agency is limiting consideration of CCS to combined cycle EGUs. Intermediate load combustion turbines tend to start and stop frequently and have relatively short periods of continuous operation. CCS systems could have difficulty starting sufficiently quickly to get significant levels of CO2 capture. In addition, the CCS equipment could essentially remain idle for much of the time while these units are not running. For these reasons, CCS would be significantly less cost-effective for intermediate load combustion turbine EGUs as compared to base load units. 
Background Discussion of Hydrogen and the Electric Power Sector, Hydrogen Co-firing in Combustion Turbines, and Hydrogen Production Processes
Hydrogen in the United States is primarily used for refining petroleum, treating metals, producing fertilizer, and processing foods. In recent years, applications of hydrogen have expanded to include co-firing in combustion turbines used to generate electricity. In fact, many models of existing combustion turbines that are used for electricity generation have successfully demonstrated the ability to co-fire blends of 5 to 10 percent hydrogen by volume without modification to the combustion system. Furthermore, combustion of hydrogen blends as high as 20 to 30 percent by volume are being tested and demonstrated; and new turbine designs that can accommodate co-firing 30 to 50 percent hydrogen by volume are being developed.
Several power producers made financial investments and began work on hydrogen co-firing projects prior to passage of the IRA in August 2022. For example, in early 2021, the Intermountain Power Agency (IPA) project in Utah began the transition away from an operating 1,800-MW existing coal-fired steam generating unit to an 840-MW combined cycle combustion turbine that will integrate 30 percent hydrogen by volume co-firing at start-up in 2025. IPA and its partners have announced plans to produce low-GHG hydrogen via solar-powered electrolysis with storage in underground geologic formations on route to combusting 100 percent low-GHG hydrogen in the combined cycle unit by 2045. IPA also has agreements to sell its electricity to the Los Angeles Department of Water and Power. 
Another example is the Long Ridge Energy Generation Project in Ohio. The 485-MW combined cycle combustion turbine became operational in 2021 and successfully co-fired 5 percent hydrogen by volume in March 2022.  The planned next step for Long Ridge is to co-fire 20 percent hydrogen by volume with the existing turbine design, which has been commercially available since 2017 and can co-fire 15 to 20 percent hydrogen by volume without modification. Furthermore, in June 2022, Southern Company successfully demonstrated the co-firing of a 20 percent hydrogen blend at Georgia Power's Plant McDonough-Atkinson. The co-firing demonstration was performed on a combustion turbine at partial and full loads and produced a 7 percent reduction in CO2 emissions. In September 2022, the New York Power Authority (NYPA) successfully co-fired a 44 percent blend of hydrogen by volume in a retrofitted combustion turbine. According to the Electric Power Research Institute (EPRI), the project demonstrated a 14 percent reduction in CO2 at a 35 percent by volume hydrogen blend. The unit's existing SCR controlled NOX emissions within permit limits.  
Other power producers have implemented large low-GHG hydrogen plans that integrate multiple elements of their generating assets. In Florida, NextEra announced in June 2022 a comprehensive carbon emission reduction plan that will eventually convert 16 GW of natural gas-fired generation to operate on low-GHG hydrogen as part of the utility's 2045 GHG reduction goal. Also, NextEra's Cavendish NextGen Hydrogen Hub will produce hydrogen with a 25-MW electrolyzer system powered by solar energy and the hydrogen will then be co-fired by combustion turbines at Florida Power and Light's 1.75-GW Okeechobee power plant. 
One of the first power producers to invest in hydrogen as a fuel for combustion turbines was Entergy, which reached an agreement with turbine manufacturer Mitsubishi Power in 2020 to develop hydrogen-capable combined cycle facilities that include low-GHG hydrogen production, storage, and transportation components. In October 2022, Entergy and New Fortress Energy announced plans to collaborate on a renewable energy and 120-MW hydrogen production plant in southeast Texas. The partnership includes electricity transmission infrastructure as well as the development of renewable energy resources and the offtake of low-GHG hydrogen. A feature of the agreement is Entergy's Orange County Advanced Power Station, which received approval from the Public Utility Commission of Texas in November 2022. The 1,115-MW power plant will replace end-of-life gas generation with new combined cycle combustion turbines that are ready to co-fire hydrogen. Construction will begin in 2023 and the project will be completed in 2026.
Hydrogen offers unique solutions for decarbonization because of its potential to provide dispatchable, clean energy with long-term storage and seasonal capabilities. For example, hydrogen is an energy carrier that can provide long-term storage of low-GHG energy that can be co-fired in combustion turbines and used to balance load with the increasing volumes of intermittent generation. Hydrogen also has the potential to mitigate curtailment, which is the deliberate reduction of electric output below what could have been produced. Curtailment often occurs when regional transmission operators need to balance the grid's energy supply to meet demand. For example, in 2020, the California Independent System Operator (CAISO) curtailed an estimated 1.5 million MWh of solar generation. Curtailment will likely increase as the capacity of intermittent generation continues to expand. One technology with the potential to remedy curtailment is energy storage, and some power producers envision a vital role for hydrogen in increasing the reliability and balance of an increasingly decarbonized electric grid. 
Rapid progress is being made, and, due to the demonstrated ability of new and existing combustion turbines to co-fire hydrogen other utility owners/operators have publicly made long-term commitments to hydrogen co-firing and have identified the technology as a key component of their future operations and GHG reduction strategies. As highlighted by the earlier examples, the outlook expressed by multiple power producers and developers includes a future generation asset mix that retains combustion turbines fired exclusively with hydrogen. Utilities in vertically integrated states and merchant generators in wholesale markets rely on combustion turbines to provide reliable, dispatchable power. 
Hydrogen Production Processes and Associated Levels of GHG Emissions
Hydrogen is used in industrial processes, and, as discussed previously, in recent years, applications of hydrogen co-firing have expanded to include stationary combustion turbines used to generate electricity. However, at present, nearly all industrial hydrogen is produced via methods that are GHG-intensive. To fully evaluate the potential GHG emission reductions from co-firing low-GHG hydrogen in a combustion turbine EGU, it is important to consider the different processes of producing the hydrogen and the GHG emissions associated with each process. The following discussion highlights the primary methods of hydrogen production as well as the sources of energy used during production and the level of GHG emissions that result from each production method. The varying levels of CO2 emissions associated with hydrogen production are well-recognized, and stakeholders routinely refer to hydrogen on the basis of the different production processes and their different GHG intensities. 
More than 95 percent of the dedicated hydrogen currently produced in the U.S. originates from natural gas using steam methane reforming (SMR). This method produces hydrogen by adding steam and heat to natural gas in the presence of a catalyst. Methane reacts with the steam to produce hydrogen, carbon monoxide (CO), and trace amounts of CO2. Further, the CO byproduct is routed to a second process, known as a water-gas shift reaction, to react with more steam to create additional hydrogen and CO2. After these processes, the CO2 is removed from the gas stream, leaving almost pure hydrogen. CO2 emissions are generated from the conversion process itself and from the creation of the thermal energy and steam (assuming the boilers are fueled by natural gas) or external energy sources powering the production process. Because the thermal efficiency of SMR of natural gas is generally 80 percent or less, less overall energy is in the produced hydrogen than in the natural gas required to produce the hydrogen. Therefore, the use of hydrogen produced through SMR in a combustion turbine would consume more natural gas than would have been consumed if the combustion turbine had burned the natural gas directly. Therefore, co-firing hydrogen derived from SMR based on fossil fuels without CCS results in higher overall CO2 emissions than using the natural gas directly in the EGU. 
The GHG emissions from hydrogen production via SMR can be controlled with CCS technology at different points in the production process. There are varying levels of CO2 capture for different techniques, but typically a range of 65 to 90 percent is viable. The autothermal reforming (ATR) of methane is a similar technology to SMR, but ATR utilizes natural gas in the process itself without an external heat source. CCS can also be applied to ATR.
Another process to produce hydrogen is methane pyrolysis. Methane pyrolysis is the thermal decomposition of methane in the absence (or near absence) of oxygen, which produces hydrogen and solid carbon (i.e., carbon black) as the only byproducts. Pyrolysis uses energy to power its hydrogen production process, and therefore the level of its overall GHG emissions depends on the carbon intensity of its energy inputs. For SMR, ATR, and pyrolysis technologies, emissions from methane extraction, production, and transportation are also significant aspects of their GHG emissions footprints. 
In contrast to the three methods discussed above, electrolysis does not use methane as a feedstock. In electrolysis, hydrogen is produced by splitting water into its components, hydrogen and O2, via electricity. During electrolysis, a negatively charged cathode and positively charged anode are submerged in water and an electric current is passed through the water. The result is hydrogen molecules appearing at the negative cathodes and O2 appearing at the positive anodes. Electrolysis does not have GHG emissions at the hydrogen production site; the overall GHG emissions associated with electrolysis are instead dependent upon the source of the energy used to decompose the water. According to the DOE, electrolysis powered by fossil fuels, or by energy supplied by the electric grid, would generate overall GHG emissions double those of hydrogen produced via SMR. However, electrolysis powered by wind, solar, hydroelectric, or nuclear energy are generally considered to lower overall GHG emissions.  Naturally occurring hydrogen stored in subsurface geologic formations is also gaining some attention as a potential source hydrogen. 
The EPA's Proposed BSER and Definition of Low-GHG Hydrogen
The EPA is proposing that the second component of the BSER for new combustion turbines in the relevant subcategories is co-firing 30 percent by volume low-GHG hydrogen by 2035. This section describes the factors the EPA considered in determining what level of co-firing qualifies as a component of the BSER for affected sources and the timing for when that level of co-firing could be technically feasible and of reasonable cost. Key factors informing this determination include the magnitude of CO2 stack emission reductions, the availability of combustion turbines capable of co-firing hydrogen, potential infrastructure limitations, and access to low-GHG hydrogen. 
The relationship between the volume of hydrogen fired and the reduction in CO2 stack emissions is exponential. At low levels of co-firing there are modest emission reduction benefits, but these reduction benefits amplify as the volume of hydrogen increases due to the lower energy density of hydrogen compared to natural gas. For example, co-firing 10 percent hydrogen by volume yields approximately a 3 percent CO2 reduction at the stack, co-firing 30 percent yields a 12 percent reduction, co-firing 75 percent yields a 49 percent reduction, and at 100 percent hydrogen co-firing there are zero CO2 emissions at the stack.
Importantly, co-firing 30 percent hydrogen by volume is consistent with existing technologies across multiple combustion turbine designs and should be considered a minimal level for evaluation as a system of emission reduction. While all major manufacturers are developing combustors that can co-fire higher volumes of hydrogen, some combustion turbine models are already able to co-fire relatively high percentages. Several currently available new combustion turbine models can burn up to 75 percent hydrogen by volume. Combustion turbine designs capable of co-firing 30 percent hydrogen by volume are available from multiple manufactures at multiple sizes. As such, a BSER that included co-firing 30 percent hydrogen would not pose challenges for near-term implementation for the EPA's proposed second phase standards beginning in 2035. The EPA is soliciting comment on whether the new and reconstructed combustion turbines will have available combustion turbine designs that would allow higher levels of hydrogen co-firing, such as 50 percent by volume by 2030 or 2035. If such combustion turbines are widely available, this would support moving forward the starting compliance date of the second phase of the standards of performance and/or increasing the percent of hydrogen co-firing assumed in establishing the standards.
Access to low-GHG hydrogen, however, is also an important component of the BSER analysis. Midstream infrastructure limitations and the adequacy and availably of hydrogen storage facilities currently present obstacles and increase prices for delivered low-GHG hydrogen. This is part of the rationale for why the EPA is not proposing hydrogen co-firing as part of the first component of the BSER. Moving gas via pipeline tends to be the least expensive transport and today there are 1,600 miles of dedicated hydrogen pipeline infrastructure. As noted later in a section of this preamble, based on industry announcements, many electrolytic hydrogen production projects will be sited near existing infrastructure and, in certain cases, will provide combustion turbines access to supply and delivery solutions. Hydrogen blending into existing natural gas pipelines presents another mode of transport and distribution that is actively under exploration. On-road distribution methods include gas-phase trucking and liquid hydrogen trucking, the latter requiring cooling and compression prior to transport. Different regional distribution solutions may emerge initially in response to localized hydrogen demand.
Gaseous and liquified hydrogen storage technologies are developing, along with lined hard rock storage and limited but promising geologic salt cavern storage. Increased storage capacity and market demand for low-GHG hydrogen is anticipated in response to federal H2Hub investments as low-GHG hydrogen develops from a localized fuel into a national commodity. 
Given the growth in the hydrogen sector and Federal funding for the H2Hubs, which will explicitly explore and incentivize hydrogen distribution, the EPA therefore believes hydrogen distribution and storage infrastructure will not present a barrier to access for new combustion turbines opting to co-fire 30 percent hydrogen by volume in 2035. The EPA is soliciting comment on whether hydrogen infrastructure will likely be sufficiently developed by 2030 to provide access to low-GHG hydrogen for new and reconstructed combustion turbines. If so, this would support moving forward the compliance date of the second phase of the standards of perforamnce and/or increase the percent of hydrogen co-firing assumed in establishing the standards.
Whether there will be sufficient volumes of low-GHG hydrogen between 2030 to 2035will depend on the deployment of additional low-GHG electric generation sources, the growth of electrolyzer capacity, and market demand. Along with the power sector, the industrial and transportation sectors are also advancing hydrogen-ready technologies. Industries and policymakers in those sectors are actively planning to use hydrogen to drive decarbonization. For the industrial sector where hydrogen is a chemical input to the process or a replacement for liquid fuels, multiple projection pathways are being considered as approaches to lower the GHG intensity of these sectors. The production pathways for the industrial sector include, but are not limited to, fossil-derived hydrogen in combination with CCS. However, due to thermodynamic inefficiencies in using fossil-derived hydrogen to produce electricity, it is likely that only a specific type of low-GHG hydrogen will be used in the power sector. Announcements of co-firing applications support this assertion, and as discussed in another section of this preamble, the power sector is already focused on utilizing low-GHG hydrogen, electricity generators are likely to have ample access to low-GHG hydrogen and in sufficient quantities to support 30 percent co-firing by 2035. The DOE's estimates of clean hydrogen production volumes of 10 MMT by 2030 and 40 MMT by 2040, referenced throughout this rulemaking, do not apportion which type of hydrogen is likely to be produced, just that it is `clean,' which is below overall emissions of 4 kg CO2e/kg H2. The EPA estimates power sector demand for hydrogen in response to this rulemaking to be in the range of 2.2 to 3.4 MMT by 2035. The available credit for the lowest hydrogen production tier under IRC section 45V tax subsidies going into effect in 2023, as outlined in another section of this preamble, are three times higher than the other credits alloted for other hydrogen production tiers in IRC section 45V, combined with additional monetization access through direct pay, and are therefore highly likely to drive significant volumes of electrolytic hydrogen, which is likely to be considered as low-GHG hydrogen in this proposal. These incentives will be multiplied by investments through the DOE's H2Hub program. Based on this assessment, ample supplies are likely to be available for combustion turbine co-firing in 2035. The EPA is soliciting comment on whether sufficient quantities of low-GHG hydrogen will likely be available at reasonable costs by 2030. If so, this would support moving forward the compliance date of the second component of the BSER and/or increase the percent of hydrogen co-firing assumed in establishing the standard of performance.
As explained above, a central and universally recognized feature of hydrogen is its level of GHG emissions generated during its production process, with different hydrogen production processes resulting in different levels of GHG emissions. As explained in another section in the preamble, the EPA proposes to conclude that only co-firing with low-GHG hydrogen appropriately considers the statutory factors and constitutes the "best" system of emission reduction. Here, the EPA discusses the proposed definition of "low-GHG hydrogen." In the IIJA and IRA, Congress established various programs to support the development of low-GHG hydrogen. Several federal agencies, including the EPA, are implementing those programs, as well as pre-IIJA and IRA programs that involve low-GHG hydrogen. These various programs have a range of definitions of low-GHG hydrogen. As a result, they provide useful points of reference for the EPA to use in selecting a definition for this proposed rulemaking.
In enacting the IRA, Congress recognized that different methods of hydrogen production generate different amounts of GHG emissions and sought to encourage lower-emitting production methods through the multi-tier hydrogen production tax credit (IRC section 45V). The IRC section 45V tax credits provide four tiers of tax credits, and thus award the highest amount of tax credits to the hydrogen production processes with the lowest estimated GHG emissions. The highest tier of the credits is $3/kg H2 for 0.0 to 0.45 kg CO2e/kg H2 produced, and the lowest is $0.6/kg H2 for 2.5 to 4.0 kg CO2e/kg H2. Congress also provided a definition of "clean hydrogen" in section 822 of the IIJA. This provision sets out a non-binding goal intended for use in development of the DOE's Clean Hydrogen Production Standard (CHPS) and DOE's funding programs to promote promising new hydrogen technologies.
Several Federal agencies are engaging in low-GHG hydrogen-related efforts, some of which implement the IRA and IIJA provisions. As discussed earlier in this section, the DOE is working on a Clean Hydrogen Production Standard, an $8 billion Clean Hydrogen Hub solicitation, and several hydrogen-related research and development grant programs. The Department of the Treasury is taking public comment on examining appropriate parameters for evaluating overall emissions associated with hydrogen production pathways as it prepares to implement IRC section 45V. Within the EPA, there are rulemaking efforts that could impact low-GHG hydrogen production pathways, namely the proposed and supplemental oil and gas emission guidelines to reduce methane emissions. 
Upon review of the reference points that these legislative provisions and agency programs provide, it is apparent that the "clean hydrogen" definition in section 822 of the IIJA is not appropriate for purposes of this rule. As noted, this provision sets out a non-binding goal for use in development of the DOE's Clean Hydrogen Production Standard (CHPS), and DOE's funding programs to promote promising new hydrogen technologies. The CHPS is limited to GHG produced at the site of the hydrogen production, and so is not intended to consider overall GHG emissions associated with that production. According to the IIJA, clean hydrogen as defined as part of the CHPS is "... hydrogen produced with a carbon intensity equal to or less than 2 kilograms of carbon dioxide-equivalent produced at the site of production per kilogram of hydrogen produced" (emphasis added). A significant portion of the GHG emissions associated with hydrogen derived from natural gas originates from upstream methane emissions, which are not accounted for in the CHPS definition. 
In contrast, the EPA believes that the highest tier of the IRC section 45V(b)(2) production tax credit is salient for purposes of the present rule. That provision provides the highest available amount of production tax credit for hydrogen produced through a process that has a GHG emissions rate of 0.45 kg CO2e/kg H2 or less, from well-to-gate. As explained further below, the EPA proposes that co-firing hydrogen meeting this criteria qualifies as a component of the "best" system of emission reduction taking into account the statutory considerations. Thus, the EPA is proposing that low-GHG hydrogen is hydrogen that is produced through a process that has a GHG emissions rate of 0.45 kg CO2e/kg H2 or less, from well-to-gate. Each of the subsequent hydrogen production categories outlined in 45V(b)(2) convey increasingly higher amounts of GHG emissions (from a well-to-gate analysis), making them less suitable to be a component of the BSER.
Electrolyzers with various low-GHG energy inputs, like solar, wind, hydroelectric, and nuclear appear most likely to produce hydrogen that would meet the 0.45 kg CO2e/kg H2 or less, from well-to-gate criteria. Hydrogen production pathways using methane as a feedstock induce upstream methane emissions associated with extraction, production, and transport of the methane. SMR and ATR also release heating and process-related CO2 emissions, which can be only partially captured by CCS. High contributions to overall GHG emission rates may disqualify certain hydrogen production pathways from producing low-GHG hydrogen. The EPA recognizes that the pace and scale of government programs and private research suggest that we will gain significant experience and knowledge on this topic during the timeframe of this proposed rulemaking. Accordingly, the EPA is soliciting comment broadly on its proposed definition for low-GHG hydrogen, and on alternative approaches, to ensure that co-firing low-GHG hydrogen minimizes GHG emissions, and that combustion turbines subject to this standard utilize only low-GHG hydrogen.
The EPA is also taking comment on whether it is even necessary to provide a definition of low-GHG hydrogen in this rule. Given the incentives provided in both the IRA and IIJA for low-GHG hydrogen production and the current trajectory of hydrogen use in the power sector, by 2035, the start date for compliance with the proposed second phase of the standards for this rule, low-GHG hydrogen may be the most common source of hydrogen available for electricity production. For the most part, companies that have announced that they are exploring the use of hydrogen co-firing have stated that they intend to use low-GHG hydrogen. These power suppliers include NextEra, Los Angeles Department of Power and Water, and New York Power Authority, as discussed earlier in this section. Many utilities and merchant generators own nuclear, wind, solar, and hydroelectric generating sources as well as combustion turbines. The EPA has identified an emerging trend in which energy companies with this broad collection of generation assets are planning to produce low-GHG hydrogen for sale and to use a portion of it to fuel their stationary combustion turbines. This emerging trend lends support to the view that the power sector is likely to have access to and will choose to utilize low-GHG hydrogen for its co-firing applications.
Moreover, by the next decade, costs for low-GHG hydrogen are expected to be competitive with higher-GHG forms of hydrogen. Given the tax credits in IRC section 45V(b)(2)(D) of $3/kg H2 for hydrogen with GHG emissions of less than 0.45 kg CO2e/kg H2, and substantial DOE grant programs to drive down costs of clean hydrogen, electrolytic low-GHG hydrogen is projected by industry estimates to result in delivered hydrogen costs ranging from $1/kg H2 to $0/kg H2 or less by 2030.  These projections are more optimistic but generally consistent with the DOE's (pre-IRA) program targets of clean hydrogen production costs converging on $1/kg H2 between 2029 and 2036 with 10 MMT of annual production by 2030, 20 MMT of annual production by 2040, and 50 MMT of annual production by 2050. A growing number of studies are demonstrating more efficient and less expensive techniques to produce low-GHG electrolytic hydrogen; and, tax credits and market forces are expected to accelerate innovation and drive down costs even further over the next decade.  The combination of competitive pricing and widespread net-zero commitments throughout the utility and merchant electricity generation market is likely to drive future hydrogen co-firing applications to be low-GHG hydrogen. The EPA is therefore soliciting comment on whether low-GHG hydrogen needs to be defined as part of the BSER in this rulemaking.
Justification for Proposing 30 Percent Co-firing Low-GHG Hydrogen as the BSER
The EPA is proposing that co-firing 30 percent low-GHG hydrogen, as proposed to be defined above, by new combustion turbines in the relevant subcategories, by 2035, meets the requirements under CAA section 111(a)(1) to qualify as a component of the BSER. As discussed below, co-firing 30 percent low-GHG hydrogen is adequately demonstrated because it is feasible and well-demonstrated for new combustion turbines to co-fire that percentage of hydrogen, and the EPA reasonably expects that adequate quantities of low-GHG hydrogen will be available by 2035; it is of reasonable cost; it will achieve reductions because, when burned, hydrogen does not produce GHG emissions; and it will not have adverse non-air quality health or environmental impacts or energy requirements, including on the nationwide energy sector. It also creates market demand and advances the development of low GHG-hydrogen, a fuel that is useful for reducing emissions. The EPA includes in this section a more detailed justification for our definition of low-GHG hydrogen and an explanation for why the statutory considerations lead us to believe that requiring low-GHG hydrogen (as contrasted with any hydrogen) is a component of the "best" system of emission reduction. 
Adequately Demonstrated
As part of the present rulemaking, the EPA evaluated the ability of new combustion turbines to operate with certain percentages (by volume) of hydrogen blended into their fuel systems. This evaluation included an analysis of the technical challenges of co-firing hydrogen in a combustion turbine EGU to generate electricity. The EPA also evaluated available information to determine if adequate quantities of low-GHG hydrogen can be reasonably expected to be available for combustion turbine EGUs by 2035. 
Although industrial combustion turbines have been burning byproduct fuels containing large percentages of hydrogen for decades, utility combustion turbines have only recently begun to co-fire smaller amounts of hydrogen as a fuel to generate electricity. The primary technical challenges of hydrogen co-firing are related to certain physical characteristics of the gas. Hydrogen fuel produces a higher flame speed when combusted than the flame speed produced with the combustion of natural gas; and hydrogen typically combusts at a faster rate than natural gas. When the combustion speed is faster than the flow rate of the fuel, a phenomenon known as "flashback" can occur, which can lead to upstream complications. Hydrogen also has a higher flame temperature and a wider flammability range compared to natural gas. 
The industrial combustion turbines currently burning hydrogen are smaller than the larger utility combustion turbines and use diffusion flame combustion, often in combination with water injection, for NOX control. While water injection requires demineralized water and is generally only a NOX control option for simple cycle turbines, existing simple cycle combustion turbines have successfully demonstrated that relatively high levels of hydrogen can be co-fired in combustion turbines using diffusion flame and supports the EPA's proposal to determine that co-firing 30 percent hydrogen is technically feasible for new base load and intermediate load stationary combustion turbine EGUs by 2035.
The more commonly used NOX combustion control for base load combined cycle turbines is dry low NOX (DLN) combustion. Even though the ability to co-fire hydrogen in combustion turbines that are using DLN combustors to reduce emissions of NOX is currently more limited, all major combustion turbine manufacturers have developed DLN combustors for utility EGUs that can co-fire hydrogen. Moreover, the major combustion turbine manufacturers are designing combustion turbines that will be capable of combusting 100 percent hydrogen by 2030, with DLN designs that assure acceptable levels of NOX emissions.  Several developers have announced installations with plans to initially co-fire lower percentages of low-GHG hydrogen by volume before gradually increasing their co-firing percentages -- to as high as 100 percent in some cases -- depending on the pace of the anticipated expansion of low-GHG hydrogen production processes and associated infrastructure. The goals of equipment manufacturers and the fact that existing combined cycle combustion turbines have successfully demonstrated the ability to co-fire various percentages of hydrogen supports the EPA's proposal to determine that co-firing 30 percent hydrogen is technically feasible for new base load stationary combustion turbine EGUs by 2035.
The combustion characteristics of hydrogen can lead to localized higher temperatures during the combustion process. These "hotspots" can increase emissions of the criteria pollutant NOX. NOX emissions resulting from the combustion of high percentage by volume blends of hydrogen are also of concern in many regions of the country. For turbines using diffusion flame combustion, water injection is used to control emissions of NOX. The level of water injection can be varied for different levels of NOX control and adjustments can be made to address any potential increases in NOX that would occur from co-firing hydrogen in combustion turbines using diffusion flame combustion. As stated previously, all major combustion turbine manufacturers have developed DLN combustors for utility EGUs that can co-fire hydrogen, and are designing combustion turbines that will be capable of combusting 100 percent hydrogen by 2030, with DLN designs that assure acceptable levels of NOX emissions. Furthermore, while DLN combustion is able to achieve low levels of NOX, the majority of new intermediate load and base load combustion turbines using DLN combustion also use selective catalytic reduction (SCR) to reduce NOX emissions even further. The design level of control from SCR can be tied to the exhaust gas concentration. At higher levels of incoming NOX, either the reagent injection rate can be increased and/or the size of the catalyst bed can be increased. The EPA has concluded that any potential increases in NOX emissions do not change the Agency's view that on balance, co-firing 30 percent low-GHG hydrogen qualifies as a component of the BSER.
As noted above, at present, most of the hydrogen produced in the U.S. is produced for the industrial sector through SMR, which is a high GHG-emitting process. Limited quantities of hydrogen are currently being produced via SMR with CCS, which reduces some, but not all, of the associated GHG-emitting processes. Only small-scale facilities are currently producing hydrogen through electrolysis with renewable or nuclear energy, and as described below, much larger facilities are under development.
However, as also noted above, incentives in recent Federal legislation are anticipated to significantly increase the availability of low-GHG hydrogen by 2035, including for the utility power sector. The IIJA, enacted in 2021, allocated more than $9 billion to the DOE for research, development, and demonstration of low-GHG hydrogen technologies and the creation of at least four regional low-GHG hydrogen hubs. The DOE has indicated its intention to fund between six and 10 hubs. In addition, the IRA provided significant incentives to invest in low-GHG hydrogen production (For additional discussion of the IIJA and/or IRA, see section IV.E of this preamble.) 
Programs from the IIJA and IRA have been successful in inciting new low-GHG hydrogen projects and infrastructure. As of August 2022, 374 new projects had been announced that would produce 2.2 megatons (Mt) of low-GHG hydrogen, which represents a 21 percent increase over current output. Examples include:
 In June 2022, the DOE issued a $504.4 million loan guarantee to finance Advanced Clean Energy Storage (ACES), a low-GHG hydrogen production and long-term storage facility in Delta, Utah. The facility will use 220 MW of electrolyzers powered by renewable energy to produce low-GHG hydrogen. The hydrogen will be stored in salt caverns and serve as a long-term fuel supply for the combustion turbine at the Intermountain Power Authority (IPA) project, which is described earlier in this section.
 In January 2023, NextEra announced an 800-MW solar project in the central U.S. to support the development of low-GHG hydrogen as well as plans to produce its own low-GHG hydrogen at a facility in Arizona. Both projects will potentially receive funding from the IIJA. 
 In New York, Constellation (formerly Exelon Generation) is exploring the potential benefits of integrating onsite low-GHG hydrogen production, storage, and usage at its Nine Mile Point nuclear station. The project is funded by a DOE grant and includes partners such as Nel Hydrogen, Argonne National Laboratory, Idaho National Laboratory, and the National Renewable Energy Laboratory. The project is expected to generate an economical supply of low-GHG hydrogen that will be safely captured, stored, and potentially taken to market as a source of power for other purposes, including industrial applications such as transportation. 
 Bloom Energy began installation of a 240-kW electrolyzer at Xcel Energy's Prairie Island nuclear plant in Minnesota in September 2022 to produce low-GHG hydrogen. The demonstration project, designed to create "immediate and scalable pathways" for producing cost-effective hydrogen, is expected to be operational in 2024 and is also funded with a DOE grant.
 In California, Sempra subsidiary SoCalGas has announced plans to develop the nation's largest hydrogen infrastructure system called "Angeles Link." When operational, the project will provide enough hydrogen to convert up to four natural gas-fired power plants. Developers predict the increased access to hydrogen will also displace 3 million gallons of diesel fuel from heavy-duty trucks. 
 In December 2022, Air Products and AES announced plans to build a $4-billion low-GHG hydrogen production facility at the site of a former coal-fired power plant in Texas.  The plant is expected to be completed in 2027, and once operational, will produce approximately 200 metric tons of low-GHG hydrogen per day from electrolyzers powered by 1.4 GW of wind and solar energy, as noted earlier. This follows an announcement by Air Products in October 2022 to invest $500 million in a low-GHG hydrogen production facility in New York. This 35 metric-ton-per-day project is also expected to be operational by 2027, and in July 2022, received approval from the New York Power Authority for 94 MW of hydroelectric power. 
 The DOE National Clean Hydrogen Strategy and Roadmap identified a plausible path forward for the production of 10 MMT of low-GHG hydrogen annually by 2030, 20 MMT annually by 2040, and 50 MMT annually by 2050. 
 The H2@Scale is a DOE initiative that brings together stakeholders to advance affordable hydrogen production, transport, storage, and utilization to enable decarbonization and revenue opportunities across multiple sectors. 
 Publication of the Clean Hydrogen Production Standard, which establishes a quantitative non-regulatory standard for hydrogen projects, such as hub-funded projects, to meet via mitigating emissions across the supply chain as much as possible (e.g., high rates of carbon capture, low-carbon electricity, or upstream methane emissions mitigation).
These legislative actions, utility initiatives, and industrial sector production and infrastructure projects indicate that sufficient low-GHG hydrogen and sufficient distribution infrastructure can reasonably be expected to be available by 2035 so that, at a minimum, the majority of new combustion turbines could co-fire low-GHG hydrogen. The EPA specifically solicits comment on whether rural areas and small utility distribution systems (serving 50,000 customers or less) can expect to have access to low-GHG hydrogen or if infrastructure will be limited to areas with higher population densities. 
By 2035, substantial additional amounts of renewable energy are expected to be available, which can support the production of low-GHG hydrogen through electrolysis. For example, in the EPA's post-IRA 2022 reference case projections, non-hydroelectric utility-scale renewable capacity is projected to increase from 209 GW in 2021 to 668 GW by 2035 and then to 1,293 GW by 2050 (See section IV.F of this preamble for additional discussion of the EPA's post-IRA 2022 reference case).
Costs
There are three sets of potential costs associated with co-firing hydrogen in combustion turbines: (i) the capital costs of combustion turbines that have the capability of co-firing hydrogen; (ii) pipeline infrastructure to deliver hydrogen; and (iii) the fuel costs related to production of low-GHG hydrogen.
As stated previously, manufacturers are already developing combustion turbines that can co-fire up to approximately 30 to 50 percent hydrogen by volume. Accordingly, no additional costs arise from this aspect. The EPA is soliciting comment on additional costs required to co-fire between 30 to 50 percent hydrogen and if there are efficiency impacts from co-firing hydrogen.
With respect to pipeline infrastructure, there are approximately 1,600 miles of dedicated hydrogen pipelines currently operating in the U.S. and existing natural gas infrastructure can blend approximately 15 percent hydrogen with modest investments. Due to the lower energy density of hydrogen relative to natural gas, the piping required to deliver pure hydrogen would have to be larger, and the material used to construct the piping could need to be specifically designed to be able to handle higher concentrations of hydrogen that would prevent embrittlement and leaks. Existing steel natural gas pipelines and the welds are at an increased risk of embrittlement from higher percentage blends of hydrogen. The larger piping system could also require that the location of the combustion turbine be different than for a combustion turbine designed to burn 100 percent natural gas (e.g., could have to be elevated to accommodate the larger pipes). However, a new combustion turbine installation typically has to install new pipeline infrastructure as part of the project. These pipelines can be constructed from fiber reinforced polymer (FRP) to avoid concerns about embrittlement. The majority of announced combustion turbine EGU projects proposing to co-fire hydrogen are located close to the source of hydrogen. Therefore, the fuel delivery systems (i.e., pipes) for new combustion turbines can be designed to transport 30 percent hydrogen without additional costs. Therefore, the EPA proposes that co-firing rates of 30 percent by volume or less would have limited, if any, additional capital costs for new combustion turbine EGU projects. The EPA is soliciting comment on if additional infrastructure costs should be accounted for when determining the costs of hydrogen co-firing.
The primary cost for co-firing hydrogen is the cost of hydrogen relative to natural gas. The cost of delivered hydrogen depends on the technology used to produce the hydrogen and the cost to transport the hydrogen to the end user. For context, the DOE National Clean Hydrogen Strategy and Roadmap cites the current cost of low-GHG electrolytic hydrogen at approximately $5/kg. The DOE has projected a goal of reducing the cost of low-GHG hydrogen to $1/kg (equivalent to $7.4/MMBtu) by 2030, which is approximately the same as the current costs of hydrogen from SMR. Using $1/kg (equivalent to $7.4/MMBtu) as the delivered cost of low-GHG hydrogen, co-firing 30 percent hydrogen in a combined cycle EGU operating at a capacity factor of 65 percent would increase both the levelized cost of electricity (LCOE) and the variable operating costs by $2.9/MWh. This is a 6 percent increase from the baseline LCOE and an 11 percent increase from the baseline variable operating costs. This is equivalent to a CO2 abatement cost of $64/ton ($70/tonne) at the affected facility. For an aeroderivative simple cycle combustion turbine operating at a capacity factor of 40 percent, co-firing 30 percent hydrogen increases the LCOE and variable operating costs by $4.1/MWh, representing a 5 percent increase from the baseline LCOE and an 11 percent increase from the baseline variable operating costs. 
However, DOE's projected goal of $1/kg (equivalent to $7.4/MMBtu) for low-GHG hydrogen was established prior to the IIJA incentives and IRA tax subsidies for low-GHG hydrogen production, CCS, and generation from renewable sources. These subsidies could be equivalent to, or even exceed, the production costs of low-GHG hydrogen. Even when the cost to transport the hydrogen from the production facility to the end user is accounted for, the cost of low-GHG hydrogen to the end user could be less than $1/kg. Assuming a delivered price of $0.75/kg ($5.6/MMBtu), the CO2 abatement costs for co-firing hydrogen in a combined cycle and simple cycle EGU would be $32/ton ($35/tonne), respectively. If the delivered cost of low-GHG hydrogen is $0.50/kg ($3.7/MMBtu), this would represent cost parity with natural gas and abatement costs would be zero. 
The EPA is proposing to determine that the increase in operating costs from a BSER based on co-firing 30 percent low-GHG hydrogen is reasonable.
Non-air Quality Health and Environmental Impact and Energy Requirements
The non-air quality health and environmental impacts and energy requirements vary based on the technology that is used to produce the hydrogen. Multiple hydrogen production pathways use methane as a feedstock, including SMR, ATR, and pyrolysis. Methane extraction operations are known to contribute to air toxics including benzene, ethylbenzene, and n-hexane. Aside from methane pyrolysis and byproduct hydrogen, other hydrogen production methods consume water. Electrolysis and other technologies that break apart water to form hydrogen and oxygen consume the most water, 9 kg of water per 1 kg of hydrogen produced, which is twice the water requirements of SMR. The EPA does not consider the additional water demands to be unreasonable. Costs associated with water supply will be reflected in the cost of producing the low-GHG hydrogen, which, as noted above, is reasonable. If water-intensive hydrogen production methods are impractical in certain areas of the country where new affected combustion turbines are located, low-GHG hydrogen can be transported into those areas through pipelines.
The creation of hydrogen is an energy-intensive process. Moreover, inherent thermodynamic inefficiencies mean that more energy is needed to make a quantity of hydrogen for use in a combustion turbine than the amount of energy that would be consumed by a combustion turbine if it were to burn natural gas directly. In the case of pyrolysis and electrolysis, if that energy is supplied by renewable or nuclear power, adverse energy impacts could arise, under certain circumstances, if that energy could otherwise have displaced fossil fuel-fired electricity been deployed directly on the grid. The EPA does not consider these impacts will be unreasonable or unduly concerning for the grid in 2035. The EPA's post-IRA 2022 reference case projects 668 GW of new renewable generation by 2035. Given this influx, coupled with expected fossil fuel-fired EGU retirements, the carbon intensity of the grid would be correspondingly lower, mitigating concerns about energy-intense hydrogen production displacing clean energy from the grid. Moreover, incentives for low-GHG hydrogen will likely encourage more renewable development.
The EPA has also considered the impact of determining co-firing 30 percent low-GHG hydrogen as a component of the BSER on the energy sector. Because combustion turbines can be constructed to co-fire this amount of hydrogen in lieu of natural gas, this BSER would not have adverse impacts on the structure of the energy sector. 
Extent of Reductions in CO2 Emissions
The site-specific reduction in CO2 emissions achieved by a combustion turbine co-firing hydrogen is dependent on the volume of hydrogen blended into the fuel system. Due to the lower energy density by volume of hydrogen compared to natural gas, an affected source that combusts 30 percent by volume hydrogen with natural gas would achieve approximately a 12 percent reduction in CO2 emissions versus firing 100 percent natural gas. 
Promotion of the Development and Implementation of Technology
Determining co-firing 30 percent low-GHG hydrogen to be a component of the BSER would generally advance technology development in both the production of low-GHG hydrogen and the use of hydrogen in combustion turbines. This would facilitate co-firing larger amounts of low-GHG hydrogen and facilitate co-firing low-GHG hydrogen in existing combustion turbines. Developing new configurations for flame dimensions and turbine modifications to adjust for the characteristics unique to hydrogen combustion are technology forcing advancements that industry appears to be already leaning into based on the project announcements. Thus, co-firing 30 percent low-GHG hydrogen fulfills the requirements of BSER to generally advance technology development. In addition, co-firing 30 percent low-GHG hydrogen would promote co-firing additional amounts of low-GHG hydrogen. As discussed in the preceding section, there are over 18GW of projects initiated by industry to co-fire turbines with 30 percent hydrogen initially and progress to firing with 100 percent hydrogen. Fueling combustion turbines with 100 percent hydrogen would eliminate all carbon dioxide stack emissions. It would also promote reliability because it would and provide grid operators with asset options, in addition to battery and energy storage, capable of voltage support and frequency regulation. These are asset characteristics that will be required in increasing capacities as more intermittent generation is deployed.
Co-firing Low-GHG Hydrogen, Rather Than Any Hydrogen, Is the "Best" System of Emissions Reduction 
In this section, the EPA explains further why the type of hydrogen co-fired as a component of the BSER must be limited to low-GHG hydrogen, and not other types of hydrogen. The EPA explains further the proposed definition of low-GHG hydrogen as 0.45 kg CO2e/kg H2 or less from the production of hydrogen, from well-to-gate. Finally, the Agency summarizes the reasons, described above, for the proposal that co-firing 30 percent low-GHG hydrogen meets the criteria under CAA section 111 as the BSER. 
Limitation of Co-firing to Low-GHG Hydrogen 
Hydrogen is a zero-GHG emitting fuel when combusted, so that co-firing it in a combustion turbine in place of natural gas reduces GHG emissions at the stack. Co-firing low-emitting fuels  -  sometimes referred to as clean fuels  -  is well-recognized as an acceptable type of emissions control, including as a system of emission reduction under CAA section 111. In West Virginia v. EPA, the Supreme Court noted with approval a statement the EPA made in the Clean Power Plan that "fuel-switching" was one of the "more traditional air pollution control measures." 142 S. Ct. at 2611 (quoting 80 FR 64784; October 23, 2015). The EPA has relied on lower-emitting fuels as the BSER in several CAA section 111 rules. See 44 FR 33580, 33593 (June 11, 1979) (coal that undergoes washing prior to its combustion to remove sulfur, so that its combustion emits fewer SO2 emissions); 72 FR 32742 (June 13, 2007) (same); 2015 NSPS (natural gas and clean fuel oil). 
In the present proposal, the EPA recognizes that even though the combustion of hydrogen is zero-GHG emitting, its production entails a range of GHG emissions, from low to high, depending on the method. As noted above, the differences in GHG emissions from the different methods of hydrogen production are well recognized in the energy sector, and, in fact, hydrogen is generally characterized by its production method and the attendant level of GHG emissions.
Accordingly, the EPA is proposing to require that to qualify as the "best" system of emission reduction, the hydrogen that is co-fired must be low-GHG hydrogen, as defined above. This is because the purpose of CAA section 111 is to reduce pollution that endangers human health and welfare to the extent achievable, CAA section 111(b), through promulgation of standards of performance that reflect the "best system of emission reduction" that, taking into account certain factors, is adequately demonstrated. CAA section 111(a)(1). Co-firing hydrogen at a combustion turbine when that hydrogen is produced with large amounts of GHG emissions would yield the anomalous result of increasing overall GHG emissions, compared to combusting solely natural gas at the combustion turbine. Therefore, in evaluating a "system of emission reduction" of co-firing hydrogen, the GHG emissions from producing the hydrogen should be recognized to determine whether co-firing that hydrogen is the "best" system of emission reduction, within the meaning of CAA section 111(a)(1).
D.C. Circuit caselaw supports applying the term "best" in this manner. In several cases decided under CAA section 111(a)(1) as enacted by the 1970 CAA Amendments, which did not provide that the EPA must consider non-air quality health and environmental impacts in determining the BSER, the court stated that the EPA must consider whether byproducts of pollution control equipment could cause environmental damage in determining whether the pollution control equipment qualified as the best system of emission reduction. See Portland Cement v. Ruckelshaus, 465 F.2d 375, 385 n.42 (D.C. Cir. 1973), cert. denied, 417 U.S. 921 (1974) (stating that "[t]he standard of the `best system' is comprehensive, and we cannot imagine that Congress intended that "best" could apply to a system which did more damage to water than it prevented to air"); Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427, 439 (D.C. Cir. 1973) (remanding because the EPA failed to consider "the significant land or water pollution potential" from byproducts of air pollution control equipment). The situation here is analogous because a standard that allowed for co-firing with other hydrogen would create more damage than it prevented, the precise problem CAA section 111 is intended to address. Considering the overall emissions impact of the production of fuel used by the affected facility to lower its emissions -- here, hydrogen -- is consistent with considering the environmental impacts of the byproducts of pollution control technology used by the affected facility to lower its emissions.
In addition, the EPA's proposed determination that co-firing low-GHG hydrogen qualifies as the BSER is supported by the IRA and its legislative history. In the IRA, Congress enacted or expanded tax credits to encourage the production and use of low-GHG hydrogen. In addition, as discussed in section IV.E.1 of this preamble, IRA section 60107 added new CAA section 135, LEEP. This provision provides $1 million for the EPA to assess the GHG emissions reductions from changes in domestic electricity generation and use anticipated to occur annually through fiscal year 2031; and further provides $18 million for the EPA to promulgate additional CAA rules to ensure GHG emissions reductions that go beyond the reductions expected in that assessment. CAA section 135(a)(5)-(6). The legislative history of this provision makes clear that Congress anticipated that the EPA could promulgate rules under CAA section 111(b) to ensure GHG emissions reductions from fossil fuel-fired electricity generation. 168 Cong. Rec. E879 (August 26, 2022) (statement of Rep. Frank Pallone, Jr.). The legislative history goes on to state that "Congress anticipates that EPA may consider ... clean hydrogen as [a] candidate[] for BSER for electric generating plants...." Id.
Most broadly, proposing that only low-GHG hydrogen qualifies as part of the co-firing BSER is required by the "reasoned decisionmaking" that the Supreme Court has long held, including recently in Michigan v. EPA 576 U.S. 743 (2015), that "[f]ederal administrative agencies are required to engage in." Id. at 751 (internal quotation marks omitted and citation omitted). In Michigan, the Court held that CAA section 112(n)(1)(A), which directs the EPA to regulate hazardous air pollutants from coal-fired power plants if the EPA "finds such regulation is appropriate and necessary," must be interpreted to require the EPA to consider the costs of the regulation. The Court explained that if the EPA failed to consider cost, it could promulgate a regulation to eliminate power plant emissions harmful to human health, but do so through the use of technologies that "do even more damage to human health" than the emissions they eliminate. Id. at 752. The Court emphasized, "No regulation is `appropriate' if it does significantly more harm than good." Id. Here, as explained above, permitting EGUs to burn high-GHG hydrogen would "do even more damage to human health" than the emissions eliminated and therefore could not be considered "reasoned decisionmaking." Id. at 751. Likewise, the Supreme Court has long said that an agency engaged in reasoned decisionmaking may not ignore "an important aspect of the problem." Motor Vehicles Mfrs. Ass'n v. State Farm Auto Ins. Co., 463 U.S. 29, 43 (1983). Permitting EGUs to burn high-GHG hydrogen to meet the emissions standard here would ignore an important aspect of the problem being addressed, contrary to reasoned decisionmaking.
 (2) Definition of Low-GHG Hydrogen
As noted in section of VII.F.3.c.vi. of this preamble, the EPA proposes a definition for low-GHG hydrogen that aligns with the highest of the four tiers of tax credit available for hydrogen production, IRC section 45V(b)(2)(D). Under this provision, taxpayers are eligible for a tax credit of $3 per kilogram of hydrogen that is produced with a GHG emissions rate of 0.45 kg CO2e/kg H2 or less, from well-to-gate. This amount is three times higher than the amount for the next tier of credit, which is for hydrogen produced with a GHG emissions rate between 1.5 and 0.45 kg CO2e/kg H2, from well-to-gate, IRC section 45V(b)(2)(C); and four and five times higher than the amount for the next two tiers of credit, respectively. IRC section 45V(b)(2)(B), (A). With these provisions, Congress indicated its judgement as to what constitutes the lowest-GHG hydrogen production, and its intention to incentivize production of that type of hydrogen. Congress's views inform the EPA's proposal to define low-GHG hydrogen for purposes the BSER for this CAA section 111 rulemaking consistent with IRC section 45V(b)(2)(D).
It should be noted that the EPA is not proposing that the "clean hydrogen" definition in section 822 of the IIJA is appropriate for the EPA's regulatory purposes. This definition is designed for a non-regulatory purpose. It sets out a non-binding goal, not a standard or a regulatory definition, intended for use in development of the DOE's CHPS and funding programs to promote promising new hydrogen technologies. It could include hydrogen produced with much higher overall GHG emissions than low-GHG hydrogen, the production of which qualifies for the IRC section 45V(b)(2)(D) tax credit. 
For the reasons discussed above, co-firing 30 percent low-GHG hydrogen qualifies as the BSER because it is adequately demonstrated, is of reasonable cost, does not have adverse non-air quality health or environmental impacts or energy requirements -- in fact, it offers potential benefits to the energy sector -- and reduces GHG emissions. The fact that this control promotes the advancement of low-GHG production and deployment provides additional, although not essential, support for proposing it as part of the BSER. Finally, Congress's direction to choose the "best" system of emissions reduction and principles of reasoned decision-making dictate that the standard should be based on burning low-GHG hydrogen, and not other hydrogen.
Other Options for BSER
The EPA considered several other systems of emission reduction as candidates for the BSER for combustion turbines, but is not proposing them as the BSER. They include CHP and the hybrid power plant, as discussed below.
Combined Heat and Power (CHP)
CHP, also known as cogeneration, is the simultaneous production of electricity and/or mechanical energy and useful thermal output from a single fuel. CHP requires less fuel to produce a given energy output, and because less fuel is burned to produce each unit of energy output, CHP has lower emission rates and can be more economic than separate electric and thermal generation. However, a critical requirement for a CHP facility is that it primarily generates thermal output and generates electricity as a byproduct and must therefore be physically close to a thermal host that can consistently accept the useful thermal output. It can be particularly difficult to locate a thermal host with sufficiently large thermal demands such that the useful thermal output would impact the emissions rate. The refining, chemical manufacturing, pulp and paper, food processing, and district energy systems tend to have large thermal demands. However, the thermal demand at these facilities is generally only sufficient to support a smaller EGU, approximately a maximum of several hundred MW. This would limit the geographically available locations where new generation could be constructed in addition to limiting its size. Furthermore, even if a sufficiently large thermal host were in close proximity, the owner/operator of the EGU would be required to rely on the continued operation of the thermal host for the life of the EGU. If the thermal host were to shut down, the EGU could be unable to comply with the emissions standard. This reality would likely result in difficulty in securing funding for the construction of the EGU and could also lead the thermal host to demand discount pricing for the delivered useful thermal output. For these reasons, the EPA is not proposing CHP as the BSER. 
Hybrid Power Plant
Hybrid power plants combine two or more forms of energy input into a single facility with an integrated mix of complementary generation methods. While there are multiple types of hybrid power plants, the most relevant type for this proposal is the integration of solar energy (e.g., concentrating solar thermal) with a fossil fuel-fired EGU. Both coal-fired and NGCC EGUs have operated using the integration of concentrating solar thermal energy for use in boiler feed water heating, preheating makeup water, and/or producing steam for use in the steam turbine or to power the boiler feed pumps. 
One of the benefits of integrating solar thermal with a fossil fuel-fired EGU is the lower capital and operation and maintenance (O&M) costs of the solar thermal technology. This is due to the ability to use equipment (e.g., HRSG, steam turbine, condenser, etc.) already included at the fossil fuel-fired EGU. Another advantage is the improved electrical generation efficiency of the non-emitting generation. For example, solar thermal often produces steam at relatively low temperatures and pressures, and the conversion of the thermal energy in the steam to electricity is relatively low. In a hybrid power plant, the lower quality steam is heated to higher temperatures and pressures in the boiler (or HSRG) prior to expansion in the steam turbine, where it produces electricity. Upgrading the relatively low-grade steam produced by the solar thermal facility in the boiler improves the relative conversion efficiencies of the solar thermal to electricity process. The primary incremental costs of the non-emitting generation in a hybrid power plant are the costs of the mirrors, additional piping, and a steam turbine that is 10 to 20 percent larger than that in a comparable fossil-only EGU to accommodate the additional steam load during sunny hours. A drawback of integrating solar thermal is that the larger steam turbine will operate at part loads and reduced efficiency when no steam is provided from the solar thermal panels during periods when the sun is not shining (i.e., the night and cloudy weather). This limits the amount of solar thermal that can be integrated into the steam cycle at a fossil fuel-fired EGU. 
In the 2018 Annual Energy Outlook, the levelized cost of concentrated solar power (CSP) without transmission costs or tax credits is $161/MWh. Integrating solar thermal into a fossil fuel-fired EGU reduces the capital cost and O&M expenses of the CSP portion by 25 and 67 percent compared to a stand-alone CSP EGU respectively. This results in an effective LCOE for the integrated CSP of $104/MWh. Assuming the integrated CSP is sized to provide 10 percent of the maximum steam turbine output and the relative capacity factors of a NGCC and the CSP (those capacity factors are 65 and 25 percent, respectively) the overall annual generation due to the concentrating solar thermal would be 3 percent of the hybrid EGU output. This would result in a three percent reduction in the overall CO2 emissions and a one percent increase in the LCOE, without accounting for any reduction in the steam turbine efficiency. However, these costs do not account for potential reductions in the steam turbine efficiency due to being oversized relative to a non-hybrid EGU. A 2011 technical report by the National Renewable Energy Laboratory (NREL) cited analyses indicating solar-augmentation of fossil power stations is not cost-effective, although likely less expensive and containing less project risk than a stand-alone solar plant. Similarly, while commenters stated that solar augmentation has been successfully integrated at coal-fired plants to improve overall unit efficiency, commenters did not provide any new information on costs or indicate that such augmentation is cost-effective.
In addition, solar thermal facilities require locations with abundant sunshine and significant land area in order to collect the thermal energy. Existing concentrated solar power projects in the U.S. are primarily located in California, Arizona, and Nevada with smaller projects in Florida, Hawaii, Utah, and Colorado. NREL's 2011 technical report on the solar-augment potential of fossil-fired power plants examined regions of the U.S. with "good solar resource as defined by their direct normal insolation (DNI)" and identified sixteen states as meeting that criterion: Alabama, Arizona, California, Colorado, Florida, Georgia, Louisiana, Mississippi, Nevada, New Mexico, North Carolina, Oklahoma, South Carolina, Tennessee, Texas, and Utah. The technical report explained that annual average DNI has a significant effect on the performance of a solar-augmented fossil plant, with higher average DNI translating into the ability of a hybrid power plant to produce more steam for augmenting the plant. The technical report used a points-based system and assigned the most points for high solar resource values. An examination of a NREL-generated DNI map of the U.S. reveals that states with the highest DNI values are located in the southwestern U.S., with only portions of Arizona, California, Nevada, New Mexico, and Texas (plus Hawaii) having solar resources that would have been assigned the highest points by the NREL technical report (7 kWh/m2/day or greater). 
The EPA is not proposing hybrid power plants as the BSER because of the limited amount of emission reductions, on a nationwide basis, that the technology offers. Gaps in the EPA's knowledge about costs, and concerns about the cost-effectiveness of the technology, as noted above, also point away from proposing the technology as the BSER. 
Proposed Standards of Performance 
Once the EPA has determined that a particular system or technology represents BSER, the CAA authorizes the Administrator to establish standards of performance for new units that reflect the degree of emission limitation achievable through the application of that BSER. As noted above, the EPA proposes that because the technology for reducing GHG emissions from combustion turbines is advancing rapidly, a two-phase set of standards of performance, which reflect a two-component BSER, is appropriate for base load and intermediate load combustion turbines. Under this approach, for the first phase of the standards, which applies as of the effective date the final rule, the BSER is highly efficient generation for both base load and intermediate load combustion turbines. During this phase, owners/operators of EGUs will be subject to a numeric emissions standard that is representative of the performance of the best performing EGUs in the subcategory. For the second phase of the standards, beginning in 2035, the BSER for base load turbines includes either 90 percent capture CCS or 30 percent low-GHG hydrogen co-firing, and the BSER for intermediate load EGUs includes 30 percent low-GHG hydrogen co-firing. The affected EGUs would be subject to either an emissions rate that reflects continued use of highly efficient generation coupled with CCS, or one that reflects continued use of highly efficient generation coupled with co-firing low-GHG hydrogen. In addition, the EPA is proposing a single component BSER, applicable from the date of proposal, for low load combustion turbines. 
Phase-1 Standards
The first component of the BSER is the use of highly efficient combined cycle technology for base load EGUs in combination with the best operating and maintenance practices, the use of highly efficient simple cycle technology in combination with the best operating and maintenance practices for intermediate load EGUs, and the use of clean fuels for low load EGUs. 
For new and reconstructed natural gas-fired base load combustion turbine EGUs, the EPA proposes to find that the most efficient available combined cycle technology -- which qualifies as the BSER for base load combustion turbines -- supports a standard of 770 lb CO2/MWh-gross for large natural gas-fired EGUs (i.e., those with a nameplate heat input greater than 2,000 MMBtu/h) and 900 lb CO2/MWh-gross for natural gas-fired small EGUs (i.e., those with a nameplate base load rating of 250 MMBtu/h). The proposed emissions standard for natural gas-fired base load EGUs with base load ratings between 250 MMBtu/h and 2,000 MMBtu/h would be between 900 and 770 lb CO2/MWh-gross and be determined based on the base load rating of the combustion turbine. The EPA proposes to find that the most efficient available simple cycle technology -- which qualifies as the BSER for intermediate load combustion turbines -- supports a standard of 1,150 lb CO2/MWh-gross for natural gas-fired EGUs. For new and reconstructed low load combustion turbines, the EPA proposes to find that the use of clean fuels -- which qualifies as the BSER -- supports a standard that ranges from 120 lb CO2/MMBtu to 160 lb CO2/MMBtu depending on the fuel burned. The EPA proposes these standards to apply at all times and compliance to be determined on a 12-operating-month rolling average basis. 
The EPA has determined that these emission standards are achievable specifically for natural gas-fired base load and intermediate load combustion turbine EGUs. However, combustion turbine EGUs burn a variety of fuels, including fuel oil during natural gas curtailments. Owners/operators of combustion turbines burning fuels other than natural gas would not necessarily be able to comply with the proposed standards for base load and intermediate load natural gas-fired combustion turbines using highly efficient generation. Therefore, the Agency is proposing that owners/operators of combustion turbines burning fuels other than natural gas may elect to use the ratio of the heat input-based emissions rate of the specific fuel(s) burned to the heat input-based emissions rate of natural gas to determine a site-specific emissions standard for the operating period. For example, the NSPS emissions rate for a large base load combustion turbine burning 100 percent distillate oil during the 12-operaitng month period would be 1,070 lb CO2/MWh-gross.
To determine what emission rates are currently achieved by existing high-efficiency combined cycle EGUs and simple cycle EGUs, the EPA reviewed 12-operating-month generation and CO2 emissions data from 2015 through 2021 for all combined and simple cycle EGUs that submitted continuous emissions monitoring system (CEMS) data to the EPA's emissions collection and monitoring plan system (ECMPS). The data were sorted by the lowest maximum 12-operating-month emissions rate for each unit to identify long-term emission rates on a lb CO2/MWh-gross basis that have been demonstrated by the existing combined cycle and simple cycle EGU fleets. Since an NSPS is a never-to-exceed standard, the EPA is proposing that use of long-term data are more appropriate than shorter term data in determining an achievable standard. These long-term averages account for degradation and variable operating conditions, and the EGUs should be able to maintain their current emission rates, as long as the units are properly maintained. While annual emission rates indicate a particular standard is achievable for certain EGUs in the short term, they are not necessarily representative of emission rates that can be maintained over an extended period using highly efficient generating technology in combination with best operating and maintenance practices. 
To determine the 12-operating-month average emissions rate that is achievable by application of the BSER, the EPA calculated 12-month CO2 emission rates by dividing the sum of the CO2 emissions by the sum of the gross electrical energy output over the same period. The EPA did this separately for combined cycle EGUs and simple cycle EGUs to determine the emissions rate for the base load and intermediate load subcategories, respectively.
For base load combustion turbines, the EPA evaluated three emission rates: 730, 770, and 800 lb CO2/MWh-gross. An emissions rate of 730 lb CO2/MWh-gross has been demonstrated by a single combined cycle facility -- the Okeechobee Clean Energy Center. This facility is a large 3-on-1 combined cycle EGU that commenced operation in 2019 and uses a recirculating cooling tower for the steam cycle. Each turbine is rated at 380 MW and the three HRSGs feed a single steam turbine of 550 MW. The EPA is not proposing to use the emissions rate of this EGU to determine the standard of performance, for multiple reasons. The Okeechobee Clean Energy Center uses a 3-on-1 multi-shaft configuration but, many combined cycle EGUs use a 1-on-1 configuration. Combined cycle EGUs using a 1-on-1 configuration can be designed such that both the combustion turbine and steam turbine are arranged on one shaft and drive the same generator. This configuration has potential capital cost and maintenance costs savings and a smaller plant footprint that can be particularly important for combustion turbines enclosed in a building. In addition, a single shaft configuration has higher net efficiencies when operated at part load than a multi-shaft configuration. Basing the emissions standard on the performance of multi-shaft combined cycle EGUs could limit the ability of owners/operators to construct new combined cycle EGUs in space-constrained areas (typically urban areas) and combined cycle EGUs with the best performance when operated as intermediate load EGUs. Either of these outcomes could result in greater overall emissions from the power sector. An advantage of multi-shaft (2-on-1 and 3-on-1) configurations is that the turbine engine can be installed initially and run as a simple cycle EGU, with the HRSG and steam turbines added at a later date, all of which allows for more flexibility for the regulated community. In addition, a single large steam turbine can generate electricity more efficiently than multiple smaller steam turbines, increasing the overall efficiency of comparably sized combined cycle EGUs. According to Gas Turbine World 2021, multi-shaft combined cycle EGUs have design efficiencies that are 0.7 percent higher than single shaft combined cycle EGUs using the same turbine engine.
The efficiency of the Rankine cycle (i.e., HRSG plus the steam turbine) is determined in part by the ability to cool the working fluid (e.g., steam) after it has been expanded through the turbine. All else equal, the lower the temperature that can be achieved, the more efficient the Rankine cycle. The Okeechobee Clean Energy Center used a recirculating cooling system, which can achieve lower temperatures than EGUs using dry cooling systems and therefore would be more efficient and have a lower emissions rate. However dry cooling systems have lower water requirements and therefore could be the preferred technology in arid regions or in areas where water requirements could have significant ecological impacts. Therefore, the EPA proposes that the efficient generation standard for base load EGUs should account for the use of dry cooling. 
Finally, the Okeechobee Clean Energy Center is a relatively new EGU and full efficiency degradation might not be accounted for in the emissions analysis. Therefore, the EPA is not proposing that an emissions rate of 730 lb CO2/MWh-gross is an appropriate nationwide standard. However, the EPA is soliciting comment on whether the use of alternate working fluid, such as supercritical CO2, or other potential efficiency improvements would make this emissions rate an appropriate emissions standard for base load combustion turbines.
An emissions rate of 770 lb CO2/MWh-gross has been demonstrated by 14 percent of recently constructed combined cycle EGUs. These turbines include combined cycle EGUs using 1-on-1 configurations and dry cooling, are manufactured by multiple companies, and have long-term emissions data that fully account for potential degradation in efficiency. One of the best performing large combined cycle EGUs that has maintained an emissions rate of 770 lb CO2/MWh-gross is the Dresden plant, located in Ohio. This 2-on-1 combined cycle facility, uses a recirculating cooling tower, and has maintained an emissions rate of 765 lb CO2/MWh-gross, measured over 12 operating months with 99 percent confidence. The turbine engines are rated at 2,250 MMBtu/h, which demonstrates that the standard of 770 lb CO2/MWh-gross is achievable at a heat input rating of 2,000 MMBtu/h. In addition, while a 2-on-1 configuration and a cooling tower are more efficient than a 1-on-1 configuration and dry cooling, the Dresden Energy Facility does not use the most efficient combined cycle design currently available. Multiple more efficient designs have been developed since the Dresden Energy Facility commenced operation a decade ago that more than offset these efficiency losses. Therefore, the EPA proposes that while the Dresden combined cycle EGUs uses a 2-on-1 configuration with a cooling tower, it demonstrates that an emissions rate of 770 lb CO2/MWh-gross is achievable for all new large combined cycle EGUs. For additional information on the EPA analysis of emission rates for high efficiency base load combined cycle EGUs, see the TSD titled Efficient Generation at Combustion Turbine Electric Generating Units, which is available in the rulemaking docket. 
The EPA is not proposing an emissions rate of 800 lb CO2/MWh-gross because it does not represent the most efficient combined cycle EGUs designs. Nearly half of recently constructed combined cycle EGUs have maintained an emissions rate of 800 lb CO2/MWh-gross. However, the EPA is soliciting comment on whether this higher emissions rate is appropriate on grounds that it would increase flexibility and reduce costs to the regulated community by allowing more available designs to operate as base load combustion turbines. 
With respect to small combined cycle combustion turbines, the best performing unit is the Holland Energy Park facility in Holland, Michigan, which commenced operation in 2017 and uses a 2-on-1 configuration and a cooling tower. The 50 MW turbine engines have individual heat input ratings of 590 MMBtu/h and serve a single 45 MW steam turbine. The facility has maintained a 12-operating month, 99 percent confidence emissions rate of 870 lb CO2/MWh-gross. This long-term data accounts for degradation and variable operating conditions and demonstrates that a base load combustion turbine EGU with a turbine rated at 250 MMBtu/h should be able to maintain an emissions rate of 900 lb CO2/MWh-gross. In addition, there is a commercially available HRSG that uses supercritical CO2 instead of steam as the working fluid. This HRSG would be significantly more efficient than the HRSG that uses dual pressure steam, which is common for small combined cycle EGUs. When these efficiency improvements are accounted for, a new small natural gas-fired combined cycle EGU would be able to maintain an emissions rate of 850 lb CO2/MWh-gross. Therefore, the Agency is soliciting comment on whether the small natural gas-fired base load combustion turbine emissions standard should be 850 lb CO2/MWh-gross.
In summary, the Agency solicits comment on the following range of potential standards of performance: 
 New and reconstructed natural gas-fired base load combustion turbines with a heat input rating that is greater than 2,000 MMBtu/h: a range of 730 - 800 lb CO2/MWh-gross;
 New and reconstructed natural gas-fired base load combustion turbines with a heat input rating of 250 MMBtu/h: a range of 850 to 900 lb CO2/MWh-gross. 
For intermediate load combustion turbines, the EPA evaluated the performance of recently constructed high efficiency natural gas-fired simple cycle EGUs. The EPA evaluated three emission rates for the intermediate load emissions standard: 1,200, 1,150, and 1,100 lb CO2/MWh-gross. Sixty two percent of recently constructed intermediate load simple cycle EGUs have maintained an emissions rate of 1,200 lb CO2/MWh-gross, 17 percent have maintained an emissions rate of 1,150 lb CO2/MWh-gross, and 6 percent have maintained an emissions rate of 1,100 lb CO2/MWh-gross. However, the units that have maintained an emissions rate of 1,100 lb CO2/MWh-gross generally have a single large aeroderivative combustion turbine design. In contrast, the ones that have maintained an emission rate of 1,150 lb CO2/MWh-gross have multiple different designs, including an industrial frame combustion turbine design, and are made by multiple manufacturers. Therefore, the EPA is proposing an intermediate load emissions standard of 1,150 lb CO2/MWh-gross. The Agency is soliciting comment on whether the standard should be 1,100 lb CO2/MWh-gross, or whether that would result in unacceptably high costs because currently only a single design for a large aeroderivative simple cycle turbine would be able to meet this standard. The Agency is also soliciting comment on a standard of performance of 1,200 lb CO2/MWh-gross. While this would achieve fewer GHG reductions, it would increase flexibility, and potentially reduce costs, to the regulated community by allowing the currently available designs to operate as intermediate load combustion turbines. For additional information on the EPA analysis of emission rates for high efficiency intermediate load simple cycle EGUs, see the TSD Efficient Generation at Combustion Turbine Electric Generating Units, which is available in the rulemaking docket
      The EPA is also soliciting comment on whether the use of steam injection is applicable to intermediate load combustion turbines. Steam injection is the use of a relatively low cost HRSG to produce steam that is injected into the combustion chamber of the combustion turbine engine instead of using a separate steam turbine. Advantages of steam injection include improved efficiency and increases the output of the combustion turbine as well as reducing NOX emissions. Combustion turbines using steam injection have characteristics in-between simple cycle and combined cycle combustion turbines. They are more efficient, but more complex and have higher capital costs than simple cycle combustion turbines without steam injection. Combustion turbines using steam injection are simpler and have lower capital costs than combined EGUs but have lower efficiencies. The EPA is aware of a single combustion turbine that is using steam injection that has maintained a 12-operaitng month emission rates of less than 1,000 lb CO2/MWh-gross. The EPA requests that commenters include information on whether this technology would be applicable to intermediate load combustion turbines along with cost information.
Phase-2 Standards
The use of CCS and hydrogen co-firing are both approaches developers are considering to reduce GHG emissions beyond highly efficient generation. However, as noted above, these approaches apply to different subcategories and are not applicable to the same EGUs. The proposed phase-2 standards are in table 3.
                  Table 3 -- Phase-2 Standards of Performance
Subcategory
BSER
Standard of Performance
Low load 
Clean Fuels
120 - 160 lb CO2/MMBtu
Intermediate load
Highly efficient simple cycle technology coupled with co-firing 30 percent low-GHG hydrogen
1,000 lb CO2/MWh-gross
Base load, not combusting at least 10 percent hydrogen
Highly efficient combined cycle technology coupled with 90 percent CCS
90 lb CO2/MWh-gross
Base load, combusting at least 10 percent hydrogen
Highly efficient combined cycle technology coupled with co-firing 30 percent low-GHG hydrogen 
680 lb CO2/MWh-gross
Co-firing 30 percent by volume low-GHG hydrogen reduces emissions by 12 percent. The EPA applied this percent reduction to the emission rates for the intermediate load and base load, combusting at least 10 percent hydrogen subcategories, to determine the phase-1 standards. For the base load combustion turbines not combusting at least 10 percent hydrogen subcategory, the EPA reduced the emissions rate by 89 percent to determine the phase-1 standards. The CCS percent reduction is based on a CCS system capturing 90 percent of the emitting CO2 being operational anytime the combustion turbine is operating. However, if the carbon capture equipment has lower availability/reliability than the combustion turbine or the CCS equipment takes longer to startup than the combustion turbine itself there would be periods of operation where the CO2 emissions would not be controlled by the carbon capture equipment. The EPA is soliciting comment on the expected availability and startup time of carbon capture equipment and if those should be accounted for in the CCS-based numeric standard of performance. 
The emission standards for the intermediate and base load combustion turbines would also be adjusted based on the uncontrolled emission rates of the fuels relative to natural gas. For 100 percent distillate oil-fired combustion turbines, the emission rates would be 1,300 lb CO2/MWh-gross, 120 lb CO2/MWh-gross, and 910 lb CO2/MWh-gross for the intermediate load, non low-GHG hydrogen co-firing base load, and low-GHG hydrogen co-firing base load subcategories respectively.
Reconstructed Stationary Combustion Turbines
In the previous sections, the EPA explained the background of and requirements for new and reconstructed stationary combustion turbines and evaluated various control technology configurations to determine the BSER. Because the BSER is the same for new and reconstructed stationary combustion turbines, the Agency is proposing to use the same emissions analysis for both new and reconstructed stationary combustion turbines. For each of the subcategories, the EPA is proposing that the proposed BSER results in the same standard of performance for new stationary combustion turbines and reconstructed stationary combustion turbines. Since reconstructed turbines could likely incorporate technologies to co-fire hydrogen as part of the reconstruction process at little or no cost, the low-GHG hydrogen co-firing would likely to be similar to those for newly constructed combustion turbines. For CCS, the EPA approximated the cost to add CCS to a reconstructed combustion turbine by increasing the capital costs of the carbon capture equipment by 10 percent relative to the costs for a newly constructed combustion turbine. This increases the capital cost from $949/kW to $1,044/kW. Using a 12-year amortization period, the a 90 percent-capture amine-based post combustion CCS system increases the LCOE by $8.5/MWh and has an overall CO2 abatement costs of $25/ton ($28/tonne).
A reconstructed stationary combustion turbine is not required to meet the standards if doing so is deemed to be "technologically and economically" infeasible. This provision requires a case-by-case reconstruction determination in the light of considerations of economic and technological feasibility. However, this case-by-case determination would consider the identified BSER, as well as technologies the EPA considered, but rejected, as BSER for a nationwide rule. One or more of these technologies could be technically feasible and of reasonable cost, depending on site-specific considerations and if so, would likely result in sufficient GHG reductions to comply with the applicable reconstructed standards. Finally, in some cases, equipment upgrades and best operating practices would result in sufficient reductions to achieve the reconstructed standards.
Modified Stationary Combustion Turbines
CAA section 111(a)(4) defines a "modification" as "any physical change in, or change in the method of operation of, a stationary source" that either "increases the amount of any air pollutant emitted by such source or ... results in the emission of any air pollutant not previously emitted." Certain types of physical or operational changes are exempt from consideration as a modification. Those are described in 40 CFR 60.2, 60.14(e). 
In the 2015 NSPS, the EPA did not finalize standards of performance for stationary combustion turbines that conduct modifications; instead, the EPA concluded that it was prudent to delay issuing standards until the Agency could gather more information (80 FR 64515; October 23, 2015). There were two several reasons for this determination: few sources had undertaken NSPS modifications in the past, the EPA had little information concerning them, and available information indicated that very few existing combustion turbines would undertake NSPS modifications in the future; and since the Agency eliminated proposed subcategories for small EGUs in the 2015 NSPS, questions were raised as to whether smaller existing combustion turbines that undertake a modification could meet the final performance standard of 1,000 lb CO2/MWh-gross.
It continues to be the case that the EPA is aware of no evidence indicating that combustion turbines may undertake actions that could qualify as NSPS modifications in the future. Combustion turbines have unique characteristics that make determining an appropriate emission standard for modified sources a challenging task. For example, each combustion turbine engine has a specific corresponding combustor. The development of more efficient combustor upgrades for existing turbine designs typically requires manufacturers to expend considerable resources. Consequently, not all manufacturers offer combustor upgrades for smaller or older designs because it would be difficult to recoup their investment. 
In addition, natural gas has the lowest CO2 emission rate (in terms of CO2/MMBtu) of any fossil fuel. As a result, an owner or operator that adds the ability to burn a backup fuel, such as distillate oil, to an existing turbine would likely trigger an NSPS modification. This is a relatively low-capital cost upgrade that would significantly increase a unit's potential hourly emission rate, even though the annual emissions increase would be relatively minor because operating permits generally limit the amount of distillate oil that a unit can burn. The EPA needs to conduct additional analysis to determine an appropriate emission standard for units that undertake this type of modification, which does not involve any of the combustion turbine components that impact efficiency.
To be clear, the EPA is not proposing a decision that modifications should be subject to different requirements than those being proposed for new and reconstructed sources. The EPA plans to continue to gather information, consider the options for modifications, and may develop a new proposal for modifications in the future. Therefore, the EPA is not proposing a standard of performance for combustion turbines that conduct modifications.
Startup, Shutdown, and Malfunction
In its 2008 decision in Sierra Club v. EPA, 551 F.3d 1019 (D.C. Cir. 2008), the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) vacated portions of two provisions in the EPA's CAA section 112 regulations governing the emissions of HAP during periods of SSM. Specifically, the court vacated the SSM exemption contained in 40 CFR 63.6(f)(1) and 40 CFR 63.6(h)(1), holding that, the SSM exemption violates the requirement under section 302(k) of the CAA that some CAA section 112 standard apply continuously. Consistent with Sierra Club v. EPA, the EPA is proposing standards in this rule that apply at all times. The NSPS general provisions in 40 CFR 60.11(c) currently exclude opacity requirements during periods of startup, shutdown, and malfunction and the provision in 40 CFR 60.8(c) contains an exemption from non-opacity standards. These general provision requirements would automatically apply to the standards set in an NSPS , unless the regulation specifically overrides these general provisions. The NSPS subpart TTTT (40 CFR part 60 subpart TTTT), does not contain an opacity standard, thus, the requirements at 40 CFR 60.11(c) are not applicable. The NSPS subpart TTTT also overrides 40 CFR 60.8(c) in table 3 and requires that sources comply with the standard(s) at all times. In reviewing NSPS subpart TTTT and proposing the new NSPS subpart TTTTa, the EPA is proposing to retain in subpart TTTTa the requirements that sources comply with the standard(s) at all times. Therefore, the EPA is proposing in table 3 of the new subpart TTTTa to override the general provisions for SSM provisions. The EPA is proposing that all standards in subpart TTTTa apply at all times.
The EPA has attempted to ensure that the general provisions we are proposing to override are inappropriate, unnecessary, or redundant in the absence of the SSM exemption. The EPA is specifically seeking comment on whether we have successfully done so.
In proposing the standards in this rule, the EPA has taken into account startup and shutdown periods and, for the reasons explained in this section of the preamble, has not proposed alternate standards for those periods. The EPA analysis of achievable emission standards used CEMS data that includes all period of operation. Since periods of startup, shutdown, and malfunction were not excluded from the analysis, the EPA is not proposing alternate standard for those periods of operation.
Periods of startup, normal operations, and shutdown are all predictable and routine aspects of a source's operations. Malfunctions, in contrast, are neither predictable nor routine. Instead, they are, by definition, sudden, infrequent, and not reasonably preventable failures of emissions control, process, or monitoring equipment. (40 CFR 60.2). The EPA interprets CAA section 111 as not requiring emissions that occur during periods of malfunction to be factored into development of CAA section 111 standards. Nothing in CAA section 111 or in case law requires that the EPA consider malfunctions when determining what standards of performance reflect the degree of emission limitation achievable through "the application of the best system of emission reduction" that the EPA determines is adequately demonstrated. While the EPA accounts for variability in setting emissions standards, nothing in CAA section 111 requires the Agency to consider malfunctions as part of that analysis. The EPA is not required to treat a malfunction in the same manner as the type of variation in performance that occurs during routine operations of a source. A malfunction is a failure of the source to perform in a "normal or usual manner" and no statutory language compels the EPA to consider such events in setting CAA section 111 standards of performance. The EPA's approach to malfunctions in the analogous circumstances (setting "achievable" standards under CAA section 112) has been upheld as reasonable by the D.C Circuit in U.S. Sugar Corp. v. EPA, 830 F.3d 579, 606 - 610 (2016).]
Testing and Monitoring Requirements
Because the NSPS reflects the application of the best system of emission reduction under conditions of proper operation and maintenance, in doing the NSPS review, the EPA also evaluates and determines the proper testing, monitoring, recordkeeping and reporting requirements needed to ensure compliance with the NSPS. This section will include a discussion on the current testing and monitoring requirements of the NSPS and any additions the EPA is proposing to include in 40 CFR part 60, subpart TTTTa.
General Requirements
The current rule allows three approaches for determining compliance with its emissions limits: Continuous measurement using CO2 CEMS and flow measurements for all EGUs; calculations using hourly heat input and `F' factors for EGUs firing uniform oil or gas or non-uniform fuels; or Tier 3 calculations using fuel use and carbon content as described in GHGRP regulations for EGUs firing non-uniform fuels. The first two approaches are in use for carbon dioxide by the Acid Rain program (40 CFR part 75), to which most, if not all, of the EGUs affected by NSPS subpart TTTT are already subject, while the last approach is in use for carbon dioxide, nitrous oxide, and methane reporting from stationary fuel combustion sources (40 CFR part 98, subpart C). 
The EPA believes continuing the use of these familiar approaches already in use by other programs represents a cost-effective means of obtaining quality assured data requisite for determining carbon dioxide mass emissions. Therefore, no changes to the current ways of collecting carbon dioxide and associated data needed for mass determination, such as flow rates, fuel heat content, fuel carbon content, and the like, are proposed. Because no changes are proposed and because the cost and burden for EGU owners or operators are already accounted for by other rulemakings, this proposed rule has minimal, if any, cost or burden associated with carbon dioxide testing and monitoring. In addition, the proposal contains no changes to measurement and testing requirements for determining electrical output, both gross and net, as well as thermal output, to current existing requirements. 
The EPA requests comment on whether continuous carbon dioxide and flow measurements should become the sole means of compliance for this rule. Such a switch would increase costs for those EGU owners or operators who are currently relying on the oil- or gas-fired or non-uniform fuel-fired calculation-based approaches for compliance. By way of reference, the annualized cost associated with adoption and use of continuous carbon dioxide and flow measurements where none now exist is estimated to be about $52,000. To the extent that the rule were to mandate continuous carbon dioxide and flow measurements in accordance with what is currently allowed as one option and that an EGU lacked this instrumentation, its owner or operator would need to incur this annual cost to obtain such information and to keep the instrumentation calibrated. 
Requirements for Sources Implementing CCS
The CCS process is also subject to monitoring and reporting requirements under the EPA's GHGRP (40 CFR part 98). The GHGRP requires reporting of facility-level GHG data and other relevant information from large sources and suppliers in the U.S. The "suppliers of carbon dioxide" source category of the GHGRP (GHGRP subpart PP) requires those affected facilities with production process units that capture a CO2 stream for purposes of supplying CO2 for commercial applications or that capture and maintain custody of a CO2 stream in order to sequester or otherwise inject it underground to report the mass of CO2 captured and supplied. Facilities that inject a CO2 stream underground for long-term containment in subsurface geologic formations report quantities of CO2 sequestered under the "geologic sequestration of carbon dioxide" source category of the GHGRP (GHGRP subpart RR). In 2022, to complement GHGRP subpart RR, the EPA proposed the "geologic sequestration of carbon dioxide with enhanced oil recovery (EOR) using ISO 27916" source category of the GHGRP (GHGRP subpart VV) to provide an alternative method of reporting geologic sequestration in association with EOR.  
The current rule leverages the regulatory requirements under GHGRP subpart RR and does not reference GHGRP subpart VV. The EPA is proposing that any affected unit that employs CCS technology that captures enough CO2 to meet the proposed standard and injects the captured CO2 underground must report under GHGRP subpart RR or GHGRP subpart VV. If the captured CO2 is sent offsite, then the facility injecting the CO2 underground must report under GHGRP subpart RR or GHGRP subpart VV. This proposal does not change any of the requirements to obtain or comply with a UIC permit for facilities that are subject to the EPA's UIC program under the Safe Drinking Water Act. 
The EPA also notes that compliance with the standard is determined exclusively by the tons of CO2 captured by the emitting EGU. The tons of CO2 sequestered by the geologic sequestration site are not part of that calculation. However, to verify that the CO2 captured at the emitting EGU is sent to a geologic sequestration site, we are leveraging regulatory requirements under the GHGRP. Further, we note that the determination that the BSER is adequately demonstrated relies on geologic sequestration that is not associated with EOR, however EGUs would have the option to send CO2 to EOR facilities that report under GHGRP subpart RR or GHGRP subpart VV. We also emphasize that this proposal does not involve regulation of downstream recipients of captured CO2. That is, the regulatory standard applies exclusively to the emitting EGU, not to any downstream user or recipient of the captured CO2. The requirement that the emitting EGU assure that captured CO2 is managed at an entity subject to the GHGRP requirements is thus exclusively an element of enforcement of the EGU standard. Similarly, the existing regulatory requirements applicable to geologic sequestration are not part of the proposed rule. 
Requirements for Sources Co-firing Low-GHG Hydrogen
Because the EPA is basing its proposed definition of low-GHG hydrogen consistent with IRC section 45V(b)(2)(D), it is reasonable, if possible and practicable, for the EPA to adopt, in whole or in part, the eligibility, monitoring, verification, and reporting protocols associated with IRC section 45V(b)(2)(D) when finalized by Treasury as applicable to demonstrations by EGUs that they are using low-GHG hydrogen. The provisions under development by Treasury are specifically designed to ensure that hydrogen that is eligible for the lowest-GHG tier of the tax credit is in fact produced consistent with that definition. Adopting very similar requirements for demonstrations by EGUs that they are using low-GHG hydrogen would help ensure there are not dueling eligibility requirements for low-GHG hydrogen production with overall emissions rates of 0.45 kg CO2e/kg H2 or less. Adopting similar methods for assessing GHG emissions associated with hydrogen production pathways would create clarity and certainty and reduce confusion. 
The EPA is taking comment on its proposal to closely follow Treasury protocols in determining how EGUs demonstrate compliance with the fuel characteristics required in this rulemaking. The EPA is taking comment on what forms of acceptable mechanisms and documentary evidence should be required for EGUs to demonstrate compliance with the obligation to co-fire low-GHG hydrogen, including proof of production pathway, overall emissions calculations or modeling results and input, purchasing agreements, contracts, and attribute certificates. Given the complexities of tracking produced hydrogen and the public interest in such data, the EPA is also taking comment on whether EGUs should be required to make fully transparent its sources of low-GHG hydrogen and the corresponding quantities procured. The EPA is also seeking comment on requiring that EGUs using low-GHG hydrogen to demonstrate that their hydrogen is exclusively from facilities that only produce low-GHG hydrogen, as a means of reducing demonstration burden and opportunities for double counting. The EPA solicits comment on a mechanism to operationalize such a burden reduction provision.
Treasury is currently developing implementing rules for IRC section 45V though an interagency process including the DOE and the EPA, which will be subject to robust public involvement. Congress specified a methodology for determining well-to-gate emissions for hydrogen production projects using the Greenhouse gases, Regulated Emissions, and Energy use in Transportation model (GREET model) to determine the credit tiers (45V(b)(2)(A), 45V(b)(2)(B), 45V(b)(2)(C), and 45V(b)(2)(D)) applicable for a proposed taxpayer project. Consistent with its proposal to define low-GHG hydrogen consistent with IRC section 45V(b)(2)(D), the EPA is also proposing to adopt to the maximum extent possible the same methodology specified in IRC section 45V and requirements currently under development for the purpose of demonstrating compliance with the requirement to combust low-GHG hydrogen under this NSPS. One example would be requiring that the owner/operator of the combustion turbine obtain from the hydrogen producer from which they purchase low-GHG hydrogen the hydrogen producer's calculation of GHG levels associated with its hydrogen production using the GREET well-to-gate analysis. The GREET model is well established, designed to adapt to evolving knowledge, and capable of including technological advances. Importantly, a publicly accessible on-line version will be released to enable a broad range of user access. The requirements under development in the Treasury-led interagency process include third-party verification requirements, and the EPA solicits comment on whether the EPA should consider such protocols as part of the standards required for EGUs to demonstrating compliance. Given the sequential timing of EPA and Treasury processes, the EPA may take further action, after promulgation of this NSPS, to provide additional guidance for implementation of Treasury's implementation framework in this particular context. The EPA requests comment on its proposal to adopt as much as possible the methodology specified in IRC section 45V and the implementing requirements currently under development by Treasury as part of the obligations for EGUs to demonstrate compliance with the requirement to combust low-GHG hydrogen under this NSPS. 
In addition to proposing to incorporate as much as possible Treasury's eligibility, monitoring, reporting, and verification protocols as sufficient to demonstrate compliance by the EGUs with the low-GHG hydrogen co-firing obligations, the EPA is also taking comment on several underlying policy issues relevant to ensuring that hydrogen used to comply with this rule is low-GHG hydrogen. New project eligibility for hydrogen production tax credits under IRC section 45V expires at the end of 2032. Co-firing with low-GHG hydrogen under this new source performance standard proposal could be phased in at the beginning of 2035, 2 years after the IRC section 45V tax credit expires for new projects, which could potentially limit its applicability. Given this and other uncertainties, the EPA is taking comment on issues that would be relevant should the Agency develop its own protocols for EGUs to demonstrate compliance with the overall emissions rate in IRC section 45V(b)(2)(D) for co-firing as BSER in this rulemaking. 
The EPA is also taking comment on strategies the EPA could adopt to inform its own eligibility, monitoring, reporting and verification protocols to ensuring compliance with the 0.45 kg CO2e/kg H2 or less emission rate for compliance with the low-GHG provisions of this rule, if the EPA does not adopt Treasury's protocols. The purpose of these strategies would be to assure that EGUs are using only low-GHG hydrogen, i.e., hydrogen that results in GHG emissions of less than 0.45 kg CO2 per kg H2. The EPA is taking comment on the appropriateness of requiring EGUs to provide verification that the hydrogen they use complies with this standard, as demonstrated by the GREET model for estimating the GHG emissions associated with hydrogen production, and to what extent EGUs would be required to verify the accuracy of the inputs and conclusions of the GREET model for the hydrogen used by the EGU to comply with this rule. The EPA is soliciting comments on other models and methods and boundary conditions to develop GHG emissions estimates for qualifying low-GHG hydrogen production.
Several important considerations with respect to determining overall GHG emissions rates for hydrogen production pathways have already taken shape in the public sphere and will continue to percolate in the various Federal government fora outlined above. The EPA is soliciting comment on these issues, as they related to co-firing low-GHG hydrogen in combustion turbines and the requisite need to only utilize the lowest-GHG hydrogen in these applications. The EPA notes this is one of multiple forthcoming opportunities for public comment on this suite of issues, and the EPA's proposal is specific to low-GHG hydrogen in the context of qualifying a co-firing fuel as part of BSER. 
It is important to note that the landscape for methane emissions monitoring and mitigation is changing rapidly. For example, the EPA is in the process of developing enhanced data reporting requirements for petroleum and natural gas systems under its GHGRP, and is in the process of finalizing requirements under New Source Performance Standards and Emission Guidelines for the oil and gas sector that will result in mitigation of methane emissions. With these changes, it is expected that the quality of data to verify methane emissions will improve and methane emissions rates will change over time. Adequately identifying and accounting for overall emissions associated with methane-based feedstocks is essential in the determination of accurate overall emissions rates to comply with the low-GHG hydrogen standards in this rule. The EPA is taking comment on how methane leak rates can be appropriately quantified and conservatively estimated given the inherent uncertainties and wide range of basin-specific characteristics. The EPA is soliciting comment on whether EGUs should be required to produce a demonstration of augmented in-situ monitoring requirements to determine upstream emissions when methane feedstock is used for low-GHG hydrogen used by the EGU for compliance with this rule. The EPA is also taking comment on whether EGUs should use a default assumption for upstream methane leak rates in the event monitoring protocols are not finalized as part of this rulemaking, and what an appropriate default leak rate should be, including what evidence would be necessary for the EGU to deviate from that default assumption. The EPA is also taking comment on the appropriateness of requiring EGUs to provide CEMS data for SMR or ATR processes seeking to produce qualifying low-GHG hydrogen for co-firing to ensure the amount of carbon captured by CCS is properly and consistently monitored and outage rates and times are recorded and considered. The EPA is soliciting comment on providing EGUs with a representative and climate-protective default assumption for carbon capture rates associated with SMR and ATR hydrogen pathways, inclusive of outages, if CCS is used for low-GHG hydrogen production as part of this rulemaking, including what evidence would be necessary for the EGU to deviate from that default assumption.
In comparison with petrochemical-based hydrogen production pathways discussed above, electroyzer-based hydrogen production has the potential for lower GHG-hydrogen because the technology is based on splitting water molecules rather than splitting hydrocarbons. For EGUs relying on hydrogen produced using this pathway, the EPA is seeking comment on the method for assuring that energy inputs to that production are consistent with the low-GHG hydrogen standard that EGUs would be required to meet under this rule. Specifically, the EPA is taking comment on requiring EGUs to provide substantiation of low-GHG energy inputs into any overall emissions assessment for electrolytic or methane reforming hydrogen production pathways for hydrogen used by the EGUs to comply with the low-GHG hydrogen standard in this rule. Energy Attribute Credits (EAC) (EAC from renewable sources are sometimes known as Renewable Energy Credits or RECs) are produced for each megawatt hour of low-GHG generation and therefore offer a measurable, auditable, and verifiable approach for determining the GHG emissions associated with the energy used to make the low-GHG hydrogen. EACs with specific attributes are commonly used in the electricity markets to substantiate corporate clean energy commitments and use, as well as for utility compliance with state RPS and CES programs. The EPA proposes requiring EGUs to provide EAC verification for low-GHG emission energy inputs into GHG emissions assessments for hydrogen used by that EGU to comply with the low-GHG standard in this rule, for all hydrogen pathways. The EPA is seeking comment on allowing EGUs to use EACs as part of the documentation required for verifying the use of low-GHG hydrogen. 
The EPA is taking comment on allowing EGUs to comply with the low-GHG hydrogen standard in this rule if they demonstrate that the hydrogen used is produced from a dedicated low-GHG emitting electricity source connected to an electrolyzer, without any grid exchanges. The EPA is also taking comment on a more detailed approach for EGUs to demonstrate that purchased hydrogen meets the low-GHG standard. Many announced hydrogen production projects pair electrolyzers with renewable and nuclear energy, which are likely capable of producing low-GHG hydrogen. These renewable generation sources are intermittent and nuclear units go offline for refueling purposes. In these cases, and others, grid-based electricity, which often has a high carbon intensity might be pursued in combination with EACs for each megawatt hour of grid-based energy used. Aligning the time and place (temporal and geographic alignment) of EACs used to allocate and describe delivered grid-based electricity consumed could potentially help ensure the cleanest possible hydrogen. Some degree of alignment geographically, for example delivery of power to the balancing authority, could ensure that EACs used are representative of the allocation of the energy mix consumed by the electrolyzers. The EPA is seeking comment on allowing EGUs to use this type of alignment to verify that the hydrogen used by the EGU meets the low-GHG standard. 
There is growing interest in hourly EAC alignment for electrolytic hydrogen, and tracking systems are evolving to meet this need in real time. To wit, PJM announced it would introduce EACs with hourly data stamping for low-GHG generators in March, 2023. Hourly EAC alignment policies could provide a high level of assurance that EACs used are displacing coincident carbon intensity grid profiles. On the other hand, stakeholders have identified the potential of hourly EAC requirements creating high-cost barriers for near term electrolyzer deployment. While hourly tracking systems are coming online, they are still nascent. The EPA is taking comment on the concept of allowing EGUs to use temporal EAC alignment, for the grid-based electricity use in hydrogen production process for hydrogen used by the EGU to comply with the low-GHG hydrogen standards, including hourly, monthly, and annual alignment.
Recordkeeping and Reporting Requirements
The current rule (subpart TTTT of 40 CFR Part 60) requires EGU owners or operators to prepare reports in accordance with the Acid Rain Program's ECMPS and, for the EGUs relying on the compliance approaches contained in Appendix G of 40 CFR part 75, with the reporting requirements of that Appendix. Such reports are to be submitted quarterly. The EPA believes all EGU owners and operators have extensive experience in using the ECMPS and use of a familiar system ensures quick and effective rollout of the program in today's proposal. Because all EGUs are expected to be covered by and included in the ECMPS, minimal, if any, costs for reporting are expected for this proposal. In the unlikely event that a specific EGU is not already covered by and included in the ECMPS, the estimated annual per unit cost would be about $8,500.
The current rule's recordkeeping requirements at 40 CFR part 60.5560 rely on a combination of general provision requirements (see 40 CFR 60.7(b) and (f)), requirements at subpart F of 40 CFR part 75, and an explicit list of items, including data and calculations; the EPA proposes to retain those existing subpart TTTT of 40 CFR Part 60 requirements in the new NSPS subpart TTTTa of 40 CFR Part 60. the annual cost of those recordkeeping requirements would be the same amount as is required for subpart TTTT of 40 CFR Part 60 recordkeeping. As the recordkeeping in subpart TTTT of 40 CFR Part 60 will be replaced by similar recordkeeping in subpart TTTTa of 40 CFR Part 60 upon promulgation, this annual cost for recordkeeping will be maintained.
Additional Solicitations of Comment and Proposed Requirements
This section includes additional issues the Agency is specifically soliciting comment on. It also provides a summary of some of the key considerations the EPA is soliciting comment on with respect to the proposed CAA section 111(b) requirements.
CCS as the Sole BSER for the Base Load Subcategory 
As described above, the EPA is proposing to establish two standards for the base load subcategory: a standard for combustion turbines that combust at least 10 percent hydrogen and that is based on co-firing 30 percent by volume low-GHG hydrogen as the BSER, and a separate standard for all other base load combustion turbines that is based on CCS as the BSER. As an alternative to this proposed approach, the EPA is soliciting comment on having a single standard for the base load subcategory which would be based only on CCS as a component of the BSER. Under this alternative, EPA would not establish a base load subcategory for combustion turbines that co-fire more than 10 percent hydrogen. This approach may achieve greater emission reductions than the EPA's proposed standards because, as the discussion above indicates, a BSER based on 90 percent post-combustion capture of GHG emissions from a base load combustion turbine would achieve significantly greater reductions in emissions than a BSER based on 30 percent co-firing with low-GHG hydrogen.
This alternative approach may also reflect the more likely uses of hydrogen as a source of fuel in new combustion turbines. The EPA has proposed a standard for base load combustion turbines that co-fire more than 10 percent hydrogen in part because the Agency understands a number of power companies are actively developing combustion turbines that are designed to co-fire hydrogen and would not find it cost-effective to implement CCS. However, the Agency recognizes that power companies may ultimately come to utilize low-GHG hydrogen as a low-GHG storage fuel reserved for intermediate load combustion turbines that back up renewable generation, rather than for combustion turbines that generate at base load. Using low-GHG hydrogen, in the form of hydrogen produced through methods such as electrolysis powered by renewable or nuclear energy, to fuel base load generation is inefficient because of thermo-dynamic inefficiencies in producing the hydrogen and because the renewable or nucelar energy used to produce the hydrogen could otherwise be put into the grid. An approach in which EPA establishes a single CCS-based second phase standard of performance for base load combustion turbines, along with a second phase standard for intermediate load combustion turbines that is based on low-GHG hydrogen as a component of the BSER, would align with this potential scenario. The EPA requests comment on this alternative approach. 
Co-firing Low-GHG Hydrogen as BSER for Intermediate Load Combined Cycle and Simple Cycle Subcategories 
The EPA is also soliciting comment on subcategorizing intermediate load combustion turbines into an intermediate load combined cycle subcategory and an intermediate load simple cycle subcategory. The BSER for both subcategories would be highly efficient generation (accordingly either simple cycle technology or combined cycle technology) coupled with co-firing 30 percent low-GHG hydrogen. Dividing the intermediate load subcategory into these two subcategories would assure that intermediate load combined cycle turbines would have a more stringent standard of performance -- that is, expressed in a lower lb CO2/MWh -- than intermediate load simple cycle turbines. In addition to the numeric emissions standards, owners/operators would also have to demonstrate that the intermediate load combustion turbine combusted a minimum of 30 percent low-GHG hydrogen during the 12-operating month compliance period.
Integrated Onsite Generation and Energy Storage
Integrated equipment is currently included as part of the affected facility and the EPA is soliciting comment on the best approach to recognizing the environmental benefits of onsite integrated non-emitting generation and energy storage. The EPA is proposing regulatory text to clarify that the output from integrated renewables is included as output when determining the NSPS emissions rate. The EPA is also proposing that the output from the integrated renewable generation is not included when determining the net electric sales for applicability purposes. In the alternative, the EPA is soliciting comment on whether instead of exempting the generation from the integrated renewables from counting toward electric sales, the potential output from the integrated renewables would be included when determining the design efficiency of the facility. Since the design efficiency is used when determining the electric sales threshold this would increase the allowable electric sales for subcategorization purposes. Including the integrated renewables when determining the design efficiency of the affected facility would have the impact of increasing the operational flexibility of owners/operators of intermediate load combustion turbines. Renewables typically have much lower 12-operating month capacity factors than the intermediate electric sales threshold so could allow the turbine engine itself to operate at a higher capacity factor while still being considered an intermediate load EGU. Conversely, if the integrated renewables operate at a 12-operating month capacity factor of greater than 20 percent that would reduce the ability of a peaking turbine engine to operate while still remaining in the low load subcategory. However, even if a combustion turbine engine itself were to operate at a capacity factor of less than 20 percent and become categorized as an intermediate load combustion turbine when the output form the integrated renewables are considered, the output from the integrated renewables could lower the emissions rate such that the affected facility would be in compliance with the intermediate load emissions standard.
For integrated energy storage technologies, the EPA is soliciting comment on including the rated output of the energy storage when determining the design efficiency of the affected facility. Similar to integrated renewables, this would increase the flexibility of owner/operators to operate at higher capacity factors while remaining in the low and intermediate load subcategories. The EPA is not proposing that the output from the energy storage be considered in either determining the NSPS emissions rate or as net electric sales for subcategorization applicability purposes. While additional energy storage will allow for integration of additional intermittent renewable generation, the energy storage devices could be charged using grid supplied electricity that is generated from other types of generation. Therefore, this is not necessarily stored low-GHG electricity. 
Definition of System Emergency
40 CFR part 60, subpart TTTT (and the proposed 40 CFR part 60, subpart TTTTa) include a provision that electricity sold during hours of operation when a unit is called upon to operate due to a system emergency is not counted toward the percentage electric sales subcategorization threshold. The EPA concluded that this exclusion is necessary to provide flexibility, to maintain system reliability, and to minimize overall costs to the sector (80 FR 64612; October 23, 2015). Some in the regulated community have informed the Agency that additional clarification on a system emergency would be determined and documented for compliance purposes. The intent is that the local grid operator would determine which EGUs are essential to maintain grid reliability. The EPA is soliciting comments on amending the definition of system emergency to clarify how it would be implemented. The current text is any abnormal system condition that the Regional Transmission Organizations (RTO), Independent System Operators (ISO) or control area Administrator determines requires immediate automatic or manual action to prevent or limit loss of transmission facilities or generators that could adversely affect the reliability of the power system and therefore call for maximum generation resources to operate in the affected area, or for the specific affected EGU to operate to avert loss of load.
Definition of Natural Gas 
40 CFR part 60, subpart TTTT (and the proposed 40 CFR part 60, subpart TTTTa) include a definition of natural gas. Natural gas is a fluid mixture of hydrocarbons (e.g., methane, ethane, or propane), composed of at least 70 percent methane by volume or that has a gross calorific value between 35 and 41 megajoules (MJ) per dry standard cubic meter (950 and 1,100 Btu per dry standard cubic foot), that maintains a gaseous state under ISO conditions. Finally, natural gas does not include the following gaseous fuels: Landfill gas, digester gas, refinery gas, sour gas, blast furnace gas, coal-derived gas, producer gas, coke oven gas, or any gaseous fuel produced in a process which might result in highly variable CO2 content or heating value. The EPA is soliciting comment on if the exclusions for specific gases such as landfill gas, etc. are necessary of if they should be deleted. If landfill gas, coal-derived gas, or other gases are processed to meet the methane and heating value content of pipeline quality natural gas they could be mixed into the pipeline network and it is the intent that this mixture be considered natural gas for the purposes of 40 CFR part 60, subpart TTTT and the proposed 40 CFR part 60, subpart TTTTa.
Additional Amendments
The EPA is proposing multiple less significant amendments. These amendments would be either strictly editorial and would not change any of the requirements of 40 CFR part 60, subpart TTTT or are intended to add additional compliance flexibility. The proposed amendments would also be incorporated into the proposed subpart TTTTa. For additional information on these amendments, see the redline strikeout version of the rule showing the proposed amendments. First, the EPA is proposing editorial amendments to define acronyms the first time they are used in the regulatory text. Second, the EPA is proposing to add International System of Units (SI) equivalent for owners/operators of stationary combustion turbines complying with a heat input-based standard. Third, the EPA is proposing to fix errors in the current 40 CFR part 60, subpart TTTT regulatory text referring to part 63 instead of part 60. Fourth, as a practical matter owners/operators of stationary combustion turbines subject to the heat input-based emissions standard need to maintain records of electric sales to demonstrate that they are not subject to the output-based emissions standard. Therefore, the EPA is proposing to add a specific requirement that owner/operators maintain records of electric sales to demonstrate they did not sell electricity above the threshold that would trigger the output-based standard. Next, the EPA is proposing to update the ANSI, ASME, and ASTM test methods to include more recent versions of the test methods. Finally, the EPA is proposing to add additional compliance flexibilities for EGUs either serving a common electric generator or using a common stack. Specifically, for EGUs serving a common electric generator, the EPA is soliciting comment on whether the Administrator should be able to approve alternate methods for determining energy output. For EGUs using a common stack, the EPA is soliciting comment on whether specific procedures should be added for apportioning the emissions and/or if the Administrator should be able to approve site-specific alternate procedures.
Summary of Solicitation of Comment on BSER Variations
This section summarizes the variations on the subcategories and on BSER for combustion turbines on which the EPA is soliciting comment. It is intended to highlight certain aspects of the proposal the Agency is soliciting comment on and is not intended to cover all aspects of the proposal. 
For the low load subcategory, the EPA is soliciting comment on:
 An electric sales threshold of between 15 to 25 percent for all combustion turbines regardless of the specific design efficiency.
 An electric sales threshold based on three quarters of the design efficiency of the combustion turbine. This would result in electric sales thresholds of 18 to 22 percent for simple cycle turbines and 26 to 31 percent for combined cycle turbines.
For the intermediate load subcategory, the EPA is soliciting comment on:
             An efficiency-based emissions standard of between 1,000 to 1,200 lb CO2/MWh-gross.
             The use of steam injection as part of the first BSER component. 
             An electric sales threshold based on 94 percent of the design efficiency. This would result in electric sales thresholds of 29 to 35 percent for simple cycle turbines and 40 to 49 percent for combined cycle turbines.
             A hydrogen co-firing range of 30 to 50 percent as the second component of the BSER.
             Beginning implementation of the second component of the BSER (i.e., hydrogen co-firing) as early as 2030.
             The second component of the BSER would establish separate subcategories for simple and combined cycle intermediate load combustion turbines, both based on co-firing low-GHG hydrogen.
For the base load subcategory, the EPA is soliciting comment on:
             An efficiency-based emissions standard of between 730 to 800 lb CO2/MWh-gross for large combustion turbines.
             An efficiency-based emissions standard of between 850 to 900 lb CO2/MWh-gross for small combustion turbines.
             Beginning implementation of the second component of the BSER (i.e., CCS or hydrogen co-firing) as early as 2030.
             A hydrogen co-firing range of 30 to 50 percent as the second component of the BSER for combustion turbines co-firing hydrogen.
             A single BSER based on the use of CCS for all base load combustion turbines.
Compliance Dates
The EPA is proposing that affected sources that commenced construction or reconstruction after [INSERT DATE OF PUBLICATION OF PUBLICATION IN THE FEDERAL REGISTER], would need to meet the requirements of 40 CFR part 60, subpart TTTTa upon startup of the new or reconstructed affected facility or the effective date of the final rule, whichever is later. This proposed compliance schedule is consistent with the requirements in section 111 of the CAA. 
Requirements for New, Modified, and Reconstructed Fossil Fuel-fired Steam Generating Units
Overview
As is further explained in this section, because the EPA is unaware of any coal-fired steam generating projects under development or any projections that suggest that new coal will be built in the near term in the U.S., the EPA is not proposing to review the standards of performance in NSPS TTTT with regards to new or reconstructed coal-fired units. The EPA is proposing to make slight changes to the applicability requirements of 40 CFR part 60, subpart TTTT as further explained in this section. As discussed in section V.B.2 of this preamble, on December 20, 2018, the EPA proposed amendments that would revise the determination of the BSER for control of GHG emissions from newly constructed coal-fired steam generating units in 40 CFR part 60, subpart TTTT (83 FR 65424). The EPA has not taken further action to finalize the 2018 proposed rule and intends to withdraw it in a separate notice.
Eight-year Review of NSPS for Fossil Fuel-fired Steam Generating Units
The EPA promulgated NSPS for GHG emissions from fossil fuel-fired steam generating units in 2015. As noted in section IV.C, the EPA is not aware of any plans by any companies to undertake new construction of a new fossil fuel-fired steam generating unit, or to undertake a modification or reconstruction of a fossil fuel-fired steam generating unit, that would be subject to the 2015 NSPS for steam generating units. Accordingly, the EPA does not consider it necessary to review that NSPS. See "New Source Performance Standards (NSPS) Review: Advanced notice of proposed rulemaking," 76 FR 65653, 65658 (October 24, 2011) (suggesting it may not be necessary for the EPA to review an NSPS when no new construction, modification, or reconstruction is expected in the source category).
Projects Under Development
      Finally, during the 2015 NSPS rulemaking, the EPA identified the Plant Washington project in Georgia and the Holcomb 2 project in Kansas as EGU "projects under development" based on representations by developers that the projects had commenced construction prior to the proposal of the 2015 NSPS and, thus, would not be new sources subject to the final NSPS (80 FR 64542 - 43; October 23, 2015). The EPA did not set a performance standard at the time but committed to doing so if new information about the projects became available. These projects were never constructed and are no longer expected to be constructed. 
      The Plant Washington project was to be an 850-MW supercritical coal-fired EGU. The Environmental Protection Division (EPD) of the Georgia Department of Natural Resources issued air and water permits for the project in 2010 and issued amended permits in 2014.   In 2016, developers filed a request with the EPD to extend the construction commencement deadline specified in the amended permit, but the director of the EPD denied the request, effectively canceling the approval of the construction permit and revoking the plant's amended air quality permit.
      The Holcomb 2 project was intended to be a single 895-MW coal-fired EGU and received permits in 2009 (after earlier proposals sought approval for development of more than one unit). In 2020, after developers announced they would no longer pursue the Holcomb 2 expansion project, the air permits were allowed to expire, effectively canceling the project.
      For these reasons, the EPA is proposing to remove these projects under the applicability exclusions in subpart TTTT.
Proposed ACE Repeal
The EPA is proposing to repeal the ACE Rule. A general summary of the ACE Rule, including its regulatory and judicial history, is included in section V.B. of this preamble. The EPA proposes to repeal the ACE Rule on three grounds that together and, with respect to the first two grounds, independently, justify the rule's repeal. First, the EPA no longer believes that heat rate improvements (HRI) are the BSER for existing coal-fired EGUs. In fact, the EPA now believes that HRI are unnecessary and even counterproductive in the context of this source category because they would provide negligible CO2 reductions overall and lead to increases in CO2 emissions from certain designated facilities due to the rebound effect. Moreover, due to changes in the industry and developments in the costs of controls, more impactful technologies like co-firing of natural gas and CCS, which the ACE Rule rejected, are now cost reasonable for designated facilities with longer operating horizons. Second, the ACE Rule was contrary to CAA section 111 and the EPA's implementing regulations because it did not identify the BSER or the "degree of emission limitation achievable" by applying the BSER with sufficient precision to provide the states with adequate guidance as to the level of emission reduction that their standards of performance must achieve in order for the EPA to approve them. Rather, the ACE Rule provided states with virtually unfettered discretion to determine how much, if any, emission reductions their standards would achieve. Third, as explained in the recently proposed revisions to the EPA's implementing regulations, the ACE Rule adopted an incorrect legal interpretation of CAA section 111 that precluded states from allowing their sources to comply with standards of performance by trading or averaging. On the contrary, CAA section 111(d) accords states with discretion to provide sources with compliance flexibilities, including trading or averaging in appropriate circumstances, as long as state plans maintain equivalent emission reductions as would be achieved if each affected source was achieving its applicable standard of performance.
Summary of the Key Features of the ACE Rule
The key features of the ACE Rule were that it determined that HRI was the BSER for coal-fired EGUs; it rejected several other controls, including co-firing with natural gas and CCS; and it interpreted CAA section 111 to preclude states from allowing compliance flexibilities such as trading or averaging.
The ACE Rule determined that the BSER for coal-fired EGUs was a "list of `candidate technologies,'" consisting of seven types of the "most impactful HRI technologies, equipment upgrades, and best operating and maintenance practices," (84 FR 32536; July 8, 2019), including, among others, "Boiler Feed Pumps" and "Redesign/Replace Economizer." Id. at 32537 (table 1). The rule provided a range of improvements in heat rate that each of the seven "candidate technologies" could achieve if applied to coal-fired EGUs of different capacities. For six of the technologies, the expected level of improvement in heat rate ranged from 0.1 - 0.4 percent to 1.0 - 2.9 percent, and for the seventh technology, "Improved Operating and Maintenance (O&M) Practices," the range was "0 to >2%." Id. The ACE Rule went on to explain that states were to review each of their designated facilities, on either a source-by-source or group-of-sources basis, and "evaluate the applicability of each of the candidate technologies." Id. at 32550. Specifically, "states will use the information provided by the EPA [i.e., the list of candidate technologies and each technology's range of HRI potential] as guidance but will be expected to conduct unit-specific evaluations of HRI potential, technical feasibility, and applicability for each of the BSER candidate technologies." Id. at 32538. The ACE Rule emphasized that states had "inherent flexibility" in undertaking this task with "a wide range of potential outcomes." Id. at 32542. The ACE Rule was clear that states could conclude that it was not appropriate to apply some of the technologies. Id. at 32550. Moreover, if a state did decide to apply a particular technology to a particular source, the state could determine the level of heat rate improvement from the technology to be anywhere within the range that the EPA had identified for that technology, or even outside that range. Id. at 32551. The ACE Rule went on to say that after the state applied the technologies and calculated the amount of HRI in this discretionary manner, it should determine the standard of performance that the source could achieve, Id. at 32550, but the state could then adjust that standard further based on the application of source-specific factors such as remaining useful life. Id. at 32551. Moreover, according to the ACE Rule, the state could combine both of those actions into a "hybridized" approach in which it determined the standard of performance in a single combined step. Id. at 32550. 
The ACE Rule went on to identify the process by which states were required to take these actions. According to the rule, states must "evaluat[e] each" of the seven candidate technologies and provide a summary, which "include[s] an evaluation of the ... degree of emission limitation achievable through application of the technologies." Id. at 32580. Further, the state must provide a variety of information about each power plant, including, the plant's "annual generation," "CO2 emissions," "[f]uel use, fuel price, and carbon content," "operation and maintenance costs," "[h]eat rates," "[e]lectric generating capacity," and the "timeline for implementation," among other information. Id. at 32581. The EPA explained that the purpose of this data was to allow the Agency to "adequately and appropriately review the plan to determine whether it is satisfactory." Id. at 32558. 
The ACE Rule projected that if states generally applied the set of candidate technologies to their sources, the rule would achieve a less-than-1-percent reduction in power-sector CO2 emissions by 2030. However, the rule also projected that it would result in increased CO2 emissions from power plants in 15 states and the District of Columbia due to the rebound effect. 
The ACE Rule considered several other control measures as the BSER, including co-firing with natural gas and CCS, but rejected them. The ACE Rule rejected co-firing with natural gas primarily on grounds that it was too costly in general, and especially for sources that have limited or no access to natural gas. 84 FR 32545 (July 8, 2019). The rule also concluded that generating electricity by co-firing natural gas in a utility boiler would be an inefficient use of the gas when compared to combusting it in a combustion turbine. Id. The ACE Rule also rejected CCS on grounds that it was too costly. Id. at 32548. The rule identified the high capital and operating costs of CCS and noted the fact that the IRC 45Q tax credit, as it then applied, would provide only limited benefit to sources. Id. at 32548-49.
In addition, the ACE Rule interpreted CAA section 111 to preclude states from allowing their sources to trade or average to demonstrate compliance with their emission standards. Id. at 32556 - 57.
Changes in Factual and Policy Underpinnings of ACE Rule
The EPA's first basis for proposing to repeal the ACE Rule is that changes have occurred in the factual and policy underpinnings of the rule concerning the structure of the industry and CO2 control requirements, leading the EPA to conclude that the BSER of HRI that the ACE Rule included was flawed and that other control measures qualify as the BSER instead. 
In explaining its proposal to repeal the ACE Rule and replace it with this proposed rule, the EPA is following the direction of the Supreme Court in F.C.C. v. Fox Television Stations, Inc., 556 U.S. 502 (2009). There, the Court described the type of reasoning an agency must provide to justify changing a rule it has previously adopted:
      [T]he requirement that an agency provide reasoned explanation for its action would ordinarily demand that it display awareness that it is changing position.... And of course the agency must show that there are good reasons for the new policy. But it need not demonstrate to a court's satisfaction that the reasons for the new policy are better than the reasons for the old one; it suffices that the new policy is permissible under the statute, that there are good reasons for it, and that the agency believes it to be better, which the conscious change of course adequately indicates. This means that the agency need not always provide a more detailed justification than what would suffice for a new policy created on a blank slate. Sometimes it must -- when, for example, its new policy rests upon factual findings that contradict those which underlay its prior policy; or when its prior policy has engendered serious reliance interests that must be taken into account.... It would be arbitrary or capricious to ignore such matters. In such cases it is not that further justification is demanded by the mere fact of policy change; but that a reasoned explanation is needed for disregarding facts and circumstances that underlay or were engendered by the prior policy.

Id. at 514 - 16 (emphasis in original; citation omitted).
Since the promulgation of the ACE Rule in 2019, the factual underpinnings of the rule have changed in several ways. The first concerns the structure of the power sector. The EPA discusses these changes in section IV of this preamble. For more than the past decade, coal-fired EGUs have experienced greater competitive pressure from natural gas-fired combustion turbines and renewable energy generating sources, and as a result, have been reducing their utilization and retiring. This trend has continued since the promulgation of the ACE Rule in 2019, with a number of sources announcing retirements. Importantly, in part because of the enactment of the IRA, which provides substantial incentives for renewable energy, more coal-fired EGUs are expected to announce retirements in the near future. 
In addition to these significant changes in the structure of the power sector, the costs of two control measures, co-firing with natural gas and CCS, have fallen substantially for sources with longer-term operating horizons. As noted above, the ACE Rule rejected natural gas co-firing as the BSER on grounds that it was too costly and would lead to inefficient use of natural gas. However, as discussed in section X.D.2.b.ii of this preamble, the costs of natural gas co-firing have decreased, and the EPA is proposing that the costs of co-firing 40 percent by volume natural gas are reasonable for existing coal-fired EGUs in the medium-term subcategory, i.e., units that plan to operate during, in general, the 2032 to 2040 period. In addition, natural gas is available in greater amounts, and there are fewer coal-fired EGUs, than at the time of the ACE Rule's promulgation, which mitigates the concerns in that rule about inefficient use of natural gas. See section X.D.2.b.iii.(B).
Similarly, the ACE Rule rejected CCS as the BSER on grounds that it was too costly. However, as discussed in section X.D.1.b.ii of this preamble, the costs of CCS have substantially declined, partly because of developments in the technology that have lowered capital costs, and partly because the IRA extended and increased the IRC section 45Q tax credit so that it defrays a higher portion of the costs of CCS. Accordingly, for coal-fired EGUs that will continue to operate past 2040, the EPA is proposing that the costs of CCS, which have fallen to approximately $7 -  $12/MWh, are reasonable. 
On the other hand, the EPA now recognizes that the ACE Rule's view of HRI improvements as appropriate for the BSER for coal-fired EGUs was flawed. HRI achieve only a limited amount of GHG emission reductions. The ACE Rule projected that if states generally applied the set of candidate technologies to their sources, the rule would achieve a less-than-1-percent reduction in power-sector CO2 emissions by 2030. Moreover, as a practical matter, as discussed in section IX.C., the ACE Rule would not necessarily achieve any reductions, and, in fact could result in at least some states establishing emission standards that allow sources to increase their emission rates. It is clear that the amount of emission reductions that the ACE Rule would achieve is minimal, which raises significant concerns that the rule's determination that HRI qualify as the BSER was flawed because one of the criteria for whether a control measure qualifies as the BSER is the amount of emission reductions that the measure achieves. Moreover, at least for a subset of sources, HRI are likely to cause a rebound effect leading to an increase in GHG emissions, for the reasons explained in section X.D.5.a. The rebound effect was quite pronounced in the ACE Rule  -  the rule projected that it would result in increased CO2 emissions from power plants in 15 states and the District of Columbia. In addition, as discussed in section IX.C, the BSER based on HRI as included in the ACE Rule would not necessarily achieve any reductions, and, in fact could result in at least some states establishing emission standards that allow sources to increase their emission rates. Accordingly, the EPA believes that HRI do not qualify as the BSER for any coal-fired EGUs.
Based on the just-described developments and changes in policy, the EPA is proposing to fundamentally change its regulatory scheme for coal-fired power plants from the ACE Rule. As discussed in section X.C.3, of this preamble, the EPA is proposing to subcategorize coal-fired power plants according to the period of time that they will continue to operate. For sources in the imminent-term and near-term subcategories  -  which include sources that, in general, have federally enforceable commitments to permanently cease operations by 2032 or 2035, respectively  -  the EPA is proposing that the BSER is routine methods of operation and maintenance, with associated presumptive emission standards that do not permit an increased emission rate and are not anticipated to have a rebound effect. For sources in the medium-term subcategory  -  which includes sources that are not in the other subcategories and that have a federally enforceable commitment to permanently cease operations by 2040  -  the EPA is proposing that the BSER is co-firing 40 percent by volume natural gas. The EPA believes that this control measure is appropriate because it achieves substantial reductions and can be implemented at reasonable cost. In addition, the EPA believes that because of the large supply of natural gas that is available, devoting part of this supply for fuel for a coal-fired steam generating unit in place of a percentage of the coal burned at the unit should not be considered an inefficient use of natural gas and will not cause any adverse impacts on the energy system. See section X.D.2.b.iii.(B). For sources in the long-term subcategory  -  which includes sources that do not have a federally enforceable commitment to permanently cease operations by 2040  -  the EPA is proposing that the BSER is CCS with 90 percent capture of CO2. The EPA believes that this control measure is appropriate because it achieves substantial reductions and can be implemented at reasonable cost. See section X.D.1.c.
The EPA is not proposing HRI as the BSER for any of the subcategories. As discussed in section X.D.5.a, the EPA does not consider HRI to be an appropriate BSER for the imminent-term and near-term subcategories because it would achieve relatively few, if any, emissions reductions, and, for at least a subset of sources, it could have the effect of increasing emissions through the rebound effect. The EPA is proposing to reject HRI as the BSER for the medium-term and long-term subcategories because HRI could also lead to a rebound effect for them, and, most importantly, because co-firing natural gas and CCS, respectively, are available, can be implemented at reasonable cost, and will achieve more GHG emissions reductions. 
For these reasons, the EPA proposes to repeal the ACE Rule and to replace it with the emission guidelines proposed in this action.
Insufficiently Precise BSER and Degree of Emission Limitation
The second reason why the EPA is proposing to repeal the ACE Rule is that the rule did not identify the BSER or the degree of emission limitation achievable through the application of the BSER with sufficient precision to provide adequate guidance to the states as to the level of emission reduction that the standards of performance must achieve. The ACE Rule determined the BSER to be a menu of HRI "candidate technologies," but did not identify a meaningful degree of emission limitation and, further, authorized the states wide latitude to decide which, if any, candidate technologies to apply and what amount of heat rate improvement, if any, to achieve. As a result, the ACE Rule was contrary to CAA section 111 and the implementing regulations, and, in any event, poor policy. 
CAA section 111 and the EPA's long-standing implementing regulations establish a step-by-step process for the EPA and states to regulate emissions of certain air pollutants from existing sources. First, the EPA determines the BSER and calculates the degree of emission limitation achievable by application of the BSER. The EPA promulgates this information as part of the emission guidelines, CAA section 111(d)(1), (a)(1), 40 CFR 60.22, 60.22a; this information constitutes the necessary basis for determining the emission reductions that state plans must achieve in order to comport with CAA section 111. The Supreme Court has confirmed that the EPA is responsible for determining both the BSER and the associated degree of emission limitation. West Virginia v. EPA, 142 S. Ct. 2587, 2607 (2022). 
Once the EPA makes these determinations, the state must establish "standards of performance" for its sources that are based on the degree of emission limitation that the EPA determines in the emissions guidelines. CAA section 111(a)(1) makes this clear through its definition of the term "standard of performance:" "a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the [BSER]." The state includes the standards of performance in its state plan and submits it to the EPA for review. CAA section 111(d)(2)(A). 
The EPA approves the plan, including the standards of performance, if they are "satisfactory," under CAA section 111(d)(2)(A). EPA's long-standing implementing regulations make clear that the EPA's basis for determining whether the plan is "satisfactory" includes that the plan must contain "emission standards . . . no less stringent than the corresponding emission guideline(s)." 40 CFR 60.24(c). The EPA's revised implementing regulations contain the same requirement. 40 CFR 60.24a(c). In adopting the implementing regulations, the EPA explained that if its review of state plans were based "solely on procedural criteria," then "states could set extremely lenient standards . . . so long as EPA's procedural requirements were met." 40 FR 53343 (November 17, 1975). It should be noted that in applying the standards to any particular source, the state may take into consideration, among other factors, the remaining useful life of the source, CAA section 111(d)(1) (RULOF provision), as discussed in section XI.D.2. 
In the ACE Rule, the EPA recognized that it has the responsibility to determine the BSER and the degree of emission limitation achievable through application of the BSER. 84 FR 32537 (July 8, 2019). However, the rule was flawed because it did not in fact make those determinations. Rather, what the rule described as the BSER, which was the list of "candidate technologies," and what the rule described as the degree of emission limitation achievable by application of the BSER, which was the ranges of HRI calculated for the technologies, did not identify either the BSER or the associated degree of emission limitation with sufficient precision. Instead, the rule shifted the responsibility for those determinations to the states. Accordingly, the ACE Rule did not meet the CAA section 111 or regulatory requirements to determine the BSER or the degree of emission limitation. 
As described above, the ACE Rule identified the HRI in the form of a list of seven "candidate technologies," accompanied by a broad wide range of percentage improvements to heat rate that these technologies could provide. Indeed, for one of them, improved O&M practices, the range was "0 to >2%", which is effectively unbounded. 84 FR 32537 (table 1). The ACE Rule was clear that this list was simply the starting point for the state to use in calculating the standards of performance for its sources and that the state had significant discretion in doing so. That is, the seven sets of technologies were "candidate[s]" that the state could, but was not required to, apply and if the state did choose to apply one or more of them, the state could do so in a manner that yielded any percentage of heat rate improvement within the range that the EPA identified, or even outside that range, if the state chose. Thus, as a practical matter, the ACE Rule did not determine either the BSER or any degree of emission limitation; both those were up to the state. In this manner, the ACE Rule in effect transferred the EPA's responsibilities to the state, directing each state to determine for its sources what the BSER would be (that is, which HRI technologies should be applied to the source and with what intensity), and, based on that, what the degree of emission limitation achievable by application of the BSER should be. See 84 FR 32537-38 (July 8, 2019). 
The only constraints that the ACE Rule imposed on the states were procedural ones, and those did not give the EPA any benchmark for how to determine whether a plan could be approved or give the states any certainty to know whether their plan would be approved. As noted above, when the state submitted its plan, it needed to show that it evaluated each candidate technology for each source or group of sources, explain how it determined the degree of emission limitation achievable, and include data about the sources. However, because the ACE Rule did not include a degree of emission limitation that the standards must reflect, and instead placed the responsibility on the states to determine that amount by deciding which "candidate technologies" the source could apply to improve its performance and by how much, the EPA had no benchmark against which to judge a state's submission to determine whether it is "satisfactory" under CAA section 111(d)(2)(A). The procedural requirements that the ACE Rule imposed on the states were not sufficient for this purpose. As the EPA stated when it adopted its implementing regulations in 1975, it is "essential" that "EPA review ... [state] plans for their substantive adequacy." 40 FR 53342-43 (November 17, 1975). The EPA rejected limiting its review based "solely on procedural criteria" because "states could set extremely lenient standards . . . so long as EPA's procedural requirements were met." Id. at 53343.
A draft partial state plan to implement the ACE Rule submitted by West Virginia highlights both the state's discretion to determine what the ACE Rule described as the BSER and associated degree of emission limitation and the risks that, absent minimum requirements for emission reductions, the states could set lenient standards. The D.C. Circuit vacated the ACE Rule before any state plans were required to be submitted or had been formally submitted, but West Virginia did release a draft of a partial state plan prior to the vacatur. The draft partial plan would have applied to one source, the Longview Power, LLC facility, and would have established a standard of performance, based on the state's consideration of the "candidate technologies," that was higher (i.e., less stringent) than the source's historical emission rate. Thus, the draft plan did not achieve any emission reductions from the source, and instead would have allowed the source to increase its emissions.
Finally, it should be noted that the ACE Rule's approach to determining the BSER and degree of emission limitation was a significant departure from prior emission guidelines under CAA section 111(d), in which the EPA included a numeric degree of emission limitation. See, e.g., 42 FR 55796, 55797 (October 18, 1977) (limiting emission rate of acid mist from sulfuric acid plants to 0.25 grams per kilogram of acid); 44 FR 29828, 29829 (May 22, 1979) (limiting concentrations of total reduced sulfur from most of the subcategories of kraft pulp mills, such as digester systems and lime kilns, to 5, 20, or 25 ppm over 12-hour averages); 61 FR 9905, 9919 (March 12, 1996) (limiting concentration of non-methane organic compounds from solid waste landfills to 20 parts per million by volume or 98-percent reduction).
For these reasons, the EPA proposes to repeal the ACE Rule. Its failure to determine a BSER and associated degree of emission limitation were contrary to CAA section 111 and the implementing regulations. In any event, those failures were poor policy because the ACE Rule failed to set a benchmark that would guide the states in developing their state plans, and by which the EPA could determine whether those state plans were satisfactory.
ACE Rule's Preclusion of Emissions Trading or Averaging
While not an independent basis for repeal, the EPA also now disagrees with the ACE Rule's interpretation of CAA section 111(d) to preclude states from allowing emissions trading or averaging among their sources. It is paradoxical that in the area where Congress left matters to states' discretion -- how to implement and enforce the standards set forth in the EPA's emission guidelines -- the ACE Rule incorrectly interpreted the statute as constraining states' discretion. That is, CAA section 111(d) accords states discretion in developing a plan that determines the emission reduction obligations of its sources, including allowing compliance flexibilities like trading or averaging in appropriate circumstances, as long as the plan achieves equivalent emissions reductions to the EPA's emission guidelines. The ACE Rule's legal interpretation that CAA section 111(d) precludes the state from adopting those flexibilities was incorrect.
Under CAA section 111(d)(1), each state is required to submit to the EPA "a plan which ... establishes standards of performance for any existing source" that emits certain types of air pollutants, and which "provides for the implementation and enforcement of such standards of performance." Under CAA section 111(a)(1), a "standard of performance" is defined as "a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the [BSER]."
The ACE Rule interpreted these provisions to preclude states from allowing their sources to trade or average to demonstrate compliance with their standards of performance. 84 FR 32556 - 57 (July 8, 2019). The ACE Rule based this interpretation on its view that CAA section 111 limits the type of "system" that the EPA may select as the BSER to a control measure that could be applied inside the fenceline of each source to reduce emissions at each source. Id. at 32523 - 24. The ACE Rule also concluded that the compliance measures the states include in their plans must "correspond with the approach used to set the standard in the first place," and therefore must also be limited to inside-the-fenceline measures that reduce the emissions of each source. Id. at 32556. 
The EPA has proposed to determine that the ACE Rule's legal interpretation was incorrect in its recently published notice of proposed rulemaking to amend the CAA section 111(d) implementing regulations, "Implementing Regulations under 40 CFR Part 60 Subpart Ba Adoption and Submittal of State Plans for Designated Facilities: Proposed Rule," 87 FR 79176, 79207 (December 23, 2022). As discussed in that notice, CAA section 111(d)(1) provides, in relevant part, that states "establish[]," "implement[]," and "enforce[]" "standards of performance for any existing source." No provision in CAA section 111(d), by its terms, precludes states from having flexibility in determining which measures will best achieve compliance with the EPA's emission guidelines. Such flexibility is consistent with the framework of cooperative federalism that CAA section 111(d) establishes, which vests states with substantial discretion. As the U.S. Supreme Court has explained, CAA section 111(d) "envisions extensive cooperation between federal and state authorities, generally permitting each State to take the first cut at determining how best to achieve EPA emissions standards within its domain." American Elec. Power Co. v. Connecticut, 564 U.S. 410, 428 (2011) (citations omitted). It should also be noted, however, that the flexibility that CAA section 111(d) grants to states in adopting measures for their state plans is not unfettered. The EPA may preclude certain flexibilities in specific emission guidelines where necessary to ensure that state plans achieve equivalent emission reductions to what the EPA determined is achievable through application of the BSER. Additionally, CAA section 111(d)(2) requires the EPA to review state plans to assure that they are "satisfactory." 
For the reasons just noted, the EPA proposed to disagree with the ACE Rule's conclusion that state plan compliance measures must always correspond with the approach the EPA uses to determine the BSER, so long as the plan meets the requirements of CAA section 111(d) and its implementing regulations, including the requirement that the state plan (taking into account its compliance measures) achieves equivalent emissions reductions to EPA's emission guidelines. See 87 FR 79208 (December 23, 2022). The EPA's proposed legal interpretation that CAA section 111(d) does not preclude emissions trading is consistent with the D.C. Circuit's decision in American Lung Ass'n v. EPA, 985 F.3d 914 (D.C. Cir. 2021). There, the court vacated the ACE Rule, including invalidating the rule's preclusion of emissions trading in state plans, on the basis of the reasoning that the EPA explains above. Id. at 957-58. As noted in section V.B.6, the U.S. Supreme Court reversed the D.C. Circuit's vacatur of the ACE Rule's embedded repeal of the CPP in West Virginia v. EPA, 142 S. Ct. 2587 (2022), but the Court did not rule on the scope of the states' compliance flexibilities and declined to address whether CAA section 111 limits the type of "system" the EPA could consider as the BSER to inside-the-fenceline measures. See id. at 2615. 
For these reasons, in its notice of proposed rulemaking to amend the CAA section 111(d) implementing regulations, the EPA proposed to interpret CAA section 111(d) as authorizing the EPA to approve state plans, in particular emission guidelines, that achieve the requisite emission limitation through the aggregate reductions from their sources, including through trading or averaging, where appropriate for a particular emission guideline and consistent with the intended environmental outcomes of the guideline. As discussed in section XI.E.2., the EPA is soliciting comment on whether trading and averaging would be appropriate compliance mechanism for the proposed emission guideline for coal-fired steam generating units and if so, how such compliance mechanisms could be implemented to ensure equivalency with the emission reductions that would be achieved if each affected source was achieving its appliable standard of performance. 
The ACE Rule's flawed legal interpretation that CAA section 111(d) precludes states from emissions trading is incorrect, and adds to EPA's reasoning for proposing to repeal the rule.
Proposed Regulatory Approach for Existing Fossil Fuel-fired Steam Generating Units
Overview
In this section of the preamble, the EPA explains the basis for its proposed emission guidelines for GHG emissions from existing fossil fuel-fired steam generating units for states' use in plan development. This includes proposing different subcategories of designated facilities, the BSER for each subcategory, and the degree of emission limitation achievable by application of each proposed BSER. In this action, the EPA is not proposing BSER for existing electric utility natural gas-fired combustion turbines, including simple cycle and combined cycle units. However, as detailed in section XII of this preamble, the EPA is soliciting comment on possible BSER for those units, to inform future regulatory action for those units. 
The proposed subcategories, the BSER for each subcategory, and the associated degrees of emission limitation are summarized in table 4, below. In brief, the EPA is proposing subcategories for steam generating units based on the type and amount of fossil fuel (i.e., coal, oil, and natural gas) fired in the unit. In addition, the EPA is proposing to divide the subcategory for coal-fired units into additional subcategories based on operating horizon (i.e., the period of time that sources expect to continue to operate) and, for one of those subcategories, load levels (i.e., annual capacity factor). Further, the EPA is proposing to divide subcategories for oil- and natural gas-fired units based on capacity and, in some cases, geographic location.
For coal-fired steam generating units, as noted in section IV of this preamble, ongoing trends in the power sector are leading the owners or operators of many of these units to decrease utilization of their steam generating units and to announce or develop plans for retiring the units. In the course of the EPA's engagement with stakeholders to inform this proposed rule, industry stakeholders recommended that the EPA define subcategories and evaluate GHG control technology options that take these plans for ceasing operation into account. These additional subcategories are responsive to this industry input, and appropriately recognize that the GHG control technology options available to existing coal-fired steam generating units  -  and the cost-effectiveness of those options  -  differ depending on the sources' expected operating time horizon. 
Table 4 -- Summary of Proposed BSER, Subcategories, and Degrees of Emission Limitation for Affected EGUs
                                 Affected EGUs
                            Subcategory Definition
                                     BSER
                         Degree of Emission Limitation
               Presumptively Approvable Standard of Performance
          Ranges in Values on Which the the EPA is Soliciting Comment
Long-term existing coal-fired steam generating units 
Coal-fired steam generating units that have not adopted a federally enforceable commitment to permanently cease operations by January 1, 2040
CCS with 90 percent capture of CO2
88.4 percent reduction in emission rate (lb CO2/MWh-gross) 
88.4 percent reduction in annual emission rate (lb CO2/MWh-gross) from the unit-specific baseline
The achievable capture rate from 90 to 95 percent and the achievable degree of emission limitation defined by a reduction in emission rate from 75 to 90 percent
Medium-term existing coal-fired steam generating units
Coal-fired steam generating units that choose to adopt a federally enforceable commitment to permanently cease operations after December 31, 2031, and before January 1, 2040, and that are not near-term units
Natural gas co-firing at 40 percent of the heat input to the unit
A 16 percent reduction in emission rate (lb CO2/MWh-gross) 
A 16 percent reduction in annual emission rate (lb CO2/MWh-gross) from the unit-specific baseline
The percent of natural gas co-firing from 30 to 50 percent and the degree of emission limitation from 12 to 20 percent
Near-term existing coal-fired steam generating units
Coal-fired steam generating units that choose to adopt a federally enforceable commitment to permanently cease operations after December 31, 2031, and before January 1, 2035, and to operate with annual capacity factors less than 20 percent
Routine methods of operation
No increase in emission rate (lb CO2/MWh-gross) 
An emission rate limit (lb CO2/MWh-gross) defined by the unit-specific baseline
The presumptive standard: 0 to 2 standard deviations in annual emission rate above or 0 to 10 percent above the unit-specific baseline
Imminent-term existing coal-fired steam generating units
Coal-fired steam generating units that choose to adopt a federally enforceable commitment to permanently cease operations before January 1, 2032
Routine methods of operation
No increase in emission rate (lb CO2/MWh-gross) 
An emission rate limit (lb CO2/MWh-gross) defined by the unit-specific baseline
The presumptive standard: 0 to 2 standard deviations in annual emission rate above or 0 to 10 percent above the unit-specific baseline
Base load continental existing oil-fired steam generating units
Oil-fired steam generating units with an annual capacity factor greater than or equal to 45 percent
Routine methods of operation and maintenance
No increase in emission rate (lb CO2/MWh-gross) 
An annual emission rate limit of 1,300 lb CO2/MWh-gross
The threshold between intermediate and base load from 40 to 50 percent annual capacity factor; 
the degree of emission limitation from 1,250 lb CO2/MWh-gross to 1,800 lb CO2/MWh-gross
Intermediate load continental existing oil-fired steam generating units
Oil-fired steam generating units with an annual capacity factor greater than or equal to 8 percent and less than 45 percent
Routine methods of operation and maintenance
No increase in emission rate (lb CO2/MWh-gross) 
An annual emission rate limit of 1,500 lb CO2/MWh-gross
The degree of emission limitation from 1,400 lb CO2/MWh-gross to 2,000 lb CO2/MWh-gross
Low load (continental and non-continental) existing oil-fired steam generating units
Oil-fired steam generating units with an annual capacity factor less than 8 percent
None proposed
-
-
The threshold between low and intermediate load from 5 to 20 percent annual capacity factor
Intermediate and base load non-continental existing oil-fired steam generating units
Non-continental oil-fired steam generating units with an annual capacity factor greater than or equal to 8 percent
Routine methods of operation and maintenance
No increase in emission rate (lb CO2/MWh-gross) 
An emission rate limit (lb CO2/MWh-gross) defined by the unit-specific baseline
The presumptive standard: 0 to 2 standard deviations in annual emission rate above or 0 to 10 percent above the unit-specific baseline
Base load existing natural gas-fired steam generating units
Natural gas-fired steam generating units with an annual capacity factor greater than or equal to 45 percent
Routine methods of operation and maintenance
No increase in emission rate (lb CO2/MWh-gross) 
An annual emission rate limit of 1,300 lb CO2/MWh-gross
The threshold between intermediate and base load from 40 to 50 percent annual capacity factor; 
The acceptable standard from 1,250 lb CO2/MWh-gross to 1,400 lb CO2/MWh-gross
Intermediate load existing natural gas-fired steam generating units
Natural gas-fired steam generating units with an annual capacity factor greater than or equal to 8 percent and less than 45 percent
Routine methods of operation and maintenance
No increase in emission rate (lb CO2/MWh-gross) 
An annual emission rate limit of 1,500 lb CO2/MWh-gross
The acceptable standard from 1,400 lb CO2/MWh-gross to 1,600 lb CO2/MWh-gross
Low load existing natural gas-fired steam generating units
Natural gas-fired steam generating units with an annual capacity factor less than 8 percent
None proposed
-
-
The threshold between low and intermediate load from 5 to 20 percent annual capacity factor

The EPA is proposing CCS with 90 percent capture as BSER for long-term existing coal-fired steam generating units. The EPA is soliciting comment on a range of maximum capture rates (90 to 95 percent) and, to potentially account for the amount of time the capture equipment operates relative to operation of the steam generating unit, a slightly lower achievable degree of emission limitation (75 to 90 percent reduction in average annual emission rate, defined in terms of pounds of CO2 per unit of generation). As it does with all coal-fired units, the EPA calculates the proposed presumptive standards of performance for long-term units by applying the degree of emission limitation to a source-specific baseline. 
Although CCS satisfies the BSER criteria for long-term coal-fired units, the EPA recognizes that many owners of existing coal-fired units have already announced plans to cease operating these units over the near- to medium-term or may soon choose to do so. For units that are planning to cease operations earlier than 2040, the cost effectiveness of CCS is likely to be less favorable in light of the capital investment required to retrofit with such systems and the relatively shorter operating period over which these units can recover costs and utilize available tax incentives for CCS. Accordingly, the EPA has determined that for units that will permanently cease operations before 2040, other GHG control options -- including standards reflecting the application of natural gas co-firing or, for units that are retiring in the near term, routine operations and maintenance -- achieve meaningful emission limitations and better satisfy the BSER criteria. Based on input provided by coal-fired unit owners and other stakeholders, the EPA believes that recognizing distinct BSER and corresponding emission limitations for units that will permanently cease operations over the imminent- to medium-term will also better align with industry trends and the business plans of many power companies. 
Accordingly, the EPA is proposing to establish additional subcategories of existing coal-fired steam generating units based on operating timeframe, with a separate BSER and degree of emission limitation corresponding to each subcategory. For medium-term coal-fired steam generating units, the EPA is proposing natural gas co-firing at 40 percent of annual heat input as BSER because it achieves meaningful emission reductions and satisfies the other BSER criteria, including being cost reasonable for units on an intermediate operating timeframe. The EPA is soliciting comment on the percent of natural gas co-firing from 30 to 50 percent and the degree of emission limitation defined by a reduction in emission rate from 12 to 20 percent. For imminent-term and near-term coal-fired steam generating units, the EPA is proposing a BSER of routine methods of operation and maintenance. Because of differences in performance between units, the EPA is proposing to determine the associated degree of emission limitation as no increase in emission rate. 
For natural gas- and oil-fired steam generating units, the EPA is proposing a BSER of routine methods of operation and maintenance and degrees of emission limitation of no increase in emission rate. However, because natural gas- and oil-fired steam generating units with similar annual capacity factors perform similarly to one another, the EPA is proposing presumptive standards of performance of 1,300 lb CO2/MWh-gross for base load units (i.e., those with annual capacity factors greater than 45 percent) and 1,500 lb CO2/MWh-gross for intermediate load units (i.e., those with annual capacity factors between 8 and 45 percent). Because natural gas- and oil-fired steam generating units with low load have large variations in emission rate, the EPA is not proposing BSER or degrees of emission limitation for those units in this action. However, the EPA is soliciting comment on a potential BSER of "clean fuels" and degree of emission limitation defined on a heat input basis by 120 to 130 lb CO2/MMBtu for low load natural gas-fired steam generating units and 150 to 170 lb CO2/MMBtu for low load oil-fired steam generating units. Also, because non-continental oil-fired steam generating units operate at intermediate and base load, and because there are relatively few of those units for which to define a limit on a fleet-wide basis, the EPA is proposing degrees of emission limitation for those units of no increase in emission rate and presumptive standards based on unit-specific emission rates, as detailed in section XI of this preamble. The EPA is soliciting comment on ranges of annual capacity factors to define the thresholds between the load levels and ranges in the degrees of emission limitation, as specified in section X.E of this preamble.
The remainder of this section is organized into the following subsections. Subsection B describes the proposed applicability requirements for existing steam generating units. Subsection C provides the explanation for the proposed subcategories. Subsection D contains, for coal-fired steam generating units, a summary of the systems considered for the BSER, detailed discussion of the systems and other options considered, and explanation and justification for the determination of BSER and degree of emission limitation. Subsection E contains, for natural gas- and oil-fired steam generating units, a summary of the systems considered for the BSER, detailed discussion of the systems and other options considered, and explanation and justification for the determination of BSER and degree of emission limitation.
Applicability Requirements for Existing Fossil Fuel-fired Steam Generating Units
For the emission guidelines, the EPA is proposing that a designated facility is any fossil fuel-fired electric utility steam generating unit (i.e., utility boiler) that: (1) was in operation or had commenced construction on or before January 8, 2014; (2) serves a generator capable of selling greater than 25 MW to a utility power distribution system; and (3) has a base load rating greater than 260 GJ/h (250 MMBtu/h) heat input of fossil fuel (either alone or in combination with any other fuel). Consistent with the implementing regulations, the term "designated facility" is used throughout this preamble to refer to the sources affected by these emission guidelines. For this action, consistent with prior CAA section 111 rulemakings concerning EGUs, the term "designated facility" refers to a single EGU that is affected by these emission guidelines. The rationale for this proposal concerning applicability is the same as that for 40 CFR part 60, subpart TTTT (80 FR 64543 - 44; October 23, 2015). We incorporate that discussion by reference here.
Section 111(a)(6) of the CAA defines an "existing source" as "any stationary source other than a new source." Therefore, the emission guidelines would not apply to any EGUs that are new after January 8, 2014, or modified or reconstructed after June 18, 2014, the applicability dates of 40 CFR part 60, subpart TTTT. In addition, the EPA is proposing to include in the applicability of the emission guidelines the same exemptions as discussed for 40 CFR part 60, subpart TTTT in section VII.E.1 of this preamble. Designated EGUs that may be excluded from a state's plan are: (1) units that are subject to 40 CFR part 60, subpart TTTT, as a result of commencing a qualifying modification or reconstruction; (2) steam generating units subject to a federally enforceable permit limiting net-electric sales to one-third or less of their potential electric output or 219,000 MWh or less on an annual basis and annual net-electric sales have never exceeded one-third or less of their potential electric output or 219,000 MWh; (3) non-fossil fuel units (i.e., units that are capable of deriving at least 50 percent of heat input from non-fossil fuel at the base load rating) that are subject to a federally enforceable permit limiting fossil fuel use to 10 percent or less of the annual capacity factor; (4) CHP units that are subject to a federally enforceable permit limiting annual net-electric sales to no more than either 219,000 MWh or the product of the design efficiency and the potential electric output, whichever is greater; (5) units that serve a generator along with other steam generating unit(s), where the effective generation capacity (determined based on a prorated output of the base load rating of each steam generating unit) is 25 MW or less; (6) municipal waste combustor units subject to 40 CFR part 60, subpart Eb; (7) commercial or industrial solid waste incineration units that are subject to 40 CFR part 60, subpart CCCC; or (8) EGUs that derive greater than 50 percent of the heat input from an industrial process that does not produce any electrical or mechanical output or useful thermal output that is used outside the affected EGU. The EPA solicits comment on the proposed definition of "designated facility" and applicability exemptions for fossil fuel-fired steam generating units. 
The exemptions listed above at (4), (5), (6), and (7) are among the current exemptions at 40 CFR 60.5509(b), as discussed in section VII.E.1 of this preamble. The exemptions listed above at (2), (3), and (8) are exemptions the EPA is proposing to revise for 40 CFR part 60, subpart TTTT, and the rationale for proposing the exemptions is in section VII.E.1 of this preamble. For consistency with the applicability requirements in 40 CFR part 60, subpart TTTT, we are proposing these same exemptions for the applicability of the emission guidelines.
The EPA is proposing to apply the same requirements to fossil fuel-fired steam generating units in non-continental areas (i.e., Hawaii, the Virgin Islands, Guam, American Samoa, the Commonwealth of Puerto Rico, and the Northern Mariana Islands) and non-contiguous areas (non-continental areas and Alaska) as the EPA is proposing for comparable units in the contiguous 48 states. However, units in non-continental and non-contiguous areas operate on small, isolated electric grids, may operate differently from units in the contiguous 48 states, and may have limited access to certain components of the proposed BSER due to their uniquely isolated geography or infrastructure. Therefore, the EPA is soliciting comment on the proposed BSER and degrees of emission limitation for units in non-continental and non-contiguous areas, and the EPA is soliciting comment on whether those units in non-continental and non-contiguous areas should be subject to different, if any, requirements.
Subcategorization of Fossil Fuel-fired Steam Generating Units
Steam generating units can have a broad range of technical and operational differences. Based on these differences, they may be subcategorized, and different BSER and degrees of emission limitation may be applicable to different subcategories. Subcategorizing allows for determining the most appropriate control requirements for a given class of steam generating unit. Therefore, the EPA is proposing subcategories for steam generating units based on fossil fuel type, operating horizon and load level, and is proposing different BSER and degrees of emission limitation for those different subcategories. The EPA notes that, in section XI.B of this preamble, comment is solicited on the compliance deadline (i.e., January 1, 2030), for imminent-term and near-term coal-fired steam generating units, and different subcategories of natural gas- and oil-fired steam generating units.
Subcategorization by Fossil Fuel Type
In the 2015 NSPS, the EPA promulgated GHG standards of performance for all new fossil fuel-fired steam generating units. 40 CFR 60.5509(a). Accordingly, existing fossil fuel-fired steam generating units are subject to regulation for GHG emissions under CAA section 111(d). In this action, the EPA is proposing definitions for subcategories of existing fossil fuel-fired steam generating units based on the type and amount of fossil fuel used in the unit. The subcategory definitions proposed for these emission guidelines are based on the definitions in 40 CFR part 63, subpart UUUUU, and using the fossil fuel definitions in 40 CFR part 60, subpart TTTT. 
A coal-fired steam generating unit is an electric utility steam generating unit or IGCC unit that meets the definition of "fossil fuel-fired" and that burns coal for more than 10.0 percent of the average annual heat input during the 3 calendar years prior to the proposed compliance deadline (i.e., January 1, 2030), or for more than 15.0 percent of the annual heat input during any one of those calendar years, or that retains the capability to fire coal after December 31, 2029.
An oil-fired steam generating unit is an electric utility steam generating unit meeting the definition of "fossil fuel-fired" that is not a coal-fired steam generating unit and that burns oil for more than 10.0 percent of the average annual heat input during the 3 calendar years prior to the proposed compliance deadline (i.e., January 1, 2030), or for more than 15.0 percent of the annual heat input during any one of those calendar years, and that no longer retains the capability to fire coal after December 31, 2029.
A natural gas-fired steam generating unit is an electric utility steam generating unit meeting the definition of "fossil fuel-fired" that is not a coal-fired or oil-fired steam generating unit and that burns natural gas for more than 10.0 percent of the average annual heat input during the 3 calendar years prior to the proposed compliance deadline (i.e., January 1, 2030), or for more than 15.0 percent of the annual heat input during any one of those calendar years, and that no longer retains the capability to fire coal after December 31, 2029. 
Subcategorization of Natural Gas- and Oil-fired Steam Generating Units by Load Level
The EPA is also proposing additional subcategories for oil-fired and natural gas-fired steam generating units, based on load levels: "low" load, defined by annual capacity factors less than 8 percent; "intermediate" load, defined by annual capacity factors greater than or equal to 8 percent and less than 45 percent; and "base" load, defined by annual capacity factors greater than or equal to 45 percent. In addition, the EPA is soliciting comment on a range from 5 to 20 percent to define the threshold value between low and intermediate load and a range from 40 to 50 percent to define the threshold value between intermediate and base load. The rationale for the proposed load thresholds is detailed in the description of the BSER for oil- and natural gas-fired steam generating units in section X.E of this preamble.
Subcategorization of Coal-fired Steam Generating Units by Operating Horizon and Load Level
As discussed in section IV of this preamble, the electric power sector is undergoing a period of significant change, with increases in the deployment of natural gas and renewable sources of electricity and decreases in the utilization of steam generating units. Many fossil fuel-fired steam generating units have plans to cease operations, are part of utilities with commitments to net zero power by certain dates, or are in states or localities with commitments to net zero power by certain dates. Over one-third of existing coal-fired steam generating capacity has planned to cease operation by 2032, and approximately half of the capacity has planned to cease operations by 2040. Certain technologies that are cost reasonable for EGUs that intend to operate for the long term are less cost reasonable for EGUs with shorter operating horizons because of shorter amortization periods and, for CCS, less time to utilize the IRC section 45Q tax credit. To accommodate this reality, and to limit unnecessary investment in facilities with shorter remaining operating periods, the EPA is proposing four subcategories for steam generating units by operating horizon (i.e., federally enforceable commitments to permanently cease operations) and, in one case, by load level (i.e., annual capacity factor) as well. "Imminent-term" steam generating units are those that choose to adopt federally enforceable commitments to permanently cease operations prior to January 1, 2032. "Near-term" steam generating units are those that choose to adopt federally enforceable commitments to permanently cease operations on or after January 1, 2032, and prior to January 1, 2035, and have federally enforceable annual capacity factor limits that are less than 20 percent. "Medium-term" steam generating units are those that choose to adopt federally enforceable commitments to permanently cease operations prior to January 1, 2040, and that are not imminent-term or near-term units. "Long-term" steam generating units are those that have not adopted federally enforceable commitments to permanently cease operations prior to January 1, 2040. Details regarding the implementation of subcategories in state plans are available in section XI.D of this preamble.
The EPA is proposing the imminent-term subcategory based on a 2-year operating horizon from the proposed compliance deadline (January 1, 2030, see section XI.B for additional details). This proposed subcategory is designed to accommodate units with operating horizons short enough that no additional CO2 control measures would be cost reasonable. The EPA is proposing the near-term subcategory to provide an alternative option for units that intend to operate for a slightly longer horizon but as peaking units, i.e., that intend to run at lower load levels. The load level of 20 percent for the near-term subcategory is based on spreading an average 2 years of generation (i.e., 50 percent in each year, a typical load level) that would occur under the imminent-term subcategory over the 5-year operating horizon of the near-term subcategory.
The EPA is proposing the 10-year operating horizon (i.e., January 1, 2040) as the threshold between medium-term and long-term subcategories because about half of the existing steam generating unit capacity has planned operation after that date. Additionally, long-term units will have a longer amortization period and may be better able to fully utilize the IRC section 45Q tax credit. The EPA is soliciting comment on the dates and load levels used to define the coal-fired subcategories. As noted in section X.D.1.a.ii.(C) of this preamble, the costs for CCS may be reasonable for units with amortization periods as short as 8 years. Therefore, the EPA is specifically soliciting comment on an operating horizon of between 8 and 10 years (i.e., January 1, 2038, to January 1, 2040) to define the date for the threshold between medium-term and long-term coal-fired steam generating units. 
Legal Basis for Subcategorization
As noted in section V of this preamble, the EPA has broad authority under CAA section 111(d) to identify subcategories. As also noted in section V, the EPA's authority to "distinguish among classes, types, and sizes within categories," as provided under CAA section 111(b)(2) and as we interpret CAA section 111(d) to provide as well, generally allows the Agency to place types of sources into subcategories when they have characteristics that are relevant to the controls that the EPA may determine to be the BSER for those sources. One element of the BSER is cost reasonableness. See CAA section 111(d)(1) (requiring the EPA, in setting the BSER, to "tak[e] into account the cost of achieving such reduction"). As noted in section V, the EPA's long-standing regulations under CAA section 111(d) explicitly recognize that subcategorizing may be appropriate for sources based on the "costs of control." Subcategorizing on the basis of federally enforceable dates for permanently ceasing operation is consistent with a central characteristic of the coal-fired power industry that is relevant for determining the cost reasonableness of control requirements: A large percentage of the industry has announced, or is expected to announce, dates for ceasing operation, and the fact that many coal-fired steam generating units intend to cease operation affects what controls are "best" for different subcategories. Whether the costs of control are reasonable depends in part on the period of time over which the affected sources can amortize those costs. Sources that have shorter operating horizons will have less time to amortize capital costs and the controls will thereby be less cost-effective and therefore may not qualify as the BSER. 
	In addition, subcategorizing by length of period of continued operation is similar to two other bases for subcategorization on which the EPA has relied in prior rules, each of which implicates the cost reasonableness of controls: The first is load level, noted in section X.C of this preamble. For example, in the 2015 NSPS, the EPA divided new natural gas-fired combustion turbines into the subcategories of base load and non-base load. 80 FR 64510, 64602 (table 15) (October 23, 2015). The EPA did so because the control technologies that were "best"-including consideration of feasibility and cost-reasonableness -- depended on how much the unit operated. The load level, which relates to the amount of product produced on a yearly or other basis, bears similarity to a limit on a period of continued operation, which concerns the amount of time remaining to produce the product. In both cases, certain technologies may not be cost reasonable because of the capacity to produce product -- i.e., because the costs are spread over less product produced. 
The second is fuel type, as also noted in section X.C of this preamble. The 2015 NSPS provides an example of this type of subcategorization as well. There, the EPA divided new combustion turbines into subcategories on the basis of type of fuel combusted. Id. Subcategorizing on the basis of the type of fuel combusted may be appropriate when different controls have different costs, depending on the type of fuel, so that the cost-reasonableness of the control depends on the type of fuel. In that way, it is similar to subcategorizing by operating horizon because in both cases, the subcategory is based upon the cost reasonableness of controls. Subcategorizing by fuel type presents an additional analogy to the present case of subcategorizing on the basis of the length of time when the source will continue to operate because this timeframe is tantamount to the length of time when the source will continue to combust the fuel. Subcategorizing on this basis may be appropriate when different controls for a particular fuel have different costs, depending on the length of time when the fuel will continue to be combusted, so that the cost-reasonableness of controls depends on that timeframe. Some prior EPA rules for coal-fired sources have made explicit the link between length of time for continued operation and type of fuel combusted by codifying federally enforceable retirement dates as the dates by which the source must "cease burning coal."
Determination of BSER for Coal-fired Steam Generating Units
The EPA evaluated two primary control technologies as potentially representing the BSER for existing coal-fired steam generating units: CCS and natural gas co-firing. This section of the preamble discusses each of these alternatives, based on the criteria described in section V.C of this preamble. 
The EPA is proposing CCS with 90 percent capture as BSER for long-term coal-fired steam generating units, that is, ones that are expected to continue to operate past 2039, because CCS can achieve an appropriate amount of emission reductions and satisfies the other BSER criteria. Because CCS is less cost reasonable for EGUs that do not plan to operate in the long term, the EPA is proposing other measures as BSER for the other subcategories of existing coal-fired steam generating units. 
Specifically, for medium-term units, that is, ones that choose to adopt federally enforceable commitments to permanently cease operations after December 31, 2031, and before January 1, 2040, and are not near-term units, the EPA is proposing a BSER of 40 percent natural gas co-firing on a heat input basis. However, the EPA is taking comment on the date that defines the threshold between medium-term and long-term coal-fired steam generating units, and it is possible that the costs of CCS may be considered reasonable for some portion of the units that may be covered by the medium-term subcategory as proposed.
For imminent-term and near-term units, that is, ones that choose to adopt federally enforceable commitments to permanently cease operations before January 1, 2032, and between December 31, 2031, and January 1, 2035, coupled with an annual capacity factor limit, respectively, the EPA is proposing a BSER of routine methods of operation and maintenance that maintain current emission rates.
Long-term Coal-fired Steam Generating Units
In this section of the preamble, the EPA evaluates CCS and natural gas co-firing as potential BSER for long-term coal-fired steam generating units.
The EPA is proposing CCS with 90 percent capture of CO2 at the stack as BSER for long-term coal-fired steam generating units. The Agency is taking comment on the range of the amount of capture of CO2 from 90 to 95 percent. CCS achieves substantial reductions in emissions and can capture and permanently sequester more than 90 percent of CO2 emitted by coal-fired steam generating units. The technology is adequately demonstrated, as indicated by the facts that it has been operated at scale and is widely applicable to sources, and there are vast sequestration opportunities across the continental U.S. Additionally, accounting for the tax credit under IRC section 45Q, the costs for CCS are reasonable. Moreover, the non-air quality health and environmental impacts and energy requirements of CCS are not unreasonably adverse. These factors provide the basis for proposing CCS as BSER for these sources. In addition, determining CCS as the BSER promotes this useful control technology.
The EPA also evaluated natural gas co-firing at 40 percent of heat input as a potential BSER for long-term coal-fired steam generating units. While the unit level emission rate reductions of 16 percent achieved by 40 percent natural gas co-firing are reasonable, those reductions are less than CCS with 90 percent capture of CO2. Therefore, because CCS achieves more reductions at the unit level and is cost reasonable, the EPA is not proposing natural gas co-firing as the BSER for these units.
 CCS
In this section of the preamble, the EPA evaluates the use of CCS as the BSER for existing long-term coal-fired steam generating units. This section incorporates by reference the parts of section VII.F.3.b.iii of this preamble that discuss the aspects of CCS that are common to new combustion turbines and existing steam generating units. This section also discusses additional aspects of CCS that are relevant for existing steam generating units and, in particular, long-term units. 
Adequately Demonstrated
The EPA is proposing that CCS is technically feasible and has been adequately demonstrated, based on the utilization of the technology at existing coal-fired steam generating units and industrial sources in addition to combustion turbines. While the EPA would propose that CCS is adequately demonstrated on those bases alone, this determination is further corroborated by EPAct05-assisted projects.
The fundamental CCS technology has been in existence for decades, and the industry has extensive experience with and knowledge about it. Thus, the EPA will explain how existing and planned fossil fuel-fired electric power plants and other industrial projects that have installed or expect to install some or all of the components of CCS technology support the EPA's proposed determination that CCS is adequately demonstrated for existing coal-fired power plants, and the EPA will explain how EPAct05-assisted projects support that proposed determination, consistent with the legal interpretation of the EPAct05 in section VII.F.3.b.iii.(A).
CO2 Capture Technology
The technology of CO2 capture, in general, is detailed in section VII.F.3.b.iii of this preamble. As noted there, solvent-based (i.e., amine-based) post-combustion CO2 capture is the technology that is most applicable at existing coal-fired steam generating units. Technology considerations specific to existing coal-fired steam generating units, including energy demands, non-GHG emissions, and water use and siting, are discussed in section X.D.1.a.iii of this preamble. As detailed in section VII.F.3.b.iii.(A) of this preamble, the CO2 capture component of CCS has been demonstrated at existing coal-fired steam generating units, industrial processes, and existing combustion turbines. In particular, SaskPower's Boundary Dam Unit 3 has demonstrated capture rates of 90 percent of the CO2 in flue gas using solvent-based post-combustion capture retrofitted to existing coal-fired steam generating units. While the EPA would propose that the CO2 capture component of CCS is adequately demonstrated on the basis of Boundary Dam Unit 3 alone, CO2 capture has been further demonstrated at other coal-fired steam generating units (CO2 capture from slipstreams of AES's Warrior Run and Shady Point) and industrial processes (e.g., Quest CO2 capture project), detailed descriptions of which are provided in section VII.F.3.b.iii.(A)2 of this preamble. The core technology of CO2 capture applied to combustion turbines is similar to that of coal-fired steam generating units (i.e., both may use amine solvent-based methods); therefore the demonstration of CO2 capture at combustion turbines (e.g., the Bellingham, Massachusetts, combined cycle unit), as detailed in section VII.F.3.b.iii.(A)3 of this preamble, provide additional support for the adequate demonstration of CO2 capture for coal-fired steam generating units. Finally, EPAct05-assisted CO2 capture projects (e.g., Petra Nova) further corroborate the adequate demonstration of CO2 capture.
CO2 Transport
As discussed in section VII.F.3.b.iii of this preamble, CO2 pipelines are available and their network is expanding in the U.S., and the safety of existing and new CO2 pipelines is comprehensively regulated by PHMSA. Other modes of CO2 transportation also exist.
Based on data from DOE/NETL studies of storage resources, 77 percent of existing coal-fired steam generating units that have planned operation during or after 2030 are within 80 km (50 miles) of potential saline sequestration sites, and another 5 percent are within 100 km (62 miles) of potential sequestration sites. Additionally, of the coal-fired steam generating units with planned operation during or after 2030, 90 percent are located within 100 km of one or more types of sequestration formations, including deep saline, unmineable coal seams, and oil and gas reservoirs. This distance is consistent with the distances referenced in studies that form the basis for transport cost estimates in this proposal.
Geologic Sequestration of CO2 
Geologic sequestration (i.e., the long-term containment of a CO2 stream in subsurface geologic formations) is well proven and broadly available throughout the U.S. Geologic sequestration is based on a demonstrated understanding of the processes that affect the fate of CO2 in the subsurface. As discussed in section VIII.F.3.a.iii of this preamble, there have been numerous instances of geologic sequestration in the U.S. and overseas, and the U.S. has developed a detailed set of regulatory requirements to ensure the security of sequestered CO2. This regulatory framework includes the UIC Class VI well regulations, which are under the authority of SDWA, and the GHGRP, under the authority of the CAA.
Geologic sequestration potential for CO2 is widespread and available throughout the U.S. Through an availability analysis of sequestration potential in the U.S. based on resources from the DOE, the USGS, and the EPA, the EPA found that there are 43 states with access to, or are within 100 km from, onshore or offshore storage in deep saline formations, unmineable coal seams, and depleted oil and gas reservoirs.
Sequestration potential as it relates to distance from existing resources is a key part of the EPA's regular power sector modeling development, using data from DOE/NETL studies. These data show that of the coal-fired steam generating units with planned operation during or after 2030, 60 percent are located within the boundary of a saline reservoir, 77 percent are located within 40 miles (80 km) of the boundary of a saline reservoir, and 82 percent are located within 62 miles (100 km) of a saline reservoir. Additionally, of the coal-fired steam generating units with planned operation during or after 2030, 90 percent are located within 100 km of any of the considered formations, including deep saline, unmineable coal seams, and oil and gas reservoirs.
Costs 
The EPA has analyzed the costs of CCS for existing coal-fired long-term sources, including costs for CO2 capture, transport, and sequestration. The EPA is proposing that this analysis demonstrates that the costs of CCS for these sources are reasonable. 
The EPA assessed costs of CCS for a reference unit as well as the average cost for the fleet of coal-fired steam generating units with planned operation during or after 2030. The reference unit, which represents an average unit in the fleet, has a 400 MW-gross nameplate capacity and a 10,000 Btu/kWh heat rate. Applying CCS to the reference unit with a 12-year amortization period and assuming a 50 percent annual capacity factor -- a typical value for the fleet -- results in annualized total costs that can be expressed as an abatement cost of $14/ton of CO2 reduced and an incremental cost of electricity of $12/MWh. For the fleet of coal-fired steam generating units with planned operation during or after 2030, and assuming a 12-year amortization period and 50 percent annual capacity factor, the average total costs of CCS are $8/ton of CO2 reduced and $7/MWh. Included in these estimates is the EPA's assessment that the transport and storage costs are roughly $30/ton, on average. These total costs also account for the IRC section 45Q tax credit, a detailed discussion of which is provided in section VII.F.3.b.iii.(B)3 of this preamble. Compared to the representative costs of controls for other pollutants (i.e., wet FGD SO2 emission control costs of $15.00 to $18.50/MWh as detailed in section VII.F.3.b.iii.(B)5 of this preamble), the costs for CCS on long-term coal-fired steam generating units are similar or better on an incremental cost of electricity ($/MWh) basis. Therefore, the EPA is proposing that for the purposes of the BSER analysis, CCS is cost reasonable for long-term coal-fired steam generating units. The EPA also evaluated costs of CCS under various other assumptions of amortization period and annual capacity factor. Finally, it is noted that these CCS costs are lower than those in prior rulemakings due to the IRC section 45Q tax credit and reductions in the cost of the technology.
CO2 Capture Costs at Existing Coal-fired Steam Generating Units
A variety of sources provide information for the cost of CCS systems, and they generally agree around a range of cost. The EPA has relied heavily on information recently developed by NETL, in the U.S. Department of Energy, in particular, "Cost and Performance Baseline for Fossil Energy Plants," and the "Pulverized Coal Carbon Capture Retrofit Database." In addition, the EPA developed an independent engineering cost assessment for CCS retrofits, with support from Sargent and Lundy.
CO2 Transport and Sequestration Costs
 As discussed in section VII.F.3.b.iii. of this preamble, NETL's "Quality Guidelines for Energy System Studies; Carbon Dioxide Transport and Sequestration Costs in NETL Studies" is one of the more comprehensive sources of information on CO2 transport and storage costs available. The Quality Guidelines provide an estimation of transport costs for a single point-to-point pipeline. Estimated costs reflect pipeline capital costs, related capital expenditures, and operations and maintenance costs. These Quality Guidelines also provide an estimate of sequestration costs reflecting the cost of site screening and evaluation, permitting and construction costs, the cost of injection wells, the cost of injection equipment, operation and maintenance costs, pore volume acquisition expense, and long-term liability protection. 
NETL's Quality Guidelines model costs for a given cumulative storage potential. At a storage potential of 25 gigatons of CO2, costs range between $7.54/ton ($8.32/metric ton) sequestered (in the Illinois Basin) and $18.00/ton ($19.84/metric ton) sequestered (in the Powder River Basin).
Amortization Period and Annual Capacity Factor
In the EPA's cost analysis for long-term coal-fired steam generating units, the EPA assumes a 12-year amortization period and a 50 percent annual capacity factor. The 12-year amortization period is consistent with the period of time during which the IRC section 45Q tax credit can be claimed and the 50 percent annual capacity factor is consistent with the historical fleet average. However, increases in utilization are likely to occur for units that apply CCS due to the incentives provided by the IRC section 45Q tax credit. Therefore, the EPA also assessed the costs for CCS retrofitted to existing coal-fired steam generating units assuming a 70 percent annual capacity factor. For a 70 percent annual capacity factor and a 12-year amortization period, the costs for the reference unit are -$8/ton of CO2 reduced and -$7/MWh. For either capacity factor assumption, the $/MWh costs are comparable to or less than the representative cost of installing and operating wet FGD, costs for which are detailed in VII.F.3.b.iii.(B)5. 
As noted in section X.C.3 of this preamble, the EPA is also taking comment on the date for the threshold between medium-term and long-term coal-fired steam generating units. For a 70 percent annual capacity factor and an 8-year amortization period, costs for the reference unit are $24/ton of CO2 reduced and $21/MWh, and it is possible that the cost of generation may be reasonable relative to the representative cost for wet FGD. However, CCS may be less cost favorable for units with shorter amortization periods. For a 70 percent annual capacity factor and a 7-year amortization period, costs for the reference unit are $34/ton of CO2 reduced and $21/MWh. Additional details of the cost analysis are available in the GHG Mitigation Measures  -  111(d) TSD.
Comparison to Costs for CCS in Prior Rulemakings
In the CPP and ACE Rule, the EPA determined that CCS did not qualify as the BSER due to cost considerations. Two key developments have led the EPA to reevaluate this conclusion: the costs of CCS technology have fallen and, most importantly, the extension and increase in the IRC section 45Q tax credit, as included in the IRA, in effect provide a significant stream of revenue for sequestered CO2 emissions. The CPP and ACE Rule relied on a 2015 NETL report estimating the cost of CCS. NETL has issued updated reports to incorporate the latest information available, most recently in 2022, which show cost reductions. The 2015 report estimated levelized cost of CCS at a new pulverized coal facility at $74/MWh (2022$), while the 2022 report estimated levelized cost at $44/MWh (2022$). Additionally, the IRA increased the IRC section 45Q tax credit from $50/metric ton to $85/metric ton (and, in the case of EOR or certain industrial uses, from $35/metric ton to $60/metric ton), assuming prevailing wage and apprenticeship conditions are met. The combination of lower costs and higher tax credits significantly improves the cost effectiveness of CCS for purposes of determining whether it qualifies as the BSER.
Non-air Quality Health and Environmental Impact and Energy Requirements
CCS for steam generating units is not expected to have unreasonable adverse consequences related to non-air quality health and environmental impacts or energy requirements. As discussed later in the preamble, the EPA has considered non-GHG emissions impacts, the water use impacts, the transport and sequestration of captured CO2, and energy requirements resulting from CCS. Because the non-air quality health and environmental impacts are closely related to the energy requirements, the latter are discussed first.
Energy Requirements
For a steam generating unit with 90 percent amine-based CO2 capture, parasitic/auxiliary energy demand increases and the net power output decreases. Amine-based CO2 capture is an energy-intensive process. In particular, the solvent regeneration process requires substantial amounts of heat in the form of steam and CO2 compression requires a large amount of electricity. Heat and power for the CO2 capture equipment can be provided either by using the steam and electricity produced by the steam generating unit or by an auxiliary cogeneration unit. However, any auxiliary source of heat and power is part of the "designated facility," along with the steam generating unit. The standards of performance apply to the designated facility. Thus, any CO2 emissions from the connected auxiliary equipment need to be captured or they will increase the facility's emission rate.
Using integrated heat and steam can reduce the capacity (i.e., the amount of electricity that a unit can distribute to the grid) of a 474 MW-net (501 MW-gross) coal-fired steam generating unit without CCS to 425 MW-net with CCS and contributes to a reduction in net efficiency of 23 percent. Despite decreases in efficiency, IRC section 45Q tax credits provide an incentive for increased utilization. The Agency is proposing that the energy penalty is relatively minor compared to the GHG benefits of CCS and, therefore, does not disqualify CCS as being considered the BSER for existing coal-fired steam generating units.
Additionally, the EPA considered the impacts on the power sector, on a nationwide and long-term basis, of determining CCS to be the BSER for long-term coal-fired steam generating units. The EPA is proposing that designating CCS as the BSER for existing long-term coal-fired steam generating units would have limited and non-adverse impacts on the long-term structure of the power sector. Absent the requirements defined in this action, the EPA projects that 9 GW of coal-fired steam generating units would apply CCS by 2030 and 35 GW of coal-fired steam generating units, some without controls, would remain in operation in 2040. Designating CCS to be the BSER for existing long-term coal-fired steam generating units would likely result in more of the coal-fired steam generating unit capacity applying CCS. The time available before the compliance deadline of January 1, 2030, provides for adequate resource planning, including accounting for the downtime necessary to install the CO2 capture equipment at long-term coal-fired steam generating units. While the IRC 45Q tax credit is available, long-term coal-fired steam generating units are anticipated to run at base load conditions. Total generation from coal-fired steam generating units in the other subcategories would gradually decrease over an extended period of time through 2039, subject to the commitments those units have chosen to adopt. Any decreases in the amount of generation from coal-fired steam generating units, whether locally or more broadly, are compensated for by increased generation from other sources. Additionally, for the long-term units applying CCS, the EPA is proposing the increase in the annualized cost of generation for those units is reasonable. Therefore, the EPA is proposing that there would be no unreasonable impacts on the reliability of electricity generation. A broader discussion of reliability impacts of the proposed actions is available in section XIV.F of this preamble. Finally, changes in the amount of generation from coal-fired steam generating units may contribute to additional generation from combined cycle combustion turbines. Since these EGUs have lower GHG and criteria pollutant emission rates than existing coal-fired steam generating units, overall emissions from the power sector would likely decrease. 
Non-GHG Emissions
For amine-based CO2 capture retrofits to coal-fired steam generating units, decreased efficiency and increased utilization would otherwise result in increases of non-GHG emissions; however, importantly, most of those impacts would be mitigated by the flue gas conditioning required by the CO2 capture process and by other control equipment that the units already have or may need to install to meet other CAA requirements. Decreases in efficiency result in increases in the relative amount of coal combusted per amount of electricity generated and would otherwise result in increases in the amount of non-GHG pollutants emitted per amount of electricity generated. Additionally, increased utilization would otherwise result in increases in total non-GHG emissions. However, substantial flue gas conditioning, particularly to remove SO2, is critical to limiting solvent degradation and maintaining reliable operation of the capture plant. To achieve the necessary limits on SO2 levels in the flue gas for the capture process, steam generating units will need to add an FGD column, if they do not already have one, and may need an additional polishing column (i.e., quencher). A wet FGD column and a polishing column will also reduce the emission rate of particulate matter. Additional improvements in particulate matter removal may also be necessary to reduce the fouling of other components of the capture process (e.g., heat exchangers). NOx emissions can cause solvent degradation and nitrosamine formation by chemical absorption of NOX, depending on the chemical structure of the solvent. A conventional multistage water wash and mist eliminator at the exit of the CO2 scrubber is effective at removal of gaseous amine and amine degradation products (e.g., nitrosamine) emissions.  NOX levels of the flue gas required to avoid solvent degradation and nitrosamine formation in the CO2 scrubber vary. For most units, the requisite limits on NOX levels to assure that the CO2 capture process functions properly may be met by the existing NOX combustion controls, and those units may not need to install SCR for process purposes. However, most existing coal-fired steam generating units either already have SCR or will be covered by proposed Federal Implementation Plan (FIP) requirements regulating interstate transport of NOX (as an ozone precursors) from EGUs. See 87 FR 20036 (April 6, 2022). For units not otherwise required to have SCR, increased utilization from a CO2 capture retrofit could result in increased emissions that may trigger New Source Review (NSR) permitting requirements and, in turn, may require the installation of SCR for those units. See section XIII.A of this preamble.
Water Use and Siting
Water consumption at the plant increases when applying carbon capture, due to solvent water makeup and cooling demand. Water consumption can increase by 36 percent on a gross basis. A separate cooling water system dedicated to a CO2 capture plant may be necessary. However, the amount of water consumption depends on the design of the capture system. For example, the cooling system cited in the CCS feasibility study for SaskPower's Shand Power station would rely entirely on water condensed from the flue gas and thus would not require any increase in external water consumption. Regions with limited water supply may rely on dry or hybrid cooling systems, although, in areas with adequate water, wet cooling systems can be more effective.
With respect to siting considerations, CO2 capture systems have a sizeable physical footprint and a consequent land-use requirement. The EPA is proposing that the water use and siting requirements are manageable and therefore the EPA does not expect any of these considerations to preclude coal-fired power plants generally from being able to install and operate CCS. However, the EPA is soliciting comment on these issues. 
Transport and Geologic Sequestration
As noted in section VII.F.3.b.iii of this preamble, PHMSA oversight of CO2 pipeline safety protects against environmental release during transport and UIC Class VI regulations under the SDWA, in tandem with GHGRP subpart RR requirements, ensure the protection of USDWs and the security of geologic sequestration. 
Extent of Reductions in CO2 Emissions
CCS can be applied to coal-fired steam generating units at the source and reduce the CO2 emission rate by 90 percent or more. Increased steam and power demand have a small impact on the reduction in emission rate that occurs with 90 percent capture. According to the 2016 NETL Retrofit report, 90 percent capture will result in emission rates that are 88.4 percent lower on a lb/MWh-gross basis and 87.1 percent lower on a lb/MWh-net basis compared to units without capture. After capture, CO2 can be transported and securely sequestered. Although steam generating units with CO2 capture will have an incentive to operate at higher utilization because the cost to install the CCS system is largely fixed and the IRC section 45Q tax credit increases based on the amount of CO2 captured and sequestered, any increase in utilization will be far outweighed by the substantial reductions in emission rate.
Technology Advancement
The EPA considered the potential impact of designating CCS as the BSER for long-term coal-fired steam generating units on technology advancement, and the EPA is proposing that designating CCS as the BSER will provide for meaningful advancement of CCS technology, for many of the same reasons as noted in section VII.F.3.b.iii.(F) of this preamble. 
Natural Gas Co-firing
The EPA also evaluated natural co-firing at 40 percent of the heat input as the potential BSER for long-term coal-fired steam generating units. Because the EPA is proposing natural gas co-firing as the BSER for medium-term units, details that are common to medium-term and long-term units are discussed in section X.D.2.b of the preamble. Based on the discussion therein, the EPA is proposing that natural gas co-firing is adequately demonstrated and that the non-air quality health and environmental effects and energy requirements are not unreasonable. The costs of natural gas co-firing for a long-term unit may also be reasonable. For example, for a representative unit with a 10-year amortization period, the cost of reductions is $53/ton of CO2. Finally, while the unit-level emission rate reductions of 16 percent achieved by 40 percent natural gas co-firing are reasonable, those reductions are less than CCS with 90 percent capture. Therefore, because CCS achieves more reductions at the unit level and is proposed as cost reasonable for long-term units, the EPA is not proposing natural gas co-firing as the BSER for long-term coal-fired steam generating units.
Conclusion
The EPA proposes that CCS at a capture rate of 90 percent is the BSER for long-term coal-fired steam generating units because CCS is adequately demonstrated, as indicated by the facts that it has been operated at scale and is widely applicable to sources, and there are vast sequestration opportunities across the continental U.S. Additionally, accounting for the tax credit under IRC section 45Q, the costs for CCS are reasonable. Moreover, any adverse non-air quality health and environmental impacts and energy requirements of CCS, including impacts on the power sector on a nationwide basis, are limited and are outweighed by the benefits of the significant emission reductions at reasonable cost. In contrast, co-firing 40 percent natural gas would achieve far fewer emission reductions without improving the cost effectiveness of the control strategy. These considerations provide the basis for proposing CCS as the best of the systems of emission reduction for long-term coal-fired power plants. In addition, determining CCS as the BSER promotes this useful control technology. 
Medium-term Coal-fired Steam Generating Units
In this section of the preamble, the EPA evaluates CCS and natural gas co-firing as potential BSER for medium-term coal-fired steam generating units.
In section X.D.1.a of this preamble, the EPA evaluated CCS with 90 percent capture of CO2 as the BSER for long-term coal-fired steam generating units. Much of this evaluation is relevant for medium-term units. However, because they have shorter operating horizons and, as a result, a shorter period for amortization and for collecting the IRC section 45Q tax credits, CCS would be less cost effective for those units. Therefore, the EPA is not proposing CCS as BSER for medium-term coal-fired steam generating units. 
Instead, the EPA is proposing that 40 percent natural gas co-firing on a heat input basis is the BSER for medium-term coal-fired steam generating units. Co-firing 40 percent natural gas, on an annual average heat input basis, results in a 16 percent reduction in CO2 emission rate. The technology has been adequately demonstrated, can be implemented at reasonable cost, does not have adverse non-air quality health and environmental impacts or energy requirements, and achieves meaningful reductions in CO2 emissions. Co-firing also advances useful control technology and has acceptable national and long-term impacts on the energy sector, which provide additional, although not essential, support for treating it as the BSER.
CCS
In this section of the preamble, the EPA evaluates the use of CCS as the BSER for existing medium-term coal-fired steam generating units. This evaluation is much the same as the evaluation for long-term units, with the important difference of costs. 
For long-term units, as discussed earlier in this preamble, the EPA's analysis used to evaluate the reasonableness of CCS costs employs a 12-year amortization period, which is consistent with the period of time during which the IRC section 45Q tax credit can be claimed. However, existing coal-fired steam generating units that choose to adopt federally enforceable commitments to permanently cease operations prior to 2040 -- ones in the medium-term subcategory, as well as in the near-term, and imminent-term subcategories -- would have a shorter period to amortize capital costs and also would not be able to fully utilize the IRC section 45Q tax credit. As a result, for these sources, the cost effectiveness of CCS is less favorable. As noted in section X.D.1.a.ii.(C) of this preamble, for a 70 percent annual capacity factor and a 7-year amortization period, costs for the reference unit are $39/ton of CO2 reduced and $34/MWh. This $/MWh generation cost is less favorable relative to the representative cost ($/MWh) for wet FGD, the costs for which are detailed in section VII.F.3.b.iii.(B)5. Due to the higher incremental cost of generation, the EPA is not proposing CCS as the BSER for medium-term coal-fired steam generating units.
While the EPA is not proposing CCS as BSER for the proposed subcategory of medium-term units, the EPA is taking comment on what dates most appropriately define the threshold between medium-term and long-term units and the EPA is also taking comment on the level of costs of CCS that should be considered reasonable.
Natural Gas Co-firing
In this section of the preamble, the EPA evaluates natural gas co-firing as potential BSER for medium-term coal-fired steam generating units. Considerations that are common to the proposed subcategories of existing coal-fired steam generating units are discussed in this section (X.D.1.a) of the preamble, in addition to considerations that are specific to medium-term units.
For a coal-fired steam generating unit, the substitution of natural gas for some of the coal, so that the unit fires a combination of coal and natural gas, is known as "natural gas co-firing." The EPA is proposing natural gas co-firing at a level of 40 percent of annual heat input as BSER for medium-term coal-fired steam generating units. 
Adequately Demonstrated
The EPA is proposing to find that natural gas co-firing at the level of 40 percent of annual heat input is adequately demonstrated for coal-fired steam generating units. Many existing coal-fired steam generating units already use some amount of natural gas, and several have co-fired at relatively high levels at or above 40 percent of heat input in recent years. 
Boiler Modifications
Most existing coal-fired steam generating units can be modified to co-fire natural gas in any desired proportion with coal, up to 100 percent natural gas. Generally, the modification of existing boilers to enable or increase natural gas firing typically involves the installation of new gas burners and related boiler modifications, including, for example, new fuel supply lines and modifications to existing air ducts. The introduction of natural gas as a fuel can reduce boiler efficiency slightly, due in large part to the relatively high hydrogen content of natural gas. However, since the reduction in coal can result in reduced auxiliary power demand, the overall impact on net heat rate can range from a 2 percent increase to a 2 percent decrease.
It is common practice for steam generating units to have the capability to burn multiple fuels onsite, and of the 565 coal-fired steam generating units operating at the end of 2021, 249 of them reported consuming natural gas as a fuel or startup source. Coal-fired steam generating units often use natural gas or oil as a startup fuel, to warm the units up before running them at full capacity with coal. While startup fuels are generally used at low levels (up to roughly 1 percent of capacity on an annual average basis), some coal-fired steam generating units have co-fired natural gas at considerably higher shares. Based on hourly reported CO2 emission rates from the start of 2015 through the end of 2020, 29 coal-fired steam generating units co-fired with natural gas at rates at or above 60 percent of capacity on an hourly basis. The capability of those units on an hourly basis is indicative of the extent of boiler burner modifications and sizing and capacity of natural gas pipelines to those units, and implies that those units are technically capable of co-firing at least 60 percent natural gas on a heat input basis on average over the course of an extended period (e.g., a year). Additionally, during that same 2015 through 2020 period, 29 coal-fired steam generating units co-fired natural gas at over 40 percent on an annual heat input basis. Because of the number of units that have demonstrated co-firing above 40 percent of heat input, the EPA is proposing that co-firing at 40 percent is adequately demonstrated. A more detailed discussion of the record of natural gas co-firing, including current trends, at coal-fired steam generating units is included in the GHG Mitigation Measures  -  111(d) TSD.
Natural Gas Pipeline Development
In addition to any potential boiler modifications, the supply of natural gas is necessary to enable co-firing at existing coal-fired steam boilers. As discussed in the previous section, many plants already have at least some access to natural gas. In order to increase natural gas access beyond current levels, many will find it necessary to construct natural gas supply pipelines.
The U.S. natural gas pipeline network consists of approximately 3 million miles of pipelines that connect natural gas production with consumers of natural gas. To increase natural gas consumption at a coal-fired boiler without sufficient existing natural gas access, it is necessary to connect the facility to the natural gas pipeline transmission network via the construction of a lateral pipeline. The cost of doing so is a function of the total necessary pipeline capacity (which is characterized by the length, size, and number of laterals) and the location of the plant relative to the existing pipeline transmission network. The EPA estimated the costs associated with developing new lateral pipeline capacity sufficient to meet 60 percent of the net summer capacity at each coal-fired steam generating unit. As discussed in the GHG Mitigation Measures  -  111(d) TSD, the EPA estimates that this lateral capacity would be sufficient to enable each unit to achieve 40 percent natural gas co-firing on an annual average basis. 
The EPA considered the availability of the upstream natural gas pipeline capacity to satisfy the assumed co-firing demand implied by these new laterals. This analysis included pipeline development at all EGUs that could be included in this subcategory. The EPA's assessment reviewed the reasonableness of each assumed new lateral by determining whether the peak gas capacity of that lateral could be satisfied without modification of the transmission pipeline systems to which it is assumed to be connected. This analysis found that most, if not all, existing pipeline systems are currently able to meet the peak needs implied by these new laterals in aggregate, assuming that each existing coal-fired unit in the analysis co-fired with natural gas at a level implied by these new laterals, or 60 percent of net summer generating capacity. While this is a reasonable assumption for the analysis to support this mitigation measure in the BSER context, it is also a conservative assumption that overstates the amount of natural gas co-firing expected under the proposed rule.
The maximum amount of pipeline capacity, if all coal-fired steam capacity in the medium-term subcategory implemented the proposed BSER by co-firing 40 percent natural gas, would be a fraction of the pipeline capacity constructed recently. The EPA estimates that this maximum total capacity would be about 17.3 billion cubic feet per day, which would require almost 4,000 miles of pipeline costing roughly $13.3 billion. Over 5 years, this maximum total incremental pipeline capacity would amount to 800 miles per year and approximately $2.7 billion per year in capital expenditures, on average. By comparison, based on data collected by EIA, the total annual mileage of natural gas pipelines constructed over the 2017 - 2021 period ranged from approximately 1,000 to 2,500 miles per year, with a total capacity of 10 to 25 billion cubic feet per day. This represents an estimated annual investment of up to nearly $15 billion. These historical annual values are much higher than the maximum annual values that could be expected under this proposed BSER measure -- which, as noted above, represent a conservative estimate that overstates the amount of co-firing that the EPA projects would occur under this proposed rule. 
These conservatively high estimates of pipeline requirements also compare favorably to industry projections of future pipeline capacity additions. Based on a review of a 2018 industry report, titled "North America Midstream Infrastructure through 2035: Significant Development Continues," investment in midstream infrastructure development is expected to average about $37 billion per year through 2035, which is lower than historical levels. Approximately $10 to $20 billion annually is expected to be invested in natural gas pipelines through 2035. This report also projects that an average of over 1,400 miles of new natural gas pipeline will be built through 2035, which is similar to the approximately 1,670 miles that were built on average from 2013 to 2017. These values are considerably greater than the average annual expenditure of $2.7 billion on 800 miles per year of new pipeline construction that would be necessary for the entire operational fleet of coal-fired steam generating units to co-fire with natural gas. The actual pipeline investment for this subcategory would be substantially lower.
Costs
The capital costs associated with the addition of new gas burners and other necessary boiler modifications depend on the extent to which the current boiler is already able to co-fire with some natural gas and on the amount of gas co-firing desired. The EPA estimates that, on average, the total capital cost associated with modifying existing boilers to operate at up to 100 percent of heat input using natural gas is approximately $52/kW. These costs could be higher or lower, depending on the equipment that is already installed and the expected impact on heat rate or steam temperature. 
While fixed O&M (FOM) costs can potentially decrease as a result of decreasing the amount of coal consumed, it is common for plants to maintain operation of one coal pulverizer at all times, which is necessary for maintaining several coal burners in continuous service. In this case, coal handling equipment would be required to operate continuously and therefore natural gas co-firing would have limited effect on reducing the coal-related FOM costs. Although, as noted, coal-related FOM costs have the potential to decrease, the EPA does not anticipate a significant increase in impact on FOM costs related to co-firing with natural gas.
In addition to capital and FOM cost impacts, any additional natural gas co-firing would result in incremental costs related to the differential in fuel cost, taking into consideration the difference in delivered coal and gas prices, as well as any potential impact on the overall net heat rate. The EPA's post-IRA 2022 reference case projects that in 2030, the average delivered price of coal will be $1.47/MMBtu and the average delivered price of natural gas will be $2.53/MMBtu. Thus, assuming the same level of generation and no impact on heat rate, the additional fuel cost would be above $1/MMBtu on average in 2030. The total additional fuel cost could increase or decrease depending on the potential impact on net heat rate. An increase in net heat rate, for example, would result in more fuel required to produce a given amount of generation and thus additional cost. In the GHG Mitigation Measures  -  111(d) TSD, the EPA's cost estimates assume a 1 percent increase in net heat rate.
Finally, for plants without sufficient access to natural gas, it is also necessary to construct new natural gas pipelines ("laterals"). Pipeline costs are typically expressed in terms of dollars per inch of pipeline diameter per mile of pipeline distance (i.e., dollars per inch-mile), reflecting the fact that costs increase with larger diameters and longer pipelines. On average, the cost for lateral development within the contiguous U.S. is approximately $280,000 per inch-mile (2019$), which can vary based on site-specific factors. The total pipeline cost for each coal-fired steam generating unit is a function of this cost, as well as a function of the necessary pipeline capacity and the location of the plant relative to the existing pipeline transmission network. The pipeline capacity required depends on the amount of co-firing desired as well as on the desired level of generation -- a higher degree of co-firing while operating at full load would require more pipeline capacity than a lower degree of co-firing while operating at partial load. It is reasonable to assume that most plant owners would develop sufficient pipeline capacity to deliver the maximum amount of desired gas use in any moment, enabling higher levels of co-firing during periods of lower fuel price differentials. Once the necessary pipeline capacity is determined, the total lateral cost can be estimated by considering the location of each plant relative to the existing natural gas transmission pipelines as well as the available excess capacity of each of those existing pipelines. For purposes of the cost reasonableness estimates as follows, the EPA assumes pipeline costs of $92/kW, which is the median value of all unit-level pipeline cost estimates, as explained in the GHG Mitigation Measures  -  111(d) TSD. The range in costs reflects a range in the amortization period of the capital costs over 6 to 10 years, which is consistent with the amount of time over which the units in the medium-term subcategory could be operational.
The EPA sums the natural gas co-firing costs as follows: For a typical base load coal-fired steam generating unit in 2030, the EPA estimates that the cost of co-firing with 40 percent natural gas on an annual average basis is approximately $53 to $66/ton CO2 reduced, or $9 to $12/MWh, respective to amortization periods of 10 to 6 years. This estimate is based on the characteristics of a typical coal-fired unit in 2021 (400 MW capacity and an average heat rate of 10,500 Btu/kWh) operating at a typical capacity factor of about 50 percent, and it assumes a pipeline cost of $92/kW, as discussed earlier in this preamble. 
Based on the coal-fired steam generating units that existed in 2021 and that do not have known plans to cease operations or convert to gas by 2030, and assuming that each of those units continues to operate at the same level in 2030 as it operated in 2017-2021, on average, the EPA estimates that the weighted average cost of co-firing with 40 percent natural gas on an annual average basis is approximately $64 to $78/ton CO2 reduced, or $11 to $14/MWh. The $/ton cost estimate is lower than average for approximately 82 GW, and the $/MWh cost estimate is lower than average for 86 GW (about 69 percent and 72 percent, respectively, of the relevant coal fleet). These estimates and all underlying assumptions are explained in detail in the GHG Mitigation Measures  -  111(d) TSD. 
As was described in section X.D.1 of this preamble, the EPA has compared the estimated costs discussed in section X.D.2 of this preamble to costs that coal-fired steam generating units have incurred to install controls that reduce other air pollutants, such as SO2. Representative wet FGD SO2 emission control costs are $15.00 to $18.50/MWh, as detailed in section VII.F.3.b.iii.(B)5 of this preamble. The estimated range of annualized costs of natural gas co-firing (approximately $9 - $14/MWh) is lower than or comparable to the representative annualized costs of installing and operating wet FGD, which are detailed in section VII.F.3.b.iii.(B)5 of this preamble. The range of cost effectiveness estimates presented in this section is lower than previously estimated by the EPA in the proposed CPP, for several reasons. Since then, the expected difference between coal and gas prices has decreased significantly, from over $3/MMBtu to about $1/MMBtu in this proposal. Additionally, a recent analysis performed by Sargent and Lundy for the EPA supports a considerably lower capital cost for modifying existing boilers to co-fire with natural gas. The EPA also recently conducted a highly detailed facility-level analysis of natural gas pipeline costs, the median value of which is slightly lower than the value used by the EPA previously to approximate the cost of co-firing at a representative unit.
Based on the range of costs presented in this section, the EPA is proposing that the costs of natural gas co-firing are reasonable for the medium-term coal-fired steam generating unit subcategory. 
Non-air Quality Health and Environmental Impact and Energy Requirements
Natural gas co-firing for steam generating units is not expected to have any significant adverse consequences related to non-air quality health and environmental impacts or energy requirements. 
Non-GHG Emissions
Non-GHG emissions are reduced when steam generating units co-fire with natural gas because less coal is combusted. SO2, PM2.5, acid gas, mercury and other hazardous air pollutant emissions that result from coal combustion are reduced proportionally to the amount of natural gas consumed, i.e., under this proposal, by 40 percent. Natural gas combustion does produce NOX emissions, but in lesser amounts than from coal-firing. However, the magnitude of this reduction is dependent on the combustion system modifications that are implemented to facilitate natural gas co-firing.
Additionally, sufficient regulations exist related to natural gas pipelines and transport that assure natural gas can be safely transported with minimal risk of environmental release. PHMSA develops and enforces regulations for the safe, reliable, and environmentally sound operation of the nation's 2.6 million mile pipeline transportation system. Recently, PHMSA finalized a rule that will improve the safety and strengthen the environmental protection of more than 300,000 miles of onshore gas transmission pipelines. PHMSA also recently promulgated a rule covering natural gas transmission, as well as a rule that significantly expanded the scope of safety and reporting requirements for more than 400,000 miles of previously unregulated gas gathering lines. Additionally, FERC oversees the development of new natural gas pipelines. 
Energy Requirements
The introduction of natural gas co-firing will cause steam boilers to be slightly less efficient due to the high hydrogen content of natural gas. Co-firing at levels between 20 percent and 100 percent can be expected to decrease boiler efficiency between 1 percent and 5 percent. However, despite the decrease in boiler efficiency, the overall net output efficiency of a steam generating unit that switches from coal- to natural gas-firing may change only slightly, in either a positive or negative direction. Since co-firing reduces coal consumption, the auxiliary power demand related to coal handling and emissions controls typically decreases as well. While a site-specific analysis would be required to determine the overall net impact of these countervailing factors, generally the effect of co-firing on net unit heat rate can vary within approximately plus or minus 2 percent. 
The EPA previously determined in the ACE Rule (84 FR 32520 at 32545; July 8, 2019) that "co-firing natural gas in coal-fired utility boilers is not the best or most efficient use of natural gas and [...] can lead to less efficient operation of utility boilers." That determination was informed by the more limited supply of natural gas, and the larger amount of coal-fired EGU capacity and generation, in 2019. Since that determination, the expected supply of natural gas has expanded considerably, and the capacity and generation of the existing coal-fired fleet has decreased, reducing the total mass of natural gas that might be required for sources to implement this measure. Additionally, the natural gas co-firing measure is now being proposed for a medium-term coal-fired steam generating unit subcategory, a group of units that will operate at most for 10 years following the compliance date, which would further reduce the total amount of required natural gas. 
Furthermore, regarding the efficient operation of boilers, the ACE determination was based on the observation that "co-firing can negatively impact a unit's heat rate (efficiency) due to the high hydrogen content of natural gas and the resulting production of water as a combustion by-product." That finding does not consider the fact that the effect of co-firing on net unit heat rate can vary within approximately plus or minus 2 percent, and therefore the net impact on overall utility boiler efficiency for each steam generating unit is uncertain.
For all of these reasons, the EPA is proposing that natural gas co-firing at medium-term coal-fired steam generating units does not result in any significant adverse consequences related to energy requirements.
Additionally, the EPA considered longer term impacts on the energy sector, and the EPA is proposing these impacts are reasonable. Designating natural gas co-firing as the BSER for medium-term coal-fired steam generating units would not have significant adverse impacts on the structure of the energy sector. Steam generating units that currently are coal-fired would be able to remain primarily coal-fired. The replacement of some coal with natural gas as fuel in these sources would not have significant adverse effects on the price of natural gas or the price of electricity.
Extent of Reductions in CO2 Emissions
One of the primary benefits of natural gas co-firing is emission reduction. CO2 emissions are reduced by approximately 4 percent for every additional 10 percent of co-firing. When shifting from 100 percent coal to 60 percent coal and 40 percent natural gas, CO2 stack emissions are reduced by approximately 16 percent. Non-CO2 emissions are reduced as well, as noted earlier in this preamble. 
Technology Advancement
Natural gas co-firing is already well-established and widely used by coal-fired steam boiler generating units. As a result, this proposed rule is not likely to lead to technological advances or cost reductions in the components of natural gas co-firing, including modifications to boilers and pipeline construction. However, greater use of natural gas co-firing may lead to improvements in the efficiency of conducting natural gas co-firing and operating the associated equipment.
Conclusion
The EPA proposes that natural gas co-firing at 40 percent of heat input is the BSER for medium-term coal-fired steam generating units because natural gas co-firing is adequately demonstrated, as indicated by the facts that it has been operated at scale and is widely applicable to sources. Additionally, the costs for natural gas co-firing are reasonable. Moreover, any adverse non-air quality health and environmental impacts and energy requirements of natural gas co-firing are limited and are outweighed by the benefits of the emission reductions at reasonable cost. In contrast, CCS, although achieving greater emission reductions, would be less cost-effective, in general, for the proposed subcategory of medium-term units. 
While the EPA is not proposing CCS as BSER for the proposed subcategory definition of medium-term units, the EPA is taking comment on the dates that define the threshold between medium-term and long-term units and on what amount of costs should be considered reasonable.
Imminent-term and Near-term Coal-fired Steam Generating Units
In this section of the preamble, the EPA evaluates CCS, natural gas co-firing, and routine methods of operation and maintenance as the BSER for imminent-term and near-term coal-fired steam generating units. Primarily because of the effect of a short operating horizon on the cost of controls for these units, the EPA proposes routine methods of operation and maintenance as the BSER. 
CCS
As noted in section X.D.2.a of this preamble, the EPA is not proposing CCS for medium-term units due to $/MWh costs being less favorable based on the appropriate cost metrics. Because of the shorter operating horizons for imminent-term and near-term coal-fired steam generating units, CCS is less cost favorable for them than for medium-term units. Therefore, the EPA is not proposing CCS as BSER for imminent-term or near-term coal-fired steam generating units. Additional details of cost values for amortization periods representative of imminent-term and near-term units are available in the GHG Mitigation Measures  -  111(d) TSD.
Natural Gas Co-firing
Much of the discussion of natural gas co-firing in section X.D.2.b of this preamble for medium-term units is relevant for imminent-term and near-term units, except that natural gas co-firing is less cost effective for the latter units because of their short operating horizons. For a 2-year amortization period, annualized costs for the representative unit are $130/ton of CO2 reduced and $23/MWh of generation. Therefore, the EPA is not proposing natural gas co-firing as BSER for imminent-term or near-term units. Additional details of cost are available in the GHG Mitigation Measures  -  111(d) TSD.
Routine Methods of Operation and Maintenance
For the imminent-term and near-term coal-fired steam generating units, the EPA is proposing that the BSER is routine methods of operation and maintenance already occurring at the unit, so as to maintain the current unit-specific CO2 emission rates (expressed as lb CO2/MWh). Furthermore, requiring additional investment in those units could have the counterproductive effects of leading them to increase operations and thereby increase CO2 emissions.
Routine methods of operation and maintenance are adequately demonstrated because units already operate by those methods. They will not result in additional costs from any controls, and will not create adverse non-air quality health and environmental impacts or energy requirements. They will not achieve CO2 emission reductions at the unit level relative to current performance, but they can prevent worsening of emission rates over time. Although they do not advance useful control technology, they do not have adverse impacts on the energy sector from a nationwide or long-term perspective. 
Degree of Emission Limitation
Under CAA section 111(d), once the EPA determines the BSER, it must determine the "degree of emission limitation" achievable by the application of the BSER. States then determine standards of performance and include them in the state plans, based on the specified degree of emission limitation. Proposed presumptive standards of performance are detailed in section XI.D of this preamble. There is substantial variation in emission rates among coal-fired steam generating units -- the range is, approximately, from 1,700 lb CO2/MWh-gross to 2,500 lb CO2/MWh-gross -- which makes it challenging to determine a single, uniform emission limit. Accordingly, for each of the four subcategories of coal-fired steam generating units, the EPA is proposing to determine the degree of emission limitation by a percentage change in emission rate, as follows:
Long-term Coal-fired Steam Generating Units
As discussed earlier in this preamble, the EPA is proposing the BSER for long-term coal-fired steam generating units as "full-capture" CCS, defined as 90 percent capture of the CO2 in the flue gas. The degree of emission limitation achievable by applying this BSER can be determined on a rate basis. A capture rate of 90 percent results in reductions in the emission rate of 88.4 percent on a lb CO2/MWh-gross basis, and this reduction in emission rate can be observed over an extended period (e.g., an annual calendar-year basis). Therefore, the EPA is proposing that the degree of emission limitation for long-term units is an 88.4 percent reduction in emission rate on a lb CO2/MWh-gross basis over an extended period (e.g., an annual calendar-year basis).
As noted in section X.D.1.a of this preamble, new CO2 capture retrofits on existing coal-fired steam generating units may achieve capture rates greater than 90 percent, and the EPA is taking comment on a range of capture rates that may be achievable. As also discussed in section X.D.1.a, the operating availability (i.e., the amount of time a process operates relative to the amount of time it planned to operate) of industrial processes is usually less than 100 percent. Assuming that CO2 capture achieves 90 percent capture when available to operate, that CCS is available to operate 90 percent of the time the coal-fired steam generating unit is operating, and that the steam generating unit operates the same whether or not CCS is available to operate, total emission reductions would be 81 percent. Higher levels of emission reduction could occur for higher capture rates coupled with higher levels of operating availability relative to operation of the steam generating unit. If the steam generating unit were not permitted to operate when CCS was unavailable, there may be local reliability consequences, and the EPA is soliciting comment on how to balance these issues. Additionally, the EPA is soliciting comment on a range of the degree of emission limitation achievable, in the form of a reduction in emission rate of 80 to 90 percent when determined over an extended period (e.g., an annual calendar-year basis). 
Medium-term Coal-fired Steam Generating Units
As discussed earlier in this preamble, the BSER for medium-term coal-fired steam generating units is 40 percent natural gas co-firing. The application of 40 percent natural gas co-firing results in reductions in the emission rate of 16 percent. Therefore, the degree of emission limitation for these units is a 16 percent reduction in emission rate on a lb CO2/MWh-gross basis over an extended period (e.g., an annual calendar-year basis). 
Imminent-term and Near-term Coal-fired Steam Generating Units
As discussed above, the BSER for imminent-term and near-term coal-fired steam generating units is routine methods of operation and maintenance. Application of this BSER results in no increase in emission rate. Thus, the degree of emission limitation corresponding to the application of the BSER is no increase in emission rate on a lb CO2/MWh-gross basis over an extended period (e.g., an annual calendar-year basis).
Other Emission Reduction Measures
Heat Rate Improvements
Heat rate is a measure of efficiency that is commonly used in the power sector. The heat rate is the amount of energy input, measured in Btu, required to generate one kWh of electricity. The lower an EGU's heat rate, the more efficiently it operates. As a result, an EGU with a lower heat rate will consume less fuel and emit lower amounts of CO2 and other air pollutants per kWh generated as compared to a less efficient unit. HRI measures include a variety of technology upgrades and operating practices that may achieve CO2 emission rate reductions of 0.1 to 5 percent for individual EGUs. The EPA considered HRI to be part of the BSER in the CPP and to be the BSER in the ACE Rule. However, the reductions that may be achieved by HRI are small relative to the reductions from natural gas co-firing and CCS. Also, some facilities that apply HRI would, as a result of their increased efficiency, increase their utilization and therefore increase their CO2 emissions (as well as emissions of other air pollutants), a phenomenon that the EPA has termed the "rebound effect." Therefore, the EPA is not proposing HRI as a part of BSER. 
CO2 Reductions from HRI in Prior Rulemakings
In the CPP, the EPA quantified emission reductions achievable through heat rate improvements on a regional basis by an analysis of historical emission rate data, taking into consideration operating load and ambient temperature. The Agency concluded that EGUs can achieve on average a 4.3 percent improvement in the Eastern Interconnection, a 2.1 percent improvement in the Western Interconnection, and a 2.3 percent improvement in the Texas Interconnection. See 80 FR 64789 (October 23, 2015). The Agency then applied all three of the building blocks to 2012 baseline data and quantified, in the form of CO2 emission rates, the reductions achievable in each interconnection in 2030, and then selected the least stringent as a national performance rate. Id. At 64811 - 19. The EPA noted that building block 1 measures could not by themselves constitute the BSER because the quantity of emission reductions achieved would be too small and because of the potential for an increase in emissions due to increased utilization (i.e., the "rebound effect").
A description of the ACE Rule is detailed in section IX of this preamble.
Updated CO2 Reductions from HRI
The HRI measures include improvements to the boiler island (e.g., neural network system, intelligent sootblower system), improvements to the steam turbine (e.g., turbine overhaul and upgrade), other equipment upgrades (e.g., variable frequency drives), and improvements in operation and maintenance practices. Specific details of the HRI measures are described in the GHG Mitigation Measures  -  111(d) TSD and an updated 2023 Sargent and Lundy HRI report (Heat Rate Improvement Method Costs and Limitations Memo), available in docket. Most HRI measures achieve reductions in heat rate of less than 2 percent. Steam path overhaul and upgrade may achieve reductions up to 5.15 percent, with the average being around 1.5 percent. Different combinations of HRI measures do not necessarily result in cumulative reductions in emission rate (e.g., intelligent sootblowing systems combined with neural network systems). Some of the HRI measures (e.g., variable frequency drives) only impact heat rate on a net generation basis by reducing the parasitic load on the unit. Assuming many of the HRI measures could be applied to a unit, it is possible that some units could achieve a maximum emission rate reduction of up to 5 percent. However, the reductions that the fleet could achieve on average are likely much smaller. The unit level reductions in emission rate from HRI are small relative to CCS or natural gas co-firing. In the CPP and ACE Rule, the EPA viewed the CCS and natural gas co-firing as too costly to qualify as the BSER; those costs have fallen since those rules and, as a result, CCS and natural gas co-firing do qualify as the BSER for the long-term and medium-term subcategories, respectively.
Potential for Rebound in CO2 Emissions
Reductions achieved on a rate basis from HRI may not result in overall emission reductions and could instead cause a "rebound effect" from increased utilization. A rebound effect would occur where, because of an improvement in its heat rate, a steam generating unit experiences a reduction in variable operating costs that makes the unit more competitive relative to other EGUs and consequently raises the unit's output. The increase in the unit's CO2 emissions associated with the increase in output would offset the reduction in the unit's CO2 emissions caused by the decrease in its heat rate and rate of CO2 emissions per unit of output. The extent of the offset would depend on the extent to which the unit's generation increased. The CPP did not consider HRI to be BSER on its own, in part because of the potential for a rebound effect. Analysis for the ACE Rule, where HRI was the entire BSER, observed a rebound effect for certain sources in some cases. In this action, where different subcategories of units are proposed to be subject to different BSER measures, steam generating units in a hypothetical subcategory with HRI as BSER could experience a rebound effect. Because of this potential for perverse GHG emission outcomes resulting from deployment of HRI at certain steam generating units, coupled with the relatively minor overall GHG emission reductions that would be expected from this measure, the EPA is not proposing HRI as the BSER for any subcategory of existing coal-fired steam generating units.
Natural Gas-fired and Oil-fired Steam Generating Units
In this section of the preamble, the EPA is addressing natural gas- and oil-fired steam generating units. The EPA is proposing the BSER and degree of emission limitation achievable by application of the BSER for those units and identifying the associated emission rates that states may apply to these units. For the reasons described here, the EPA is proposing subcategories based on load level (i.e., annual capacity factor), specifically, units that are base load, intermediate load, and low load. At this time, the EPA is not proposing requirements for low load units but is taking comment on a BSER of "clean fuels" for those units. The EPA is proposing routine methods of operation and maintenance as BSER for intermediate and base load units. Applying that BSER would not achieve emission reductions but would prevent increases in emission rates. The EPA is proposing presumptive standards of performance that differ between intermediate and base load units due to their differences in operation, as detailed in section XI.D.1.f of this preamble. The EPA is also proposing a separate subcategory for non-continental oil-fired steam generating units, which operate differently from continental units, with presumptive standards of performance detailed in section XI.D.1.g of this preamble.
Natural gas- and oil-fired steam generating units combust natural gas or distillate fuel oil or residual fuel oil in a boiler to produce steam for a turbine that drives a generator to create electricity. In non-continental areas, existing natural gas- and oil-fired steam generating units may provide base load power, but in the continental U.S., most existing units operate in a load-following manner. There are approximately 200 natural gas-fired steam generating units and fewer than 30 oil-fired steam generating units in operation in the continental U.S. Fuel costs and inefficiency relative to other technologies (e.g., combustion turbines) result in operation at lower annual capacity factors for most units. Based on data reported to EIA and CAMD for the contiguous U.S., for natural gas-fired steam generating units in 2019, the average annual capacity factor was less than 15 percent and 90 percent of units had annual capacity factors less than 35 percent. For oil-fired steam generating units in 2019, no units had annual capacity factors above 8 percent. Additionally, their load-following method of operation results in frequent cycling and a greater proportion of time spent at low hourly capacities, when generation is less efficient. Furthermore, because startup times for most boilers are usually long, natural gas steam generating units may operate in standby mode between periods of peak demand. Operating in standby mode requires combusting fuel to keep the boiler warm, and this further reduces the efficiency of natural gas combustion. 
Unlike coal-fired steam generating units, the CO2 emission rates of oil- and natural gas-fired steam generating units that have similar annual capacity factors do not vary considerably between units. This is partly due to the more uniform qualities (e.g., carbon content) of the fuel used. However, the emission rates for units that have different annual capacity factors do vary considerably, as detailed in the Natural Gas- and Oil-fired Steam Generating Unit TSD. Low annual capacity factor units cycle frequently, have a greater proportion of CO2 emissions that may be attributed to startup, and have a greater proportion of generation at inefficient hourly capacities. Intermediate annual capacity factor units operate more often at higher hourly capacities, where CO2 emission rates are lower. High annual capacity factor units operate still more at base load conditions, where units are more efficient and CO2 emission rates are lower. Based on these performance differences between these load levels, the EPA is, in general, proposing to divide natural gas- and oil-fired steam generating units into three subcategories each -- low load, intermediate load, and base load -- as specified in section X.C.2 of this preamble: "low" load is defined by annual capacity factors less than 8 percent, "intermediate" load is defined by annual capacity factors greater than or equal to 8 percent and less than 45 percent, and "base" load is defined by annual capacity factors greater than 45 percent.
Options Considered for BSER 
The EPA has considered various methods for controlling CO2 emissions from natural gas- and oil-fired steam generating units to determine whether they meet the criteria for BSER. Co-firing natural gas cannot be the BSER for these units because natural gas- and oil-fired steam generating units already fire large proportions of natural gas. Most natural gas-fired steam generating units fire more than 90 percent natural gas on a heat input basis, and any oil-fired steam generating units that would potentially operate above an annual capacity factor of around 15 percent would combust natural gas as a large proportion of their fuel as well. Nor is CCS a candidate for BSER. The utilization of most gas-fired units, and likely all oil-fired units, is relatively low, and as a result, the amount of CO2 available to be captured is low. However, the capture equipment would still need to be sized for the nameplate capacity of the unit. Therefore, the capital and operating costs of CCS would be high relative to the amount of CO2 available to be captured. Additionally, again due to lower utilization, the amount of IRC section 45Q tax credits that owner/operators could claim would be low. Because of the relatively high costs and the relatively low cumulative emission reduction potential for these natural gas- and oil-fired steam generating units, the EPA is not proposing CCS as the BSER for them. 
The EPA has reviewed other possible controls but is not proposing any of them as the BSER for natural gas- and oil-fired units either. Co-firing hydrogen in a boiler is technically possible, but, for the same reasons discussed in section VII of this preamble, the only hydrogen that could be considered for the BSER would be low-GHG hydrogen, and there is limited availability of that hydrogen now and in the near future. Additionally, for natural gas-fired steam generating units, setting a future standard based on hydrogen would have limited GHG reduction benefits given the low utilization of natural gas- and oil-fired steam generating units. Lastly, HRI for these types of units would face many of the same issues as for coal-fired steam generating units; in particular, HRI could result in a rebound effect that would increase emissions.
However, the EPA recognizes that natural gas- and oil-fired steam generating units could possibly, over time, operate more, in response to other changes in the power sector. Additionally, some coal-fired steam generating units have converted to 100 percent natural gas-fired, and it is possible that more may do so in the future. Moreover, in part because the fleet continues to age, the plants may operate with degrading emission rates. In light of these possibilities, identifying the BSER and degrees of emission limitation for these sources would be useful to provide clarity and prevent backsliding in GHG performance. Therefore, the EPA is proposing BSER for intermediate and base load natural gas- and oil-fired steam generating units to be routine methods of operation and maintenance, such that the sources could maintain the emission rates (on a lb/MWh-gross basis) currently maintained by the majority of the fleet across discrete ranges of annual capacity factor. The EPA is proposing this BSER for intermediate load and base load natural gas- and oil-fired steam generating units, regardless of the operating horizon of the unit. 
A BSER based on routine methods of operation and maintenance is adequately demonstrated because units already operate with those practices. There are no or negligible additional costs because there is no additional technology that units are required to apply and there is no change in operation or maintenance that units must perform. Similarly, there are no adverse non-air quality health and environmental impacts or adverse impacts on energy requirements. Nor do they have adverse impacts on the energy sector from a nationwide or long-term perspective. The EPA's initial modeling, which supports this proposed rule, indicates that by 2040, a number of natural gas-fired steam generating units have remained in operation since 2030, although at reduced annual capacity factors. There are no CO2 reductions that may be achieved at the unit level, but applying the BSER should preclude increases in emission rates. Routine methods of operation and maintenance do not advance useful control technology, but this point is not significant enough to offset their benefits.
The EPA is also taking comment on, but not proposing, a BSER of "clean fuels" for low load natural gas- and oil-fired steam generating units. As noted earlier in this preamble, non-coal fossil fuels combusted in utility boilers typically include natural gas, distillate fuel oil (i.e., fuel oil No. 1 and No. 2), and residual fuel oil (i.e., fuel oil No. 5 and No. 6). The EPA previously established "clean fuels" as BSER in the 2015 NSPS for new non-base load natural gas- and multi-fuel-fired stationary combustion turbines (80 FR 64615 - 17; October 23, 2015), and the EPA is similarly proposing "clean fuels" as BSER for new low load combustion turbines as described in section VII of this preamble. For low load natural gas- and oil-fired steam generating units, the high variability in emission rates associated with the variability of load at the lower-load levels limits the benefits of a BSER based on routine maintenance and operation. That is because the high variability in emission rates would make it challenging to determine an emission rate (i.e., on a lb CO2/MWh-gross basis) that could serve as the presumptive standard of performance that would reflect application of a BSER of routine operation and maintenance. On the other hand, for those units, a BSER of "clean fuels" and an associated presumptive standard of performance based on a heat input basis, as described in section XI.D of this preamble, may be reasonable. The EPA is soliciting comment on the fuel types that would constitute "clean fuels" specific to low load natural gas- and oil-fired steam generating units. 
Degree of Emission Limitation
As discussed above, because the proposed BSER for base load and intermediate load natural gas- and oil-fired steam generating plants is routine operation and maintenance, which the units are, by definition, already employing, the degree of emission limitation by application of this BSER is no increase in emission rate on a lb CO2/MWh-gross basis over an extended period of time (e.g., an annual calendar year). 
State Plans for Proposed Emission Guidelines for Existing Fossil Fuel-fired EGUs 
Overview
State plan submissions under these emission guidelines are governed by the requirements of 40 CFR part 60, subpart Ba (subpart Ba). The EPA proposed to revise certain aspects of 40 CFR part 60, subpart Ba, in its December 2022 proposal, "Adoption and Submittal of State Plans for Designated Facilities: Implementing Regulations Under Clean Air Act Section 111(d)" (proposed subpart Ba). The Agency intends to finalize revisions to 40 CFR part 60, subpart Ba, before promulgating these emission guidelines. Therefore, state plans and state plan submissions under these emission guidelines would be subject to the requirements of subpart Ba as revised in that future final action, including any changes the EPA makes to the proposal in response to public comments. To the extent the EPA is proposing to add to, supersede, or otherwise vary the requirements of subpart Ba for the purposes of these particular emission guidelines, those proposals are explicitly addressed in this section. Unless expressly amended or superseded in these proposed emission guidelines, the provisions of subpart Ba, as revised by the EPA's forthcoming final rule, would apply. 
This section provides information on several aspects of state plan development, including compliance deadlines, a presumptive methodology for establishing standards of performance for affected EGUs, compliance flexibilities, and state plan components and submission. The EPA notes that, in section X of this preamble, comment is solicited on ranges for dates and values for defining subcategories, BSER, and degrees of emission limitation, and that those solicitations for comment extend to the proposed values and dates discussed in this section of the preamble. In Section XI.B, the EPA proposes and explains its reasoning for a compliance deadline of January 1, 2030. In Section XI.C, the EPA describes its requirement that state plans achieve equivalent stringency to the EPA's BSER. Section XI.D proposes a presumptive methodology for calculating the standards of performance for affected EGUs based on subcategory as well as requirements related to invoking RULOF to apply a less stringent standard of performance than results from the EPA's presumptive methodology. Section XI.D also describes requirements for increments of progress and milestones for federally enforceable commitments to cease operations. Because many of the subcategories take into account operating horizon, the EPA is proposing milestones to provide the public with assurance that steps towards permanently ceasing operations will be concluded in a timely manner. In Section XI.E, the EPA requests comment on whether emission trading and averaging are appropriate in the context of these emission guidelines. Finally, Section XI.F describes what must be included in state plans, including plan components specific to these emission guidelines and requirements for conducting meaningful engagement. 
Compliance Deadlines
The EPA is proposing a compliance date of January 1, 2030. This means that starting on January 1, 2030, designated EGUs would be required to demonstrate compliance with the standards of performance and associated requirements in their applicable state plans under these emission guidelines. The EPA is proposing that this is the soonest compliance with standards of performance could reasonably commence based on the proposed state plan submission timeline (24 months; see section XI.F.2 of this preamble) and the amount of time affected EGUs will need to install CCS or natural gas co-firing. However, the BSER for other subcategories are routine methods of operation and maintenance, which can be applied earlier. Therefore, the EPA is soliciting comment on compliance dates defined by the date of approval of the state plan or January 1, 2030, whichever is earlier, for imminent-term coal-fired steam generating units, near-term coal-fired steam generating units, and the different subcategories of natural gas- and oil-fired steam generating units.
The proposed compliance timeframe in these proposed emission guidelines is based on the amount of time the EPA believes is needed to comply with standards of performance based on implementation of natural gas co-firing or CCS. Each of these systems would require several years to plan, permit, and construct. However, as explained further in section XI.F.2 of this preamble, the EPA is proposing to adjust the state plan submission deadline so that certain necessary planning and design steps for natural gas co-firing or CCS implementation can take place as part of the state plan development process. That is, we expect that some of the planning and design steps described below would take place prior to state plan submission. The EPA believes that coordinating state plan development and implementation in this manner reflects how the owners/operators of affected EGUs and states would actually undertake the steps leading to ultimate deployment of a control technology and compliance with a standard of performance.
The GHG Mitigation Measures  -  111(d) TSD discusses the timeframes for implementation of natural gas co-firing and CCS at existing coal-fired EGUs. Based on this analysis, the time needed to design and implement CCS is an important aspect for setting a compliance date under these emission guidelines. CCS projects will include planning, design, and construction of both carbon capture and transport and storage systems; the EPA believes that all of these steps can be completed within roughly 5 years. Deployment of carbon capture systems starts with a technical and economic feasibility evaluation, including a FEED study. The owner/operator of an affected EGU would then proceed to making technical and commercial arrangements, including arranging project financing and permitting. These initial steps do not need to be undertaken sequentially and may be complete in 3 years or less. As noted above, the EPA also believes that at least some of these project design and development steps, including feasibility evaluations and FEED studies, can and will be completed prior to state plan submission deadline. The EPA believes that the commencement of CCS project implementation activities, including more detailed engineering work and procurement, construction of the carbon capture system, and startup and testing, will overlap with the final steps of the initial project design and development phase. Project implementation takes approximately 3 years to complete. 
In addition to planning and implementing a carbon capture system, the owners/operators of affected EGUs will also have to design and construct a system for transporting and storing captured CO2. The necessary steps for implementing transport and storage can be undertaken simultaneously with development of the capture system, and the EPA believes they can also be completed within roughly 5 years. As with the planning and design phases associated with a carbon capture system, the EPA believes that the initial phases of planning and design for CO2 transport and storage, including site characterization and pipeline feasibility and design activities, can and will occur prior to state plan submission deadline. First, the owner/operator of an affected EGU would undertake a feasibility analysis associated with CO2 transport and storage, as well as site characterization and permitting of potential storage areas. These three steps can overlap with each other and the EPA anticipates they will take 2 - 3 years to complete. Similar to the design and implementation of the carbon capture system, the EPA believes there is significant opportunity to overlap the design and planning phase for CO2 transport and storage with the engineering and construction phase, which is anticipated to take 2 - 3 years. 
The EPA expects that implementation of natural gas co-firing projects, including any necessary construction of natural gas pipelines, can be completed in approximately 3.5 years. As discussed in the GHG Mitigation Measures  -  111(d) TSD, any necessary boiler modifications to accommodate natural gas co-firing can be completed within 3 years. The process of planning, permitting, and construction for boiler modifications can occur simultaneously with the steps that owners/operators of affected EGUs would need to undertake if construction of a new natural gas pipeline is needed. The time required to develop and construct natural gas laterals can be broken into three phases: planning and design; permitting and approval; and construction. It is reasonable to assume that the planning and design phase can typically be completed in a matter of months and will often be finalized in less than a year. The time required to complete the permitting and approval phase can vary. Based on a review of recent FERC data, the average time for pipeline projects similar in scope to the projects considered in this TSD is about 1.5 years and would likely not exceed 4 years. Finally, the actual construction could likely be completed in less than 1 year. Based on a sum of these estimates, the EPA believes that 3.5 years is a reasonable timeframe for pipeline projects.
The EPA expects that final emission guidelines will be published in June 2024 and is proposing a state plan submission deadline that is 24 months from publication, meaning June 2026. The proposed compliance date is January 1, 2030. The EPA requests comment on whether using a period of 3.5 years after state plan submission is appropriate for establishing a compliance deadline for these emission guidelines. As explained above, the EPA is basing this proposed timeframe on the expectation that some of the initial evaluation and planning steps for both natural gas co-firing and CCS would take place as part of state plan development, i.e., before the state plan submission deadline. To the extent that commenters believe more or less time after state plan submission is more appropriate, the EPA requests that commenters provide information supporting the provision of a different compliance date. Additionally, the proposed state plan submission date and proposed compliance date are based on the EPA's anticipation that it will publish final emission guidelines for affected EGUs in June 2024. Should the actual date of publication of the final emission guidelines differ from this target, the EPA will adjust the state plan submission and compliance dates accordingly. 
Requirement for State Plans to Maintain Stringency of the EPA's BSER Determination
As explained in section V.C of this preamble, CAA section 111(d)(1) requires the EPA to establish requirements for state plans that, in turn, must include standards of performance for existing sources. Under CAA section 111(a)(1), a standard of performance is "a standard for emissions of air pollutants which reflects the degree of emission limitation achievable through the application of the best system of emission reduction which . . . the Administrator determines has been adequately demonstrated." That is, the EPA has the responsibility to determine the best system of emission reduction for a given category or subcategory of sources and to determine the degree of emission limitation achievable through application of the BSER to affected sources. The level of emission performance required under CAA section 111 is reflected in the EPA's presumptive standards of performance. 
States use the EPA's presumptive standards of performance as the basis for establishing requirements for affected sources in their state plans. In order for the EPA to find a state plan "satisfactory," that plan must address each affected source within the state and achieve the level of emission performance that would result if each affected source was achieving its presumptive standard of performance, after accounting for any application of RULOF. That is, while states have the discretion to establish the applicable standards of performance for affected sources in their state plans, the structure and purpose of CAA section 111 require that those plans achieve equivalent stringency as applying the EPA's presumptive standards of performance to each of those sources (again, after accounting for any application of RULOF). 
The EPA's December 2022 proposed revisions to the CAA section 111 implementing regulations (subpart Ba) would provide that states are permitted, in appropriate circumstances, to adopt compliance measures that allow their sources to meet their standards of performance in the aggregate. As with the establishment of standards of performance for affected sources, CAA section 111 requires that state plans that include such flexibilities for complying with standards of performance demonstrate equivalent stringency as would be achieved if each affected source was achieving its standard of performance. 
The requirement that state plans achieve equivalent stringency to the EPA's BSER and stringency determinations is borne out of the structure and purpose of CAA section 111, which is to mitigate air pollution that is reasonably anticipated to endanger public health or welfare. It achieves this purpose by requiring source categories that cause or contribute to dangerous air pollution to operate more cleanly. Unlike the Clean Air Act's NAAQS-based programs, section 111 is not designed to reach a level of emissions that has been deemed "safe" or "acceptable"; there is no air-quality target that tells states and sources when emissions have been reduced "enough." Rather, CAA section 111 requires affected sources to reduce their emissions to the level that the EPA has determined is achievable through application of the best system of emission reduction, i.e., to achieve emission reductions consistent with the applicable presumptive standard of performance. Consistent with the statutory purpose of requiring affected sources to operate more cleanly, the EPA typically expresses presumptive standards of performance as rate-based emission limitations.
In the course of complying with a rate-based standard of performance under a state plan, an affected source may take an action that removes it from the source category, e.g., by permanently ceasing operations. In this case, the source is no longer subject to the emission guidelines. An affected source may also choose to change its operating characteristics in a way that impacts its overall emissions, e.g., by changing its utilization; however, the source is still required to meet its rate-based standard. In either instance, the changes to one affected source do not implicate the obligations of other affected sources. Although such changes may reduce emissions from the source category, they do not absolve the remaining affected EGUs from the statutory obligation to improve their emission performance consistent with the level that the EPA has determined is achievable through application of the BSER. This fundamental statutory requirement applies regardless of whether a standard of performance is expressed or implemented as a rate- or mass-based emission limitation, or whether standards of performance are achieved on a source-specific or aggregate basis.
In sum, consistent with the respective roles of the EPA and states under CAA section 111, states have discretion to establish standards of performance for affected sources in their state plans, and to provide flexibilities for affected sources to use in complying with those standards. However, state plans must demonstrate that they ultimately provide for equivalent stringency as would be achieved if each affected source was achieving the applicable presumptive standard of performance, after accounting for any application of RULOF.
Establishing Standards of Performance
CAA section 111(d)(1)(A) provides that "each State shall submit to the Administrator a plan which establishes standards of performance for any existing source"; that plan must also "provide[] for the implementation and enforcement of such standards of performance." That is, states must use the BSER and stringency in the EPA's emission guidelines to establish standards of performance for each existing affected EGU (as defined in section IX of this preamble) through a state plan. 
To assist states in developing state plans that achieve the level of stringency required by the statute, it has been the EPA's longstanding practice to provide presumptively approvable standards of performance or a methodology for establishing such standards. For the purpose of these emission guidelines, the EPA is proposing a methodology for states to use in establishing presumptively approvable standards of performance for affected EGUs. Per CAA section 111(a)(1), the basis of this methodology is the degree of emission limitation the EPA has determined is achievable through application of the BSER to each subcategory. The EPA anticipates and intends for most states to apply the presumptive standards of performance to affected EGUs. 
Additionally, CAA section 111(d)(1)(B) permits states to take into consideration a particular affected EGU's RULOF when applying a standard of performance to that source. The EPA's proposed revisions to the CAA section 111 implementing regulations at 40 CFR part 60, subpart Ba provide that a state would be able to apply a less stringent standard of performance to an affected EGU when the state can demonstrate that the source cannot reasonably apply the BSER to achieve the degree of emission limitation determined by the EPA. Proposed subpart Ba describes the conditions that would warrant application of a less stringent RULOF standard under these emission guidelines and how a RULOF standard would be determined. Further detail about how the EPA proposes to implement the RULOF provision in the context of this rulemaking is provided in section XI.D.2 of this preamble.
States also have the authority to apply standards of performance to affected EGUs that are more stringent than the EPA's presumptively approvable standards of performance. 
Application of Presumptive Standards 
As described in section X.C of this preamble, the EPA is proposing to first subcategorize the affected EGUs under these emission guidelines by fuel type: coal-fired and oil- or natural gas-fired steam generating units. The EPA is proposing further subcategorization into four subcategories for coal-fired steam generating units and seven subcategories for oil- and natural gas-fired steam generating units. Under this proposal, each subcategory with a proposed BSER and degree of emission limitation would have a corresponding methodology for establishing presumptively approvable standards of performance (also referred to as "presumptive standards of performance" or "presumptive standards"). As explained in section X.C.3, the EPA is proposing that an affected coal-fired steam EGU's operating horizon determines the applicable subcategory in three of the four subcategories; in the case of the near-term subcategory, the operating horizon and load level establish applicability. For affected oil- and natural gas-fired steam generating units, subcategories are defined by load level and the type of fuel fired, as well as locality (i.e., continental and non-continental U.S.). There are four subcategories for oil-fired steam generating units based on different combinations of load level (base load, intermediate load, and low load) and locality, and three subcategories for natural gas-fired steam generating units based on load level (base load, intermediate, and low).
A state, when establishing standards of performance for affected EGUs in its plan, would identify each affected EGU in the state and specify into which subcategory each EGU falls. The EPA is proposing that the state would then use the corresponding methodology for the given subcategory to calculate and apply the presumptively approvable standard of performance for each affected EGU. 
The EPA notes that, as explained in section X.C.3 of this preamble, commitments for dates to permanently cease operation and capacity factor commitments on which a state relies to subcategorize coal-fired steam generating units under these emission guidelines will become federally enforceable upon EPA approval of a state plan including those commitments. While such commitments must be enforceable by the state when its plan is submitted to the EPA, they do not necessarily have to be federally enforceable at that time. However, this preamble uses the term "federally enforceable commitment" throughout to make clear that date and capacity factor commitments contained in a state plan will become federally enforceable upon EPA approval of that plan.
States also have the authority to deviate from the methodology for presumptively approvable standards, in order to apply a more stringent standard of performance through increasing the degree of emission limitation beyond what the EPA has determined to be achievable for units as a general matter (e.g., a state decides that an EGU in the medium-term coal-fired subcategory should co-fire 50 percent natural gas instead of 40 percent). Deviations to increase stringency do not trigger use of the RULOF mechanism, which requires states to demonstrate that an affected EGU cannot reasonably apply the BSER to achieve the degree of emission limitation determination by the EPA. The EPA proposes to presume that standards of performance that are more stringent than the EPA's presumptive standards are "satisfactory" for the purposes of CAA section 111(d). 
Establishing Baseline Emission Performance for Presumptive Standards
For each of the coal-fired subcategories and for the non-continental intermediate and base load oil-fired subcategory, the proposed methodology to calculate a standard of performance entails establishing a baseline of CO2 emissions and corresponding electricity generation for an affected EGU and then applying the degree of emission limitation achievable through the application of the BSER (as established in section X.D of this preamble). The methodology for establishing baseline emission performance for an affected EGU is identical in each of the subcategories but will result in a value that is unique to each affected EGU. To establish baseline emission performance for an affected EGU, the EPA is proposing that a state will use the CO2 mass emissions and corresponding electricity generation data for a given affected EGU from any continuous 8-quarter period from 40 CFR part 75 reporting within the 5 years immediately prior to the date the final rule is published in the Federal Register. This proposed period is based on the NSR program's definition of "baseline actual emissions" for existing electric steam generating units. See 40 CFR 52.21(b)(48)(i). Eight quarters of 40 CFR part 75 data corresponds to a 2-year period, but the EPA is proposing 8 quarters of data as that corresponds to quarterly reporting according to 40 CFR part 75. Functionally, the EPA expects states to utilize the most representative 8-quarter period of data from the 5 years immediately preceding the date the final rule is published in the Federal Register. For the 8 quarters of data, the EPA is proposing that a state would divide the total CO2 emissions (in the form of pounds) over that continuous time period by the total gross electricity generation (in the form of MWh) over that same time period to calculate baseline CO2 emission performance in lb CO2 per MWh. As an example, a state establishing baseline emission performance in the year 2023 would start by evaluating the CO2 emissions and electricity generation data for each of its affected EGUs for 2018 through 2022 and choosing, for each affected EGU, a continuous 8-quarter period that it deems to be the best representation of the operation of that affected EGU. While the EPA will evaluate the choice of baseline periods chosen by states when reviewing state plan submissions, the EPA intends to defer to a state's reasonable exercise of discretion as to which 8-quarter period is representative.
The EPA is proposing to require the use of 8 quarters during the 5-year period prior to the date the final rule is published in the Federal Register as the relevant period for the baseline methodology for a few reasons. First, each affected EGU has unique operational characteristics that affect the emission performance of the EGU (load, geographic location, hours of operation, coal rank, unit size, etc.), and the EPA believes each affected EGU's emission performance baseline should be representative of the source-specific conditions of the affected EGU and how it has typically operated. Additionally, allowing a state to choose (likely in consultation with the owners or operators of affected EGUs) the 8-quarter period for assessing baseline performance can avoid situations in which a prolonged period of atypical operating conditions would otherwise skew the emissions baseline. Relatedly, the EPA believes that by using total mass CO2 emissions and total electric generation for an affected EGU over an 8-quarter period, any relatively short-term variability of data due to seasonal operations or periods of startup and shutdown, or other anomalous conditions, will be averaged into the calculated level of baseline emission performance. The baseline-setting approach of using total CO2 mass emissions and total electric generation over an 8-quarter period also aligns with the reporting and compliance requirements. The EPA is proposing that compliance would be demonstrated annually based on the lb CO2/MWh emission rate derived by dividing the total reported CO2 mass emissions by the total reported electric generation for an affected EGU during the compliance year, which is consistent with the expression of the degree of emission limitation proposed for each subcategory in sections X.D.4 and X.E.2. The EPA believes that using total mass CO2 emissions and total electric generation provides a simple and streamlined approach for calculating baseline emission performance without the need to sort and filter non-representative data; any minor amount of non-representative data will be subsumed and accounted for through implicit averaging over the course of the 8-quarter period. Moreover, this approach, by not sorting or filtering the data, eliminates any need for discretion in assessing whether the data is appropriate to use. 
The EPA is soliciting comment on the proposed baseline-setting approach and specifically on the applicability of such an approach for each of the different subcategories. The EPA is proposing a continuous 8-quarter period to better average out operating variability but solicits comment on whether a different time period would be more appropriate for assessing baseline emission performance, as well as on the 5-year window from which the period for baseline emission performance is chosen. The EPA also solicits comment on the use of total mass CO2 emissions and total electric generation over a consecutive 8-quarter time period as representative and on whether the EPA's proposed approach is appropriate.
The EPA believes that using the proposed baseline-setting approach as the basis for establishing presumptively approvable standards of performance will provide certainty for states, as well as transparency and a streamlined process for state plan development. While this approach is specifically designed to be flexible enough to accommodate unit-specific circumstances, states retain the ability to deviate from the methodologies the EPA is proposing for establishing baselines of emission performance for affected EGUs. The EPA believes that the instances in which a state may need to use an alternate baseline-setting methodology will be limited to anticipated changes in operation, i.e., circumstances in which historical emission performance is not representative of future emission performance. The EPA is proposing that states wishing to vary the baseline calculation for an affected EGU based on anticipated changes in operation, when those changes result in a less stringent standard of performance, must use the RULOF mechanism, which is designed to address such contingencies.
Long-term Coal-fired Steam Generating Units
This section describes the EPA's proposed methodology for establishing presumptively approvable standards of performance for long-term coal-fired steam generating units. Affected EGUs that choose to adopt a federally enforceable commitment to permanently cease operations of January 1, 2040, or later, or that do not adopt a federally enforceable date to permanently cease operations included in the state's plan submission, fall within this subcategory and have a proposed BSER of CCS with 90 percent capture and a proposed degree of emission limitation of 90 percent capture of the mass of CO2 in the flue gas (i.e., the mass of CO2 after the boiler but before the capture equipment) over an extended period of time and an 88.4 percent reduction in emission rate on a gross basis over an extended period of time. The EPA is proposing that where states use the methodology described here to establish standards of performance for an affected EGU in this subcategory, those established standards would be presumptively approvable when included in a state plan submission. In section X of this preamble, for the long-term coal-fired subcategory, the EPA is soliciting comment on a capture rate of 90 to 95 percent and a degree of emission limitation defined by a reduction in emission rate on a gross basis from 75 to 90 percent.
Establishing a standard of performance for an affected coal-fired EGU in this subcategory consists of two steps: establishing a source-specific level of baseline emission performance (as described above); and applying the level of stringency, based on the application of the BSER, to that level of baseline emission performance. Implementation of CCS with a capture rate of 90 precent translates to a level of stringency of an 88.4 percent reduction in CO2 emission rate (see section X.D.4.a of this preamble) compared to the baseline level of emission performance. Using the complement of 88.44 percent (i.e., 11.6 percent) and multiplying it by the baseline level of emission performance results in the presumptively approvable standard of performance. For example, if a long-term coal-fired EGU's level of baseline emission performance is 2,000 lbs per MWh, it will have a presumptively approvable standard of performance of 232 lbs per MWh (2,000 lbs per MWh multiplied by 0.116).
The EPA is also proposing that affected coal-fired EGUs in the long-term subcategory comply with federally enforceable increments of progress, which are described in section XI.D.3.a of this preamble.
The EPA solicits comments on this proposed methodology for calculating presumptively approvable standards of performance for long-term coal-fired steam generating units.
Medium-term Coal-fired Steam Generating Units
This section describes the EPA's proposed methodology for establishing presumptively approvable standards of performance for medium-term coal-fired steam generating units. Affected EGUs that choose to adopt a federally enforceable commitment to permanently cease operations after December 31, 2031, and before January 1, 2040, have a proposed BSER of 40 percent co-firing of natural gas. The EPA is proposing that where states use the methodology described here to establish standards of performance for affected coal-fired EGUs in this subcategory, those established standards of performance would be presumptively approvable when included in a state plan submission. 
Establishing a standard of performance for an affected EGU in this subcategory consists of two steps: establishing a source-specific level of baseline emission performance (as described earlier in this preamble); and applying the level of emission reduction stringency, based on the application of the BSER, to that level of baseline emission performance. Implementation of natural gas co-firing at a level of 40 percent of total annual heat input translates to a level of stringency of a 16 percent reduction in CO2 emissions (see section X.D.4.b of this preamble) compared to the baseline level of emission performance. Using the complement of 16 percent (i.e., 84 percent) and multiplying it by the baseline level of emission performance results in the presumptively approvable standard of performance for the affected EGU. For example, if a medium-term coal-fired EGU's level of baseline emission performance is 2,000 lbs per MWh, it will have a presumptively approvable standard of performance of 1,680 lbs per MWh (2,000 lbs per MWh multiplied by 0.84). In section X of this preamble, for the medium-term coal-fired subcategory, the EPA is soliciting comment on a natural gas co-firing level of 30 to 50 percent and a degree of emission limitation from 12 to 20 percent.
For medium-term coal-fired steam generating units that have an amount of co-firing that is reflected in the baseline operation, the EPA is proposing that states account for such preexisting co-firing in adjusting the degree of emission limitation. If, for example, an EGU co-fires natural gas at a level of 10 percent of the total annual heat input during the applicable 8-quarter baseline period, the corresponding degree of emission limitation would be adjusted to 30 percent to reflect the preexisting level of natural gas co-firing. This results in a standard of performance based on the degree of emission limitation achieving an additional 30 percent co-firing beyond the 10 percent that is accounted for in the baseline. The EPA believes this approach is a more straightforward mathematical adjustment than adjusting the baseline to appropriately reflect a preexisting level of co-firing. However, the EPA solicits comment on whether the adjustment of a standard of performance based on preexisting levels of natural gas co-firing should be done through the baseline. To adjust the baseline to account for preexisting natural gas co-firing, the state would need to calculate a baseline of emission performance for an EGU that removes the mass emissions and electric generation that are attributable to the natural gas portion of the fuel. With this adjusted baseline that removes the natural gas-fired portion, the presumptive standard of performance would be calculated by multiplying the adjusted baseline by the degree of emission limitation factor that reflects 40 percent co-firing. The EPA is not proposing this methodology, because parsing the attributable emissions and electric generation associated with natural gas co-firing from the attributable emissions and electric generation associated with coal-fired generation requires manipulation of the emissions and electric generation data. However, the EPA solicits comment on whether baseline adjustment is more appropriate and also why that may be so. 
The standard of performance for the medium-term coal-fired subcategory is based on the degree of emission limitation that is achievable through application of the BSER to the affected EGUs in the subcategory and consists exclusively of the rate-based emission limitation. However, to qualify for inclusion in the subcategory an affected coal-fired EGU must have chosen to commit to permanently cease operations prior to January 1, 2040. This date will be included in a state's plan submission and, if approved by the EPA, will become a federally enforceable component of the state plan. 
The EPA is proposing that affected coal-fired EGUs that are required to have enforceable dates to permanently cease operations for subcategory applicability, including EGUs in the medium-term coal-fired subcategory, have corresponding federally enforceable milestones with which they must comply. The EPA intends these milestones to assist affected EGUs in ensuring they are completing the necessary steps to comply with their state plan and commitments to dates to permanently cease operations. These milestones are described in detail in section XI.D.3.b of this preamble. Affected EGUs in this subcategory would also be required to comply with the federally enforceable increments of progress described in section XI.D.3.a of this preamble.
The EPA solicits comment on the proposed methodology for calculating presumptively approvable standards of performance for medium-term coal-fired steam generating units, including on the proposed approach for adjusting a presumptively approvable standard of performance to accommodate preexisting natural gas co-firing. 
Imminent-term Coal-fired Steam Generating Units
This section describes the EPA's proposed methodology for establishing presumptively approvable standards of performance for imminent-term coal-fired steam generating units. Affected EGUs that choose to adopt a federally enforceable commitment to permanently cease operations before January 1, 2032, have a proposed BSER of routine methods of operation and maintenance. Therefore, the proposed presumptively approvable standard of performance is based on the baseline emission performance of the affected EGU (as described in section XI.D.1.a of this preamble). 
Unlike the proposed standards of performance for the long-term and medium-term coal-fired steam generating units, establishing a standard of performance for an affected EGU in the imminent-term subcategory consists of just one step. The EPA is proposing that where states use the methodology described in section XI.D.1.a of this preamble to establish the baseline level of emission performance for an affected EGU, the emission rate described by that baseline would constitute the presumptively approvable standard of performance. This standard of performance reflects that the proposed BSER for these affected EGUs is routine methods of operation and maintenance and a degree of emission limitation equivalent to no increase in emission rate from the baseline level of emission performance. This also ensures that the affected EGU will not backslide in its emission performance.
Although the EPA believes that the baseline performance level adequately accounts for variability in annual emission rate, the EPA is also soliciting comment on a methodology for a presumptive standard above the baseline emission performance. For the imminent-term coal-fired subcategory, the EPA is soliciting comment on a presumptive standard that is defined by 0 to 2 standard deviations in annual emission rate (using the 5-year period of data) above the baseline emission performance, or that is 0 to 10 percent above the baseline emission performance.
The standard of performance for the imminent-term coal-fired subcategory is based on the degree of emission limitation that is achievable through application of the BSER to the affected EGUs in the subcategory and consists exclusively of the rate-based emission limitation. However, to qualify for inclusion in the subcategory an affected coal-fired EGU must have chosen to commit to permanently cease operations prior to January 1, 2032. This date will be included in a state's plan submission and, if approved by the EPA, will become a federally enforceable component of the state plan. 
The EPA is also proposing that affected coal-fired EGUs that are required to have enforceable dates to permanently cease operations for subcategory applicability, including EGUs in the imminent-term coal-fired subcategory, have corresponding federally enforceable milestones with which they must comply. The EPA intends these milestones to assist affected EGUs in ensuring they are completing the necessary steps to comply with these dates in their state plan. These milestones are described in detail in section XI.D.3.b of this preamble.
The EPA solicits comment on the proposed methodology for establishing presumptively approvable standards of performance for imminent-term coal-fired steam generating units. 
Near-term Coal-fired Steam Generating Units
Similar to the proposed approach for establishing presumptively approvable standards of performance for affected EGUs in the imminent-term coal-fired subcategory, the EPA is proposing that affected EGUs in the near-term coal-fired subcategory have a presumptively approvable standard of performance based on the baseline emission performance of the affected EGU (as described in section XI.D.1.a of this preamble). The near-term subcategory includes affected EGUs that choose to adopt a federally enforceable commitment to permanently cease operations after December 31, 2031, and before January 1, 2035, and that choose to make a federally enforceable commitment to operate with an annual capacity factor of less than 20 percent. 
The EPA is proposing that where states use the methodology described in section XI.D.1.a of this preamble to establish the baseline level of emission performance for an affected EGU, the emission rate described by that baseline would constitute the presumptively approvable standard of performance. This standard of performance reflects the proposed BSER of routine methods of operation and maintenance and a degree of emission limitation equivalent to no increase in emission rate. This also ensures that the affected EGU will not backslide in its emission performance. 
For the near-term coal-fired subcategory, the EPA is soliciting comment on a presumptive standard that is defined by 0 to 2 standard deviations in annual emission rate (using the 5-year period of data) above the baseline emission performance, or that is 0 to 10 percent above the baseline emission performance.
The standard of performance for the near-term coal-fired subcategory is based on the degree of emission limitation that is achievable through application of the BSER to the affected EGUs in the subcategory and consists exclusively of the rate-based emission limitation. However, to qualify for inclusion in the subcategory an affected coal-fired EGU must have chosen to commit to permanently cease operations after December 31, 2031, and before January 1, 2035, and must have chosen to commit to operate at an annual capacity factor of less than 20 percent. These commitments will be included in a state's plan submission and, if approved by the EPA, will become a federally enforceable component of the state plan. 
The EPA is also proposing that affected coal-fired EGUs that are required to have enforceable dates to permanently cease operations for subcategory applicability, including EGUs in the near-term coal-fired subcategory, have corresponding federally enforceable milestones with which they must comply. The EPA intends these milestones to assist affected EGUs in ensuring they are completing the necessary steps to comply with these dates in their state plan . These milestones are described in detail in section XI.D.3.b of this preamble.
The EPA solicits comment on the proposed methodology for establishing presumptively approvable standards of performance for near-term coal-fired steam generating units. 
Natural Gas-fired Steam Generating Units and Continental Oil-fired Steam Generating Units
This section describes the EPA's proposed methodology for presumptively approvable standards of performance for affected natural gas-fired and continental oil-fired steam generating units: low load natural gas-fired steam generating units, intermediate load natural gas- fired steam generating units, base load natural gas-fired steam generating units, low load oil-fired steam generating units, intermediate load continental oil-fired steam generating units, and base load continental oil-fired steam generating units. It does not address non-continental intermediate oil-fired and non-continental base load oil-fired steam generating units, which are described in section XI.D.1.f of this preamble. The proposed definitions of these subcategories are discussed in section X.C.2 of this preamble. The proposed presumptive standards of performance are based on degrees of emission limitation that units are currently achieving, consistent with the proposed BSER of routine methods of operation and maintenance, which amounts to a proposed degree of emission limitation of no increase in emission rate.
Unlike the approach to establishing presumptive standards of performance for coal-fired EGUs in these proposed emission guidelines, the EPA is proposing presumptive standards of performance for affected natural gas-fired and continental oil-fired steam generating units in lieu of methodologies that states would use to establish presumptive standards of performance. This is largely because the low variability in emissions data at intermediate and base load for these units and relatively consistent performance between these units at those load levels, as discussed in section X.E of this preamble and detailed in the Natural Gas- and Oil-fired Steam Generating Unit TSD, allows for the identification of a generally applicable emission standard.
However, for natural gas- or oil-fired units with low annual capacity factors, annual emission rates can be high (greater than 2,500 lb CO2/MWh-gross) and can vary considerably across units and from year to year. Despite their relatively high emission rates, though, overall emissions from these units are low. Based on these considerations, the EPA is not proposing a BSER or that states establish standards of performance for these units at this time. However, as noted above, the EPA is soliciting comment on determining a BSER of clean fuels for these units. In addition, the EPA is soliciting comment on a presumptive standard of performance for these units based on heat input. Specifically, the EPA is soliciting comment on a range of presumptive standards of performance from 120 to 130 lb CO2/MMBtu for low load natural gas-fired steam generating units, and from 160 to 170 lb CO2/MMBtu for low load oil-fired steam generating units.
For intermediate load natural gas-fired units (annual capacity factors greater than or equal to 8 percent and less than 45 percent), annual emission rates are less than 1,500 lb CO2/MWh-gross for about 90 percent of the units. Therefore, the EPA is proposing the presumptive standard of performance of an annual calendar-year emission rate of 1,500 lb CO2/MWh-gross for these units. 
For base load natural gas-fired units (annual capacity factors greater than or equal to 45 percent), annual emission rates are less than 1,300 lb CO2/MWh-gross for about 80 percent of units. Therefore, the EPA is proposing the presumptive standard of performance of an annual calendar-year emission rate of 1,300 lb CO2/MWh-gross for these units.
In the continental U.S., there are few if any oil-fired steam generating units that operate with intermediate or high utilization. Liquid-oil-fired steam generating units with 24-month capacity factors less than 8 percent do qualify for a work practice standard in lieu of emission requirements under the Mercury and Air Toxics Standards rule (MATS) (40 CFR 63, subpart UUUUU). If oil-fired units operated at higher annual capacities, it is likely they would do so with substantial amounts of natural gas firing and have emission rates that are similar to steam generating units that fire only natural gas at those levels of utilization. There are a few natural gas-fired steam generating units that are near the threshold for qualifying as oil-fired units (i.e., firing more than 15 percent oil in a given year) but that on average fire more than 90 percent of their heat input from natural gas. Therefore, the EPA is proposing the same presumptive standards of performance for oil-fired steam generating units as for natural gas-fired units, noted above. 
The EPA is also taking comment on a range of presumptive standards of performance for natural gas- and oil-fired steam generating units. Specifically, the EPA is soliciting comment on standards between (i) 1,400 and 1,600 lb CO2/MWh-gross for intermediate load natural gas-fired units, (ii) 1,250 and 1,400 lb CO2/MWh-gross for base load natural gas-fired units, (iii) 1,400 and 2,000 lb CO2/MWh-gross for intermediate load oil-fired units, and (iv) 1,250 and 1,800 lb CO2/MWh-gross for base load oil-fired units. The upper end of the ranges for oil-fired units is higher because of the limited data available for oil-fired units that operate at those annual capacity factors.
Non-continental Oil-fired Steam Generating Units
The EPA is proposing that for affected EGUs in the non-continental intermediate oil-fired and non-continental base load oil-fired subcategory, a presumptively approvable standard of performance would be based on baseline emission performance, consistent with the EPA's proposed BSER determination of routine methods of operation and maintenance and the proposed degree of emission limitation of no increase in emission rate. The EPA is proposing that where states use the methodology described in section XI.D.1.a of the preamble to establish unit-specific baseline levels of emission performance for affected EGUs in this subcategory, those emission rates would constitute presumptively approvable standards of performance when included in a state plan submission. This standard of performance would ensure no increase in the unit-specific emission rate from the baseline level of emission performance.
For the intermediate and base load non-continental oil-fired subcategory, the EPA is soliciting comment on a presumptive standard that is defined by 0 to 2 standard deviations in annual emission rate (using the 5-year period of data) above the baseline emission performance, or that is 0 to 10 percent above the baseline emission performance.
The EPA solicits comment on the proposed methodology for establishing presumptively approvable standards of performance for non-continental oil-fired steam generating units in the intermediate and base load subcategories. 
Remaining Useful Life and Other Factors 
Under CAA section 111(d), the EPA is required to promulgate regulations under which states submit plans applying standards of performance to affected EGUs. While states establish the standards of performance, there is a fundamental obligation under CAA section 111(d) that such standards reflect the degree of emission limitation achievable through the application of the BSER, as determined by the EPA. The EPA identifies this degree of emission limitation as part of its emission guideline. 40 CFR 60.22a(b)(5). Thus, as described in section X.D of this preamble, the EPA is providing proposed methodologies for states to follow in determining and applying presumptively approvable standards of performance to affected EGUs in each of the subcategories covered by these emission guidelines.
While standards of performance must generally reflect the degree of emission limitation achievable through application of the BSER, CAA section 111(d)(1) also requires that the EPA regulations permit the states, in applying a standard of performance to a particular designated facility, to "take into consideration, among other factors, the remaining useful life of the existing sources to which the standard applies." The EPA's implementing regulations under 40 CFR 60.24a thus allow a state to consider a particular designated facility's remaining useful life and other factors in applying to that facility a standard of performance that is less stringent than the presumptive level of stringency given in an emission guideline. 
In December 2022, the EPA proposed to clarify the existing requirements in subpart Ba governing what a state must demonstrate in order to invoke RULOF and provide a less stringent standard of performance when submitting a state plan. Specifically, the EPA proposed to require the state to demonstrate that a particular facility cannot reasonably achieve the degree of emission limitation achievable through application of the BSER based on one or more of three delineated circumstances, and proposed to clarify those three circumstances. The EPA also proposed additions and further clarifications to the process of invoking RULOF and determining a standard of performance based on RULOF, to ensure that use of the provision does not undermine the overall presumptive level of stringency of the BSER, as well as to provide a clear analytical framework for states and the regulated community as they seek to craft satisfactory plans that the EPA can ultimately approve.
The EPA is not soliciting comment in this rulemaking on the proposed revisions to the RULOF provisions in subpart Ba, which are subject to a separate rulemaking process. As noted in section XI.A of this preamble, the EPA intends to finalize revisions to subpart Ba prior to finalizing these emission guidelines. Those revised RULOF provisions, including any changes made in response to public comments, will apply to these emission guidelines. While the EPA is not taking comment on the proposed provisions of subpart Ba themselves, the EPA is requesting comment on how each of the RULOF provisions that the EPA proposed in December 2022 would be implemented in the context of these particular emission guidelines.
The remainder of this section of the preamble addresses how the requirements associated with RULOF, as the EPA has proposed to revise them, would apply to states and state plans under these emission guidelines. First, it addresses the threshold requirements for considering RULOF and how those requirements would apply to an affected EGU under these emission guidelines. Second, it addresses how, if a state has appropriately invoked RULOF for a particular affected EGU under the previous step, it would be required to determine a source-specific BSER and calculate a standard of performance for that affected EGU. Third, it discusses the proposed requirement for plans that apply less stringent standards of performance pursuant to RULOF to consider the potential pollution impacts and benefits of control to communities most affected by and vulnerable to emissions from the affected EGU. Fourth, this section addresses the proposed provisions for the standard for EPA review of state plans that include RULOF standards of performance. And, finally, it discusses the EPA's proposed interpretation of the Clean Air Act as laid out in the proposed revisions to subpart Ba that the Act allows states to adopt and enforce standards of performance more stringent than required by an applicable emission guideline, and that the EPA has the ability and authority to approve such standards of performance into state plans.
Threshold Requirements for Considering RULOF
As discussed earlier in this preamble, CAA section 111(d)(1) expressly requires the EPA to permit states to consider RULOF when applying a standard of performance to a particular affected EGU. The EPA's proposed revisions to the regulations governing states' use of RULOF would provide a clear analytical framework to ensure that its use to apply less stringent standards of performance for particular sources is consistent across states. The proposed revisions would also ensure that the use of the RULOF framework does not undermine the overall presumptive level of stringency of the EPA's BSER determination or render it meaningless. Such a result would be contrary to the overarching purpose of CAA section 111(d), which is generally to achieve meaningful emission reductions from designated facilities, in this case affected EGUs, based on the BSER in order to mitigate pollution that endangers public health and welfare. 
To this end, proposed subpart Ba would provide that a state may apply a less stringent standard of performance to a particular facility, taking into consideration remaining useful life and other factors, provided that the state demonstrates with respect to that facility (or class of facilities) that it cannot reasonably apply the BSER to achieve the degree of emission limitation determined by the EPA. Invocation of RULOF would be required to be based on one or more of three circumstances: (1) unreasonable cost of control resulting from plant age, location, or basic process design, (2) physical impossibility or technical infeasibility of installing necessary control equipment, or (3) other circumstances specific to the facility that are fundamentally different from the information considered in the determination of the BSER in the emission guidelines. 
A state wishing to invoke RULOF in order to apply a less stringent standard to a particular affected EGU would be required to demonstrate that there are fundamental differences between that EGU and the EPA's BSER determination, based on consideration of the BSER factors that the EPA considered in its analysis. In determining the BSER and the degree of emission reductions achievable through application of the BSER in these proposed emission guidelines, the EPA considered whether a system of emission reduction is adequately demonstrated for the subcategory based on the physical possibility and technical feasibility of applying that system, the costs of a system of emission reduction, the non-air quality health and environmental impacts and energy requirements associated with a system of emission reduction, and the extent of emission reductions from a system. 
For each subcategory, the EPA evaluated certain metrics related to each of these BSER factors. For example, in evaluating the costs associated with CCS and natural gas co-firing, the EPA considered both $/ton CO2 reduced and increases in levelized costs expressed as dollars per MWh electricity generation. For long-term coal-fired steam generating units, the EPA assessed the cost of CCS under a range of scenarios varying the amortization period and capacity factor. In section X.D.1.a.ii of this preamble, the EPA discusses various representative scenarios under which it is proposing to find that the costs of CCS are reasonable. For example, the EPA is proposing that a cost of $12/MWh for a reference unit with 50 percent capacity factor and an amortization period of 12 years is reasonable, but notes that a cost of $34/MWh for reference unit with a 7-year amortization period at a 70 percent capacity factor is less favorable. A state wishing to invoke RULOF for a particular affected EGU in the long-term coal-fired subcategory based on unreasonable cost of control would also be required to consider the cost per ton of CO2 reduced and cost per MWh electricity generated. The state would further have to demonstrate that the costs, as represented by these two metrics, for the particular affected EGU are significantly higher than the costs the EPA determines to be reasonable due to that EGU's age, location, or basic process design.
The RULOF provision, currently and as the EPA has proposed to revise it, also allows states to invoke RULOF based on other circumstances specific to an affected EGU. As an illustrative example, a state may wish to invoke RULOF for a medium-term coal-fired steam generating unit that is extremely isolated (e.g., on a small island more than 200 miles offshore) such that it would require construction of an LNG terminal and shipping of LNG by barge to have natural gas available to fire at the unit. In the EPA's evaluation of natural gas co-firing as the potential BSER for medium-term coal-fired steam generating units, the EPA considered the distance and cost of lateral pipeline builds in proposing natural gas co-firing as BSER. If a state can demonstrate that there is something unique to the source's being on a remote island, that this was not considered in evaluation of the BSER, and that the affected EGU cannot otherwise reasonably achieve the standard of performance, then it may be reasonable to invoke RULOF for that source. 
Under the EPA's proposed approach, states would not be able to invoke RULOF based on minor, non-fundamental differences between a particular affected EGU and what the EPA determined was reasonable for the BSER. There could be instances in which an affected EGU may not be able to comply with the presumptively approvable standard of performance based on the precise metrics of the BSER determination but is able to do so within a reasonable margin. The EPA is providing a range of cost evaluations based on different assumptions regarding amortization period and capacity factor, and is proposing to find that the costs of CCS and natural gas co-firing are reasonable for long-term and medium-term coal-fired steam generating units, respectively, under the range of relevant scenarios. For example, the costs of CCS for a particular affected EGU with an amortization period of 12 years and a 50 percent capacity factor may be $18/MWh, which is higher than the $12/MWh that the EPA determined for a reference unit and the $7/MWh that EPA determined was the average cost for the fleet. However, $18/MWh is not an unreasonable cost given, e.g., costs the EPA has determined are reasonable under other scenarios in this proposed rule and the comparisons to the costs of other rules that the EPA discussed in section X.D.1.a.ii of this preamble. A cost of $18/MWh would therefore not constitute a fundamental difference between the EPA's BSER determination and the circumstances of the affected EGU and would not be a reasonable basis for invoking RULOF. On the other hand, costs that constitute outliers, e.g., that are greater than the 95th percentile of costs on a fleetwide basis for comparable circumstances or that are the same as costs the EPA has determined are unreasonable elsewhere under these emission guidelines would likely represent a valid demonstration of a fundamental difference and could be the basis of invoking RULOF. 
Importantly, the costs evaluated in the BSER determination are, in general, for representative, average units or are based on average values across the fleet of steam generating units. Those BSER cost analysis values represent the average of a distribution of costs including costs that are above or below the average representative value. On that basis, implicit in the proposed determination that those average representative values are reasonable is a proposed determination that a significant portion of the unit specific costs around those average representative values are also reasonable, including some portion of those unit specific costs that are above but not significantly different than the average representative values.
Another example of a fundamental difference between the EPA's BSER determination and a particular affected EGU's circumstances is a difference based on physical impossibility or technical infeasibility. In making BSER determinations, the EPA must find that a system is adequately demonstrated; among other things, this means that the BSER must be technically feasible for the source category. For long-term coal-fired steam generating units, the EPA determined that CCS is adequately demonstrated because its components can be and have been applied to the source category and because it is generally geographically available to affected EGUs. However, it may be possible that a particular affected coal-fired EGU is physically unable to implement CCS due to, e.g., the impossibility of constructing a pipeline for CO2 transport. If a state can demonstrate that it is physically impossible or technically infeasible for this affected EGU to apply CCS because there are no other options to transport captured CO2, there is a fundamental difference between the EPA's BSER determination and the circumstances of this particular affected EGU and the state may invoke RULOF.
The EPA has proposed that states may invoke RULOF if they can demonstrate that an affected EGU cannot apply the BSER to achieve the degree of emission limitation determined by the EPA based on one or more of the three circumstances discussed earlier in this preamble. It thus follows that states would be able to invoke RULOF if they can demonstrate that an affected EGU can apply the BSER but cannot achieve the degree of emission limitation that the EPA determined is possible for the source category generally. 
However, the EPA has proposed in 40 CFR part 60, subpart Ba that a state may not invoke RULOF to provide a less stringent standard of performance for a particular affected EGU if that EGU cannot apply the BSER but can reasonably implement a different system of emission reduction to achieve the degree of emission limitation required by the EPA's BSER determination. While a state may be able to demonstrate that the affected EGU cannot reasonably apply the BSER based on one of the three circumstances, it would be inappropriate to invoke RULOF to apply a less stringent standard of performance because the source can still reasonably achieve the presumptive degree of emission limitation. In this instance, providing a less stringent standard of performance would be inconsistent with the purpose of CAA section 111(d) and these emission guidelines. 
States' consideration of the remaining useful life of a particular source for affected coal-fired EGUs will also be informed by the structure of the EPA's proposed subcategories, each of which has its own BSER determination under these emission guidelines. Under CAA section 111(d)(1) and the EPA's proposed RULOF provisions, states may consider an affected EGU's remaining useful life in determining whether application of the BSER to achieve the presumptive level of stringency would result in unreasonable cost resulting from plant age. In determining the BSER, the EPA considers costs and, in many instances, specifically considers annualized costs associated with payment of the total capital investment of the technology associated with the BSER. However, plant age can have considerable variability within a source category and the annualized costs can change significantly based on an affected EGU's remaining useful life and associated length of the capital recovery period. Thus, the costs of applying the BSER to an affected EGU with a short remaining life may differ fundamentally from the costs that the EPA found were reasonable in making its BSER determination.
These proposed emission guidelines include BSER determinations and presumptive standards of performance for affected coal-fired EGUs in four subcategories: imminent-term, near-term, medium-term, and long-term. As explained in section X.C.3 of this preamble, these subcategories are designed to accommodate ongoing trends in the power sector, which include many coal-fired EGUs that have currently planned or announced dates to cease operations. The EPA's proposed BSER determinations for each of these subcategories, as a practical matter, already account for the remaining useful lives of the affected EGUs by amortizing costs consistent with the operating horizons of sources within each subcategory. The EPA therefore does not anticipate that states would be likely to demonstrate the need to invoke RULOF based on a particular coal-fired EGU's remaining useful life, although doing so is not prohibited under these emission guidelines. The proposed requirements for states and affected EGUs invoking RULOF based on remaining useful life are addressed in the next subsection. 
The EPA is proposing to allow states to use the RULOF mechanism to provide a different compliance deadline for a source that can meet the presumptive standard of performance for the applicable subcategory but cannot do so by the final compliance date under these emission guidelines. In such cases, a state may be able to demonstrate that there are "other circumstances specific to the facility . . . that are fundamentally different from the information considered in the determination of the best system of emission reduction in the emission guidelines" that make timely compliance impossible. However, given the relatively long lead times and compliance timeframes proposed in these emission guidelines, the EPA anticipates that these circumstances will be rare. As explained here, under the proposed revisions to subpart Ba, RULOF demonstrations, including those in support of extending a compliance deadline, would have to be based on information from reliable and adequately documented sources and be applicable to and appropriate for the affected facility. 
As discussed in section XI.D.1.a of this preamble, the EPA is proposing a methodology for calculating an affected EGU's baseline emissions as part of determining its presumptively approvable standard of performance. The EPA explained that while the proposed methodology should be flexible enough to accommodate most unit-specific circumstances, it may not be appropriate to use recent historical emissions data to represent baseline emission performance when an affected EGU anticipates that its future operating conditions will change significantly. Consistent with the proposed subpart Ba, the EPA is proposing that states wishing to rely on an affected EGU's anticipated change in operating conditions as the basis for using a different methodology to set an emissions baseline would be required to use the RULOF mechanism described in this section of the preamble.
The EPA solicits comment on the application of the RULOF provisions of proposed subpart Ba to these emission guidelines. In particular, the EPA requests comment on factual circumstances in which it may or may not be appropriate for states to invoke RULOF for affected EGUs, given the proposed requirements and the EPA's proposed "fundamental difference" standard in the subpart Ba rulemaking. For the consideration of cost, the EPA requests comment on whether it should provide further guidance or requirements for determining when the costs of a BSER technology are "fundamentally different" from the Agency's BSER determination. The EPA additionally seeks comment on any source category-specific considerations for invoking RULOF for affected EGUs, including any additional or different requirements that might be necessary to ensure that use of RULOF does not undermine the presumptive stringency of these emission guidelines.
Calculation of a Standard That Accounts for RULOF
Subpart Ba, both the presently applicable requirements and as the EPA has proposed to revise them, provides that, if a state has demonstrated that accounting for RULOF is appropriate for a particular affected EGU, the state may then apply a less stringent standard to that EGU. The EPA's proposed subpart Ba would require that, in doing so, the state must determine a source-specific BSER by identifying all the systems of emission reduction available for the source and evaluating each system using the same factors and evaluation metrics that the EPA considered in determining the BSER for the applicable subcategory. As part of determining source-specific BSER, the state would also have to determine the degree of emission limitation that can be achieved by applying this source-specific BSER to the particular source. The state would then calculate and apply the standard of performance that reflects this degree of emission limitation. 
 Consistent with these proposed requirements in subpart Ba, the EPA is proposing to require states invoking RULOF for affected coal-fired EGUs in the long-term subcategory to evaluate natural gas co-firing as a potential source-specific BSER. Additionally, if an EGU in the long-term subcategory can implement CCS but cannot achieve the degree of emission limitation prescribed by the presumptive standard of performance, the EPA is proposing that the state evaluate CCS with a source-specific degree of emission limitation as a potential BSER. The EPA is also proposing that states invoking RULOF for long-term and medium-term affected coal-fired EGUs must evaluate different levels of natural gas co-firing. For example, for a source in the medium-term subcategory that cannot reasonably co-fire 40 percent natural gas, the state must evaluate lower levels of natural gas co-firing unless it has demonstrated that natural gas co-firing at any level is physically impossible or technically infeasible at the source. Similarly, if a state invoking RULOF for an affected EGU in the long-term subcategory demonstrates that the EGU cannot co-fire with natural gas at 40 percent, the EPA is proposing that the state must evaluate lower levels of co-firing as potential BSERs for the source, unless the state can demonstrate that it is physically impossible or technically infeasible for the source to co-fire natural gas. States may also consider additional potential source-specific BSERs for affected EGUs in either subcategory.
The EPA notes again that, under both the proposed subpart Ba and CAA section 111(d), an affected EGU that cannot reasonably apply the EPA's BSER but can achieve the degree of emission limitation for the applicable subcategory through other reasonable systems of emission reduction cannot be given a less stringent standard of performance. In this case, the affected EGU's standard of performance would still reflect the degree of emission limitation achievable through application of the EPA's BSER.
The EPA has proposed in its revisions to subpart Ba that specific requirements would apply when invoking RULOF based on an affected source's remaining useful life. Among other requirements, the EPA would have to either identify in an emission guideline the outermost date to cease operations for the relevant source category that qualifies for consideration of remaining useful life or provide a methodology and considerations for states to use in establishing such an outermost date. Proposed subpart Ba also provides that an affected source with a date to cease operations that is both imminent and prior to the outermost date could be eligible for a standard of performance that reflects that source's BAU. The EPA is proposing to supersede the application of subpart Ba with respect to the proposed requirements to establish outermost and imminent dates to cease operations for invoking RULOF based on an affected EGU's remaining useful life. As explained earlier in this section of the preamble, the EPA has designed the subcategories for coal-fired affected EGUs under these emission guidelines to accommodate sources' operating horizons. This approach to subcategorization obviates the need to establish an outermost date to cease operations to bound states' and affected EGUs' consideration of remaining useful life. Additionally, the EPA is proposing to establish an imminent-term subcategory with a proposed BSER determination of routine operation and maintenance, which serves the same purpose as establishing an imminent date to cease operations under the RULOF provision. It is not anticipated that states will have a reason to invoke RULOF due to a coal-fired EGU's imminent date to cease operations based on the structure of the subcategories under these emission guidelines.
Because of the small number of sources in the oil- and natural gas-fired steam generating unit subcategories and the diversity of circumstances in which they operate, the EPA is not proposing to establish outermost or imminent dates to cease operations for the purpose of considering remaining useful life for these sources. Regardless, because the proposed BSER determinations for these EGUs is routine methods of operation and maintenance (other than for low-load oil- and natural gas-fired steam generating units), the EPA does not anticipate that states will find it necessary to invoke RULOF for these sources. 
The proposed subpart Ba would require that any plan that applies a less stringent standard to a particular affected EGU based on remaining useful life must include the date by which the EGU commits to permanently cease operations as an enforceable requirement. The plan would also have to include measures that provide for the implementation and enforcement of such a commitment. The EPA is not proposing to supersede this proposed requirement for the purpose of this emission guideline; states that include a RULOF standard based on an affected EGU's remaining useful life must make the date that the source commits to permanently cease operations enforceable in the state plan.
Similarly, subpart Ba would require that if a state seeks to rely on a source's operating conditions, such as its restricted capacity, as the basis for invoking RULOF and setting a less stringent standard, the state plan must include that operating condition as an enforceable requirement. This requirement would apply to operating conditions that are within an affected EGU's control and is necessary to ensure that a source's standard of performance matches what that source can reasonably achieve and does not undermine the stringency of these emission guidelines. 
The proposed presumptively approvable standards of performance for affected EGUs in these emission guidelines are expressed in the form of rate-based emission limitations, specifically, as lb CO2/MWh. Therefore, to ensure transparency and to enable the EPA, states, and stakeholders to ensure that RULOF standards do not undermine the presumptive stringency of these emission guidelines, the EPA is proposing to require that standards of performance determined through this RULOF mechanism be in the same form of rate-based emission limitations.
The EPA seeks comment on implementation of the proposed subpart Ba requirements pertaining to determining a source-specific BSER and calculating a less stringent standard for sources invoking RULOF under these emission guidelines. It also seeks comment on the proposed requirements that are specific to these emission guidelines, including but not limited to the proposed requirement that states evaluate certain control options for affected EGUs in the long-term and medium-term subcategories as part of their source-specific BSER determination and the proposal to not provide outermost or imminent dates to cease operations for the consideration of remaining useful life. 
Consideration of Impacted Communities
While the consideration of RULOF may warrant application of a less stringent standard of performance to a particular affected EGU, such standards have the potential to result in disparate health and environmental impacts to communities most affected by and vulnerable to impacts from those EGUs. Those communities could be put in the position of bearing the brunt of the greater health and environmental impacts resulting from an affected EGU implementing a less stringent standard of performance than would otherwise have been required pursuant to the emission guidelines. A lack of consideration of such potential outcomes would be antithetical to the public health and welfare goals of CAA section 111(d).
Therefore, the proposed subpart Ba revisions would require that states applying less stringent standards of performance consider the potential pollution impacts and benefits of control to communities most affected by and vulnerable to emissions from the affected EGU in determining source-specific BSERs and the degree of emission limitation achievable through application of such BSERs. The state will have identified these communities as pertinent stakeholders in the process of meaningful engagement, which is discussed in section XI.F.1.b of this preamble. 
The EPA is proposing that, pursuant to the proposed requirement to consider the potential pollution impacts and benefits for impacted communities, state plan submissions would have to demonstrate that the state considered where and how a less stringent standard of performance impacts these communities. The plan submission under these emission guidelines must clearly identify impacted communities and how the state determined which communities were considered. The EPA is proposing that, in evaluating potential source-specific BSERs, a state must describe the health and environmental impacts anticipated from each control option it considered. A state must document how it considered these impacts, including any health and environmental benefits of control options, in determining the source-specific BSER. The EPA is also proposing that states must consider and include in their state plan submissions any feedback they received during meaningful engagement regarding their proposed RULOF standards of performance. 
As an example, the state plan submission could include a comparative analysis assessing potential BSER options for an affected EGU and the corresponding potential benefits to the identified communities under each option. If the comparative analysis shows that emissions from an affected EGU could be controlled at a higher cost than under the EPA's BSER but that such control benefits the communities that would otherwise be adversely impacted by a less stringent standard of performance, the state could balance these considerations and determine that a higher cost is warranted for the source-specific BSER. 
The EPA solicits comments on the proposed requirements for implementing subpart Ba's proposed provisions for consideration of impacted communities under these emission guidelines. In particular, the Agency is requesting comment on metrics or information concerning health and environmental impacts from affected EGUs that states can consider in source-specific RULOF determinations. As discussed in section XI.F.1.b, the EPA is also requesting comment on tools and methodologies for identifying communities that are most affected by and vulnerable to emissions from affected EGUs under these emission guidelines. 
The EPA's Standard of Review of State Plans Invoking RULOF
Under CAA section 111(d)(2), the EPA has the obligation to determine whether a state plan submission is "satisfactory." This obligation extends to all aspects of a state plan, including the application of less stringent standards of performance that account for RULOF. Pursuant to CAA section 111(d) and the proposed subpart Ba provisions, states carry the burden of making the demonstrations required under the RULOF mechanism and have the obligation to justify any accounting for RULOF in support of standards of performance that are less stringent than the proposed presumptively approvable standards in these emission guidelines. While the EPA has the discretion to supplement a state's demonstration, the EPA may also find that a state plan's demonstration is a basis for concluding that the plan is not "satisfactory" and may therefore disapprove the plan. 
As a general matter, a less stringent standard of performance pursuant to RULOF must meet all other applicable requirements of subpart Ba and these emission guidelines. 
In determining whether a state has met its burden in providing a less stringent standard of performance based on RULOF, the EPA will consider, among other things, the applicability and appropriateness of the information on which the state relied. Both a demonstration that a particular affected EGU meets the threshold requirements to invoke RULOF and the determination of a source-specific standard of performance entail the use of technical, cost, engineering, and other information. The proposed subpart Ba revisions would require states to use information that is applicable to and appropriate for the particular source at issue. This means that, when available, the state must use source- and site-specific information. This is consistent with the premise that invoking RULOF is appropriate for a particular source when there are fundamental differences between the EPA's BSER and that source's specific circumstances.
In some instances, site-specific information may not be available. In such cases, it may be reasonable for a state to use information from, e.g., cost, engineering, and other analyses the EPA has provided to support this rulemaking. The EPA is proposing that states using non-site-specific information must explain why that information is reasonable to rely on to determine a less stringent standard of performance based on RULOF. Regardless of the information used, it must come from reliable and adequately documented sources, which the proposed subpart Ba revisions explain presumptively include sources published by the EPA, permits, environmental consultants, control technology vendors, and inspection reports.
The EPA solicits comment on the types of source-specific and other information that states should be required to provide to support the inclusion of standards of performance based on RULOF in state plans, as well as on any additional sources of information that may be appropriate for states to use in this context.
Authority to Apply More Stringent Standards as Part of State Plans
As explained in the subpart Ba notice of proposed rulemaking, the EPA reevaluated its interpretation of CAA sections 111(d) and 116 and, consistent with its revised interpretation, has proposed revisions to subpart Ba to clarify that states may consider RULOF to include more stringent standards of performance in their state plans. The allowance in CAA section 111(d)(1) that states may consider "other factors" does not limit states to considering only factors that may result in a less stringent standard of performance; other factors that states may wish to account for in applying a more stringent standard than provided in these emission guidelines include, but are not limited to, effects on local communities, the availability of control technologies that allow a particular source to achieve greater emission reductions, and local or state policies and requirements. 
Pursuant to proposed subpart Ba, states seeking to apply a more stringent standard of performance based on other factors would have to adequately demonstrate that the standard is in fact more stringent than the presumptively approvable standard of performance for the applicable subcategory. However, a state would not be required to conduct a source-specific BSER evaluation for the purpose of applying a more stringent standard of performance, so long as the standard will achieve equivalent or better emission reductions. In this case, the EPA believes it is appropriate to defer to the state's discretion to impose a more stringent standard on an individual source because such a standard does not have the potential to undermine the presumptive stringency of these emission guidelines. 
More stringent standards of performance must meet all applicable statutory and regulatory requirements, including that they are adequately demonstrated. As for all standards of performance, the state plan must include requirements that provide for the implementation and enforcement of a more stringent standard. The EPA has the ability and authority to review more stringent standards of performance and to approve them provided that the minimum requirements of subpart Ba and these emission guidelines are met, rendering them federally enforceable. 
The EPA requests comment on the implementation of the proposed subpart Ba provisions pertaining to more stringent standards of performance in the context of these particular emission guidelines. 
Increments of Progress and Milestones for Federally Enforceable Commitment to Cease Operations
      The CAA section 111 implementing regulations at 40 CFR part 60, subpart Ba provide that state plans must include legally enforceable increments of progress to achieve compliance for each designated facility when the compliance schedule extends more than a specified length of time from the state plan submission date. The EPA's December 2022 proposed revisions to subpart Ba would require increments of progress when the compliance date is more than 16 months after the state plan submission deadline. Under these proposed emission guidelines, the state plan submission date would be 24 months (see Section XI.F.2 of this preamble) from promulgation of the emission guidelines, which the EPA is currently anticipating will be June 2026. The proposed compliance date is January 1, 2030, which is more than 16 months after the state plan submission deadline. The EPA is therefore proposing to require that state plans include increments of progress as discussed in this section. For the purpose of these emission guidelines, the EPA refers to pre-January 1, 2030, enforceable requirements associated with the planning, construction, and operation of natural gas co-firing infrastructure and CCS as increments of progress. The EPA is also proposing separate, federally enforceable "milestones" associated with activities surrounding enforceable dates to permanently cease operations for EGUs in the imminent-term, near-term, and medium-term subcategories. These additional state plan requirements are intended to ensure that affected EGUs can complete the steps necessary to qualify for a subcategory with a less stringent BSER and to provide the public assurance that those steps will be concluded in a timely manner. 
Increments of Progress
The EPA is proposing that state plans must include specified enforceable increments of progress as required elements for coal-fired EGUs that use co-firing to meet the standard of performance for the medium-term existing coal-fired steam generating subcategory or that use CCS to meet the standard of performance for the long-term existing coal-fired steam generating subcategory. This proposal adopts emission guideline-specific implementation of the five increments specified in the CAA section 111(d) implementing regulations at 40 CFR 60.21a(h). These five increments of progress are: (1) Submittal of a final control plan for the designated facility to the appropriate air pollution control agency; (2) Awarding of contracts for emission control systems or for process modifications, or issuance of orders for the purchase of component parts to accomplish emission control or process modification; (3) Initiation of on-site construction or installation of emission control equipment or process change; (4) Completion of on-sites construction or installation of emission control equipment or process change; and (5) Final compliance.
 Some increments have been adjusted to more closely align with planning, engineering, and construction steps anticipated for designated facilities that will be complying with standards of performance with co-firing or CCS, but they retain the basic structure and substance of the increments in the general implementing regulations. In addition, consistent with 40 CFR 60.24a(d), the EPA is proposing one additional increment of progress for both the long-term and medium-term coal-fired subcategories to ensure timely progress on the planning, permitting, and construction activities related to pipelines that may be required to enable full compliance with the applicable standard of performance. The EPA is also proposing a second additional increment of progress for the long-term subcategory related to the identification of an appropriate sequestration site. 
The EPA is proposing that final compliance with the applicable standard of performance, also defined as the final increment of progress in the implementing regulations, must occur no later than January 1, 2030. For the remaining increments, the EPA is not proposing date-specific deadlines for achieving increments of progress. Instead, we propose that states must assign calendar day deadlines for each of the remaining increments for each affected EGU in the medium-term and long-term coal-fired subcategories in their state plan submissions subject to one additional constraint: that the increment of progress corresponding to 40 CFR 60.21(h)(1) (submittal of a final control plan to the air pollution control agency) in both subcategories be assigned the earliest calendar date deadline among the increments. This approach would provide states with flexibility to tailor compliance timelines to individual facilities, allow simultaneous work toward separate increments, and still ensure full performance by 2030. The EPA solicits comment on this approach as well as whether the EPA should instead finalize date-specific deadlines or more general timeframes for achieving increments of progress rather than leaving the timing for most increments to state discretion. The EPA also seeks comment on the specific deadlines or timeframes that the EPA could assign to each increment under a more prescriptive approach. 
The EPA is not proposing increments of progress for either the imminent- or near-term subcategories for coal-fired steam generating units, or for oil- or natural gas-fired steam generating units. The proposed BSERs for these affected EGUs are routine operation and maintenance, which does not require the installation of new emission controls or operational changes. Because there is no need for the types of increments of progress specified in 40 CFR 60.21a(h) to ensure that affected EGUs in the imminent and near-term coal-fired and oil- and natural gas-fired subcategories can achieve full compliance by the compliance date, the EPA is proposing that the requirement for increments of progress in 40 CFR 60.24a(d) does not apply to these units. 
For coal-fired EGUs falling within the medium-term subcategory, the EPA proposes the following increments of progress as enforceable elements required to be included in a state plan: (1) Submission of a final control plan for the affected EGU to the appropriate air pollution control agency. The final control plan must be consistent with the subcategory declaration in the state plan and must include supporting analysis for the affected EGU's control strategy, including the design basis for modifications at the facility, the anticipated timeline to achieve full compliance, and the benchmarks the facility anticipates along the way. (2) Awarding of contracts for boiler modifications, or issuance of orders for the purchase of component parts to accomplish boiler modifications. Affected EGUs can demonstrate compliance with this increment by submitting sufficient evidence that the appropriate contracts have been awarded. (3) Initiation of onsite construction or installation of any boiler modifications necessary to enable natural gas co-firing at a level of 40 percent on an annual average basis. (4) Completion of onsite construction of any boiler modifications necessary to enable natural gas co-firing at a level of 40 percent on an annual average basis. (5) Final compliance with the standard of performance by January 1, 2030. 
In addition to the five increments of progress derived from the CAA section 111(d) implementing regulations, the EPA is proposing an additional increment of progress for affected EGUs that adopt co-firing to meet the standard of performance for the medium-term subcategory, to ensure timely completion of any pipeline infrastructure needed to transport natural gas to designated facilities within subcategory. Affected EGUs are required to demonstrate that all permitting actions related to pipeline construction have commenced by a date specified in the state plan. Evidence in support of the demonstration must include pipeline planning and design documentation that informed the permitting application process, a complete list of pipeline-related permitting applications, including the nature of the permit sought and the authority to which each permit application was submitted, an attestation that the list of pipeline-related permit applications is complete with respect to the authorizations required to operate the facility at full compliance with the standard of performance, and a timeline to complete all pipeline permitting activities. 
For coal-fired EGUs falling within the long-term subcategory, the EPA proposes the following increments of progress as required, enforceable elements to be included in a state plan submission: (1) Submission of a final control plan for the affected EGU to the appropriate air pollution control agency. The final control plan must be consistent with the subcategory declaration in the state plan and must include supporting analysis for the affected EGU's control strategy, including a feasibility and/or FEED study. (2) Awarding of contracts for emission control systems or for process modifications, or issuance of orders for the purchase of component parts to accomplish emission control or process modification. Affected EGUs can demonstrate compliance with this increment by submitting sufficient evidence that the appropriate contracts have been awarded. (3) Initiation of onsite construction or installation of emission control equipment or process change required to achieve 90 percent CCS on an annual basis. (4) Completion of onsite construction or installation of emission control equipment or process change required to achieve 90 percent CCS on an annual basis. (5) Final compliance with the standard of performance by January 1, 2030. 
In addition to the five increments of progress derived from the CAA section 111(d) implementing regulations, the EPA is proposing two additional increments for affected EGUs that adopt CCS to meet the standard of performance for the long-term subcategory. The first reflects the approach proposed earlier in this preamble for the co-firing subcategory to ensure timely completion of pipeline infrastructure and the second is designed to ensure timely selection of an appropriate sequestration site. As the first additional increment, the EPA proposes that affected EGUs using CCS to comply with their standards of performance be required to demonstrate that all permitting actions related to pipeline construction have commenced by a date specified in the state plan. Evidence in support of the demonstration must include pipeline planning and design documentation that informed the permitting process, a complete list of pipeline-related permitting applications, including the nature of the permit sought and the authority to which each permit application was submitted, an attestation that the list of pipeline-related permits is complete with respect to the authorizations required to operate the facility at full compliance with the standard of performance, and a timeline to complete all pipeline permitting activities. 
The EPA proposes a second additional increment of progress for affected EGUs using CCS to comply with their standards of performance for the long-term subcategory, to ensure timely completion of site selection for geologic sequestration of captured CO2 from the facility. Affected EGUs within this subcategory must submit a report identifying the geographic location where CO2 will be injected underground, how the CO2 will be transported from the capture location to the storage location, and the regulatory requirements associated with the sequestration activities, as well as an anticipated timeline for completing related permitting activities.
The EPA requests comment on the substance of each of the six proposed increments of progress for coal-fired steam generating units falling within the medium-term subcategory as well as the seven increments of progress proposed for the long-term subcategory. The EPA seeks comment on whether the increments contain an appropriate level of specificity to establish clear, verifiable criteria to ensure that states and affected EGUs are taking the steps necessary to reach full compliance. If commenters believe they do not, we request comment on the appropriate level of specificity for each increment. Additionally, as discussed in section XI.F.1.b.i of this preamble, the EPA is proposing a requirement that each state plan provide for the establishment of "CAA Section 111(d) EGU Rule Websites" by the owners or operators of affected EGUs. The EPA is further proposing that state plans must require affected EGUs with increments of progress to post those increments, the schedule required in the state plan for achieving them, and any documentation necessary to demonstrate that they have been achieved to this website in a timely manner. 
Milestones for Federally Enforceable Commitment to Cease Operations
The EPA is proposing that state plans must include legally enforceable milestones for affected EGUs within the imminent-term, near-term, and medium-term coal-fired steam generating unit subcategories. As described in section X.C.3 of this preamble, the applicability criteria for each of the subcategories of coal-fired steam generating units include an affected EGU's intended operating horizon, which is represented by a federally enforceable commitment to cease operation by a date certain. Accordingly, affected EGUs in the imminent-term, near-term, and medium-term subcategories have BSERs that are specifically tailored to and dependent on their shorter operating horizons. The EPA is aware that there are many processes an affected EGU must complete in order to permanently cease operation. Therefore, to ensure that affected EGUs can complete the steps necessary to qualify for a subcategory with a less stringent standard of performance and to provide the public assurance that those steps will be concluded in a timely manner, the EPA is proposing additional state plan requirements, referred to as "milestones," for EGUs in the imminent-term, near-term, and medium-term subcategories. 
The proposed milestone reporting requirements count backward from an affected EGU's federally enforceable date to permanently cease operations to ensure timely progress toward that date. Five years before any date used to determine the applicable subcategory under these emission guidelines or 60 days after state plan submission, whichever is later, designated facilities must submit a Milestone Report to the applicable state administering authority that includes the following: (1) A summary of the process steps required for the affected EGU to cease operation by the federally enforceable date, including the approximate timing and duration of each step. (2) A list of key milestones, metrics that will be used to assess whether each milestone has been met, and calendar day deadlines for each milestone. These milestones must include at least the following: notice to the official reliability authority of the federally enforceable retirement date; submittal of an official suspension filing (or equivalent filing) made to the affected EGU's reliability authority; and submittal of an official retirement filing with the unit's reliability authority. (3) An analysis of how the process steps, milestones, and associated timelines included in the Milestone Report compare to the timelines of similar units within the state that have permanently ceased operations within the 10 years prior to the date of promulgation of these emission guidelines. (4) Supporting regulatory documents, including correspondence and official filings with the relevant regional transmission organization, balancing authority, public utility commission, or other applicable authority, as well as any filings with the SEC or notices to investors in which the plans for the EGU are mentioned and any integrated resource plan. 
For each of the remaining years prior to the federally enforceable date to permanently cease operations that is used to determine the applicable subcategory, affected EGUs must submit an annual Milestone Status Report that addresses the following: (1) progress toward meeting all milestones and related metrics identified in the Milestone Report; and (2) supporting regulatory documents, including correspondence and official filings with the relevant regional transmission organization, balancing authority, public utility commission, or other applicable authority to demonstrate compliance with or progress toward all milestones. 
The EPA is also proposing that affected EGUs with reporting milestones associated with federally enforceable commitments to permanently cease operations would be required to submit a Final Milestone Status Report no later than 6 months following its federally enforceable date. This report would document any actions that the unit has taken subsequent to ceasing operation to ensure that such cessation is permanent, including any regulatory filings with applicable authorities or decommissioning plans. The EPA requests input on whether 6 months after the federally enforceable date is an appropriate period of time to capture any actions affected EGUs taken following cessation of operations.
The EPA is proposing that affected EGUs with reporting milestones for federally enforceable commitments to permanently cease operations would be required to post their initial Milestone Report, annual Milestone Status Reports, and final Milestone Status Report, including the schedule for achieving milestones and any documentation necessary to demonstrate that milestones have been achieved, on the CAA Section 111(d) EGU Rule Website, as described in Section XI.F.1.b, within 30 business days of being filed. 
The EPA recognizes that applicable regulatory authorities, retirement processes, and retirement approval criteria will vary across states and affected EGUs. The proposed milestone requirements are intended to establish a general framework flexible enough to account for significant differences across jurisdictions while assuring timely planning toward the dates by which affected EGUs permanently cease operations. The EPA requests comment on this proposed approach, specifically whether any jurisdictions present unique state circumstances that should be considered when defining milestones and the required reporting elements. 
Testing and Monitoring Requirements 
The EPA is proposing to require states to include in their plans a requirement that affected EGUs monitor and report hourly CO2 mass emissions emitted to the atmosphere, total heat input, and total gross electricity output, including electricity generation and, where applicable, useful thermal output converted to gross MWh, in accordance with the 40 CFR part 75 monitoring and reporting requirements. Under this proposal, affected EGUs would be required to use a 40 CFR part 75 certified monitoring methodology and report the hourly data on a quarterly basis, with each quarterly report due to the Administrator 30 days after the last day in the calendar quarter. The monitoring requirements of 40 CFR part 75 require most fossil fuel-fired boilers to use a CO2 CEMS, including a CO2 concentration monitor and stack gas flow monitor, although some oil- and natural gas-fired boilers may have options to use alternative measurement methodologies (e.g., fuel flow meters). A CO2 CEMS is the most technically reliable method of emission measurement for EGUs, as it provides a measurement method that is performance based rather than equipment specific and is verified based on NIST traceable standards. A CEMS provides a continuous measurement stream that can account for variability in the fuels and the combustion process. Reference methods have been developed to ensure that all CEMS meet the same performance criteria, which helps to ensure consistent, accurate data.
The majority of EGUs will generally have no changes to their monitoring and reporting requirements and will continue to monitor and submit emissions reports under 40 CFR part 75 as they have under existing programs, such as the Acid Rain Program (ARP) and RGGI -- a cooperative of several states formed to reduce CO2 emissions from EGUs. The majority of coal- and oil-fired EGUs not subject to the ARP or RGGI are subject to the MATS program and, therefore, will have installed stack gas flow monitors and/or CO2 concentration monitors necessary to comply with the MATS. Relying on the same monitors that are certified and quality-assured in accordance with 40 CFR part 75 ensures cost efficient, consistent, and accurate data that may be used for different purposes for multiple regulatory programs. 
The EPA requests comment on monitoring and reporting requirements for captured CO2 mass emissions and net electricity output, and on allowable testing methods for stack gas flow rate. 
The CCS process is also subject to monitoring and reporting requirements under the EPA's GHGRP (40 CFR part 98). The GHGRP requires reporting of facility-level GHG data and other relevant information from large sources and suppliers in the U.S. The "suppliers of carbon dioxide" source category of the GHGRP (GHGRP subpart PP) requires those affected facilities with production process units that capture a CO2 stream for purposes of supplying CO2 for commercial applications or that capture and maintain custody of a CO2 stream in order to sequester or otherwise inject it underground to report the mass of CO2 captured and supplied. Facilities that inject a CO2 stream underground for long-term containment in subsurface geologic formations report quantities of CO2 sequestered under the "geologic sequestration of carbon dioxide" source category of the GHGRP (GHGRP subpart RR). In 2022, to complement GHGRP subpart RR, the EPA proposed the "geologic sequestration of carbon dioxide with enhanced oil recovery (EOR) using ISO 27916" source category of the GHGRP (GHGRP subpart VV) to provide an alternative method of reporting geologic sequestration in association with EOR.[,][,] 
The EPA is proposing that any affected unit that employs CCS technology that captures enough CO2 to meet the proposed standard and injects the captured CO2 underground must report under GHGRP subpart RR or GHGRP subpart VV. If the captured CO2 is sent offsite, then the facility injecting the CO2 underground must report under GHGRP subpart RR or GHGRP subpart VV. This proposal does not change any of the requirements to obtain or comply with a UIC permit for facilities that are subject to the EPA's UIC program under the Safe Drinking Water Act. 
The EPA also notes that compliance with the standard is determined exclusively by the tons of CO2 captured by the emitting EGU. The tons of CO2 sequestered by the geologic sequestration site are not part of that calculation. However, to verify that the CO2 captured at the emitting EGU is sent to a geologic sequestration site, we are leveraging regulatory requirements under the GHGRP. Further, we note that the determination that the BSER is adequately demonstrated relies on geologic sequestration that is not associated with EOR; however EGUs would have the option to send CO2 to EOR facilities that report under GHGRP subpart RR or GHGRP subpart VV. We also emphasize that this proposal does not involve regulation of downstream recipients of captured CO2. That is, the regulatory standard applies exclusively to the emitting EGU, not to any downstream user or recipient of the captured CO2. The requirement that the emitting EGU assure that captured CO2 is managed at an entity subject to the GHGRP requirements is thus exclusively an element of enforcement of the EGU standard. Similarly, the existing regulatory requirements applicable to geologic sequestration are not part of the proposed rule. 
The EPA requests comment on the following questions related to additional monitoring and reporting of hourly captured CO2 under 40 CFR part 75: a) should EGUs with carbon capture technologies be required to monitor and report the hourly captured CO2 mass emissions under 40 CFR part 75, b) if EGUs with carbon capture technologies are not required to monitor and report the hourly captured CO2 mass emissions, the calculation procedures for total heat input and NOX rate in appendix F to 40 CFR part 75 may no longer provide accurate results; therefore, what changes might be necessary to accurately determine total heat input and NOX rate, c) to ensure accurate and complete accounting of CO2 mass emissions emitted to the atmosphere and captured for use or sequestration, at what locations should CO2 concentration and stack gas flow be monitored, and should other values also be monitored at those locations, d) are there quality assurance activities outside of those required under 40 CFR part 75 for CO2 concentration monitors and stack gas flow monitors that should be required of the monitors to accurately and reliably measure captured CO2 mass emissions, and e) what monitoring plan, quality assurance, and emissions data should be reported to the EPA to support evaluation and ensure consistent and accurate data as it relates to CO2 emissions capture.
The 40 CFR part 75 monitoring and reporting provisions require hourly reporting of total gross electricity output, including useful thermal output, but do not require the reporting of net electricity output. The EPA requests comment on the following questions related to reporting of net electricity output: a) should EGUs be required to measure and report total net electricity output, including useful thermal output, under 40 CFR part 75, b) what guidance should the EPA provide on how to measure and apportion net electricity output, c) should EGUs measure and report net electricity output at the unit or facility level, and d) what monitoring plan, quality assurance, and output data should be reported to the EPA to support evaluation and ensure consistent and accurate data as it relates to total net electricity output.
To calculate CO2 mass emissions at a fossil fuel-fired boiler, the EGU typically measures CO2 concentration and flue gas flow rate as the exhaust gases from combustion pass through the stack (or duct). Under 40 CFR part 75, EGUs must complete regular performance tests on the flue gas flow monitor based on EPA Reference Method 2 or its allowable alternatives that are provided in 40 CFR part 60, appendices A-1 and A-2. In general, the allowable alternative measurement methods reduce or eliminate the potential overestimation of stack gas flow rate that results from the use of EPA Reference Method 2 when the specific flow conditions (e.g., angular flow) are present in the stack. However, EGUs with stack gas flow monitors are not required to use the allowable alternative measurement methods and EGUs may change methods at any time. The EPA requests comment on the following questions related to the use of EPA Reference Method 2 and its allowable alternatives for stack gas flow monitors under 40 CFR part 75: a) should or under what conditions should EGUs be required to conduct a flow study and choose the appropriate EPA reference method for each stack gas flow monitor based on the results of the study, b) once an EGU selects the use of an EPA reference method for a stack gas flow monitor, regardless of the basis for that selection, should the EGU be required to continue using the same EPA reference method until a flow study or other engineering justification is made to change the EPA reference method, and c) what additional monitoring plan, quality assurance, and emissions data should be reported to the EPA to support evaluation and ensure consistent and accurate data as it relates stack gas flow rate and performance of the stack gas flow monitor.
Compliance Flexibilities
In developing these proposed emission guidelines, the EPA has heard from stakeholders seeking compliance flexibility in light of the rapidly evolving and dynamic nature of the power sector. In particular, stakeholders have requested that the EPA allow states to include flexibilities such as averaging and market-based trading in their state plans, as has been permitted under prior EPA rules. This section discusses considerations related to potential compliance flexibilities in the context of this particular rule and set of regulated sources, and solicits comment on the appropriateness of averaging and trading for these emission guidelines. 
Overview
In the proposed subpart Ba revisions, "Adoption and Submittal of State Plans for Designated Facilities: Implementing Regulations Under Clean Air Act Section 111(d)" (87 FR 79176; December 23, 2022), the EPA explained that under its proposed interpretation of CAA section 111, each state is permitted to adopt measures that allow its sources to meet their emission limits in the aggregate when the EPA determines, in any particular emission guideline, that it is appropriate to do so given, inter alia, the pollutant, sources, and standards of performance at issue. Thus, the EPA has proposed to return to its longstanding position that CAA section 111(d) authorizes the EPA to approve state plans that achieve the requisite emission limitation through aggregate reductions from their sources, including through trading or averaging, where appropriate for a particular emission guideline and consistent with the intended environmental outcomes of the guideline. See 87 FR 79208 (December 23, 2022). 
Consistent with the return to this longstanding position, the EPA is taking comment on whether trading and averaging are appropriate under these emission guidelines. If permitted, states would not be required to allow for such compliance mechanisms in their state plans but could provide for trading and averaging at their discretion. This section discusses considerations related to the appropriateness of trading and averaging in the context of these emission guidelines and solicits comment on these considerations. This section also takes comment on how trading and averaging programs, if permitted, could be designed to ensure that state plans maintain the level of emission performance by affected EGUs that is required under these proposed emission guidelines, and it includes illustrative program design methods.
As discussed in section XI.C of this preamble, state plans must demonstrate that they achieve a level of emission performance by affected EGUs that is consistent with the application of the BSER. If a state plan was to include trading or averaging, it would need to provide a demonstration that affected EGUs complying through such flexible mechanisms would still achieve an equivalent level of emission performance consistent with the application of the BSER. In the case of averaging, discussed in section XI.E.3 of this preamble, an equivalence demonstration would be relatively straightforward. For emission trading programs, ensuring equivalent emission performance in the aggregate may be more difficult, especially given the current rapid evolution of the affected source category for these emission guidelines. In section XI.E.2 of this preamble, the EPA discusses program design examples as well as potential design elements and takes comment on whether they could ensure that use of emission trading does not erode the emission performance improvements that these emission guidelines are designed to achieve. 
The EPA also notes that, if trading and averaging are permitted under these emission guidelines, states that incorporate trading or averaging into their state plans would need to conduct meaningful engagement on this aspect of their plans with pertinent stakeholders, just as they would need to do for any other part of a plan. As discussed in greater detail in section XI.F.1.b of this preamble, meaningful engagement provides an opportunity for communities most affected by and vulnerable to the health and environmental impacts of a plan to provide input, including input on any impacts resulting from trading or averaging. 
Emission Trading
The EPA is seeking comment on whether it is appropriate to allow state plans to include emission trading programs as a compliance flexibility for affected EGUs under these emission guidelines, including whether certain types of trading programs may be more appropriate than others. This section discusses considerations related to whether the EPA should permit emission trading, as well as how, if emission trading is allowed, states could potentially incorporate a rate-based trading program or a mass-based trading program in a way that preserves the stringency of these emission guidelines. The EPA is seeking comment on these potential methods, as well as on other methods that could maintain the required level of emission performance under the proposed emission guidelines.
Considerations for Emission Trading in State Plans
Emission trading has been used to achieve required emission reductions in the power sector for nearly 3 decades. In Title IV of the Clean Air Act Amendments of 1990, Congress specified the design elements for the Acid Rain Program, a 48-state allowance trading program to reduce SO2 emissions and the resulting acid precipitation. Building on the success of that first allowance trading program as a tool for addressing multi-state air pollution issues, the EPA has promulgated and implemented multiple allowance trading programs since 1998 for SO2 or NOX emissions to address the requirements of the CAA's good neighbor provision with respect to successively more stringent NAAQS for fine particulate matter and ozone. The EPA currently administers eight power sector emission trading programs that differ in pollutants, geographic regions, covered time periods, and levels of stringency. Annual progress reports demonstrate that EPA trading programs have been successful in mitigating the problems they were designed to address, exhibiting significant emission reductions and extraordinarily high levels of compliance. In addition, several states have implemented intrastate or regional CO2 emissions trading programs to address GHG emissions from the power sector (the RGGI and California trading programs, respectively).
In general, emission trading programs provide flexibility for EGUs to secure emission reductions at a lower cost relative to more prescriptive forms of regulation. Emission trading can allow the owners and operators of EGUs to prioritize emission reduction actions where they are the quickest or cheapest to achieve while still meeting electricity demand and broader environmental and economic performance goals. These benefits are heightened where there is a diverse set of emission sources (e.g., variation in technology, fuel type, age, and operating parameters) included in an emission trading program. This diversity of sources is typically accompanied by differences in marginal emission abatement costs and operating parameters, resulting in heterogeneity in economic emission reduction opportunities that can be optimized through the compliance flexibility provided through emission trading. In addition, the EPA has observed, with the support of multiple independent analyses, that there is significant evidence that implementation of trading programs prompted greater innovation and deployment of clean technologies that reduce emissions and control costs.
Emission trading may provide important benefits as the fleet of EGUs affected by these emission guidelines is rapidly evolving. Having flexibility to prioritize the most cost effective emission reductions among affected EGUs may reduce the cost of compliance as well as provide flexibility for fleet management, while achieving the requisite level of emission performance. In particular, emission trading may provide short-term operational flexibility to meet reliability needs. 
At the same time, a rapidly evolving fleet of affected EGUs may pose challenges for implementing an emission trading program, especially in the context of the emission guidelines that the EPA is proposing here. The EPA notes that the proposed emission guidelines only include steam generating units and that the fleet of affected EGUs is expected to shrink significantly under BAU projections (see section IV.F of this preamble). As a result, there is unlikely to be as much diversity in cost and emission performance among affected emission sources (resulting in less diversity in emission reduction opportunities and marginal abatement costs) as seen in prior emission trading programs for the electric power sector. The projected BAU contraction of the fleet over the next 10 to 15 years also means there may be few affected emission sources in a state that could be included in an emission trading program. 
The utility of trading under these emission guidelines may also be obviated by subcategories the EPA has proposed to establish. The specific subcategories proposed under these emission guidelines are designed to provide for much of the same operational flexibility as trading; as a result, the EPA believes that it would not be appropriate to allow affected EGUs in certain subcategories to comply with their standards of performance through trading. As discussed in section X.D.3 of this preamble, the BSER determinations for the imminent- and near-term coal-fired steam generating unit subcategories are designed to take into account factors such as operating horizon and load level (expressed as annual capacity factor). In addition, states may invoke RULOF, where appropriate, when establishing standards of performance for certain affected EGUs. An emission trading program that includes affected EGUs that have BSERs and resulting standards of performance based on limited expected emission reduction potential--affected EGUs in the imminent- and near-term coal-fired subcategories, as well as natural gas- and oil-fired steam generating units--or a less stringent standard of performance established through a state invoking RULOF, may introduce the risk of undermining the intended stringency of the emission guidelines for other facilities that would not otherwise meet the RULOF criteria. In addition, affected EGUs in the long-term subcategory that receive the IRC section 45Q tax credit for permanent sequestration of CO2 may have an overriding incentive to maximize both the application of the CCS technology and total electric generation, leading to source behavior that may be non-responsive to the economic incentives of a trading program. 
The EPA requests comment on these challenges and on whether, in light of these and other considerations, emission trading should be permitted as a compliance flexibility under these emission guidelines. In particular, the EPA is soliciting comment on whether there is utility in permitting trading for any of the proposed subcategories of affected EGUs, after considering the operational flexibility already provided by the structure of those subcategories and their proposed BSERs. The EPA is also soliciting comment on whether trading could or should be permitted for certain subcategories and not others, and why. In the following sections, the EPA discusses potential rate-based and mass-based emission trading program approaches that, if trading is permitted, could potentially be included in a state plan and solicits comment on applied implementation issues in the context of these proposed emission guidelines and the considerations discussed earlier in this preamble.
Rate-based Emission Trading
A rate-based trading program allows affected EGUs to trade compliance instruments that are generated based on their emission performance. This section describes one method of how states could establish a rate-based trading program as part of a state plan. The EPA requests comment on whether this or another method of rate-based trading could ensure the level of emission performance required under these emission guidelines. 
In this example, affected EGUs that perform at a lower emission rate (lb CO2/MWh) than their standard of performance would be issued compliance instruments that are denominated in one ton of CO2. A tradable instrument denominated in another unit of measure, such as a MWh, is not fungible in the context of a rate-based emission trading program. A compliance instrument denominated in MWh that is awarded to one affected EGU may not represent an equivalent amount of emissions credit when used by another affected EGU to demonstrate compliance, as the CO2 emission rates (lb CO2/MWh) of the two affected EGUs are likely to differ. This may pose challenges for states trying to demonstrate equivalence with the intended stringency of the BSER. 
These compliance instruments could be transferred among affected EGUs, making them "tradable." Compliance would be demonstrated for an affected EGU based on a combination of its reported CO2 emission performance (in lb CO2/MWh) and, if necessary, the surrender of an appropriate number of tradable compliance instruments, such that the demonstrated lb CO2/MWh emission performance is equivalent to the rate-based standard of performance for the affected EGU. 
Specifically, each affected EGU would have a particular standard of performance, based on the degree of emission limitation achievable through application of the BSER, with which it would have to demonstrate compliance. Under a rate-based trading program, affected EGUs performing at a CO2 emission rate below their standard of performance would be awarded compliance instruments at the end of each control period denominated in tons of CO2. The number of compliance instruments awarded would be equal to the difference between their standard of performance CO2 emission rate and their actual reported CO2 emission rate multiplied by their generation in MWh. Affected EGUs performing worse than their standard of performance would be required to obtain and surrender an appropriate number of compliance instruments when demonstrating compliance, such that their demonstrated CO2 emission rate is equivalent to their rate-based standard of performance. Transfer and use of these compliance instruments would be accounted for with a rate adjustment as each affected EGU performs its compliance demonstration.
In general, rate-based emission trading can by design assure achievement of the requisite level of emission performance for affected sources, because reduced utilization and retirements are automatically accounted for in the award of the compliance instrument. By default, only operating steam generating units could receive or participate in the trading of compliance instruments. 
The EPA is seeking comment on whether rate-based emission trading might be appropriate under these emission guidelines. In particular, the EPA requests comment on whether there is utility in permitting rate-based emission trading and whether such program could be designed to preserve the intended stringency of these emission guidelines given the structure of the proposed subcategories, their proposed BSERs, and the dynamic nature of the power sector. The EPA also requests comment on any other methods of rate-based trading that would preserve the intended stringency of these emission guidelines. 
Mass-based Emission Trading
A mass-based trading program establishes a budget of allowable mass emissions for a group of affected EGUs, with tradable instruments (typically referred to as "allowances") issued to affected EGUs in the amount equivalent to the emission budget. Each allowance would represent a tradable permit to emit one ton of CO2, with affected EGUs required to surrender allowances in a number equal to their reported CO2 emissions during each compliance period. This section describes one method of how states could establish a mass-based trading program as part of a state plan. The EPA requests comment on whether this or another method of mass-based trading could ensure the level of emission performance required under these emission guidelines.
As previously discussed, mass-based emission trading has been used in the power sector at the Federal, regional, and state levels for nearly 3 decades. Owners and operators of EGUs, utilities, and state agencies thus have extensive familiarity with mass-based emission trading, which could make the design and implementation of a mass-based trading program as part of a state plan relatively straightforward. However, this familiarity comes with an awareness on the part of states and the EPA of the need to tailor the design of a mass-based emission trading program to the situation in which it is applied. This is especially important in instances where a sector is rapidly evolving. Past experience shows that emission budgets have often been overestimated when set many years in advance of the start of a program, as economic and technological conditions have changed significantly between the time the program was adopted and when compliance obligations begin. Projecting affected EGU fleet composition and utilization beyond the relative near term has become increasingly challenging in light of the aforementioned rapid evolution of the electric power sector, driven by factors including changes in relative fuel prices and continued rapid improvement in the cost and performance of wind and solar generation, along with new incentives for technology deployment provided by the IIJA and the IRA. Without a regular adjustment to the mass budget, if enough affected EGUs cease operations or reduce utilization, the source category could reach a point at which none of the remaining affected EGUs have to do anything to improve their emission performance. In this case, the mass budget would be established at a level such that the sources would not be collectively meeting a level of emission performance commensurate with each source's achieving its rate-based standard of performance. This outcome would be contrary to the statutory purpose of mitigating emissions from the source category to an extent that reflects application of the BSER. Such an outcome would be likewise contrary to EPA's long-standing requirement, reflected in its implementing regulations for section 111(d), that state plans establish standards of performance that are at least as stringent as EPA's emission guidelines.
States would thus need to ensure that affected EGUs participating in a mass-based trading program continue to meet the level of emission performance prescribed by category-wide, source-specific implementation of the rate-based standards of performance. This could be done by regularly adjusting emission budgets to account for sources that cease operations or change their utilization. One budget adjustment method that the EPA has developed is dynamic budgeting, as applied in the Good Neighbor Plan, in which budgets are updated annually based on recent historical generation. States could apply a similar dynamic budgeting process to mass-based trading implemented under these emission guidelines. In this context, states could establish an emission budget based on the unit-specific standards of performance of the participating affected EGUs, as described in section XI.D of this preamble, multiplied by each affected EGU's recent historical generation. The emission budgets would be updated periodically to account for units that reduce utilization or cease operation. This is one way that states could assure achievement of the requisite level of emission performance for affected EGUs through mass-based trading, though the EPA acknowledges that state or regional mass-based trading programs may have developed other regular budget adjustment methods that could provide similar assurance. 
The EPA is seeking comment on whether mass-based emission trading might be appropriate under these emission guidelines. In particular, the EPA requests comment on whether there is utility in permitting mass-based emission trading and whether such program could be designed to preserve the intended stringency of these emission guidelines given the structure of the proposed subcategories, their proposed BSERs, and the dynamic nature of the power generation sector. The EPA is also seeking comment on whether the method of mass-based emission trading using dynamic budgeting, as discussed in this section, might be appropriate under these emission guidelines. The EPA is also seeking comment on other approaches or features that could ensure that emission budgets reflect the stringency that would be achieved through unit-specific application of rate-based standards of performance. 
General Emission Trading Program Implementation Elements
The EPA notes that state plans would need to establish procedures and systems necessary to implement and enforce an emission trading program, whether it is rate-based or mass-based. This would include, but is not limited to, establishing compliance timeframes and the mechanics for demonstrating compliance under the program (e.g., surrender of compliance instruments as necessary based on monitoring and reporting of CO2 emissions and generation); establishing requirements for continuous monitoring and reporting of CO2 emissions and generation; and developing a tracking system for tradable compliance instruments. Additionally, for states implementing a mass-based emission trading program, state plans would need to specify how allowances would be distributed to participating affected EGUs.
The EPA is requesting comment on whether and to what extent there would be a desire, if emission trading is permitted under these emission guidelines, to capitalize on the EPA's existing reporting and compliance tracking infrastructure to support state implementation of an emission trading program included in a state plan. 
Banking of Compliance Instruments
The EPA requests comment on whether, if emission trading is permitted under these emission guidelines, state plans should be allowed to provide for banking of tradable compliance instruments (hereafter referred to as "allowance banking," although it is relevant for both mass-based and rate-based trading programs). Allowance banking has potential implications for a trading program's ability to maintain the requisite environmental performance of the standards of performance. The EPA recognizes that allowance banking (that is, permitting allowances that remain unused in one control period to be carried over for use in future control periods) may provide incentives for early emission reductions, promote operational flexibility and planning, and facilitate market liquidity. However, the EPA has observed that unrestricted allowance banking from one control period to the next (absent provisions that adjust future control period budgets to account for banked allowances) may result in a long-term allowance surplus that has the potential to undermine a trading program's ability to ensure that, at any point in time, the affected sources are achieving the required level of emission performance. In addition to requesting comment on whether the EPA should allow allowance banking if emission trading is permitted under these emission guidelines, the EPA requests comment on the treatment of banked allowances, specifically whether all or only some portion of an allowance bank could be carried over for use in future control periods or if additional program design elements would be necessary to accommodate allowance banking. 
Interstate Emission Trading
The EPA is requesting comment on whether, if emission trading is permitted under these emission guidelines, it should allow for interstate emission trading. Given the interconnectedness of the power sector and given that many utilities operate in multiple states, interstate emission trading may increase compliance flexibility. For interstate emission trading programs to function successfully, all participating states would need to, at a minimum, use the same form of trading and have identical program requirements. If interstate emission trading were allowed, there are many other requirements for program reciprocity and approvability that would need to be established in the emission guidelines, in addition to providing mechanisms for submission and EPA review of state plans that include interstate trading mechanisms. Given the increased level of program complexity that would be necessary to accommodate interstate trading, the operational flexibilities already provided by the structure of the proposed subcategories and their proposed BSERs, and the dynamic nature of the power sector, the EPA requests comment on whether there is utility in providing for it under these emission guidelines. In the event it is permitted, the EPA is requesting comment on the information, guidance, and requirements the EPA would need to provide for states to implement successful interstate emission trading programs.
Rate-based Averaging
The EPA is seeking comment on whether it is appropriate to allow state plans to include rate-based averaging as a compliance flexibility for affected EGUs under these emission guidelines. This section discusses considerations related to this question as well as how, if permitted under these emission guidelines, states could potentially incorporate a rate-based averaging program in a way that preserves the stringency of these emission guidelines. The EPA is seeking comment on one potential method, as well as other methods that could maintain the required level of emission performance under the proposed emission guidelines.
   Averaging allows multiple affected EGUs to jointly meet a rate-based emission standard. Affected EGUs participating in averaging could, for example, demonstrate compliance through an effective CO2 emission rate that is based on a gross generation-based weighted average of the required standards of performance of the affected EGUs that participate in averaging. The scope of such averaging could apply at the facility level or the owner or operator level. This method for calculating a composite rate could demonstrate equivalence with the intended emission performance under these emission guidelines.
Averaging can provide potential benefits. First, it offers some flexibility for sources to target cost effective reductions at any affected EGUs. For example, owners or operators of affected EGUs might target installation of emission control approaches at units that operate more. Second, averaging at the facility level provides greater ease of compliance accounting for affected EGUs with a complex stack configuration (such as a common- or multi-stack configuration). In such instances, unit-level compliance involves apportioning reported emissions to individual affected EGUs that share a stack based on electricity generation or other parameters. 
However, the EPA notes that the subcategory approach in these emission guidelines already provides significant operational flexibility for affected EGUs, potentially making the provision of further flexibility through averaging redundant or inappropriate, especially at the owner or operator level. 
The EPA is seeking comment on whether rate-based averaging should be permitted as a compliance flexibility, as well as on the illustrative method for developing a composite standard of performance for the purposes of rate-based averaging. The EPA is also seeking comment on any other considerations related to rate-based averaging, including whether the scope of averaging should be limited to a certain level of aggregation (e.g., to facility-level rate-based averaging).
Relationship to Existing State Programs
The EPA recognizes that many states have adopted binding policies and programs under their own authorities (with both a supply-side and demand-side focus) that have significantly reduced CO2 emissions from EGUs, that these policies will continue to achieve future emission reductions, and that states may continue to adopt new power sector policies addressing GHG emissions. States have exercised their power sector authorities for a variety of purposes, including economic development, energy supply and resilience goals, conventional and GHG pollution reduction, and generating allowance proceeds for investments in communities disproportionately impacted by environmental harms. The scope and approach of EPA's proposed emission guidelines differs significantly from the range of policies and programs employed by states to reduce power sector CO2 emissions, and this proposal operates more narrowly to improve the CO2 emission performance of a subset of EGUs within the broader electric power sector. The Agency recognizes the importance of state programs and their potential to reduce power sector CO2 emissions through a range of strategies broader than those proposed here pursuant to CAA section 111(d). To help facilitate the continued operation of existing state programs and to preserve opportunities for states to set and pursue their own power sector CO2 emission reduction goals, the EPA seeks comment on whether there are any elements of the proposed emission guidelines that might interfere with the implementation of state policies and programs that are designed to reduce power sector CO2 emissions, including those that apply CO2 emission limitations to fossil fuel-fired EGUs that may be subject to the proposed emission guidelines.
State Plan Components and Submission
This section describes the proposed requirements for the contents of state plans, the proposed timing of state plan submissions, and the EPA's review of and action on state plan submissions. This section also discusses issues related to the applicability of a Federal plan and timing for the promulgation of a Federal plan.
As explained earlier in this preamble, the requirements of 40 CFR part 60, subpart Ba, govern state plan submissions under these emission guidelines. Where the EPA is proposing to add to, supersede, or otherwise vary the requirements of subpart Ba for the purposes of state plan submissions under these particular emission guidelines, those proposals are addressed explicitly in section XI.F.1.b on specific state plan requirements and throughout this preamble. Unless expressly amended or superseded in these proposed emission guidelines, the provisions of subpart Ba would apply.
Components of a State Plan Submission
The EPA is proposing that a state plan must include a number of discrete components. These proposed plan components include those that apply for all state plans pursuant to 40 CFR part 60, subpart Ba. In addition, the EPA is proposing that other plan components would apply under these emission guidelines based on the type of plan submitted. For example, these required plan components may relate to the specific types of standards of performance for affected EGUs that are adopted by a state and incorporated into their state plan.
General Components
The CAA section 111 implementing regulations provide separate lists of administrative and technical criteria that must be met in order for a state plan submission to be deemed complete. The EPA's proposed revisions to subpart Ba would add one item to the list of administrative criteria related to meaningful engagement. If finalized, the applicable administrative completeness criteria for state plan submissions are: (1) A formal letter of submittal from the Governor or the Governor's designee requesting EPA approval of the plan or revision thereof; (2) Evidence that the state has adopted the plan in the state code or body of regulations; or issued the permit, order, or consent agreement (hereafter "document") in final form. That evidence must include the date of adoption or final issuance as well as the effective date of the plan, if different from the adoption/issuance date; (3) Evidence that the state has the necessary legal authority under state law to adopt and implement the plan; (4) A copy of the official state regulation(s) or document(s) submitted for approval and incorporated by reference into the plan, signed, stamped, and dated by the appropriate state official indicating that they are fully adopted and enforceable by the state. The effective date of the regulation or document must, whenever possible, be indicated in the document itself. The state's electronic copy must be an exact duplicate of the hard copy. For revisions to the approved plan, the submission must indicate the changes made to the approved plan by redline/strikethrough; (5) Evidence that the state followed all applicable procedural requirements of the state's regulations, laws, and constitution in conducting and completing the adoption/issuance of the plan; (6) Evidence that public notice was given of the plan or plan revisions with procedures consistent with the requirements of 40 CFR 60.23, including the date of publication of such notice; (7) Certification that public hearing(s) were held in accordance with the information provided in the public notice and the state's laws and constitution, if applicable and consistent with the public hearing requirements in 40 CFR 60.23; (8) Compilation of public comments and the state's response thereto; and (9) Evidence of meaningful engagement, including a list of pertinent stakeholders, a summary of the engagement conducted, and a summary of stakeholder input received. 
The technical criteria required for all plans must include each of the following: (1) Description of the plan approach and geographic scope; (2) Identification of each designated facility (i.e., affected EGU); identification of standards of performance for each affected EGU; and monitoring, recordkeeping, and reporting requirements that will determine compliance by each designated facility; (3) Identification of compliance schedules and/or increments of progress; (4) Demonstration that the state plan submission is projected to achieve emission performance under the applicable emission guidelines; (5) Documentation of state recordkeeping and reporting requirements to determine the performance of the plan as a whole; and (6) Demonstration that each emission standard is quantifiable, permanent, verifiable, and enforceable.
Specific State Plan Requirements 
Consistent with the requirements in subpart Ba, the EPA is proposing in the regulatory text that applies for these emission guidelines specific requirements that demonstrate that standards of performance for affected EGUs included in a state plan are quantifiable, verifiable, permanent, and enforceable. Consistent with CAA section 302(k), emission standards or limitations must be continuous in nature. This includes requirements that apply for all affected EGUs subject to a standard of performance under a state plan pursuant to these proposed emission guidelines, as well as requirements that apply for affected EGUs within a specific subcategory. These proposed requirements include:
       Identification of affected EGUs;
       Identification of standards of performance for each affected EGU in lb CO2/MWh-gross basis over an extended period of time (e.g., an annual calendar year), including provisions for implementation and enforcement of such standards;
       Enforceable increments of progress and milestones, as required for affected EGUs within a specific subcategory, included as enforceable elements of a state plan; and
       Identification of applicable monitoring, reporting, and recordkeeping requirements for affected EGUs.
The proposed emission guidelines include requirements pertaining to the methodologies states must use for establishing a presumptively approvable standard of performance for an affected EGU within a respective subcategory. These proposed methodologies are specified for each of the subcategories for affected EGUs. 
The EPA notes that standards of performance for affected EGUs in a state plan must be representative of the level of emission performance that results from the application of the BSER in these emission guidelines. As discussed in section XI.C of this preamble, in order for the EPA to find a state plan "satisfactory," that plan must achieve the level of emission performance that would result if each affected source was achieving its presumptive standard of performance, after accounting for any application of RULOF. That is, while states have the discretion to establish the applicable standards of performance for affected sources in their state plans, the structure and purpose of CAA section 111 require that those plans achieve an equivalent level of emission performance as applying the EPA's presumptive standards of performance to those sources (again, after accounting for any application of RULOF).
The proposed emission guidelines also include requirements that apply to states when they invoke RULOF in applying a less stringent standard of performance for an affected EGU than result from the proposed methodology for establishing a presumptively approvable standard of performance. Such requirements include a demonstration by the state of why an affected EGU for which the state invokes RULOF cannot reasonably apply the BSER. The state must also demonstrate where and how it considered communities that may be affected by the establishment of a less stringent standard of performance for the identified affected EGU. This demonstration must include an identification of the affected communities, how the state considered the potential overall impact on the identified communities, a summary of feedback from meaningful engagement with the identified communities, and a demonstration of how the state considered the health and environmental impacts to the identified communities that would result from the establishment of a source-specific BSER for the identified affected EGU for which the state is invoking RULOF.
In addition to meaningful engagement with affected communities in the context of invoking RULOF, the proposed revisions to the CAA section 111 subpart Ba implementing regulations include requirements for public engagement on state plan development to ensure that communities most affected by and vulnerable to the health and environmental impacts of a plan will share in the benefits of the plan and are protected from being adversely impacted. These proposed requirements are in addition to the existing public notice requirements under subpart Ba and, if finalized, would apply to state plan development in the context of these emission guidelines. While the existing state plan development process provides opportunities for stakeholder input through notice and public hearing, the proposed revisions addressing meaningful engagement are designed to go further to ensure that such community concerns are heard in a more robust way than in the past and at critical junctures in the state plan development process, with state plan approval at stake.
The fundamental purpose of CAA section 111 is to reduce emissions from categories of stationary sources that cause, or significantly contribute to, air pollution which may reasonably be anticipated to endanger public health or welfare. Therefore, a key consideration in the state's development of a state plan is the potential impact of the proposed plan requirements on public health and welfare. A robust and meaningful engagement process is critical to ensuring that the full range of health and environmental impacts of a proposed plan are understood and considered in the state plan development process.
In the subpart Ba revisions of December 2022, the EPA proposed to define meaningful engagement as: 
      [T]timely engagement with pertinent stakeholder representation in the plan development or plan revision process. Such engagement must not be disproportionate in favor of certain stakeholders. It must include the development of public participation strategies to overcome linguistic, cultural, institutional, geographic, and other barriers to participation to assure pertinent stakeholder representation, recognizing that diverse constituencies may be present within any particular stakeholder community. It must include early outreach, sharing information, and soliciting input on the state plan.

The EPA proposed to define that pertinent stakeholders "include but are not limited to, industry, small businesses, and communities most affected by and/or vulnerable to the impacts of the plan or plan revision." The preamble to the proposed revisions to subpart Ba notes that "increased vulnerability of communities may be attributable, among other reasons, to both an accumulation of negative and lack of positive environmental, health, economic, or social conditions within these populations or communities."
In the context of these emission guidelines, the air pollutant of concern is greenhouse gases and the air pollution is elevated concentrations of these gases in the atmosphere, which result in warming temperatures and other changes to the climate system that are leading to serious and life-threatening environmental and human health impacts. These impacts can have a disproportionate impact on communities and populations depending on, inter alia, accumulation of negative and lack of positive environmental, health, economic, or social conditions. The Agency therefore expects states' pertinent stakeholders to include not only owners and operators of affected EGUs but also communities vulnerable to the impacts of climate change, including those exposed to more extreme drought, flooding, and other severe weather impacts, including extreme heat and cold (states should refer to section III of this preamble, on climate impacts, to assist them in identifying their pertinent stakeholders). It is important for states to recognize and engage these communities, particularly as these communities may not have had a voice when the affected EGUs were originally constructed. Pertinent stakeholders should be able to provide input on how affected EGUs in their state comply with these emission guidelines. Providing input in this context means allowing communities to comment on the overall comprehensive compliance plan for all affected EGUs in a state, in contrast to permitting and other actions that focus on particular affected EGUs. Because these emission guidelines address air pollution that becomes well mixed and is long-lived in the atmosphere, pertinent stakeholders may include communities and populations that will be most affected by the overall stringency of state plans. (Note that the EPA addresses meaningful engagement in the context of RULOF for these emission guidelines in section XI.D.2.c of this preamble.) 
In engaging with stakeholders in the development of these proposed emission guidelines, the EPA has heard concerns expressed over the use of CCS technology, including concerns related to the potential for steam generating units to prolong their lifespans through its use. While the EPA endeavored to address those concerns in part by basing the BSER on CCS only for those units that intend to operate in the long-term,the EPA is proposing to require that, if states are considering assigning affected EGUs to the long-term subcategory, the state must explicitly include CCS as part of meaningful engagement to ensure that concerns regarding CCS in particular can be voiced and heard through meaningful engagement. States would be required to demonstrate that they have designed meaningful engagement to elicit input from pertinent stakeholders on issues related to CCS. While the existing state plan development process provides opportunities for stakeholder input through notice and public hearing, the proposed revisions addressing meaningful engagement are designed to go further to ensure that such community concerns are heard in a more robust way than in the past and at critical junctures in the state plan development process, with state plan approval at stake.
If the revisions to subpart Ba are finalized as proposed, states would need to demonstrate in their state plans how they provided meaningful engagement with the pertinent stakeholders. This includes providing a list of the pertinent stakeholders, a summary of engagement conducted, and a summary of the stakeholder input provided. As previously noted, the state must allow for balanced participation, including communities most vulnerable to the impacts of the plan. States must consider the best way to reach affected communities, which may include but should not be limited to notification through the Internet. Other channels may include notice through newspapers, libraries, schools, hospitals, travel centers, community centers, places of worship, gas stations, convenience stores, casinos, smoke shops, Tribal Assistance for Needy Families offices, Indian Health Services, clinics, and/or other community health and social services as appropriate. The state should also consider any geographic, linguistic, or other barriers to participation in meaningful engagement for members of the public. If a state plan submission does not meet the required elements for notice and opportunity for public participation, including requirements for meaningful engagement, this may be grounds for the EPA to find the submission incomplete or to disapprove the plan. As discussed in section XI.F.2 of this preamble, the EPA is proposing an extension of the state plan submission timeline from 15 months to 24 months, which should allow states adequate time to conduct meaningful engagement.
The EPA is requesting comment on its proposal that CCS be a required part of meaningful engagement, as well as on whether there are any other specific technologies or aspects of state plan development around which the EPA should provide requirements for meaningful engagement. The EPA is also requesting comment on what assistance states and pertinent stakeholders may need in conducting meaningful engagement in the EGU context, including tools and methodologies for identifying communities that are most affected by and vulnerable to emissions from affected EGUs under these emission guidelines.
Specific State Plan Requirements for Transparency and Compliance Assurance
The EPA is proposing or requesting comment on several requirements designed to help states ensure compliance by affected EGUs with standards of performance, as well as to assist the public in tracking increments of progress toward the final compliance date. 
First, the EPA is requesting comment on whether to require that an affected EGU's enforceable commitment to permanently cease operations, when that commitment is relied on for subcategory applicability (e.g., an affected coal-fired steam-generating unit intends to rely on a committed date to permanently cease operations by December 31, 2034, to meet the applicability requirements for the near-term subcategory), must be in the form of an emission limit of 0 lb CO2/MWh that applies on that date. Such an emission limit would be included in a state regulation, permit, order, or other acceptable legal instrument and submitted to the EPA as part of a state plan. If approved, the affected EGU would have a federally enforceable emission limit of 0 lb CO2/MWh that would become effective as of the date that the EGU permanently ceases operations. The EPA is requesting comment on whether such an emission limit would have any advantages or disadvantages for compliance and enforceability relative to a federally enforceable commitment to cease operation by a date certain. 
Second, the EPA is proposing that state plans that cover affected EGUs within any subcategory that is based on the date by which a source chooses to permanently cease operations(i.e., imminent-term, near-term, medium-term) must include, in conjunction with an enforceable date, the requirement that each source comply with applicable state and federal requirements for permanently ceasing operation of the EGU, including removal from its respective state's air emissions inventory and amending or revoking all applicable permits to reflect the permanent shutdown status of the EGU. 
Third, the EPA is proposing that each state plan must provide for the establishment of publicly accessible websites by the owners or operators of affected EGUs, referred to here as a "CAA Section 111(d) EGU Rule Website," to which all reporting and recordkeeping information for each affected EGU subject to the state plan would be posted. Although this information will also be required to be submitted directly to the EPA and the relevant state regulatory authority, the EPA is interested in ensuring that the information is made accessible in a timely manner to all pertinent stakeholders. The EPA anticipates that the owners or operators of affected EGUs may already be posting comparable reporting and recordkeeping information to publicly available websites under the EPA's April 2015 Coal Combustion Residuals Rule such that the burden of this additional website requirement could be minimal.
In particular, the EPA is proposing that the owners or operators of affected EGUs would be required to post their subcategory designations and compliance schedules, including for increments of progress and milestones, leading up to full compliance with the applicable standards of performance. Owners/operators would also be required to post any information or documentation needed to demonstrate that an increment of progress or milestone has been achieved. Similarly, the EPA is proposing that emissions data and other information needed to demonstrate compliance with a standard of performance would also be required to be posted to the CAA Section 111(d) EGU Rule Website for an affected EGU in a timely manner. The EPA is proposing that all information required to be made publicly available on the CAA Section 111(d) EGU Rule Website be posted within 30 business days of the information becoming available to or reported by the owner/operator of an affected EGU. Information would have to be retained on the website for a minimum of 10 years. The EPA solicits comment on these timeframes for posting and information retention, as well as on any concerns related to confidential business information.
The EPA proposes that owners/operators of affected EGUs that are also subject to similar website reporting requirements for the Coal Combustion Residuals Rule may use an already established website to satisfy its CAA Section 111(d) EGU Rule Website requirements. The EPA solicits comment on other ways to reduce redundancy and burden while satisfying the objective of making it easier for pertinent stakeholders to access affected EGUs' reporting and recordkeeping information. 
Fourth, to promote transparency and to assist the EPA and the public in assessing increments of progress under a state plan, the EPA is proposing that state plans must include a requirement that each affected coal-fired EGU must report any deviation from any federally enforceable state plan increment of progress or milestone within 30 business days after the owner or operator of the affected EGU knew or should have known of the event. In the report, the owner or operator of the affected EGU would be required to explain the cause or causes of the deviation and describe all measures taken or to be taken by the owner or operator of the EGU to cure the reported deviation and to prevent such deviations in the future, including the timeframes in which the owner or operator intends to cure the deviation. The owner or operator of the EGU must submit the report to the state regulatory agency and post the report to the affected EGU's CAA Section 111(d) EGU Rule Website. 
Fifth, to aid all affected parties and stakeholders in implementing these emission guidelines, the EPA is explaining its intended approach to exercising its enforcement authorities to ensure compliance while addressing genuine risks to electric system reliability. The EPA has designed these proposed emission guidelines to accommodate the transitions that are currently occurring in the electric power sector, including through the structure of subcategories and provision of relatively long planning and compliance timeframes. The Agency therefore does not anticipate that either the need for certain coal-fired steam generating units to install controls or affected EGUs' preexisting decisions to permanently cease operations will result in resource constraints that would adversely affect electric reliability.
Nonetheless, the EPA acknowledges that there may be isolated instances in which unanticipated factors beyond an owner/operator's control, and ability to predict and plan for, could have an adverse, localized impact on electric reliability. In such instances, affected EGUs could find themselves in the position of either operating in noncompliance with approved, federally enforceable state plan requirements or halting operations and thereby potentially impacting electric reliability.
CAA section 113 authorizes the EPA to bring enforcement actions against sources in violation of CAA requirements, seeking injunctive relief, civil penalties and, in certain circumstances, other appropriate relief. The EPA also has the discretion to agree to negotiated resolutions, including administrative compliance orders ("ACOs") for achieving compliance with CAA requirements, that include expeditious compliance schedules with enforceable compliance milestones. The EPA does not generally speak to the intended scope of its enforcement efforts, particularly in advance of a violation's actually occurring. However, the EPA is explaining its intended approach to ACOs here to provide confidence both with respect to electric reliability and that emission reductions under these emission guidelines will occur as required under CAA section 111(d). 
The EPA would evaluate each request for an ACO for an affected EGU that is required to run in violation of a state plan requirement for reliability purposes on a case-by-case basis. However, as a general matter, the EPA anticipates that to qualify for an ACO, the owner/operator would need to demonstrate, as a minimum, that the following conditions have been satisfied: 
The owner/operator of the affected EGU requesting an ACO has requested, in writing and in a timely manner, an enforceable compliance schedule in an ACO. 
The owner/operator of the affected EGU requesting an ACO has provided the EPA written analysis and documentation of reliability risk if the unit were not in operation, which demonstrates that operation of the unit in noncompliance is critical to maintaining electric reliability and that failure to operate the unit would result in violation of the reliability criteria required to be filed with FERC and, in the case of the Electric Reliability Council of Texas, with the Texas PUC, or cause reserves to fall below the required system reserve margin.
The owner/operator of the affected EGU requesting an ACO has provided the EPA with written concurrence with the reliability analysis from the relevant electric planning authority for the area in which the affected EGU is located. 
The owner/operator of the affected EGU requesting an ACO has demonstrated that the need to continue operating for reliability purposes is due to factors beyond the control of the owner/operator and that the owner/operator of the affected EGU has not contributed to the purported need for an ACO. 
The owner/operator of the affected EGU requesting an ACO demonstrates that it has met all applicable increments of progress and milestones in the state plan.
It can be demonstrated that there is insufficient time to address the reliability risk and potential noncompliance through a state plan revision. 
If deemed appropriate to do so, the EPA would issue an ACO that includes a compliance schedule and milestones to achieve compliance as expeditiously as practicable. The ACO would also include any operational limits, including limits on utilization reflecting the extent to which the unit is needed for grid reliability, and/or work practices necessary to minimize or mitigate any emissions to the maximum extent practicable during any operation of the affected EGU before it has achieved full compliance. The EPA reiterates that it would not be appropriate to request an ACO to address reliability risk and anticipated noncompliance in circumstances in which a state plan revision is possible.
The EPA requests comment on whether to promulgate requirements in the final emission guidelines pertaining to the demonstrations, analysis, and information the owner/operator of an affected EGU would have to submit to the EPA in order to be considered for an ACO. 
Timing of State Plan Submissions
The EPA's proposed subpart Ba revisions would require states to submit state plans within 15 months after publication of the final emission guidelines. For the purpose of these particular emission guidelines, the EPA is proposing to supersede that timeline and is proposing a state plan submission deadline that is 24 months from the date of publication of the final emission guidelines. The EPA is superseding the proposed subpart Ba 15-month plan development and submission deadline for three reasons. First, these proposed emission guidelines apply to a complex and evolving source category. Making the decisions necessary for state plan development will require significant analysis, consultation, and coordination between states, utilities, ISOs or RTOs, and the owners or operators of individual affected EGUs. The power sector is subject to many layers of regulatory and other requirements under many authorities, and the decisions states make under these emission guidelines will necessarily have to accommodate many overlapping considerations and processes. States' plan development may be additionally complicated by the fact that, unlike some other source sectors to which the general CAA section 111 implementing regulations apply, decision-making regarding control strategies and operations for affected EGUs may not be solely within the purview of the owners or operators of those sources; at the very least, affected EGUs often must obtain permission before making significant or permanent changes. The EPA does not believe it is reasonable to expect states and affected EGUs to undertake the coordination and planning necessary to ensure that their plans for implementing these emission guidelines are consistent with the broader needs and trajectory of the power sector in the space of 15 months. 
Second, and relatedly, the EPA believes that states and utilities need time to determine which subcategory and corresponding BSER is applicable for each affected EGU. Again, unlike some other source categories to which the CAA section 111 implementing regulations apply, the applicable subcategory for an affected EGU would depend on operational characteristics that are within the control of the EGU's owner/operator, subject to input from and requirements of ISO and RTOs and other authorities. Because an affected EGU may choose to change its operation in light of these emission guidelines, the process of determining the appropriate subcategory for each affected EGU is more complex than that for other source sectors to which subpart Ba applies. For any coal-fired EGU that chooses to permanently cease operations prior to 2040, the EPA anticipates that the owner or operator will be required to coordinate a date to cease operations with the corresponding RTO or ISO or other balancing authority to ensure proper retirement sequences and reliability. While the EPA expects that a number of affected EGUs already intend to cease operations at some point prior to 2040, under these emission guidelines states would require owners or operators to commit to an enforceable date to permanently cease operations for those EGUs. RTOs or ISOs or other balancing authorities will have to analyze potential impacts on the power sector and make decisions regarding these intended dates to permanently cease operations for the affected EGUs that are interested in committing to an enforceable date by which to permanently cease operations within a state plan submission. The EPA reiterates that, due to the rapid transition currently occurring in the power sector and due to the marginal nature of many affected EGUs, such changes in operation would be expected regardless of the particular requirements of these emission guidelines. 
Third, prior to an owner or operator providing a suggestion for a subcategory and standard of performance for an affected EGU to a state, that owner or operator will likely need to analyze the potential feasibility of applying the applicable BSER for the subcategory. The EPA anticipates that EGUs that intend on operating beyond 2040 will do feasibility and FEED studies to ensure that CCS is appropriate prior to committing to that subcategory in a state plan. As discussed in section XI.B of this preamble and in the GHG Mitigation Measures  -  111(d) TSD, FEED studies take approximately 12 months to complete, after which additional time is necessary to allow the conclusions from that study to be integrated into a state's planning process for certain affected EGUs. For sources that intend to permanently cease operations before January 1, 2040, and that do not qualify for the imminent- or near-term subcategories, there are also planning, design, and permitting exercises that will be necessary for utilities to undertake prior to committing to a subcategory based on natural gas co-firing. While any boiler modifications required for affected EGUs that intend to co-fire natural gas are relatively straightforward, the owners/operators of EGUs in the medium-term subcategory may also be required to construct new pipelines to enable co-firing of 40 percent natural gas. Pipeline projects also require an initial planning and design process to determine feasibility and, in some cases, could involve FERC approval. Again, it may take 12 or more months for the owner/operator of an affected EGU to ascertain the feasibility of committing to the medium-term subcategory and to natural gas co-firing. Based on the approximately 12-month period that states and the owners/operators of affected EGUs will likely take to determine the feasibility of BSER control strategies for the long-term and medium-term subcategories, the EPA does not believe it is reasonable to require state plans to be submitted 15 months after promulgation of these emission guidelines. 
In the proposed subpart Ba timelines for state plan submission, the EPA justified the generally applicable timelines in the context of public health and welfare impacts by proposing timelines that are as quick as is reasonably feasible for a generic set of emission guidelines under CAA section 111(d). The EPA is proposing 24 months for state plan timelines for these emission guidelines because 24 months is the quickest time that the EPA believes to be reasonably feasible for a state to submit a state plan based on the work and evaluation needed to establish the viability of CCS and co-firing at a given coal-fired EGU. Additionally, the EPA does not believe providing a longer timeline for the submission of state plans would ultimately impact how quickly the affected EGUs can comply with their standards of performance. As explained in section XI.B of this preamble and in the GHG Mitigation Measures  -  111(d) TSD, the EPA anticipates that CCS projects will take roughly 5 years to complete, assuming some steps are undertaken concurrently. If the EPA were to promulgate these emission guidelines in June 2024 and require state plan submissions in September 2025, the EPA anticipates that the soonest compliance could commence is in the third quarter of 2029. However, in this case, it is likely that at least some owners/operators of affected EGUs would have to commit to subcategories or control technologies before completing feasibility and FEED studies, which could result in the need for plan revisions and delayed emission reductions. In contrast, providing 24 months for state plan submission would mean that although plans would be due June 2026, owners/operators of affected EGUs would have had time to complete their feasibility and FEED studies and some initial planning steps before then. The EPA anticipates that owners/operators would need approximately another 3.5 years to reach full compliance, meaning that emission reductions would commence in the first quarter of 2030. The EPA does not believe that a difference of three months will adversely impact public health or welfare, especially when it is considered that providing more time for state plan development in this instance is more likely to ultimately result in certainty and timely emission reductions.
The EPA solicits comment on the 24-month state planning period. The EPA specifically requests comments from owners/operators of affected EGUs regarding the steps, and amount of time needed for each step, that they would have to undertake to determine the applicable subcategories and to plan and implement the associated control strategies for each of their affected EGUs. Additionally, the EPA requests comment on the 24-month planning period from states, including on any unique characteristics of the fossil fuel-fired EGU source category that they believe merit planning timeframes longer than 15 months. Through outreach, many states have expressed a need for longer planning periods and the EPA solicits comment on whether this 24-month planning period accommodates that need. The EPA also requests comment from potentially impacted communities and other pertinent stakeholders on any considerations related to providing a longer state plan submission timeframe under these emission guidelines. 
State Plan Revisions 
The EPA expects that the state plan submission deadline proposed under these emission guidelines would give states, utilities, and stakeholders sufficient time to determine in which subcategory each of the affected EGUs falls and to formulate and submit a state plan accordingly. However, the EPA also acknowledges that the power sector is rapidly evolving and that, despite states' best efforts to accurately reflect their utilities' intended paths forward at the time of plan submission, affected EGUs' plans may subsequently change. In general, states have the authority and discretion to submit revised state plans to the EPA for approval. State plan revisions are generally subject to the same requirements as initial state plans under these emission guidelines and the subpart Ba implementation regulations, including meaningful engagement, and the EPA reviews state plan revisions against the applicable requirements of these emission guidelines in the same manner in which it reviews initial state plan submissions pursuant to 40 CFR 60.27a.
Approved state plan requirements remain federally enforceable unless and until the EPA approves a plan revision that supersedes such requirements. States and affected EGUs should plan accordingly to avoid noncompliance. 
The EPA is proposing a state plan submission date that is 24 months after the publication of final emission guidelines and is proposing a compliance date of January 1, 2030. A state may choose to submit a plan revision within this period (i.e., after it has submitted its initial state plan under these emission guidelines); however, the EPA reiterates that any already approved federally enforceable requirements, including milestones, increments of progress, and standards of performance, will remain in place unless and until the EPA approves the plan revision. The EPA requests comment on whether it would be helpful to states to impose a cut-off date for the submission of plan revisions ahead of the January 1, 2030, compliance date. Such a cut-off date, e.g., January 1, 2028, would in effect establish a temporary moratorium on plan submissions in order to provide a sufficient window for the EPA to act on them ahead of the final compliance date. State plan revisions would again be permitted after the final compliance date. As an alternative to a cut-off date for state plan revisions ahead of the compliance date, the EPA requests comment on the dual-path standards of performance approach discussed in section XI.F.4 of this preamble. 
Under these proposed emission guidelines, states would place their affected coal-fired EGUs into one of four subcategories based on the time horizons over which those EGUs intend to operate. These subcategories are static -- affected EGUs would not be able move between subcategories absent a plan revision. However, the EPA acknowledges that there may be instances in which a change in subcategory will be necessary. For affected coal-fired EGUs that are switching into the imminent-term, near-term, or medium-term subcategories, the EPA proposes to require that the state include in its state plan submission documentation of the affected EGU's submission to the relevant RTO or balancing authority of the new date it intends to permanently cease operations, any responses from and studies conducted by the RTO or balancing authority addressing reliability and any other considerations related to ceasing operations, any filings with the SEC or notices to investors in which the plans for the EGU are mentioned, any integrated resource plan, and any other relevant information in support of the new date. This documentation must be published on the CAA Section 111(d) EGU Rule Website. These proposed requirements are modeled on the proposed milestones for sources committing to permanently ceasing operations and are intended to help states, stakeholders, and the EPA ensure that the affected EGU's change in circumstances is sufficiently certain to warrant a state plan revision. Because of the long lead times for planning and implementation of control systems for affected EGUs, revising a state plan after the submission deadline has the potential to significantly disrupt states' and affected EGUs' compliance strategies. The EPA therefore believes it is reasonable to require affected EGUs and states to provide evidence that a source's circumstances have in fact changed, in order for the EPA to approve a plan revision. Affected EGUs switching into the imminent-term, near-term, or medium-term subcategories would also be required to comply with the proposed enforceable milestones applicable to those subcategories.
Some changes between subcategories, including from the long-term into the medium-term subcategory and from the imminent-term or near-term into the medium-term or long-term subcategory, would entail new standards of performance reflecting a different add-on control strategy than initially anticipated. In order to avoid undermining the stringency of these proposed emission guidelines, the EPA expects affected EGUs changing subcategories before the January 1, 2030, compliance deadline to make every reasonable effort to meet that compliance deadline. However, the EPA acknowledges that, in some circumstances, it may not be possible to complete the necessary planning and construction within a shortened timeframe. Additionally, unforeseen circumstances could require some affected EGUs to change subcategories after the final compliance deadline has passed (e.g., to ensure reliability). 
In these circumstances, the EPA is proposing that states may use the RULOF mechanism described in section XI.D.2 of this preamble to adjust the compliance deadlines for affected EGUs that cannot comply with their applicable standards of performance by the January 1, 2030, deadline. The EPA expects that states may be able to demonstrate that the change in subcategory constitutes an "other circumstance[] specific to the facility . . . that [is] fundamentally different from the information considered in the determination of the best system of emission reduction in the emission guidelines." In order to invoke RULOF to change a compliance deadline for an affected EGU that has switched subcategories, the EPA proposes that the state must first demonstrate that the affected EGU cannot meet the applicable presumptive standard of performance by the compliance deadline in these emission guidelines. As part of this demonstration the state would be required to provide evidence supporting the affected EGU's need to switch subcategories. The state would also be required to demonstrate that the need to invoke RULOF and to provide a different compliance deadline or less stringent standard of performance was not caused by self-created impossibility. Documentation related to these demonstrations must also be posted to the CAA Section 111(d) EGU Rule Website. For example, it would not be reasonable for a state that has been notified that an RTO requires an affected EGU to switch subcategories to wait to revise its SIP until the remaining useful life of that EGU is so short as to preclude otherwise reasonable systems of emission reduction. To this end, the EPA is proposing to consider when a state knew or should have known that an affected EGU would need to switch subcategories when evaluating the approvability of state plans that include RULOF demonstrations. The EPA is additionally proposing to consider whether an affected EGU has been complying with its applicable milestones and increments of progress when evaluating RULOF demonstrations. The EPA encourages states to consult with their EPA Regional Offices as early as possible if they believe it may become necessary for an affected EGU to switch subcategories. The EPA requests comment on whether to set a deadline for states to provide plan revisions within a certain timeframe of knowing that an affected EGU needs to switch subcategories and on what timeframe would be appropriate.
The EPA is proposing that states invoking RULOF because an affected EGU cannot comply with its newly applicable presumptive standard of performance by the final compliance deadline first evaluate whether the affected EGU is able to comply with that standard by a different, later-in-time deadline. If a state can demonstrate that an affected EGU cannot reasonably comply with the applicable presumptive standard of performance under any reasonable compliance deadline, it may then evaluate different systems of emission reduction according to the proposed RULOF mechanism described in section XI.D.2 of this preamble.
Dual-Path Standards of Performance for Affected Coal-Fired Steam Generating Units
Under the structure of these emission guidelines as proposed, states would assign affected coal-fired EGUs to subcategories in their state plans and an EGU would not be able to change its applicable subcategory without a state plan revision. This is because, due to the nature of the BSERs for coal-fired EGUs, an EGU that switches between subcategories may not be able to meet compliance obligations for a new and different subcategory without considerable lag time and thus the switch would result in noncompliance and a loss of emission reductions. Therefore, as a general matter, states must assign each affected EGU to a subcategory and have in place all the measures necessary to implement the requirements for that subcategory by the time of state plan submission.
However, the EPA acknowledges that there may be circumstances in which a coal-fired EGU wishes to retain the option to choose between two different subcategories ahead of the proposed January 1, 2030, compliance date. The EPA is therefore soliciting comment on the following dual-path approach that may result in an additional flexibility for owners/operators of affected coal-fired EGUs that want additional time to commit to a particular subcategory without the need for a state plan revision. 
The EPA is soliciting comment on an approach that allows coal-fired EGUs to have two different standards of performance submitted to the EPA in a state plan based on potential inclusion in two different subcategories. A state plan would be required to have all the associated components for each subcategory. For example, for an affected EGU that wants the option to be part of either the long-term or imminent-term subcategory, the state plan would include a standard of performance based on implementation of CCS and associated requirements, including increments of progress; as well as an enforceable requirement to permanently cease operations before January 1, 2033, and a standard of performance based on routine operation and maintenance. The affected EGU would be required to meet all compliance obligations for both subcategories, including increments of progress and/or milestones for federally enforceable commitments to cease operations, leading up to the compliance date of January 1, 2030. The state and affected EGU would be required to choose a subcategory for the affected EGU ahead of that date. Specifically, the EPA is proposing that the state must notify the EPA of its final applicable subcategory and standard of performance at least 6 months prior to the compliance date (i.e., the state would have to notify the EPA of the applicable standard by July 1, 2029). If the state has not notified the EPA by July 1, 2029, of the final applicable subcategory for the affected EGU, the EPA is proposing that that EGU would automatically be subject to the requirements of the subcategory that corresponds to the longer remaining life of the EGU. Additionally, if the affected EGU misses an enforceable increment of progress, milestone (as described in section XI.D.3 of this preamble), or any other requirement for one of the two subcategories, the EGU will automatically be subject to the requirements of the other subcategory. If the EGU misses submissions for increments of progress/milestones for both subcategories, the EGU will automatically be subject to the requirements of the subcategory that corresponds to the longer remaining life of the EGU and will additionally be found to be out of compliance for the increment of progress or milestone that it has missed. 
The EPA is soliciting comment on this approach to provide flexibility to states and affected EGUs. In some instances, owners of affected EGUs may wish to have additional time to decide on a control strategy; this proposed dual-path approach should provide utilities an additional 3 years to commit to a subcategory. However, with this additional time comes additional burden on owners and operators to demonstrate compliance with each of the requirements associated with two different subcategories that would be included in a state plan. As an example, a coal-fired EGU intends to cease operations between 2038 and 2041. The state plan is submitted and contains two different enforceable dates to permanently cease operations, e.g., December 31, 2038, with a standard of performance based on natural gas co-firing and December 31, 2041, with a standard of performance based on CCS, as well as an enforceable commitment by the state to choose one path or the other by July 1, 2029. The affected EGU would then be required to comply with the increments of progress for both the long-term (CCS) and medium-term (co-firing) subcategories, until the point at which the state decides which of the two paths in its plan it will require for the unit. 
The EPA solicits comment on whether this proposed dual-path flexibility would have utility and on whether it could be implemented in a manner that ensures that states and affected coal-fired EGUs would be able to comply with applicable requirements in a timely manner. Additionally, the EPA solicits comment on whether July 1, 2029, is the appropriate date for a final decision between the two potential standards of performance and why.
EPA Action on State Plans 
Pursuant to proposed subpart Ba, the EPA would use a 60-day timeline for the Administrator's determination of completeness of a state plan submission and a 12-month timeline for action on state plans. The EPA's review of and action on state plan submissions would be governed by the requirements of revised subpart Ba. First, the EPA would review the components of the state plan to determine whether the plan meets the completeness criteria of 40 CFR 60.27a(g). The EPA must determine whether a state plan submission has met the completeness criteria within 60 days of its receipt of that submission. If the EPA has failed to make a completeness determination for a state plan submission within 60 days of receipt, the submission shall be deemed, by operation of law, complete as of that date. 
Proposed subpart Ba would require the EPA to take action on a state plan submission within 12 months of that submission's being deemed complete. The EPA will review the components of state plan submissions against the applicable requirements of subpart Ba and these emission guidelines, consistent with the underlying requirement that state plans must be "satisfactory" per CAA section 111(d). If the EPA finalizes the revisions to subpart Ba as proposed, the Administrator would have the option to fully approve, fully disapprove, partially approve, partially disapprove, and conditionally approve a state plan submission. Any components of a state plan submission that the EPA approves become federally enforceable.
The EPA requests comment on the use of the timeframes provided in subpart Ba, as the EPA has proposed to revise it, for EPA actions on state plan submissions and for the promulgation of Federal plans for these particular emission guidelines.
Federal Plan Applicability and Promulgation Timing
The provisions of subpart Ba, including any revisions the EPA finalizes pursuant to its December 2022 proposal, will apply to the EPA's promulgation of any Federal plans under these emission guidelines. The EPA's obligation to promulgate a Federal plan is triggered in three situations: where a state does not submit a plan by the plan submission deadline; where the EPA determines that a state plan submission does not meet the completeness criteria and the time period for state plan submission has elapsed; and where the EPA fully or partially disapproves a state's plan. Where a state has failed to submit a plan by the submission deadline, the EPA has 12 months from the state plan submission due date to promulgate a Federal plan; otherwise, the 12-month period starts from the date the state plan submission is deemed incomplete, whether in whole or in part, or from the date of the EPA's disapproval. The EPA may approve a state plan submission that corrects the relevant deficiency within the 12-month period, before it promulgates a Federal plan, in which case its obligation to promulgate a Federal plan is relieved. As provided by 40 CFR 60.27a(e), a Federal plan will prescribe standards of performance for affected EGUs of the same stringency as required by these emission guidelines and will require compliance with such standards as expeditiously as practicable but no later than the final compliance date under these guidelines. However, upon application by the owner or operator of an affected EGU, the EPA in its discretion may provide for a less stringent standard of performance or longer compliance schedule than provided by these emission guidelines, in which case the EPA would follow the same process and criteria in the regulations that apply to states' provision of RULOF standards. Under the proposed revisions to subpart Ba, the EPA would also be required to conduct meaningful engagement with pertinent stakeholders prior to promulgating a Federal plan.
As described in section XI.F.2 of this preamble, the EPA is proposing to allow states 24 months for a state plan submission after the promulgation of the final emission guidelines. Therefore, the EPA would be obligated to promulgate a Federal plan for all states that fail to submit plans within 36 months of the final emission guidelines. Note that this will be the earliest obligation for the EPA to promulgate Federal plans for states and that different triggers (e.g., a disapproved state plan) will result in later obligations to promulgate Federal plans contingent on when the obligation is triggered.
Under the Tribal Authority Rule (TAR) adopted by the EPA, tribes may seek authority to implement a plan under CAA section 111(d) in a manner similar to that of a state. See 40 CFR part 49, subpart A. Tribes may, but are not required to, seek approval for treatment in a manner similar to that of a state for purposes of developing a Tribal Implementation Plan (TIP) implementing the emission guidelines. If a tribe obtains approval and submits a TIP, the EPA will generally use similar criteria and follow similar procedures as those described for state plans when evaluating the TIP submission and will approve the TIP if appropriate. The EPA is committed to working with eligible tribes to help them seek authorization and develop plans if they choose. Tribes that choose to develop plans will generally have the same flexibilities available to states in this process. If a tribe does not seek and obtain the authority from the EPA to establish a TIP, the EPA has the authority to establish a Federal CAA section 111(d) plan for areas of Indian country where designated facilities are located. A Federal plan would apply to all designated facilities located in the areas of Indian country covered by the Federal plan unless and until the EPA approves an applicable TIP applicable to those facilities.
Solicitation of Comments on Emission Guidelines for Existing Fossil Fuel-fired Stationary Combustion Turbines
Overview 
Because the EPA has established NSPS for GHG emissions from new fossil fuel-fired stationary combustion turbines under CAA section 111(b), it has an obligation to also establish emission guidelines for GHG emissions from existing fossil-fuel fired stationary combustion turbines under CAA section 111(d). The EPA intends to fulfill that obligation as expeditiously as practicable. In addition to the CAA obligation, the EPA believes that it is important to address emissions from existing fossil-fuel fired stationary combustion turbines expeditiously, because they are quickly becoming the biggest source of GHG emissions from EGUs. As other fossil-fuel EGUs reduce utilization or retire, at least some of this generation may shift to the existing combustion turbine fleet, particularly if the latter is not subject to limits on GHG emissions. Indeed, the EPA's modeling for these proposed rules indicate that GHG emissions from these units may increase by a material amount in the 2030 to 2035 timeframe in part as a result of a shift in generation to existing combustion turbines associated with the NSPS and emission guidelines proposed in these actions.
In considering how to address this problem, the EPA believes there are at least two key factors to consider. The first is that determining the BSER and issuing emission guidelines covering these units sooner rather than later is important to address the GHG emissions from this growing part of the inventory. The second is related to the size of the affected fleet and the implications for the feasibility and timing of implementing potential candidates for BSER. As discussed later in this section, there are at least three technologies that could be applied to reduce GHGs from existing combustion turbines (CCS, hydrogen co-firing, and heat rate improvements), all of which are available today and are being pursued to at least some degree by owners and operators of these sources. Although the EPA believes that these technologies are available and adequately demonstrated at the level of individual existing combustion turbines, emission guidelines for these sources must also consider how much of the fleet could reasonably implement one or more of these potential BSER approaches in a given time frame. 
To provide a sense of scale, the EPA projects that there will be 60 GW of coal-fired steam generating units and 60 GW of oil-/natural gas-fired steam generating units operating in 2030 that will be subject to the CAA section 111(d) requirements for existing fossil fuel-fired steam generating units and 47 GW of new turbines subject to the CAA section 111(b) standards of performance that are proposed in this document. In other words, in 2030, the EPA anticipates there would be nearly three times as many units (414 GW) subject to a emission guidelines for existing fossil fuel-fired combustion turbines as would already be covered by the proposed NSPS and emission guidelines in these actions. 
Furthermore, the EPA is aware that grid operators and power companies currently rely on existing fossil fuel-fired combustion turbines as a flexible and readily dispatchable resource that plays a key role in fulfilling resource adequacy and operational reliability needs. Although advancements in energy storage and accelerated deployment of renewable resources may diminish reliance on existing fossil fuel-fired combustion turbines for reliability purposes over time, it is imperative that emission guidelines for these sources not impair the reliability of the bulk power system. For these reasons, the EPA believes that it is important that a BSER determination and associated emission guidelines for existing fossil fuel-fired combustion turbines rely on GHG control options that can be feasibly and cost-effectively implemented at a scale commensurate with the size of the regulated fleet, and provide sufficient lead time to allow for smooth implementation of the GHG emission limitations that preserves system reliability. Given the large size of the existing combustion turbine fleet and the lead time required to develop CCS and hydrogen-related infrastructure, the EPA believes it would be particularly challenging to implement a BSER that requires near-term, wide-scale deployment of CCS or low-GHG hydrogen co-firing at these sources. 
As a result, the EPA is considering breaking the existing turbine category into two segments and focusing an initial rulemaking effort on the most frequently operated and highest-emitting turbines, to be followed by a separate rulemaking at a later time that addresses emissions from the remaining turbines as well as additional opportunities to reduce emissions from those units regulated in the first rulemaking. In this notice, the EPA is soliciting comment on the general concept of conducting two rulemakings and developing a BSER for the most frequently operated and highest emitting turbines in a timeframe that would allow for emission reductions in the 2030-2035 window, potentially mitigating the emissions increases in that timeframe. If the BSER for those units were based on the use of CCS, establishing emission guidelines that required limits on GHG emissions in the 2030-2035 timeframe would also allow those units to take advantage of the IRC section 45Q tax credits to make these controls more cost-effective. In the rest of this section, the EPA outlines what such an approach might look like and solicits comment on specific elements of the approach. This section also briefly discusses what BSER might look like for units in the second rulemaking, noting that under this approach, the EPA would likely develop a rulemaking defining BSER for those units at a later date. 
The EPA's approach for units covered by the first rulemaking would be on a schedule similar to the proposed schedule for requirements for existing fossil fuel-fired steam generating units (i.e., with compliance deadlines falling in or not long after 2030), with emissions limitations based on heat rate/efficiency improvements, co-firing low-GHG hydrogen, or use of CCS for the most frequently operated and highest-emitting units. For units covered by the second rulemaking, requirements based on one or more of these technologies would also apply. As part of this follow-up rulemaking, the EPA could also consider establishing more stringent emission guidelines for certain units that are covered in the first rulemaking, but which are not required to significantly reduce emissions by that rulemaking due to concerns over the lead time required to build out CCS and hydrogen infrastructure. This approach would allow time for the infrastructure to implement CCS and co-firing low-GHG hydrogen to further develop. The EPA may implement this approach by subcategorizing combustion turbines based on their efficiency, the frequency with which they operate, their size, and whether they are located close to sequestration sites. 
Section XII.B provides background information concerning the composition of the current fossil fuel-fired stationary combustion turbine fleet and how it is expected to change in the near future. In section XII.C the EPA outlines the potential approach for units covered in the first rulemaking and in section XII.D, outlines a potential approach for units covered in the second rulemaking. In section XII.E, the EPA discusses potential state plan requirements. Finally, in section XIII.F, the EPA summarizes the key topics for which we are soliciting comment relative to existing combustion turbines.
The Existing Stationary Combustion Turbine Fleet 
In 2021, existing combustion turbines represented 37 percent of the GHG emissions from the power sector and 40 percent of the generation from the power sector. In the EPA's updated baseline projections for the power sector, they represent 64 percent of the GHG emissions and 34 percent of the generation in 2030. In EPA's modeling of the 2030 control case, in which both existing fossil fuel-fired EGUs and new stationary combustion turbine EGUs are subject to the emissions limitations proposed in this actions, load shifting from those two categories of sources to the existing combustion turbines s results in an increase in the share of the emissions from existing combustion turbines to 68 percent and an increase in their share of generation to 36 percent. Moreover, in that control case, existing combined cycle combustion turbines are responsible for 65 percent of the CO2 emissions from existing stationary combustion turbines.
In the EPA's modeling in support of these rules, we see two trends that are important relative to existing combustion turbines. First, the EPA's analysis of the reference case (which includes the impacts of IRA without considering the GHG limitation requirements proposed in these rules) projects a long-term decline in generation and emissions from existing combustion turbines. In this reference case, combined cycle generation falls in each model run year from 2028 through 2050, and it falls by more than 50 percent between 2030 and 2045. Generation from existing simple cycle combustion turbines is projected to peak in 2030 before declining by more than 70 percent by 2045.
Historical data shows a wide range of variation in both the heat rate and the GHG emission rates among both existing combined cycle combustion turbines and existing simple cycle combustion turbines. The GHG emission rates for existing combined cycle units range from as low as 644 lb CO2/MWh-gross to as high as 1,891 lb CO2/MWh-gross and annual capacity factors range from as low as 1 percent to as high as 85 percent. While there is some correlation between units with low-GHG emission rates (e.g., more efficient units) and utilization, some low efficiency combined cycle units have historically operated at very high capacity factors. For instance, two of the highest operating units (at 85 percent capacity utilization) have GHG emission rates of nearly 1,200 lb/MWh-gross. 
BSER for Frequently-Operated Existing Combustion Turbines
	The EPA is soliciting comment on a potential approach for regulating GHG emissions from existing combustion turbines in two rulemakings, with a BSER based on heat rate/efficiency improvements, CCS, and co-firing low-GHG hydrogen. This approach recognizes the imperatives (the urgent need to reduce greenhouse gases), the opportunities (including the availability of IRC section 45Q tax credits incentivizing CCS installation, as long as sources commence construction by January 1, 2033), and the obstacles (the need for infrastructure for CCS and co-firing low-GHG hydrogen to more fully develop).
As part of this approach, the EPA would subcategorize combustion turbines based on characteristics that are relevant for the types of controls that the EPA may identify as the BSER. These characteristics could include the level of efficiency with which the combustion turbines operate, their size, their level of utilization, their announced retirement date (if any), and whether they are located near sequestration sites.
For units covered in the first rulemaking, the EPA would establish emission guidelines specifying the BSER and the level of emission reduction that sources could comply with during an approximately 2029-2035 timeframe, consistent with the requirements for new combustion turbines. In establishing applicability requirements for sources covered in this first rulemaking, the EPA would focus primarily on the most frequently operated units (e.g., those above a capacity factor threshold of 50 to 60 percent). Such units would likely be combined cycle units, which account for the vast majority of generation and GHG emissions from existing fossil fuel-fired combustion turbines. At a 50 percent capacity factor threshold, approximately 68 percent of the current combined cycle capacity would be covered. At a 60 percent capacity factor threshold, approximately 62 percent of the capacity would be covered. In the second rulemaking, the EPA would address all units that were not covered in the initial rulemaking and could also establish more stringent requirements for certain units covered in the first rulemaking.
The EPA believes this approach would ensure that GHG emissions limitations are implemented first at the subset of existing fossil fuel-fired combustion turbines that contributes the most to GHG emissions, and where the benefits of implementing GHG controls would be greatest. In 2030, more than half of the generation and emissions from existing fossil fuel fired combustion turbines are projected to come from units that operate at a capacity factor greater than 50 percent. 
The EPA believes there are three sets of controls that could potentially qualify as the BSER for the group of large and frequently-operated combustion turbines covered in the first rulemaking. Those controls are heatrate/efficiency improvements, co-firing low-GHG hydrogen, and use of CCS.
The EPA believes that heat rate improvements for existing combustion turbines are broadly applicable today. Heat rate/efficiency improvements can be divided into two types. The first type involves smaller scale improvements to existing combustion turbines. The second type involves more comprehensive upgrades of the combustion turbines. 
Smaller scale efficiency improvements can include measures such as inlet fogging and inlet cooling. Both of these techniques can achieve about 2 percent improvements in heat rate. Inlet chilling costs approximately $19/kW and is also accompanied by a capacity increase of 11 percent. Inlet fogging is approximately $0.93/kW and is accompanied by a capacity increase of 6 percent. The EPA believes that if it did develop a subcategory for which small-scale efficiency improvements were identified as the BSER, it would likely result in an average 2 percent improvement in the heat rate of affected existing combustion turbines.
More comprehensive efficiency upgrades to combustion turbines are also possible. There is growing evidence that companies are interested in retrofitting existing combustion turbines. An upgrade to the combustion turbine can result in a heat rate improvement of 3.0 percent and a capacity increase of 13 percent for $172/kW, while an upgrade to the steam turbine can result in a heat rate improvement of 3.2 percent with a capacity increase of 3 percent for $130/kW. The EPA believes that if it did develop a subcategory for which more comprehensive efficiency improvements was identified as the BSER, it would likely result in an average efficiency improvement of 6 percent for affected existing stationary combustion turbines.
Although the EPA has proposed to reject efficiency/heat rate improvements (HRI) as the BSER for coal-fired steam generating units, it did so for two reasons that do not apply in the case of combustion turbines. First, for coal-fired steam generating units, HRI achieves only a small amount of emission reductions. In contrast, for combustion turbines, HRI could constitute an important first step for units that may ultimately adopt co-firing with low-GHG hydrogen or use of CCS as these technologies become more widely implemented and deployed. Because co-firing low-GHG hydrogen and adopting CCS are most cost effective at units that are operating at peak efficiency, combustion turbines that plan to ultimately adopt these controls are likely to implement HRI as well. 
Second, for coal-fired steam generating units, HRI could lead to a rebound effect that would result in increased emissions. HRI for combustion turbines could also result in a rebound effect, but that would not necessarily increase emissions and, in fact, could decrease them. Coal-fired steam generating units are the highest GHG intensity units; so if such a unit increases its utilization, it is almost certainly offsetting generation from a unit with similar GHG emissions, such as another coal-fired steam generating unit, or a unit with lower GHG emissions, such as a natural gas-fired combustion turbine or some other low-GHG emitting generation. This is not necessarily the case with a combined cycle unit. If a combined cycle unit becomes more efficient and operates more, it is likely to offset emissions from a higher emitting unit, such as a coal-fired unit, or even an efficient simple cycle turbine. This is especially true because many efficiency improvements also increase capacity, and with increased capacity, combined cycle units will have an even larger ability to displace other generation. 
The second potential BSER that the EPA is considering is co-firing low-GHG hydrogen. As discussed in section VII, co-firing with low-GHG hydrogen is feasible in combustion turbines that are currently being produced and can achieve meaningful reductions in GHG emissions from these sources. In section VII, the EPA proposes the use of low-GHG hydrogen as BSER for certain new base load turbines, but the EPA also solicits comment on whether limiting the use of low-GHG hydrogen to less frequently operated turbines should be considered for the following reason. Low-GHG hydrogen may be used across wide swaths of the economy, including in the transportation sector, industrial applications, and power generation. Some stakeholders in the power generation sector have suggested that low-GHG hydrogen use in that sector should be focused on energy storage applications, rather than base load applications, in light of the likely large overall demand for low-GHG hydrogen and the large energy demands associated with its production. For this reason, the EPA is considering whether co-firing with low-GHG hydrogen should be considered as a BSER option for less-frequently operated existing fossil fuel-fired combustion turbines, rather than for the most frequently operated units for which the EPA would initially be establishing emission guidelines. The EPA takes comment on whether it should consider a BSER subcategory including hydrogen co-firing for frequently used turbines.
The third set of controls that the EPA is considering is the use of CCS. The EPA believes that CCS could be a potentially effective mitigation measure for existing combustion turbines and that it would be most cost-effective for units that are frequently operating and that are in geographic locations with access to sequestration. As discussed in section VII, multiple companies are considering adding CCS to existing fossil fuel-fired power plants. The EPA believes that a number of existing combined cycle units are likely to be able to install and operate CCS within the costs that the EPA found to be reasonable for new stationary combustion turbines and existing coal-fired steam generating units. These are units that are large, have higher capacity factors, and are located close sequestration sites. The EPA estimates that there are approximately 18 GW of combined cycle facilities that are over 500 MW in size, operate at a capacity factor of over 50 percent, and are located in a state with identified deep saline reservoir sequestration sites. There are approximately 10 GW of units that meet those criteria and operate at a capacity factor of over 60 percent. 
Based on the above discussion, the EPA is soliciting comment on whether in its first rulemaking to define a subcategory of units and establish emission guidelines based on CCS as the BSER for that subcategory. The EPA is also taking comment on what the appropriate characteristics for such a category should be. Above, the EPA describes one potential subcategory definition. The EPA anticipates that such a subcategory would likely represent only a small percentage of the units with projected capacity factors of over 50 percent. For the remaining frequently operated units, the EPA is seeking comment on whether it would be appropriate to consider one or more additional subcategories for which BSER would be based on efficiency improvements or co-firing with low-GHG hydrogen. For the reasons explained above, the EPA is soliciting comment on whether it would be appropriate to have two subcategories where efficiency improvement is identified as the BSER. The first subcategory would be for units with high capacity factors and relatively high heat rates. For such units, the EPA is requesting comment on the BSER being a major combustion turbine overhaul that would result in a heat rate improvement of at least 6 percent. The EPA is soliciting comment on defining this subcategory to include units operating at a capacity factor over 50 percent and with a heat rate higher than 8,300 Btu/kwh. At this level, the most efficient units in the subcategory would be required to achieve a new heat rate of 7,800 Btu/kwh, slightly higher than the heat rate requirement for new stationary combustion turbines. For units above a capacity factor of 50 percent (or 60 percent) that are not subject to a BSER of CCS or major efficiency improvements, the EPA would likely consider a BSER of minor heat rate improvements that would require a heat rate improvement of 2 percent. The EPA is also taking comment on whether this heat rate improvement should include a floor of 7,800 Btu/kwh.
BSER for Remaining Combustion Turbines
While the EPA believes that emission guidelines for units covered in the first rulemaking, described above, can achieve important emission reductions from the most frequently operating turbines, limited infrastructure prevents widespread adoption of co-firing low-GHG hydrogen or CCS in that rulemaking. In this section, the EPA discusses how developing a BSER for units in the second rulemaking could address additional units that do not install CCS or co-fire significant amounts of low-GHG hydrogen under the emission guidelines for frequently operating turbines, as well as units that do not meet the applicability requirements for the first rulemaking. In this follow-up rulemaking, the EPA could also consider establishing emission guidelines for sources that are covered by the new source standards that are being proposed but that would continue to emit relatively large amounts of CO2 on a lb/MWh basis including intermediate units subject to a BSER based on 30 percent hydrogen co-firing and low load units that are meeting a clean fuels standard. This second rulemaking might impose requirements on sources beginning in 2035. The second rulemaking would extend CCS and co-firing low-GHG hydrogen to additional combustion turbines.
As noted in section XII.C, the EPA believes that a first rulemaking for existing turbines would apply to units most amenable to CCS, which ensures that any limits on the amount of CCS that could be installed during the relatively short timeframe of the first rulemaking, that is, by 2032, are taken into account. The second rulemaking would provide an opportunity for the EPA to consider whether CCS could be considered BSER for a larger number of frequently used turbines due to the further development of CCS infrastructure, including pipelines and sequestration sites and cost reductions in capture equipment. For example, based on updated information, the EPA could consider whether CCS is the BSER for facilities that meet somewhat lower size or capacity thresholds, or are located somewhat more distant from sequestration sites, than units for which CCS is determined to be the BSER in the first rulemaking. 
Furthermore, in the second rulemaking, the EPA would establish emission guidelines for any existing combustion turbines that are not covered by the emission guidelines promulgated in the first rulemaking  -  namely, less frequently operated turbines. The EPA anticipates that these less frequently operated turbines would consist principally of simple cycle combustion turbines. As explained above in section XII.C, the EPA believes that, absent significant further reductions in the cost of CCS, it is unlikely that CCS would meet the cost criteria used in these proposed actions as a reasonable cost for BSER for less frequently used turbines. Therefore, the EPA believes the second rulemaking would likely consider whether expanding co-firing low-GHG hydrogen is BSER for less frequently operated turbines. This could entail some combination of including more units in a co-firing low-GHG hydrogen based BSER (e.g., peaking turbines) and/or expanding the co-firing percentage to an amount greater than 30 percent. This concept of moving from 30% co-firing of hydrogen to larger amounts of hydrogen over time is consistent with many companies' stated plans. For instance, the developers of the Intermountain Power Project indicate that they intend to combust 30 percent hydrogen when their unit (currently under construction) commences operation in 2025. They intend to transition to use of 100 percent hydrogen by 2045 as technology improves. Most turbine manufacturers are developing technologies to co-fire amounts of hydrogen that are substantially larger than 30 percent. Many of these manufacturers are developing retrofit options for existing turbines to run on large percentages of hydrogen, even up to 100 percent. Given these rapid advancements in combustion turbine technology, the EPA believes that the key driver for how much hydrogen could be co-fired in turbines, particularly those operating at less than base load (e.g., 50 percent), is more likely related to how quickly low-GHG hydrogen production and distribution will expand to provide the needed low-GHG hydrogen, rather than the physical capabilities of turbines to combust it. 
State Plan Requirements for Existing Turbines
This section focuses on three specific state plan requirements: 1) setting emission standards consistent with BSER; 2) Remaining Useful Life and Other Factors (RULOF) and 3) Flexibilities and State Equivalency. It also has a brief discussion of other state plan requirements.
In the emissions guidelines, the EPA would require state plans to establish emission standards consistent with application of the BSER, similar to what section XI describes for fossil fuel-fired steam generating units. The first step would involve setting a baseline emission rate using historical data. The second step would be to adjust that emission rate to reflect the level of reductions expected with implementation of BSER. For example, if the BSER for a major turbine upgrade was based on a 6 percent heat rate improvement, the state would be required to establish emission standards that reduce the baseline emission rate by 6 percent.
The application of the RULOF provision could be important for states with respect to certain turbines. The useful life of a combined cycle unit is approximately 25 to 30 years, and because more than 151 GW of combined cycle units came on-line in the 2000 to 2010 time-frame, many could potentially be at or nearing the end of their remaining useful life in the 2030 to 2040 timeframe. The EPA anticipates that states would be required to apply the RULOF provision similar to the way that the EPA is proposing it be applied for existing fossil fuel-fired steam generating units. Thus, any retirement date that was considered in establishing a less stringent standard for the facility would need to be made federally enforceable. In addition, the state would be required to determine the source-specific BSER for the facility by evaluating the same factors that the EPA considered. For example, for a unit subject to a presumptive standard based on CCS pursuant to the emission guidelines, the state would first consider alternative standards based on CCS with a lower carbon capture rate, then co-firing with low-GHG hydrogen, then comprehensive turbine upgrades, and finally smaller scale efficiency improvements.
There are at least two areas where we anticipate states and sources being interested in additional flexibilities beyond those available through the RULOF provisions. First, states and sources have expressed significant interest in emission trading. As the EPA has explained earlier in this preamble, the Agency believes that, because so many coal-fired units are likely to cease operations in the 2030 to 2040 timeframe in the baseline, an emission trading program for those units would have significantly less utility. However, because many turbines have come on-line since 2015, have remaining useful lives that extend past 2040, and are covered by existing trading programs, the EPA anticipates more interest in emission trading under combustion turbine emission guidelines. The principles discussed earlier in this notice related to emission trading, under which any such program should ensure emission reductions equivalent to or greater than the emission reductions that would be achieved with unit-by-unit implementation of BSER, would likely be the starting point for the EPA's consideration of emissions trading for an existing combustion turbine rule.
In addition, the EPA is aware of states and utilities that have comprehensive plans to reduce GHG emissions from their turbines to zero, which do not involve either emission trading or installation of CCS. NextERA has a plan to convert 16 GW of natural gas-fired capacity to fire 100 percent hydrogen by 2045. The Illinois "Climate and Equitable Jobs Act", sets dates (ranging from 2030 to 2045) by which individual gas-fired power plants must reduce their emissions to zero. The EPA solicits comment on whether and how to assure that the emission guidelines for combustion turbines provides opportunities for states to develop plans that build upon these state programs.
In addition, the EPA also solicits comment on other key issues relating to state plan requirements that are specific to existing combustion turbines, including timing for state plan submittals, compliance deadlines, and meaningful engagement. 
Areas that the EPA is Seeking Comment on Related to Existing Turbines
The EPA is seeking comment on four general areas related to developing BSER for existing turbines. First, the EPA is soliciting comment on general assumptions about potential future utilization of turbines. Second, the EPA is soliciting comment on assumptions about sub-categorization and timing of BSER requirements for existing turbines. Third, the EPA is soliciting comment related to specific BSER assumptions for existing turbines. And finally, the EPA is soliciting comment on state plan provisions for existing turbines.
The EPA is seeking comment on a number of issues related to how its consideration of projected future utilization of combined cycles informed its consideration of a potential BSER for existing combustion turbines. First, the EPA is taking comment on its projections of how turbines will operate in the future and the key factors that influence those changes in operation. While EPA modeling shows that there is some increase in emissions from these units in all years following imposition of CAA section 111 standards on existing coal-fired steam generating units and new stationary combustion turbines, that increase is much smaller in the later years. The EPA believes the magnitude of these trends is significantly impacted by the rate at which new low emitting generation comes on-line, in part incentivized by IRA and BIL. The EPA is taking comment on all aspects of these assumptions including: the speed at which new low-emitting generation will come on-line and the impact that it has on likely capacity factors for combined cycle units (in particular the projection that capacity factors will grow in the 2028/30 timeframe but decrease in later years).
The EPA is also taking comment on how its assumptions about the potential operation of turbines in future years coupled with considerations about the availability of infrastructure should inform its BSER determination. More specifically, the EPA is requesting comment on how to consider the rate of CCS (and potentially hydrogen) infrastructure development in determining a BSER that could potentially impact hundreds of sources.
With regards to the BSER itself, the EPA is taking comment on the applicability of CCS retrofits to existing combustion turbines and its focus on base load turbines (e.g., those with a capacity factor of greater than 50 percent). The EPA is also requesting comment on appropriate parameters to use in the design of a potential subcategory for which CCS would be identified as the BSER. The EPA is also taking comment on the role of low-GHG hydrogen as part of BSER and whether EPA should focus any BSER determination on units with lower capacity factors. The EPA also requests comment on a BSER that could include requirements to co-fire more than 30 percent low-GHG hydrogen and up to 100 percent low-GHG hydrogen. Further, the EPA is soliciting comments on applying such requirements to units that would be covered under the CAA section 111(b) provisions being proposed in this preamble under a potential future CAA section 111(d) rule. Finally, the EPA requests comment on whether heat rate improvements are an appropriate BSER. This includes consideration of whether efficiency improvements make sense as a first step towards firing some amount of low-GHG hydrogen or installing CCS. It also includes consideration of the two types of efficiency subcategories discussed above, one for major turbine upgrades for more inefficient units and one for minor efficiency improvements for more efficient units.
The EPA is also taking comment on state plan requirements for a CAA section 111(d) rule for existing fossil fuel-fired turbines. Specifically, the EPA is taking comment on considerations related to an approach for setting emission standards, implementation of RULOF, and additional flexibilities beyond RULOF. With regards to RULOF, the EPA is specifically seeking comment on the likely remaining useful life of a typical combined cycle unit and simple cycle turbine, how RULOF might factor into a unit whose utilization is projected to change in the future (e.g., how should a state factor in the utilization pattern identified in the EPA's modeling where some units operate at well above 50 percent in the early 2030s, but see a significant increase in capacity factors in the later years.) With regards to flexibility measures, the EPA is seeking comment on the role of trading in implementation of a turbine BSER and how a state could ensure that under a trading program, sources achieved the same level of reductions expected under unit specific implementation of the BSER. Finally, the EPA is taking comment on if and how the EPA should provide flexibility for states who may have already developed, or who may be interested in developing approaches to reduce emissions that are very different than the BSER the EPA might develop and how one could evaluate whether such programs achieve the same or greater emission reductions than unit-by-unit implementation of the BSER.
Implications for Other EPA Programs 
Implications for New Source Review (NSR) Program
CAA section 110(a)(2)(C) requires that a state implementation plan (SIP) include a New Source Review (NSR) program that provides for the "regulation of the modification and construction of any stationary source ... as necessary to assure that [the NAAQS] are achieved." Within the NSR program, the "major NSR" preconstruction permitting program applies to new construction and to modifications of existing sources that emit "regulated NSR pollutants" at or above certain established thresholds. New sources and modifications that emit regulated NSR pollutants under the established thresholds may be subject to "minor NSR" program requirements or may be excluded from NSR requirements altogether. The NSR program for a state or local permitting authority with an approved SIP is implemented through 40 CFR 51.160 to 51.166, while the NSR program applying in areas for which the EPA or a delegated state, local or tribal agency is the permitting authority is implemented through 40 CFR part 49 and 40 CFR 52.21.
NSR applicability is pollutant-specific and, for the major NSR program, the permitting requirements that apply to a source depend on the air quality designation at the location of the source for each of its emitted pollutants at the time the permit is issued. Major NSR permits for sources located in an area that is designated as attainment or unclassifiable for the NAAQS for its pollutants are referred to as Prevention of Significant Deterioration (PSD) permits. In addition, PSD permits can include requirements for specific pollutants for which there are no NAAQS. Sources subject to PSD must, among other requirements, comply with emission limitations that reflect the Best Available Control Technology (BACT) for "each pollutant subject to regulation" as specified by CAA sections 165(a)(4) and 169(3). Major NSR permits for sources located in nonattainment areas and that emit at or above the specified major NSR threshold for the pollutant for which the area is designated as nonattainment are referred to as Nonattainment NSR (NNSR) permits. Sources subject to NNSR must, among other requirements, meet the Lowest Achievable Emissions Rate (LAER) pursuant to CAA sections 171(3) and 173(a)(2) for any pollutant subject to NNSR. Due to the pollutant-specific applicability of the NSR program, it it conceivable that a source seeking to newly construct or modify may have to obtain multiple types of NSR permits (i.e., NNSR, PSD, or minor NSR) depending on the air quality designation at the location of the source and the types and amounts of pollutants it emits.
A new stationary source is subject to major NSR requirements if its potential to emit (PTE) a regulated NSR pollutant exceeds statutory emission thresholds, upon which the NSR regulations define it as a "major stationary source." For PSD permitting, once a new stationary source is determined to be subject to major NSR for one regulated NSR pollutant (with the exception of GHG), the source can be subject to major NSR requirements for any other regulated NSR pollutant if the PTE of that pollutant is at least the "significant" emissions rate ("SER"), as defined in 40 CFR 52.21(b)(23). In the case of GHG, the EPA has not promulgated a GHG SER but applies a BACT applicability threshold of 75,000 TPY CO2e. 
For an existing source, it can be subject to major NSR requirements if it is a major stationary source and its emissions increase resulting from a modification (i.e., physical change or change in the method of operation) are equal to or greater than the SER for a regulated NSR pollutant, upon which the NSR regulations define it as a "major modification." As with new sources, the one exception to this applicability approach is GHG, which currently applies a BACT applicability threshold in lieu of a SER and can only be subject to major NSR if another pollutant is also subject to major NSR for the modification. Generally, an existing major stationary source triggering major NSR requirements for a regulated NSR pollutant would have both a significant emissions increase from the modification and a significant net emissions increase at the stationary source, and the calculation of the significant emissions increase differs depending on whether the modification is to an existing emissions unit, or the addition of a new emissions unit, or if it involves multiple types of emission units. An existing major stationary source would trigger PSD permitting requirements for GHGs if it undertakes a modification and: (1) the modification is otherwise subject to PSD for a pollutant other than GHG; and (2) the modification results in a GHG emissions increase and a GHG net emissions increase that is equal to or greater than 75,000 TPY CO2e and greater than zero on a mass basis. 
Since GHG is not a criteria pollutant, it is regulated under the CAA's PSD program, but not under the NNSR or minor NSR programs. For new sources and modifications that are subject to PSD, the permitting authority must establish emission limitations based on BACT for each pollutant that is subject to PSD at the major stationary source or at each emissions unit involved in the major modification. BACT is assessed on a case-by-case basis, and the permitting authority, in its analysis of BACT for each pollutant, evaluates the emission reductions that each available emissions-reducing technology or technique would achieve, as well as the energy, environmental, economic, and other costs associated with each technology or technique. The CAA also specifies that BACT cannot be less stringent than any applicable standard of performance under the NSPS. Permitting authorities may determine BACT by applying the EPA's five-step "top down" approach. The ultimate determination of BACT is made by the permitting authority after a public notice and comment period of at least 30-days on the draft permit and supporting information.
NSR Implications of a CAA Section 111(b) Standard
As noted above, BACT cannot be set at a level that is less stringent than the standard of performance established by an applicable NSPS, and the EPA refers to this minimum control level as the "BACT floor." While a proposed NSPS does not establish the BACT floor for affected facilities seeking a PSD permit, once an NSPS is promulgated, it then serves as the BACT floor for any new major stationary source or major modification that meets the applicability of the NSPS and commences construction after the date of the proposed NSPS in the Federal Register. In the context of combustion turbines that would be subject to this NSPS at 40 CFR part 60, subpart TTTTa, for any new major stationary source or major modification that commences construction or reconstruction of a stationary combustion turbine EGU after the date of publication of this proposed NSPS, the PSD permit should reflect a BACT determination that is at least as stringent as the promulgated NSPS for each of the source's affected EGUs.
However, the fact that a minimum control requirement is established by an applicable NSPS does not mean that a permitting authority cannot select a more stringent control level for the PSD permit or consider technologies for BACT beyond those that were considered in developing the NSPS. As explained above, BACT is a case-by-case review that considers a number of factors, and the review should reflect advances in control technology, reductions in the costs or other impacts of using particular control strategies, or other relevant information that may have become available after development of an applicable NSPS.
NSR Implications of a CAA Section 111(d) Standard
With respect to the proposed action for emission guidelines, should it be promulgated, states will be called upon to develop a plan that establish standards of performance for each affected EGU that meets the requirements in the emission guidelines. In doing so, a state agency may develop a plan that results in an affected source undertaking a physical or operational change. Under the NSR program, undertaking a physical or operational change may require the source to obtain a preconstruction permit for the proposed change, with the type of NSR permit (i.e., NNSR, PSD, or minor NSR) depending on the amount of the emissions increase resulting from the change and the air quality designation at the location of the source for its emitted pollutants. More specifically, any time an existing source adds equipment or otherwise makes physical or operational changes to its facility, regardless of whether it has done so to comply with a national or state level requirement, the source may be required to obtain a NSR permit prior to making the changes unless the permitting authority determines that the action is exempt from permitting.
Thus, there are circumstances in which an affected source that is implementing a BSER requirement from a state plan is required to obtain a major NSR permit for one or more of its pollutants. One scenario in which this could occur is if an affected source experiences greater unit availability and reliability as a result of its BSER requirement (perhaps from implementing an efficiency based BSER) that, in turn, lowers the operating costs of its EGU. Since EGUs that operate at lower costs are generally preferred in the dispatch by the system operator over units that have higher operational costs, the BSER implementation could result in improving the source's relative economics that would, in turn, increase its utilization of its EGU(s). With an increase in utilization resulting from the source implementing the BSER, the annual emissions from the EGU could increase, and if the emissions increase equals or exceeds the relevant SER for one or more of its pollutants, the source may be required to obtain a major NSR permit for the modification.
However, while it may be possible for an affected source to trigger major NSR requirements from actions it takes to implement a BSER requirement, we expect this situation to not occur often. As previously discussed in this preamble, states will have considerable flexibility in adopting varied compliance measures as they develop their plans to meet the standards of performance of the emission guidelines. One of these flexibilities is the ability for states to establish the standards of performance in their plans in such a way so that their affected sources, in complying with those standards, in fact would not have emission increases that trigger major NSR requirements. To achieve this, the state would need to conduct an analysis consistent with the NSR regulatory requirements that supports its determination that as long as affected sources comply with the standards of performance, their emissions would not increase in a way that trigger major NSR requirements. For example, a state could, as part of its state plan, develop conditions for a source expected to trigger major NSR that would effectively limit the unit's ability increase its emissions in amounts that would trigger NSR (effectively establishing a synthetic minor limitation).
Implications for Title V Program
Title V is implemented through 40 CFR parts 70 and 71. Part 70 defines the minimum requirements for state, local and tribal (state) agencies to develop, implement and enforce a title V operating permit program; these programs are developed by the state and the state submits a program to the EPA for a review of consistency with part 70. There are about 117 approved part 70 programs in effect, with about 14,000 part 70 permits currently in effect. (See Appendix A of 40 CFR part 70 for the approval status of each state program.) Part 71 is a Federal permit program run by the EPA, primarily where there is no part 70 program in effect (e.g., in Indian country, the Federal Outer Continental Shelf, and for offshore Liquified Natural Gas terminals). There are about 100 part 71 permits currently in effect (most are in Indian country).
The title V regulations require each permit to include emission limitations and standards, including operational requirements and limitations that assure compliance with all applicable requirements. Requirements resulting from these rules that are imposed on EGUs or other potentially affected entities that have title V operating permits are applicable requirements under the title V regulations and would need to be incorporated into the source's title V permit in accordance with the schedule established in the title V regulations. For example, if the permit has a remaining life of three years or more, a permit reopening to incorporate the newly applicable requirement shall be completed no later than 18 months after promulgation of the applicable requirement. If the permit has a remaining life of less than three years, the newly applicable requirement must be incorporated at permit renewal.
If a state needs to include provisions related to the state plan in a source's title V permit before submitting the plan to the EPA, these limits should be labeled as "state-only" or "not federally enforceable" until the EPA has approved the state plan. The EPA solicits comment on whether, and under what circumstances, states might use this mechanism. 
EPA Partnership Programs
For over thirty years, EPA partnership programs have worked alongside the Agency's power sector air regulatory programs. The EPA partnerships do not play a role under any regulations, including the proposed standards. Through non-regulatory efforts, partnerships can help ease the way toward meeting public and private sector air quality and climate goals. These partnership programs seek out and overcome market barriers, support policy implementation at the state, tribal, and local level, and channel marketplace ingenuity toward measurable climate action and greenhouse gas reductions. These efforts can contribute to technology adoption and subnational policy that can lower emissions and reduce compliance costs. Partnership programs support private and sub-national government action with unbiased information including specifications for efficient appliances and equipment, methodologies for measurement, and standardized platforms and templates for program implementation. These efforts are transparent, rigorous, and agreeable to all stakeholders. 
For example, ENERGY STAR plays a critical unifying role to guide hundreds of utility energy efficiency programs. ENERGY STAR enables utilities to leverage a common national program platform, avoiding the need to produce individual specifications and resources for each utility energy efficiency program across the nation, which could fragment the market and stall innovation and implementation. Similarly, the EPA's partnership programs provide a suite of off-the-shelf policy tools and guidance that states, cities, and tribes can use to cost-effectively develop and implement policies that are based on widely adopted tools and approaches.
Partnerships relevant to the power sector drive private-sector investment in energy efficiency, renewable energy, and related technologies that produce public benefits. Programs that potentially complement EGU new source performance standards for greenhouse gas emissions are:
 ENERGY STAR, which provides simple, credible, and unbiased information that consumers and businesses rely on to make well-informed decisions on energy efficient measures. ENERGY STAR programs focus on residential and commercial products, commercial buildings and multifamily housing, industrial plants, and new homes.
 EPA's Green Power Partnership, which drives voluntary participation in the green power market. The program provides information, technical assistance, and recognition to companies that use green power. In return, the companies commit to using green power for all, or a portion, of their annual electricity consumption.
 The State and Local Climate and Energy Program, which offers free tools, data, and technical expertise to help state, local, and tribal governments achieve their environmental, energy, equity, and economic objectives. These freely available tools help stakeholders overcome limited access to proprietary tools and analysis.
 Additional EPA resources are also provided to inform organizations' emission reduction measures, including guidance and tools to help measure and manage organizational GHG inventories and targets and impartial tools, policy information, and other resources to help promote environmentally beneficial CHP.
The IRA provides significant funding for Federal, state, and local voluntary policies and programs affecting electricity generation and use and greatly expands incentives for GHG emission reductions in the power sector and electricity end-use sectors. The EPA's partnership programs are well positioned to leverage these new policies to enable significant additional voluntary action, including upgrading homes, buildings, and schools for energy efficiency; achieving a carbon-free power sector; and accelerating low-carbon manufacturing. 
Impacts of Proposed Actions
In accordance with EO 12866 and 13563, the guidelines of OMB Circular A-4 and the EPA's Guidelines for Preparing Economic Analyses, the EPA prepared an RIA for these proposed actions. This RIA presents the expected economic consequences of the EPA's proposed rules, including analysis of the benefits and costs associated with the projected emission reductions for three illustrative scenarios. The first scenario represents the proposed CAA 111(b) and 111(d) proposals in combination. The second and third scenarios represent different stringencies of the combined policies. All three illustrative scenarios are compared against a single baseline. For detailed descriptions of the three illustrative scenarios and the baseline, see Section 1 of the RIA, which is titled "Regulatory Impact Analysis for the Proposed New Source Performance Standards for Greenhouse Gas Emissions from New, Modified, and Reconstructed Fossil Fuel-Fired Electric Generating Units; Emission Guidelines for Greenhouse Gas Emissions from Existing Fossil Fuel-Fired Electric Generating Units; and Repeal of the Affordable Clean Energy Rule."
The three scenarios detailed in the RIA, including the proposal scenario, are illustrative in nature and do not represent the plans that states may ultimately pursue. As there are considerable flexibilities afforded to states in developing their state plans, the EPA does not have sufficient information to assess specific compliance measures on a unit-by-unit basis. Nonetheless, the EPA believes that such illustrative analysis can provide important insights.
In the RIA, the EPA evaluates the potential impacts of the three illustrative scenarios using the present value (PV) of costs, benefits, and net benefits, calculated for the years 2024 - 2042 from the perspective of 2024, using both a three percent and seven percent discount rate. In addition, the EPA presents the assessment of costs, benefits, and net benefits for specific snapshot years, consistent with the Agency's historic practice. These specific snapshot years are 2028, 2030, 2035, and 2040. In addition to the core benefit-cost analysis, the RIA also includes analyses of anticipated economic and energy impacts, environmental justice impacts, and employment impacts.
The analysis presented in this preamble section summarizes key results of the illustrative policy scenario. For detailed benefit-cost results for the three illustrative scenarios and results of the variety of impact analysis just mentioned, please see the RIA, which is available in the docket for this action.
Air Quality Impacts
Total cumulative power sector CO2 emissions between 2028 and 2042 are projected to be 617 million metric tonnes lower under the illustrative proposal scenario than under the baseline. Table 5 shows projected aggregate annual electricity sector emission changes for the illustrative proposal scenario, relative to the baseline.
Table 5 -- Projected Electricity Sector Emission Impacts for the Illustrative Proposal Scenario, Relative to the Baseline
                                       
                          CO2 (million metric tonnes)
                       Annual NOX (thousand short tons)
                    Ozone Season NOX (thousand short tons)
                       Annual SO2 (thousand short tons)
                      Direct PM2.5 (thousand short tons)
                                     2028
                                      -10
                                      -7
                                      -3 
                                      -12
                                      -1
                                     2030
                                      -89
                                      -64
                                      -22
                                     -107
                                      -6
                                     2035
                                      -37
                                      -21
                                      -7
                                      -41
                                      -1
                                     2040
                                      -24
                                      -13
                                      -4
                                      -30
                                      -1

The emissions changes in these tables do not account for changes in HAP that may occur as a result of this action. 
Compliance Cost Impacts
The power industry's "compliance costs" are represented in this analysis as the change in electric power generation costs between the baseline and illustrative scenarios, including the cost of monitoring, reporting, and recordkeeping. In simple terms, these costs are an estimate of the increased power industry expenditures required to comply with the proposed action.
The compliance assumptions -- and, therefore, the projected compliance costs -- set forth in this analysis are illustrative in nature and do not represent the plans that states may ultimately pursue. The illustrative proposal scenario is designed to reflect, to the extent possible, the scope and nature of the proposed guidelines. However, there is uncertainty with regards to the precise measures that states will adopt to meet the requirements because there are flexibilities afforded to the states in developing their state plans.
We estimate the present value (PV) of the projected compliance costs over the 2024 - 2042 period, as well as estimate the equivalent annual value (EAV) of the flow of the compliance costs over this period. The EAV represents a flow of constant annual values that, had they occurred annually, would yield a sum equivalent to the PV. All dollars are in 2019 dollars. Consistent with Executive Order 12866 guidance, we estimate the PV and EAV using 3 and 7 percent discount rates. The PV of the compliance costs, discounted at the 3-percent rate, is estimated to be about $14 billion, with an EAV of about $0.95 billion. At the 7-percent discount rate, the PV of the compliance costs is estimated to be about $10 billion, with an EAV of about $0.98 billion. 
Section 3 of the RIA presents a detailed discussion of the compliance cost projections for the proposed requirements, as well as projections of compliance costs for less and more stringent regulatory options. For a detailed description of these compliance cost projections, please see Section 3 of the RIA.
Economic Impacts
These proposed actions have economic and energy market implications. The energy impact estimates presented here reflect the EPA's illustrative analysis of the proposed rules. States are afforded flexibility to implement the proposed rules, and thus the impacts could be different to the extent states make different choices than those assumed in the illustrative analysis. Table 6 presents a variety of energy market impact estimates for 2028, 2030, 2035, and 2040 for the illustrative proposal scenario, relative to the baseline.
Table 6 -- Summary of Certain Energy Market Impacts for the Illustrative Proposal Scenario, Relative to the Baseline
                               [Percent change]

                                   2028 (%)
                                   2030 (%)
                                   2035 (%)
                                   2040 (%)
                Average price of coal delivered to power sector
                                      -1%
                                      0%
                                      2%
                                      2%
                     Coal production for power sector use
                                      -2%
                                     -40%
                                     -23%
                                     -15%
                Price of natural gas delivered to power sector
                                      0%
                                      9%
                                      -2%
                                      -3%
                       Price of average Henry Hub (spot)
                                      0%
                                      10%
                                      -2%
                                      -2%
                  Natural gas use for electricity generation
                                      0%
                                      8%
                                      -1%
                                      -2%

These and other energy market impacts are discussed more extensively in Section 3 of the RIA.
More broadly, changes in production in a directly regulated sector may have effects on other markets when output from that sector  -  for this rule electricity  -  is used as an input in the production of other goods. It may also affect upstream industries that supply goods and services to the sector, along with labor and capital markets, as these suppliers alter production processes in response to changes in factor prices. In addition, households may change their demand for particular goods and services due to changes in the price of electricity and other final goods prices. Economy-wide models -- and, more specifically, computable general equilibrium (CGE) models -- are analytical tools that can be used to evaluate the broad impacts of a regulatory action. A CGE-based approach to cost estimation concurrently considers the effect of a regulation across all sectors in the economy. 
In 2015, the EPA established a Science Advisory Board (SAB) panel to consider the technical merits and challenges of using economy-wide models to evaluate costs, benefits, and economic impacts in regulatory analysis. In its final report, the SAB recommended that the EPA begin to integrate CGE modeling into applicable regulatory analysis to offer a more comprehensive assessment of the effects of air regulations. In response to the SAB's recommendations, the EPA developed a new CGE model called SAGE designed for use in regulatory analysis. A second SAB panel performed a peer review of SAGE, and the review concluded in 2020. The EPA used SAGE to evaluate potential economy-wide impacts of these proposed rules, and the results are contained in an appendix of the RIA. The EPA solicits comment on the SAGE analysis presented in the RIA appendix. 
Environmental regulation may affect groups of workers differently, as changes in abatement and other compliance activities cause labor and other resources to shift. An employment impact analysis describes the characteristics of groups of workers potentially affected by a regulation, as well as labor market conditions in affected occupations, industries, and geographic areas. Employment impacts of these proposed actions are discussed more extensively in Section 5 of the RIA.
Benefits
Pursuant to EO 12866, the RIA for these actions analyzes the benefits associated with the projected emission reductions under the proposals to inform the EPA and the public about these projected impacts. These proposed rules are projected to reduce emissions of CO2, SO2, NOX, and PM2.5 nationwide. The potential climate, health, welfare, and water quality impacts of these emission reductions are discussed in detail in the RIA. In the RIA, the EPA presents the projected monetized climate benefits due to reductions in CO2 emissions and the monetized health benefits attributable to changes in SO2, NOX, and PM2.5 emissions, based on the emissions estimates in illustrative scenarios described previously. We monetize benefits of the proposed standards and evaluate other costs in part to enable a comparison of costs and benefits pursuant to EO 12866, but we recognize there are substantial uncertainties and limitations in monetizing benefits, including benefits that have not been quantified or monetized.
We estimate the climate benefits from these proposed rules using estimates of the social cost of greenhouse gases (SC-GHG), specifically the SC-CO2. The SC-CO2 is the monetary value of the net harm to society associated with a marginal increase in CO2 emissions in a given year, or the benefit of avoiding that increase. In principle, SC-CO2 includes the value of all climate change impacts (both negative and positive), including (but not limited to) changes in net agricultural productivity, human health effects, property damage from increased flood risk natural disasters, disruption of energy systems, risk of conflict, environmental migration, and the value of ecosystem services. The SC-CO2, therefore, reflects the societal value of reducing emissions of the gas in question by one metric ton and is the theoretically appropriate value to use in conducting benefit-cost analyses of policies that affect CO2 emissions. In practice, data and modeling limitations naturally restrain the ability of SC-CO2 estimates to include all the important physical, ecological, and economic impacts of climate change, such that the estimates are a partial accounting of climate change impacts and will therefore, tend to be underestimates of the marginal benefits of abatement. The EPA and other Federal agencies began regularly incorporating SC-GHG estimates in their benefit-cost analyses conducted under EO 12866 since 2008, following a Ninth Circuit Court of Appeals remand of a rule for failing to monetize the benefits of reducing CO2 emissions in a rulemaking process.
We estimate the global social benefits of CO2 emission reductions expected from the proposed rule using the SC-GHG estimates presented in the February 2021 TSD: Social Cost of Carbon, Methane, and Nitrous Oxide Interim Estimates under EO 13990. These SC-GHG estimates are interim values developed under EO 13990 for use in benefit-cost analyses until updated estimates of the impacts of climate change can be developed based on the best available climate science and economics. We have evaluated the SC-GHG estimates in the TSD and have determined that these estimates are appropriate for use in estimating the global social benefits of CO2 emission reductions expected from this proposed rule. After considering the TSD, and the issues and studies discussed therein, the EPA finds that these estimates, while likely an underestimate, are the best currently available SC-GHG estimates. These SC-GHG estimates were developed over many years using a transparent process, peer-reviewed methodologies, the best science available at the time of that process, and with input from the public. As discussed in Section 4 of the RIA, these interim SC-CO2 estimates have a number of limitations, including that the models used to produce them do not include all of the important physical, ecological, and economic impacts of climate change recognized in the climate-change literature and that several modeling input assumptions are outdated. As discussed in the February 2021 TSD, the Interagency Working Group on the Social Cost of Greenhouse Gases (IWG) finds that, taken together, the limitations suggest that these SC-CO2 estimates likely underestimate the damages from CO2 emissions. The IWG is currently working on a comprehensive update of the SC-GHG estimates (under EO 13990) taking into consideration recommendations from the National Academies of Sciences, Engineering and Medicine, recent scientific literature, public comments received on the February 2021 TSD and other input from experts and diverse stakeholder groups. The EPA is participating in the IWG's work. In addition, while that process continues, the EPA is continuously reviewing developments in the scientific literature on the SC-GHG, including more robust methodologies for estimating damages from emissions, and looking for opportunities to further improve SC-GHG estimation going forward. Most recently, the EPA has developed a draft updated SC-GHG methodology within a sensitivity analysis in the regulatory impact analysis of the EPA's November 2022 supplemental proposal for oil and gas standards that is currently undergoing external peer review and a public comment process. See Section 4 of the RIA for more discussion of this effort.
In addition to CO2, these proposed rules are expected to reduce emissions of NOX and SO2 and direct PM2.5 nationally throughout the year. Because NOX and SO2 are also precursors to secondary formation of ambient PM2.5, reducing these emissions would reduce human exposure to ambient PM2.5 throughout the year and would reduce the incidence of PM2.5-attributable health effects. These proposed rules are also expected to reduce ozone season NOX emissions nationally. In the presence of sunlight, NOX and volatile organic compounds (VOCs) can undergo a chemical reaction in the atmosphere to form ozone. Reducing NOX emissions in most locations reduces human exposure to ozone and the incidence of ozone-related health effects, though the degree to which ozone is reduced will depend in part on local concentration levels of VOCs. The RIA reports estimates of the health benefits of changes in PM2.5 and ozone concentrations. The health effect endpoints, effect estimates, benefit unit-values, and how they were selected, are described in the TSD titled Estimating PM2.5- and Ozone-Attributable Health Benefits, which is referenced in the RIA for these actions. Our approach for updating the endpoints and to identify suitable epidemiologic studies, baseline incidence rates, population demographics, and valuation estimates is summarized in Section 4 of the RIA.
The following PV and EAV estimates reflect projected benefits over the 2024 - 2042 period, discounted to 2024 in 2019 dollars. We monetize benefits of the proposed standards and evaluate other costs in part to enable a comparison of costs and benefits pursuant to EO 12866, but we recognize there are substantial uncertainties and limitations in monetizing benefits, including benefits that have not been quantified. The projected PV of monetized climate benefits is about $30 billion, with an EAV of about $2.1 billion using the SC-CO2 discounted at 3 percent. The projected PV of monetized health benefits is about $77 billion, with an EAV of about $5.3 billion discounted at 3 percent. Combining the projected monetized climate and health benefits yields a total PV estimate of about $110 billion and EAV estimate of $7.5 billion.
At a 7 percent discount rate, this proposed rule is expected to generate projected PV of monetized health benefits of about $50 billion, with an EAV of about $4.8 billion discounted at 7 percent. Climate benefits remain discounted at 3 percent in this benefits analysis. Thus, this proposed rule would generate a PV of total monetized benefits of $80 billion, with an EAV of $6.9 billion discounted at a 7 percent rate. 
The results presented in this section provide an incomplete overview of the effects of the proposals. The monetized benefits estimates do not include important climate benefits that were not monetized in the RIA. In addition, important health, welfare, and water quality benefits anticipated under these proposed rules are not quantified. We anticipate that taking non-monetized effects into account would show the proposals to be more beneficial than the tables in this section reflect. Discussion of the non-monetized health, climate, welfare, and water quality benefits is found in section 4 of the RIA. 
Environmental Justice Analytical Considerations and Stakeholder Outreach and Engagement
Consistent with the EPA's commitment to integrating environmental justice (EJ) in the Agency's actions, and following the directives set forth in multiple Executive Orders, the Agency has analyzed the impacts of these proposed rules on communities with potential environmental justice concerns and engaged with stakeholders representing these communities to seek input and feedback. While these proposed rules are targeted at reducing CO2, a global pollutant, the EPA evaluates, to the extent practicable, whether proposed GHG reductions are accompanied by changes in other health-harming pollutants that may place further burdens on these communities.
Executive Order 12898 is discussed in Section XV.J of this preamble and analytical results are available in section 6 of the RIA. 
Introduction
Executive Order 12898 directs the EPA to identify the populations of concern who are most likely to experience unequal burdens from environmental harms; specifically, minority populations, low-income populations, and indigenous peoples. Additionally, Executive Order 13985 is intended to advance racial equity and support underserved communities through federal government actions. The EPA defines environmental justice as the fair treatment and meaningful involvement of all people regardless of race, color, national origin, or income, with respect to the development, implementation, and enforcement of environmental laws, regulations, and policies. The EPA further defines the term fair treatment to mean that "no group of people should bear a disproportionate burden of environmental harms and risks, including those resulting from the negative environmental consequences of industrial, governmental, and commercial operations or programs and policies". In recognizing that minority and low-income populations often bear an unequal burden of environmental harms and risks, the EPA continues to consider ways of protecting them from adverse public health and environmental effects of air pollution.
Analytical Considerations
EJ concerns for each rulemaking are unique and should be considered on a case-by-case basis, and the EPA's EJ Technical Guidance states that "[t]he analysis of potential EJ concerns for regulatory actions should address three questions: 
 Are there potential EJ concerns associated with environmental stressors affected by the regulatory action for population groups of concern in the baseline? 
 Are there potential EJ concerns associated with environmental stressors affected by the regulatory action for population groups of concern for the regulatory option(s) under consideration? 
 For the regulatory option(s) under consideration, are potential EJ concerns created or mitigated compared to the baseline?" 
To address these questions, the EPA developed an analytical approach that considers the purpose and specifics of the rulemaking, as well as the nature of known and potential exposures and impacts. For the rules, the EPA quantitatively evaluates 1) the proximity of existing affected facilities to potentially vulnerable and/or overburdened populations for consideration of local pollutants impacted by these rules but not modeled here (RIA section 6.4) the distribution of ozone and PM2.5 concentrations in the baseline and changes due to the proposed rulemakings across different demographic groups on the basis of race, ethnicity, poverty status, employment status, health insurance status, age, sex, educational attainment, and degree of linguistic isolation (RIA section 6.5). The EPA also qualitatively discusses potential EJ climate impacts (RIA section 6.3). Each of these analyses depends on mutually exclusive assumptions, was performed to answer separate questions, and is associated with unique limitations and uncertainties. 
Baseline demographic proximity analyses provide information as to whether there may be potential EJ concerns associated with environmental stressors emitted from sources affected by the regulatory actions for certain population groups of concern. The baseline demographic proximity analyses examined the demographics of populations living within 5 km and 10 km of the following three sets of sources: 1) all 140 coal plants with units potentially subject to the proposed rules, 2) three coal plants retiring by January 1, 2032 with units potentially subject to the proposed rules, and 3) 19 coal plants retiring between January 1, 2032 to January 1, 2040 with units potentially subject to the proposed rules. The proximity analysis of the full population of potentially affected units greater than 25 MW indicated that the demographic percentages of the population within 10 km and 50 km of the facilities are relatively similar to the national averages. The proximity analysis of the 19 units that will retire from 1/1/32 to 1/1/40 (a subset of the total 140 units) found that the percent of the population within 10 km that is African American is higher than the national average. The proximity analysis for the 3 units that will retire by 1/1/32 (a subset of the total 140 units) found that for both the 10 km and 50 km populations the percent of the population that is Native American for one facility is significantly above the national average, the percent of the population that is Hispanic/Latino for another facility is significantly above the national average, and all three facilities were well above the national average for both the percent below the poverty level and the percent below two times the poverty level.
Because the pollution impacts that are the focus of these rules may occur downwind from affected facilities, ozone and PM2.5 exposure analyses that evaluate demographic variables are better able to evaluate any potentially disproportionate pollution impacts of these rulemakings. The baseline PM2.5 and ozone exposure analyses respond to question 1 from EPA's EJ Technical Guidance document more directly than the proximity analyses, as they evaluate a form of the environmental stressor primarily affected by the regulatory actions (RIA section 6.5). Baseline ozone and PM2.5 exposure analyses show that certain populations, such as Hispanics, Asians, those linguistically isolated, and those less educated may experience disproportionately higher ozone and PM2.5 exposures as compared to the national average. Black populations may also experience disproportionately higher PM2.5 concentrations than the reference group, and American Indian populations and children may also experience disproportionately higher ozone concentrations than the reference group. Therefore, there likely are potential EJ concerns associated with environmental stressors affected by the regulatory actions for population groups of concern in the baseline (question 1).
Finally, the EPA evaluates how post-policy regulatory alternatives of these proposed rulemakings are expected to differentially impact demographic populations, informing questions 2 and 3 from EPA's EJ Technical Guidance with regard to ozone and PM2.5 exposure changes. We infer that baseline disparities in the ozone and PM2.5 concentration burdens are likely to remain after implementation of the regulatory action or alternatives under consideration. This is due to the small magnitude of the concentration changes associated with these rulemakings across population demographic groups, relative to the magnitude of the baseline disparities (question 2). This EJ assessment also suggests that these actions are unlikely to mitigate or exacerbate PM2.5 exposures disparities across populations of EJ concern analyzed. Regarding ozone exposures, while most policy options and future years analyzed will not likely mitigate or exacerbate ozone exposure disparities for the population groups evaluated, ozone exposure disparities may be exacerbated for some population groups analyzed in 2030 under all regulatory options. However, the extent to which disparities may be exacerbated is likely modest, due to the small magnitude of the ozone concentration changes. (question 3).
Outreach and Engagement 
In outreach with potentially vulnerable communities, residents have voiced two primary concerns. First, there is the concern that their communities have experienced historically disproportionate burdens from the environmental impacts of energy production, and second, that as the sector evolves to use new technologies such as CCS and hydrogen, they may continue to face disproportionate burden. 
With regards to CCS, the EPA is proposing that CCS is a component of the BSER for both new base load stationary combustion turbine EGUs and existing coal-fired steam generating units that intend to operate after 2040. We are aware of various concerns that potentially vulnerable communities have raised with regards to the use of CCS.
One concern is that adding CCS to EGUs can extend the life of an existing coal-fired steam generating unit, subjecting local residents who have already been negatively impacted by the operation of the coal-fired steam generating unit to additional harmful pollution. Recognizing the important stake that local residents have in this issue, the EPA is proposing that if a state intends to have an EGU retrofitted with CCS as its BSER, the state should go through an enhanced public engagement process. This is discussed more in section XI.F.1.b of the preamble. There are several important factors to consider when evaluating the emission impact of an upgraded EGU. First, CCS is the most effective add-on pollution control available for mitigation of GHG emissions from affected sources. Second, most CCS technologies work much more effectively when emitting the lowest levels of SO2 as possible, therefore it is likely that as part of a CCS installation, companies will improve their EGUs' SO2 control. Third, it is likely that a CCS retrofit will trigger preconstruction permitting requirements under the major NSR program because there is the potential for an emission increase of one or more pollutants due to the increased energy needed for CO2 capture. Major NSR permits provide for the public to comment on the draft permit, which is another avenue for affected residents to have input in the decision to install CCS.
Communities have also expressed concerns about CO2 pipeline safety and geologic sequestration. As discussed in section VII.F.3.b.iii of the preamble, CO2 pipeline safety is regulated by PHMSA. These regulations protect against environmental release during transport and PHMSA is developing new measures to further strengthen its safety oversight of CO2 pipelines. Geologic sequestration of CO2 is regulated by the EPA through the UIC Program and the GHGRP, which work in combination to ensure security and transparency.
The final concern is about the lack of opportunity to voice opinions about projects like this that affect their communities. As noted above, the major NSR permitting program already provides an opportunity for public input on a draft permit, in which the public could raise concerns specific to the pollution impact of a proposed CCS project at a new or existing source, and the EPA is proposing further community engagement requirements related to state plans under CAA section 111(d). States should have a plan that specifically ensures that community members have an opportunity to share their input if they reside near a coal-fired steam generating unit that plans to install CCS to meet the requirements of these proposed rules.
With regards to the decision to construct a new combustion turbine, most of the safeguards outlined above apply. The only exception is that the community engagement would be done as part of the major NSR permitting provisions. The major NSR provisions would likely also apply to most combustion turbines that co-fire with hydrogen, although there may be cases in which major NSR would not be triggered, specifically: (1) if the new combustion turbine is proposed on the site of an existing facility and the existing facility reduces its pollution more than the combustion turbine would increase it (e.g., if the combustion turbine replaces an existing coal-fired EGU and the facility has emission reduction credits from the shutdown unit), or (2) if the new combustion turbine's emissions are low enough to not trigger major NSR requirements.
The EPA further notes that hydrogen production presents a unique set of potential issues for vulnerable communities. For example, during the February 27th National Tribal Energy Roundtable Webinar, one of the primary concerns articulated was the potential for fossil-derived hydrogen to essentially extend the life of petrochemical industries already creating localized pollution loading. Perceived community risks with hydrogen related to storage and transportation include its combustibility and propensity to leak due to extremely low molecular weight. Water scarcity could be exacerbated in some areas by the freshwater demands of electrolytic hydrogen production which is particularly vexing for vulnerable communities.
Reliability Considerations
The requirements for sources and states set forth in these proposed actions were developed cognizant of concerns about an electric grid under transition, and related reliability considerations. As previously stated, a variety of important influences have led to notable changes in the generation mix and expectations of how the power sector will evolve. These trends have generally put existing fossil fuel-fired generators under greater economic pressure and will continue to do so even absent any EPA action pursuant to CAA section 111, and that is manifest in various economic projections and modeling of the electric power system. Recent legislation, including the IIJA, the IRA, and state policies have amplified these trends, with continued change expected for the existing fleet of EGUs. Moreover, many regions of the country have experienced a significant increase in the frequency and severity of extreme weather events -- events that are notably projected to worsen if GHG emissions are not adequately controlled. These events have impacted energy infrastructure and both the demand for and supply of electricity. A wide range of stakeholders including power generators, grid operators and state and federal regulators are actively engaged in ensuring the reliability of the electric power system is maintained and enhanced in the face of these changes. 
As explained in this preamble, these proposed actions take account of the rapidly evolving power sector and extensive input received from power companies and other stakeholders on the future of these regulated sources, while ensuring that new natural gas-fired combustion turbines and existing steam EGUs achieve significant and cost-effective reductions in GHG emissions through the application of adequately demonstrated control technologies, Preserving the ability of power companies and grid operators to maintain system reliability has been a paramount consideration in the development of these proposed actions. Accordingly, these proposed rules include significant design elements that are intended to allow the power sector continued resource and operational flexibility, and to facilitate long-term planning during this dynamic period. Among other things, these elements include subcategories of new natural gas-fired combustion turbines that allow for the stringency of GHG emission standards to vary by capacity factor; subcategories for existing steam EGUs that are based on operating horizons and fuel, and that accommodate the plans of many power companies to transition away from these sources; compliance deadlines for both new and existing EGUs that provide ample lead time to plan; and proposed state plan flexibilities  -  As such, these proposed rules provide the flexibility needed to avoid reliability concerns while still securing the pollution reductions required.
To support these proposed actions, the EPA has conducted an analysis of resource adequacy based upon power sector modeling and projections that can be found in the RIA. Any potential impact of these proposed actions is dependent upon a myriad of decisions and compliance choices source owners and operators may pursue. It is important to recognize that the proposed rules provide multiple flexibilities that preserve the ability of responsible authorities to maintain electric reliability. The results presented in the Resource Adequacy and Reliability Assessment TSD, which is available in the docket, show that the projected impacts of the proposed rules on power system operations, under conditions preserving resource adequacy, are modest and manageable. For the specific scenarios analyzed in the RIA, the implementation of the proposed rules can be achieved without undermining resources adequacy or reliability even as shifts in existing and new capacity occur. Retirements are offset by additions, along with reserve transfers where/when needed, which demonstrates that ample compliance pathways exist for sources while preserving reliability.
The EPA routinely consults with the DOE and FERC on electric reliability, and intends to continue to do so as it develops and implements a final rule. This ongoing engagement will be strengthened with routine and comprehensive communication between the agencies under the Joint Memorandum of Understanding on Interagency Communication and Consultation on Electric Reliability signed on March 8, 2023. The memorandum will provide greater interagency engagement on electric reliability issues at a time of significant dynamism in the power sector, allowing the EPA, FERC, and the DOE to use their considerable expertise in various aspects of grid reliability to support the ability of Federal and state regulators, grid operators, regional reliability entities, and power companies to continue to deliver a high standard of reliable electric service. As the power sector continues to change and as the agencies carry out their respective authorities, the agencies intend to continue to engage and collectively monitor, share information, and consult on policy and program decisions to assure the continued reliability of the bulk power system.
In addition, EPA observes that power companies, grid operators, and state public utility commissions have well-established procedures in place to preserve electric reliability in response to changes in the generating portfolio, and expects that those procedures will continue to be effective in addressing compliance decisions that power companies may make over the extended time period for implementation of these proposed rules. In response to any regulatory requirement, affected sources will have to take some type of action to reduce emissions, which will generally have costs. Some EGU owners may conclude that, all else being equal, retiring a particular EGU is likely to be the more economic option from the perspective of the unit's customers and/or owners because there are better opportunities for using the capital than investing it in new emissions controls at the unit. Such a retirement decision will require the unit's owner to follow the processes put in place by the relevant RTO, balancing authority, or state regulator to protect electric system reliability. These processes typically include analysis of the potential impacts of the proposed EGU retirement on electrical system reliability, identification of options for mitigating any identified adverse impacts, and, in some cases, temporary provision of additional revenues to support the EGU's continued operation until longer-term mitigation measures can be put in place. In some rare instances where the reliability of the system is jeopardized due to extreme weather events or other unforeseen emergencies, authorities can request a temporary reprieve from environmental requirements and constraints (through DOE) in order to meet electric demand and maintain reliability. This proposed action does not interfere with these already available provisions, but rather provides a long-term pathway for sources to develop and implement a proper plan to reduce emissions while maintaining adequate supplies of electricity.
Statutory and Executive Order Reviews
Executive Order 12866: Regulatory Planning and Review and Executive Order 13563: Improving Regulation and Regulatory Review
These actions are economically significant regulatory actions that were submitted to the Office of Management and Budget (OMB) for review. Any changes made in response to OMB recommendations have been documented in the docket. The EPA prepared an analysis of the potential costs and benefits associated with these actions. This analysis, "Regulatory Impact Analysis for the Proposed New Source Performance Standards for Greenhouse Gas Emissions from New, Modified, and Reconstructed Fossil Fuel-Fired Electric Generating Units; Emission Guidelines for Greenhouse Gas Emissions from Existing Fossil Fuel-Fired Electric Generating Units; and Repeal of the Affordable Clean Energy Rule," is available in the docket. 
Table 7 presents the estimated present values (PV) and equivalent annualized values (EAV) of the projected climate benefits, health benefits, compliance costs, and net benefits of the proposed rule in 2019 dollars discounted to 2024. The estimated monetized net benefits are the projected monetized benefits minus the projected monetized costs of the proposed rules. 
The projected climate benefits in table 7 are based on estimates of the social cost of carbon (SC-CO2) at a 3 percent discount rate and are discounted using a 3 percent discount rate to obtain the PV and EAV estimates in the table. Under EO 12866, the EPA is directed to consider all of the costs and benefits of its actions, not just those that stem from the regulated pollutant. Accordingly, in addition to the projected climate benefits of the proposal from anticipated reductions in CO2 emissions, the projected monetized health benefits include those related to public health associated with projected reductions in fine particulate matter (PM2.5) and ozone concentrations. The projected health benefits are associated with several point estimates and are presented at real discount rates of 3 and 7 percent. The power industry's compliance costs are represented in this analysis as the change in electric power generation costs between the baseline and policy scenarios. In simple terms, these costs are an estimate of the increased power industry expenditures required to implement the proposed requirements.
These results present an incomplete overview of the potential effects of the proposals because important categories of benefits -- including benefits from reducing HAP emissions  -- were not monetized and are therefore not reflected in the benefit-cost tables. The EPA anticipates that taking non-monetized effects into account would show the proposals to have a greater net benefit than this table reflects.
Table 7 -- Projected Monetized Benefits, Compliance Costs, and Net Benefits of the Proposed Rules, 2024 through 2042
                    [Billions 2019$, Discounted to 2024][a]
                                       
                                       
                               3% Discount Rate
                               7% Discount Rate
                                 Present Value
                              Climate Benefits[c]
                                      $30
                                      $30

                              Health Benefits[d]
                                      $77
                                      $50

                               Compliance Costs
                                      $14
                                      $10

                                Net Benefits[e]
                                      $93
                                      $70
                        Equivalent Annualized Value[b] 
                              Climate Benefits[c]
                                     $2.1
                                     $2.1

                              Health Benefits[d]
                                     $5.3
                                     $4.8

                               Compliance Costs
                                     $0.95
                                     $0.98

                                Net Benefits[e]
                                     $6.5
                                     $5.9
[a] Values have been rounded to two significant figures. Rows may not appear to sum correctly due to rounding.
[b] The annualized present value of costs and benefits are calculated over the 20-year period from 2024 to 2042. 
[c] Climate benefits are based on changes (reductions) in CO2 emissions. Climate benefits in this table are based on estimates of the SC-CO2 at a 3 percent discount rate and are discounted using a 3 percent discount rate to obtain the PV and EAV estimates in the table. The EPA does not have a single central SC-CO2 point estimate. We emphasize the importance and value of considering the benefits calculated using all four SC-CO2 estimates. As discussed in Section 4 of the RIA, consideration of climate benefits calculated using discount rates below 3 percent, including 2 percent and lower, is also warranted when discounting intergenerational impacts.
[d] The projected monetized health benefits include those related to public health associated with reductions in PM2.5 and ozone concentrations. The projected health benefits are associated with several point estimates and are presented at real discount rates of 3 and 7 percent. 
[e] Several categories of benefits remain unmonetized and are thus not reflected in the table. Non-monetized benefits include important climate, health, welfare, and water quality benefits.

As shown in table 7, the proposed rules are projected to reduce greenhouse gas emissions in the form of CO2, producing a projected PV of monetized climate benefits of about $30 billion, with an EAV of about $2.1 billion using the SC-CO2 discounted at 3 percent. The proposed rules are also projected to reduce PM2.5 and ozone concentrations, producing a projected PV of monetized health benefits of about $77 billion, with an EAV of about $5.3 billion discounted at 3 percent. 
The PV of the projected compliance costs are $14 billion, with an EAV of about $0.95 billion discounted at 3 percent. Combining the projected benefits with the projected compliance costs yields a net benefit PV estimate of about $93 billion and EAV of about $6.5 billion.
At a 7 percent discount rate, the proposed rules are expected to generate projected PV of monetized health benefits of about $50 billion, with an EAV of about $4.8 billion. Climate benefits remain discounted at 3 percent in this net benefits analysis. Thus, the proposed rules would generate a PV of monetized benefits of about $80 billion, with an EAV of about $6.9 billion discounted at a 7 percent rate. The PV of the projected compliance costs are about $10 billion, with an EAV of $0.98 billion discounted at 7 percent. Combining the projected benefits with the projected compliance costs yields a net benefit PV estimate of about $70 billion and an EAV of about $5.9 billion. 
As discussed in section XIV of this preamble, the monetized benefits estimates provide an incomplete overview of the beneficial impacts of the proposals. The monetized benefits estimates do not include important climate benefits that were not monetized in the RIA. In addition, important health, welfare, and water quality benefits anticipated under these proposed rules are not quantified or monetized. The EPA anticipates that taking non-monetized effects into account would show the proposals to be more net beneficial than the tables in this section reflect. 
Paperwork Reduction Act (PRA)
40 CFR Part 60, Subpart TTTT
The information collection activities in this proposed rule have been submitted for approval to the Office of Management and Budget (OMB) under the PRA. The Information Collection Request (ICR) document that the EPA prepared has been assigned EPA ICR number [placeholder]. You can find a copy of the ICR in the docket for this rule, and it is briefly summarized here. 
Respondents/affected entities: [placeholder]
Respondent's obligation to respond: Mandatory.
Estimated number of respondents: [placeholder]
Frequency of response: [placeholder] 
Total estimated burden: [placeholder] hours (per year). Burden is defined at 5 CFR 1320.3(b).
Total estimated cost: $ [placeholder] (per year), includes $ [placeholder]annualized capital or operation & maintenance costs. 
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for the EPA's regulations in 40 CFR are listed in 40 CFR part 9. 
Submit your comments on the Agency's need for this information, the accuracy of the provided burden estimates and any suggested methods for minimizing respondent burden to the EPA using the docket identified at the beginning of this rule. The EPA will respond to any ICR-related comments in the final rule. You may also send your ICR-related comments to OMB's Office of Information and Regulatory Affairs using the interface at www.reginfo.gov/public/do/PRAMain. Find this particular information collection by selecting "Currently under Review -- Open for Public Comments" or by using the search function. OMB must receive comments no later than [INSERT DATE 60 DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER].
40 CFR Part 60, Subpart TTTTa
The information collection activities in this proposed rule have been submitted for approval to the Office of Management and Budget (OMB) under the PRA. The Information Collection Request (ICR) document that the EPA prepared has been assigned EPA ICR number [placeholder]. You can find a copy of the ICR in the docket for this rule, and it is briefly summarized here. 
Respondents/affected entities: [placeholder]
Respondent's obligation to respond: Mandatory.
Estimated number of respondents: [placeholder]
Frequency of response: [placeholder] 
Total estimated burden: [placeholder] hours (per year). Burden is defined at 5 CFR 1320.3(b).
Total estimated cost: $ [placeholder] (per year), includes $ [placeholder]annualized capital or operation & maintenance costs. 
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for the EPA's regulations in 40 CFR are listed in 40 CFR part 9. 
Submit your comments on the Agency's need for this information, the accuracy of the provided burden estimates and any suggested methods for minimizing respondent burden to the EPA using the docket identified at the beginning of this rule. The EPA will respond to any ICR-related comments in the final rule. You may also send your ICR-related comments to OMB's Office of Information and Regulatory Affairs using the interface at www.reginfo.gov/public/do/PRAMain. Find this particular information collection by selecting "Currently under Review -- Open for Public Comments" or by using the search function. OMB must receive comments no later than [INSERT DATE 60 DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER].
40 CFR Part 60, Subpart UUUUb
The information collection activities in this proposed rule have been submitted for approval to the Office of Management and Budget (OMB) under the PRA. The Information Collection Request (ICR) document that the EPA prepared has been assigned EPA ICR number [placeholder]. You can find a copy of the ICR in the docket for this rule, and it is briefly summarized here. 
This rule imposes specific requirements on state governments with existing fossil fuel-fired steam generating units. The information collection requirements are based on the recordkeeping and reporting burden associated with developing, implementing, and enforcing a plan to limit GHG emissions from existing EGUs. These recordkeeping and reporting requirements are specifically authorized by CAA section 114 (42 U.S.C. 7414). All information submitted to the EPA pursuant to the recordkeeping and reporting requirements for which a claim of confidentiality is made is safeguarded according to Agency policies set forth in 40 CFR part 2, subpart B. 
The annual burden for this collection of information for the states (averaged over the first 3 years following promulgation) is estimated to be 95,680 hours at a total annual labor cost of $12.1 million. The annual burden for the Federal government associated with the state collection of information (averaged over the first 3 years following promulgation) is estimated to be 25,659 hours at a total annual labor cost of $991,451. Burden is defined at 5 CFR 1320.3(b).
Respondents/affected entities: States with one or more designated facilities covered under subpart UUUUb. 
Respondent's obligation to respond: Mandatory.
Estimated number of respondents: 50.
Frequency of response: Once.
Total estimated burden: 95,680 hours (per year). Burden is defined at 5 CFR 1320.3(b).
Total estimated cost: $12,110,762, includes $36,750 annualized capital or operation & maintenance costs. 
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for the EPA's regulations in 40 CFR are listed in 40 CFR part 9. 
Submit your comments on the Agency's need for this information, the accuracy of the provided burden estimates and any suggested methods for minimizing respondent burden to the EPA using the docket identified at the beginning of this rule. The EPA will respond to any ICR-related comments in the final rule. You may also send your ICR-related comments to OMB's Office of Information and Regulatory Affairs using the interface at www.reginfo.gov/public/do/PRAMain. Find this particular information collection by selecting "Currently under Review -- Open for Public Comments" or by using the search function. OMB must receive comments no later than [INSERT DATE 60 DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER].
40 CFR Part 60, Subpart UUUUa
This proposed rule does not impose an information collection burden under the PRA.
Regulatory Flexibility Act (RFA)
I certify that these actions will not have a significant economic impact on a substantial number of small entities under the RFA. The small entities subject to the requirements of the NSPS are private companies, investor-owned utilities, cooperatives, municipalities, and sub-divisions, that would seek to build and operate stationary combustion turbines in the future. The Agency has determined that seven small entities may be so impacted, and may experience an impact of 0 percent to 0.9 percent of revenues in 2035. Details of this analysis are presented in section 5.3 of the RIA.
The EPA started the Small Business Advocacy Review (SBAR) panel process prior to determining if the NSPS would have a significant economic impact on a substantial number of small entities under the RFA. The EPA conducted an initial outreach meeting with small entity representatives on December 14, 2022. The EPA sought input from representatives of small entities while developing the proposed NSPS which enabled the EPA to hear directly from these representatives about the regulation of GHG emissions from EGUs. The purpose of the meeting was to provide general background on the NSPS rulemaking, answer questions, and solicit input. Fifteen various small entities that potentially would be affected by the NSPS attended the meeting. The representatives included small entity municipalities, cooperatives, and industry professional organizations. When the EPA determined the NSPS would not have a significant economic impact on a substantial number of small entities under the RFA, the EPA did not proceed with convening the SBAR panel.
Emission guidelines will not impose any requirements on small entities. Specifically, emission guidelines established under CAA section 111(d) do not impose any requirements on regulated entities and, thus, will not have a significant economic impact upon a substantial number of small entities. After emission guidelines are promulgated, states establish standards on existing sources, and it is those state requirements that could potentially impact small entities. 
The analysis in the accompanying RIA is consistent with the analysis of the analogous situation arising when the EPA establishes NAAQS, which do not impose any requirements on regulated entities. As here, any impact of a NAAQS on small entities would only arise when states take subsequent action to maintain and/or achieve the NAAQS through their state implementation plans. See American Trucking Assoc. v. EPA, 175 F.3d 1029, 1043 - 45 (D.C. Cir. 1999) (NAAQS do not have significant impacts upon small entities because NAAQS themselves impose no regulations upon small entities). 
The EPA is aware that there is substantial interest in the proposed rules among small entities and invites comments on all aspects of the proposals and their impacts, including potential impacts on small entities.
Unfunded Mandates Reform Act of 1995 (UMRA)
The proposed NSPS contain a federal mandate under UMRA, 2 U.S.C. 1531 - 1538, that may result in expenditures of $100 million or more for the private sector in any one year. The proposed NSPS do not contain an unfunded mandate of $100 million or more as described in UMRA, 2 U.S.C. 1531 - 1538 for state, local,and tribal governments, in the aggregate. Accordingly, the EPA prepared, under section 202 of UMRA, a written statement of the benefit-cost analysis, which is in Section XIV and in the RIA.
The proposed repeal of the ACE Rule and emission guidelines do not contain an unfunded mandate of $100 million or more as described in UMRA, 2 U.S.C. 1531 - 1538, and do not significantly or uniquely affect small governments. The proposed emission guidelines do not impose any direct compliance requirements on regulated entities, apart from the requirement for states to develop plans to implement the guidelines under CAA section 111(d) for designated EGUs. The burden for states to develop CAA section 111(d) plans in the 24-month period following promulgation of the emission guidelines was estimated and is listed in section XV.B, but this burden is estimated to be below $100 million in any one year. As explained in section XI.F.6, the proposed emission guidelines do not impose specific requirements on tribal governments that have designated EGUs located in their area of Indian country.
The proposed actions are not subject to the requirements of section 203 of UMRA because they contain no regulatory requirements that might significantly or uniquely affect small governments.
In light of the interest in these rules among governmental entities, the EPA initiated consultation with governmental entities. The EPA invited the following 10 national organizations representing state and local elected officials to a virtual meeting on September 22, 2022: (1) National Governors Association, (2) National Conference of State Legislatures, (3) Council of State Governments, (4) National League of Cities, (5) U.S. Conference of Mayors, (6) National Association of Counties, (7) International City/County Management Association, (8) National Association of Towns and Townships, (9) County Executives of America, and (10) Environmental Council of States. These 10 organizations representing elected state and local officials have been identified by the EPA as the "Big 10" organizations appropriate to contact for purpose of consultation with elected officials. Also, the EPA invited air and utility professional groups who may have state and local government members, including the Association of Air Pollution Control Agencies, National Association of Clean Air Agencies, and American Public Power Association, Large Public Power Council, National Rural Electric Cooperative Association, and National Association of Regulatory Utility Commissioners to participate in the meeting. The purpose of the consultation was to provide general background on these rulemakings, answer questions, and solicit input from state and local governments. Subsequent to the September 22, 2022, meeting, the EPA received letters from five organizations. These letters were submitted to the pre-proposal non-rulemaking docket. See Docket ID No. EPA-HQ-OAR-2022-0723-0013, EPA-HQ-OAR-2022-0723-0016, EPA-HQ-OAR-2022-0723-0017, EPA-HQ-OAR-2022-0723-0020, and EPA-HQ-OAR-2022-0723-0021. For summary of the UMRA consultation see the memorandum in the docket titled, Federalism Pre-Proposal Consultation Summary.
Executive Order 13132: Federalism
The proposed NSPS and the proposed repeal of the ACE Rule do not have federalism implications. These actions will not have substantial direct effects on the states, on the relationship between the national government and the states, or on the distribution of power and responsibilities among the various levels of government.
The EPA has concluded that the proposed emission guidelines may have federalism implications, because it may impose substantial direct compliance costs on state or local governments, and the federal government will not provide the funds necessary to pay these costs. As discussed in the Supporting Statement found in the docket for this rulemaking, the development of state plans will entail many hours of staff time to develop and coordinate programs for compliance with the proposed emission guidelines, as well as time to work with state legislatures as appropriate, and develop a plan submittal.
The EPA consulted with representatives of state and local governments in the process of developing these actions to permit them to have meaningful and timely input into their development. The EPA's consultation regarded planned actions for the NSPS and emission guidelines. The EPA invited the following 10 national organizations representing state and local elected officials to a virtual meeting on September 22, 2022: (1) National Governors Association, (2) National Conference of State Legislatures, (3) Council of State Governments, (4) National League of Cities, (5) U.S. Conference of Mayors, (6) National Association of Counties, (7) International City/County Management Association, (8) National Association of Towns and Townships, (9) County Executives of America, and (10) Environmental Council of States. These 10 organizations representing elected state and local officials have been identified by the EPA as the "Big 10" organizations appropriate to contact for purpose of consultation with elected officials. Also, the EPA invited air and utility professional groups who may have state and local government members, including the Association of Air Pollution Control Agencies, National Association of Clean Air Agencies, and American Public Power Association, Large Public Power Council, National Rural Electric Cooperative Association, and National Association of Regulatory Utility Commissioners to participate in the meeting. The purpose of the consultation was to provide general background on these rulemakings, answer questions, and solicit input from state and local governments. Subsequent to the September 22, 2022, meeting, the EPA received letters from five organizations. These letters were submitted to the pre-proposal non-rulemaking docket. See Docket ID No. EPA-HQ-OAR-2022-0723-0013, EPA-HQ-OAR-2022-0723-0016, EPA-HQ-OAR-2022-0723-0017, EPA-HQ-OAR-2022-0723-0020, and EPA-HQ-OAR-2022-0723-0021. For a summary of the Federalism consultation see the memorandum in the docket titled Federalism Pre-Proposal Consultation Summary. A detailed Federalism Summary Impact Statement (FSIS) describing the most pressing issues raised in pre-proposal and post-proposal comments will be forthcoming with the final emission guidelines, as required by section 6(b) of Executive Order 13132. In the spirit of EO 13132, and consistent with EPA policy to promote communications between state and local governments, the EPA specifically solicits comment on these proposed actions from state and local officials.
Executive Order 13175: Consultation and Coordination with Indian Tribal Governments
These actions do not have tribal implications, as specified in Executive Order 13175. The proposed NSPS would impose requirements on owners and operators of new or reconstructed stationary combustion turbines and emission guidelines would not impose direct requirements on tribal governments. Tribes are not required to develop plans to implement the emission guidelines developed under CAA section 111(d) for designated EGUs. The EPA is aware of six fossil fuel-fired steam generating units located in Indian country but is not aware of any fossil fuel-fired steam generating units owned or operated by tribal entities. The EPA notes that the proposed emission guidelines do not directly impose specific requirements on EGU sources, including those located in Indian country, but before developing any standards for sources on tribal land, the EPA would consult with leaders from affected tribes. Thus, Executive Order 13175 does not apply to these actions.
Because the EPA is aware of tribal interest in these proposed rules and consistent with the EPA Policy on Consultation and Coordination with Indian Tribes, the EPA offered government-to-government consultation with tribes and conducted stakeholder engagement.
The EPA will hold additional meetings with tribal environmental staff to inform them of the content of these proposed rules as well as offer government-to-government consultation with tribes. The EPA specifically solicits additional comment on these proposed rules from tribal officials.
Executive Order 13045: Protection of Children from Environmental Health Risks and Safety Risks Populations and Low-Income Populations
These actions are subject to Executive Order 13045 because they are economically significant regulatory actions as defined by Executive Order 12866, and the EPA believes that these rule will reduce emissions of CO2, ozone and PM2.5. The EPA evaluated the health benefits of these emissions reductions and the results of this evaluation are contained in the RIA and are available in the docket. The EPA believes that the PM2.5-related, ozone-related, and CO2-related benefits projected under these proposed rules will improve children's health. Additionally, the PM2.5 and ozone EJ exposure analyses in section 6 of the RIA suggests that nationally, children (ages 0-17) will experience at least as great a reduction in PM2.5 and ozone exposures as adults (ages 18-64) in 2028, 2030, 2035 and 2040 under all regulatory alternatives of these rulemakings.
Executive Order 13211: Actions Concerning Regulations that Significantly Affect Energy Supply, Distribution, or Use
These actions, which are significant regulatory actions under Executive Order 12866, are likely to have a significant adverse effect on the supply, distribution or use of energy. The EPA has prepared a Statement of Energy Effects for these action as follows. The EPA estimates a 0.2 percent increase in retail electricity prices on average, across the contiguous U.S. in 2035, and a 28 percent reduction in coal-fired electricity generation in 2035 as a result of these actions. The EPA projects that utility power sector delivered natural gas prices will decrease 2.4 percent in 2035. For more information on the estimated energy effects, please refer to the economic impact analysis for this action. The analysis is available in the RIA, which is in the public docket.
National Technology Transfer and Advancement Act (NTTAA) and 1 CFR Part 51
 These proposed actions involve technical standards. Therefore, the EPA conducted searches for the New Source Performance Standards for Greenhouse Gas Emissions from New, Modified, and Reconstructed Fossil Fuel-Fired Electric Generating Units; Emission Guidelines for Greenhouse Gas Emissions from Existing Fossil Fuel-Fired Electric Generating Units; and Repeal of the Affordable Clean Energy Rule through the Enhanced National Standards Systems Network (NSSN) Database managed by the American National Standards Institute (ANSI). Searches were conducted for EPA Methods [placeholder]. No applicable voluntary consensus standards were identified for EPA Methods [placeholder]. All potential standards were reviewed to determine the practicality of the voluntary consensus standards (VCS) for these rules. [placeholder] VCS were identified as an acceptable alternative to EPA test methods for the purpose of these proposed rules. The search identified [placeholder] VCS that were potentially applicable for these proposed rules in lieu of EPA reference methods. However, these have been determined to not be practical due to lack of equivalency, documentation, validation of data and other important technical and policy considerations. For additional information, please see the March [placeholder], 2023, memorandum titled, Voluntary Consensus Standard Results for 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. In this document, the EPA is proposing to include in final rule regulatory text for 40 CFR part 60, subpart TTTT, TTTTa, and UUUUb that includes incorporation by reference. In accordance with requirements of 1 CFR part 51, the EPA is proposing to incorporate the following [placeholder] standards by reference.
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The EPA welcomes comments on this aspect of the proposed rulemakings and, specifically, invites the public to identify potentially applicable VCS and to explain why such standards should be used in these regulations.
Executive Order 12898: Federal Actions to Address Environmental Justice in Minority Populations and Low-Income Populations
Executive Order 12898 (59 FR 7629; February 16, 1994) directs federal agencies, to the greatest extent practicable and permitted by law, to make environmental justice part of their mission by identifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects of their programs, policies, and activities on minority populations (people of color and/or Indigenous peoples) and low-income populations.
For new sources constructed after the date of publication of this proposed action under CAA section 111(b), the EPA believes that it is not practicable to assess whether the human health or environmental conditions that exist prior to this action result in disproportionate and adverse effects on people of color, low-income populations and/or Indigenous peoples, because the location and number of new sources is unknown. 
For existing sources of this proposed action under CAA section 111(d), the EPA believes that the human health or environmental conditions that exist prior to this action result in or have the potential to result in disproportionate and adverse human health or environmental effects on people of color, low-income populations, and/or Indigenous peoples. The EPA believes that this proposed action is not likely to change disproportionate and adverse PM2.5 exposure impacts on people of color, low-income populations, Indigenous peoples, and/or other potential populations of concern evaluated in the future analytical years. The EPA also believes that this proposed action is not likely to change disproportionate and adverse ozone exposure impacts on people of color, low-income populations, Indigenous peoples, and/or other potential populations of concern evaluated in 2028, 2035, and 2040. However, in the analytical year of 2030, this action is likely to slightly increase existing national level disproportionate and adverse ozone exposure impacts on Asian populations, Hispanic populations, and those linguistically isolated. 
The EPA believes that it is not practicable to assess whether the GHG impacts associated with this action are likely to result in a change in disproportionate and adverse effects on people of color, low-income populations and/or Indigenous peoples. However, the EPA believes that the projected total cumulative power sector reduction of 617 million metric tonnes of CO2 emissions between 2028 and 2042 will have a beneficial effect on populations at risk of climate change effects/impacts. Research indicates that some communities of color, specifically populations defined jointly by ethnic/racial characteristics and geographic location, may be uniquely vulnerable to climate change health impacts in the U.S. See sections VII, X, and XIV of this preamble for further information regarding GHG controls and emission reductions. 

Michael S. Regan,
Administrator.