The EPA Administrator, Michael S. Regan, signed the following notice on 5/8/2023, and EPA is submitting it for
publication in the Federal Register (FR). While we have taken steps to ensure the accuracy of this Internet versionof the rule, it is not the official version of the rule for purposes of compliance. Please refer to the official version in
a forthcoming FR publication, which will appear on the Government Printing Office's govinfo website(https://www.govinfo.gov/app/collection/fr) and on Regulations.gov (https://www.regulations.gov) in Docket No.
EPA-HQ-OAR-2023-0072. Once the official version of this document is published in the FR, this version will be
removed from the Internet and replaced with a link to the official version.

6560-50-P
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 60[EPA-HQ-OAR-2023-0072; FRL-8536-02-OAR]
RIN 2060-AV09
New Source Performance Standards for Greenhouse Gas Emissions from New, Modified,and Reconstructed Fossil Fuel-Fired Electric Generating Units; Emission Guidelines forGreenhouse Gas Emissions from Existing Fossil Fuel-Fired Electric Generating Units; andRepeal of the Affordable Clean Energy Rule
AGENCY: Environmental Protection Agency (EPA)
ACTION: Proposed rule.
SUMMARY: In this notice, the Environmental Protection Agency (EPA) is proposing five
separate actions under section 111 of the Clean Air Act (CAA) addressing greenhouse gas(GHG) emissions from fossil fuel-fired electric generating units (EGUs). The EPA is proposing
revised new source performance standards (NSPS), first for GHG emissions from new fossil
fuel-fired stationary combustion turbine EGUs and second for GHG emissions from fossil fuelfired steam generating units that undertake a large modification, based upon the 8-year review
required by the CAA. Third, the EPA is proposing emission guidelines for GHG emissions fromexisting fossil fuel-fired steam generating EGUs, which include both coal-fired and oil/gas-fired
steam generating EGUs. Fourth, the EPA is proposing emission guidelines for GHG emissions
from the largest, most frequently operated existing stationary combustion turbines and issoliciting comment on approaches for emission guidelines for GHG emissions for the remainder

of the existing combustion turbine category. Finally, the EPA is proposing to repeal theAffordable Clean Energy (ACE) Rule.
DATES: Comments. Comments must be received on or before [INSERT DATE 60 DAYSAFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]. Comments on theinformation 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 21
DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER] and [INSERTDATE 22 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-20230072, 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. EPAHQ-OAR-2023-0072, Mail Code 28221T, 1200 Pennsylvania Avenue, NW, Washington,
DC 20460.

2This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

•Hand/Courier Delivery: EPA Docket Center, WJC West Building, Room 3334, 1301
Constitution Avenue, NW, Washington, DC 20004. The Docket Center’s hours ofoperation 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 thisrulemaking. Comments received may be posted without change to https://www.regulations.gov,
including any personal information provided. For detailed instructions on sending comments andadditional information on the rulemaking process, see the SUPPLEMENTARYINFORMATION section of this document.
FOR FURTHER INFORMATION CONTACT: For questions about these proposed
actions, contact Mr. Christian Fellner, Sector Policies and Programs Division (D243-02), Officeof 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 or Ms. Lisa Thompson, Sector Policies and Programs Division (D24302), 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 21 DAYS AFTER DATE OF PUBLICATION IN THE
FEDERAL REGISTER] and [INSERT DATE 22 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 ofregistrations for the public hearing, the EPA may continue the public hearing on [INSERT3This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

DATE 23 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 speakerhas testified if there are no additional speakers. The EPA will announce further details at
https://www.epa.gov/stationary-sources-air-pollution/greenhouse-gas-standards-and-guidelinesfossil-fuel-fired-power.
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 theonline registration form available at https://www.epa.gov/stationary-sources-airpollution/greenhouse-gas-standards-and-guidelines-fossil-fuel-fired-power 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 14 DAYS AFTER DATE OF
PUBLICATION IN THE FEDERAL REGISTER]. Prior to the hearing, the EPA will post ageneral agenda that will list pre-registered speakers in approximate order at:
https://www.epa.gov/stationary-sources-air-pollution/greenhouse-gas-standards-and-guidelinesfossil-fuel-fired-power.
The EPA will make every effort to follow the schedule as closely as possible on the dayof the hearing; however, please plan for the hearings to run either ahead of schedule or behindschedule.
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 ofyour oral testimony as written comments to the rulemaking docket.

4This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

The EPA may ask clarifying questions during the oral presentations but will not respondto 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 athttps://www.epa.gov/stationary-sources-air-pollution/greenhouse-gas-standards-and-guidelinesfossil-fuel-fired-power. While the EPA expects the hearing to go forward as described in thissection, please monitor our website or contact the public hearing team at (888) 372-8699 or byemail at SPPDpublichearing@epa.gov to determine if there are any updates. The EPA does notintend 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 yourneeds by [INSERT DATE 7 DAYS AFTER DATE OF PUBLICATION IN THE FEDERALREGISTER]. 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.
5This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 BusinessInformation (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 madeavailable 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 technicaldifficulties and cannot contact you for clarification, the EPA may not be able to consider yourcomment. Electronic files should not include special characters or any form of encryption andshould be free of any defects or viruses.

6
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Submitting CBI. Do not submit information containing CBI to the EPA throughhttps://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 thedigital 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 ofthe 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 forthin 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 OAQPSCBI 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 filesharing 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-20237
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

0072. The mailed CBI material should be double wrapped and clearly marked. Any CBImarkings 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 thispreamble. While this list may not be exhaustive, to ease the reading of this preamble and forreference purposes, the EPA defines the following terms and acronyms here:
ACE
BACT
BSER
Btu
CAA
CBI
CCS
CCUS
CFR
CHP
CO2
CO2e
CPP
CSAPR
DOE
DOI
DOT
EGU
EIA
EJ
EO
EOR
EPA
FEED
FGD
FR
FrEDI
GHG
GHGRP
GW
HHV
HRSG
IBR

Affordable Clean Energy rule
best available control technology
best system of emissions reduction
British thermal unit
Clean Air Act
Confidential Business Information
carbon capture and sequestration/storage
carbon capture, utilization, and sequestration/storage
Code of Federal Regulations
combined heat and powercarbon dioxidecarbon dioxide equivalent
Clean Power Plan
Cross-State Air Pollution Rule
Department of Energy
Department of the Interior
Department of Transportationelectric generating unit
Energy Information Administration
environmental justice
Executive Orderenhanced oil recovery
Environmental Protection Agency
front-end engineering and design
flue gas desulfurization
Federal Register
Framework for Evaluating Damages and Impacts
greenhouse gas
Greenhouse Gas Reporting Program
gigawatt
higher heating value
heat recovery steam generator
incorporate by reference
8This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

ICR
IGCC
IIJA
IPCC
IRC
IRP
kg
kWh
LCOE
LHV
LNG
MMBtu/hrMMst
MMT CO2e
MW
MWh
NAAQS
NAICS
NCA4
NETL
NGCC
NOx
NREL
NSPS
NSR
OMB
PM
PSD
PUC
RIA
RPS
RTO
SCR
SIP
U.S.
U.S.C.

information collection request
integrated gasification combined cycle
Infrastructure Investment and Jobs Act
Intergovernmental Panel on Climate ChangeInternal Revenue Codeintegrated resource plankilogramkilowatt-hourlevelized cost of electricity
lower heating valueliquefied natural gas
million British thermal units per hour
million short tons
million metric tons of carbon dioxide equivalent
megawatt
megawatt-hourNational Ambient Air Quality Standards
North American Industry Classification System
2017–2018 Fourth National Climate Assessment
National Energy Technology Laboratory
natural gas combined cycle
nitrogen oxides
National Renewable Energy Laboratory
new source performance standards
New Source Review
Office of Management and Budget
particulate matter
Prevention of Significant Deterioration
public utilities commission
regulatory impact analysis
renewable portfolio standard
Regional Transmission Organization
selective catalytic reduction
State Implementation Plan
United States
United States CodeOrganization of this document. The information in this preamble is organized as follows:
I. Executive Summary
A. Climate Change and the Power Sector
B. Overview of the Proposals
C. Recent Developments in Emissions Controls and the Electric Power Sector
D. How the EPA Considered Environmental Justice in the Development of These Proposals
II. General Information
9
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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. Recent Developments in Emissions Controls and the Electric Power Sector
A. Introduction
B. Background
C. CCS
D. Natural Gas Co-firing
E. Hydrogen Co-firing
F. Recent Changes in the Power Sector
G. GHG Emissions from Fossil Fuel-fired EGUs
H. The Legislative, Market, and State Law Context
I. 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. Mechanisms To Ensure Use of Actual Low-GHG Hydrogen
M. Recordkeeping and Reporting Requirements
N. Additional Solicitations of Comment and Proposed Requirements
O. Compliance Dates
VIII. Requirements for New, Modified, and Reconstructed Fossil Fuel-fired Steam Generating
Units
A. 2018 NSPS Proposal
B. Eight-year Review of NSPS for Fossil Fuel-fired Steam Generating Units
C. Projects Under Development
IX. Proposed ACE Rule Repeal
A. Summary of Selected Features of the ACE Rule10
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

B. Developments Undermining ACE Rule’s Projected Emission Reductions
C. Developments Showing that Other Technologies are the BSER for this Source Category
D. Insufficiently Precise Degree of Emission Limitation Achievable from Application of the
BSER
E. ACE Rule’s Preclusion of Emissions Trading or Averaging
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
F. Summary
XI. Proposed Regulatory Approach for Emission Guidelines for Existing Fossil Fuel-fired
Stationary Combustion Turbines
A. Overview
B. The Existing Stationary Combustion Turbine Fleet
C. BSER for Base Load Turbines Over 300 MW
D. Areas that the EPA is Seeking Comment on Related to Existing Combustion Turbines
E. BSER for Remaining Combustion Turbines
XII. 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
XIII. Implications for Other EPA Programs
A. Implications for New Source Review (NSR) Program
B. Implications for Title V Program
XIV. Impacts of Proposed Actions
A. Air Quality Impacts
B. Compliance Cost Impacts
C. Economic and Energy Impacts
D. Benefits
E. Environmental Justice Analytical Considerations and Stakeholder Outreach and Engagement
F. Grid Reliability Considerations
XV. 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
11This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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
I. Executive Summary
In 2009, the EPA concluded that GHG emissions endanger our nation’s public health andwelfare. 1 Since that time, the evidence of the harms posed by GHG emissions has only grown
and Americans experience the destructive and worsening effects of climate change every day.
Fossil fuel-fired EGUs are the nation’s largest stationary source of GHG emissions, representing
25 percent of the United States’ total GHG emissions in 2020. At the same time, a range of costeffective technologies and approaches to reduce GHG emissions from these sources are available
to the power sector, and multiple projects are in various stages of operation and development—
including carbon capture and sequestration/storage (CCS) and co-firing with lower-GHG
fuels. Congress has also acted to provide funding and other incentives to encourage thedeployment of these technologies to achieve reductions in GHG emissions from the power
sector.
In this notice, the EPA is proposing several actions under section 111 of the Clean Air
Act (CAA) to reduce the significant quantity of GHG emissions from new and existing fossil
fuel-fired EGUs by establishing new source performance standards (NSPS) and emission
guidelines that are based on available and cost-effective technologies that directly reduce GHG
emissions from these sources. Consistent with the statutory command of section 111, the1

74 FR 66496 (December 15, 2009).

12

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

proposed NSPS and emission guidelines reflect the application of the best system of emission
reduction (BSER) that, taking into account costs, energy requirements, and other statutory
factors, is adequately demonstrated.
Specifically, the EPA is proposing to update and establish more protective NSPS for
GHG emissions from new and reconstructed fossil fuel-fired stationary combustion turbine
EGUs that are based on highly efficient generating practices, hydrogen co-firing, and CCS. The
EPA is also proposing to establish new emission guidelines for existing fossil fuel-fired steam
generating EGUs that reflect the application of CCS and the availability of natural gas co-firing.
The EPA is simultaneously proposing to repeal the Affordable Clean Energy (ACE) rule because
the emission guidelines established in ACE do not reflect the BSER for steam generating EGUs
and are inconsistent with section 111 of the CAA in other respects. To address GHG emissions
from existing fossil fuel-fired stationary combustion turbines, the EPA is proposing emission
guidelines for large and frequently used existing stationary combustion turbines. Further, the
EPA is soliciting comment on how the Agency should approach its legal obligation to establish
emission guidelines for the remaining existing fossil fuel-fired combustion turbines not coveredby this proposal, including smaller frequently used, and less frequently used, combustion
turbines.
Each of the NSPS and emission guidelines proposed here would ensure that EGUs reduce
their GHG emissions in a manner that is cost-effective and improves the emissions performanceof the sources, consistent with the applicable CAA requirements and caselaw. These proposed
standards and emission guidelines, if finalized, would significantly decrease GHG emissions
from fossil fuel-fired EGUs and the associated harms to human health and welfare. Further, the13This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 affordable electricity.
A. 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 frequentand 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 ofclimate 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. 2 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 lowGHG fuels and CCS) that can allow steam generating EGUs and stationary combustion turbines(the focus of these proposals) to provide power while emitting significantly lower GHG
emissions. Moreover, with the increased electrification of other GHG-emitting sectors of theeconomy, such as personal vehicles, heavy-duty trucks, and the heating and cooling of buildings,

2

https://www.epa.gov/ghgemissions/sources-greenhouse-gas-emissions.
14

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

a power sector with lower GHG emissions can also help reduce pollution coming from othersectors of the economy.
B. Overview of the Proposals
As noted above, 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 repeal of the ACE Rule, proposed BSER
determinations and emission guidelines for existing fossil fuel-fired steam generating units,
proposed BSER determinations and emission guidelines for large, frequently used existing fossil
fuel-fired stationary combustion turbines, and solicitation for comment on potential BSER
options and emission guidelines for existing fossil fuel-fired stationary combustion turbines nototherwise covered by the proposal.
The EPA is taking these actions consistent with the process that CAA section 111
establishes. Under CAA section 111, once the EPA has identified a source category that emits
dangerous air pollutants, it proceeds to regulate new sources and, for GHGs and certain other air
pollutants, existing sources. The central requirement is that the EPA must determine the “bestsystem of emission reduction … adequately demonstrated,” taking into account the cost of the
reductions, non-air quality health and environmental impacts, and energy requirements. CAA
section 111(a)(1). The EPA may determine that different sets of sources have different
characteristics relevant for determining the BSER and may subcategorize sources accordingly.
Once it determines the BSER, the EPA must determine the “degree of emission
limitation” achievable by application of the BSER. For new sources, the EPA determines thestandard of performance with which the sources must comply, which is a standard for emissions
that reflects the degree of emission limitation. For existing sources, the EPA includes the15This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

information it has developed concerning the BSER and associated degree of emission limitation
into emission guidelines and directs the states to adopt state plans that contain standards ofperformance that are consistent with the emission guidelines.
Since the early 1970s, the EPA has promulgated regulations under section 111 for morethan 60 source categories, which has established a robust regulatory history. During this period,
the courts, primarily the U.S. Court of Appeals for the D.C. Circuit and the Supreme Court, havedeveloped a body of caselaw interpreting section 111. As the Supreme Court has recognized, inthese CAA section 111 actions, the EPA has determined the BSER to be “measures that improve
the pollution performance of individual sources,” including add-on controls and clean fuels. West
Virginia v. EPA, 142 S. Ct. 2587, 2614 (2022). For present purposes, several of a BSER’s key
features include that costs of controls must be reasonable, that the EPA may determine a control
to be “adequately demonstrated” even if it is new and not yet in widespread commercial use, and,further, that the EPA may reasonably project the development of a control system at a future
time and establish requirements that take effect at that time. The actions that the EPA is
proposing are consistent with the requirements of CAA section 111 and its regulatory history andcaselaw.
1. New and Reconstructed Fossil Fuel-Fired Combustion Turbines
For new and reconstructed fossil fuel-fired combustion turbines, the EPA is proposing tocreate 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 lessthan 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
16This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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; however, the EPA is now proposing to subdivide the nonbase load subcategory into a low load subcategory and a separate intermediate load subcategory.
This revised approach to subcategories is consistent with the fact that utilities and power plant
operators are building new combustion turbines with plans to operate them at varying levels of
capacity, in coordination with existing and expected energy sources. These patterns of operation
are important for the type of controls that the EPA is proposing as the BSER for these turbines,
in terms of the feasibility of, emissions reductions that would be achieved by, and costreasonableness of, those controls.
For the low load subcategory, the EPA is proposing that the BSER is the use of lower
emitting fuels (e.g., natural gas and distillate oil) with standards of performance ranging from120 lb CO2/MMBtu to 160 lb CO2/MMBtu, depending on the type of fuel combusted. 3 For theintermediate load and base load subcategories, the EPA is proposing an approach in which the
BSER has multiple components: (1) Highly efficient generation; and (2) depending on thesubcategory, use of CCS or co-firing low-GHG hydrogen.
These components of the BSER for the intermediate and base load subcategories form thebasis of a standard of performance that applies in multiple phases. That is, affected facilities—
which are facilities that commence construction or reconstruction after the date of publication in3

In the 2015 NSPS, the EPA referred to clean fuels as fuels with a consistent chemicalcomposition (i.e., uniform fuels) that result in a consistent emission rate of 69 kilograms per
gigajoule (kg/GJ) (160 lb CO2/MMBtu). Fuels in this category include natural gas and distillateoil. In this rulemaking, the EPA refers to these fuels as both lower emitting fuels or uniform
fuels.
17
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

the Federal Register of this proposed rulemaking—must meet the first phase of the standard of
performance, which is based exclusively on application of the first component of the BSER
(highly efficient generation), by the date the rule is promulgated. Affected sources in theintermediate load and base load subcategories must also meet the second and in some cases thirdand more stringent phases of the standard of performance, which are based on the continued
application of the first component of the BSER and the application of the second and in somecases third component of the BSER. For base load units, the EPA is proposing two pathways as
potential BSER—(1) the use of CCS to achieve a 90 percent capture of GHG emissions by 2035and (2) the co-firing of 30 percent (by volume) low-GHG hydrogen by 2032, and ramping up to
96 percent by volume low-GHG hydrogen by 2038. These two BSER pathways both offer
significant opportunities to reduce GHG emissions but, may be available on slightly different
timescales. Depending upon the phase in periods for both CCS and hydrogen, the CCS pathway
could provide greater cumulative emission reductions than the low GHG hydrogen pathway. The
EPA seeks comment specifically upon the percentages of hydrogen co-firing and CO2 capture aswell as the dates that meet the statutory BSER criteria for each pathway. The EPA solicits
comment on the differences in emissions reductions in both scale and time that would result fromthe two standards and BSER pathways, including how to calculate the different amounts ofemission reductions, how to compare them, and what conclusions to draw from thosedifferences. The EPA also seeks comment on whether the Agency should finalize both pathways
as separate subcategories with separate standards of performance, or whether it should finalize
one pathway with the option of meeting the standard of performance using either system of
emission reduction, e.g., a single standard based on application of CCS with 90 percent capture,
which could also be met by co-firing 96 percent (by volume) low-GHG hydrogen.
18
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

It should be noted that utilization of highly efficient generation is a logical complement toboth 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. Thisapproach 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. However, in proposing that compliance begins in2032 (for co-firing with low-GHG hydrogen) and 2035 (for use of CCS), the EPA recognizes
that building the infrastructure required to support wider 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 combustion 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/hor more. For smaller base load combustion turbines (with a base load rating of less than 2,000
MMBtu/h), the proposed associated standard would range from 770 to 900 lb CO2/MWh-grossdepending on the specific base load rating of the combustion turbine. These standards would
apply immediately upon the effective date of the final rule.

19
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

With respect to the second phase of the standards of performance, for the intermediateload subcategory, the EPA is proposing that the BSER includes co-firing 30 percent by volume
low-GHG hydrogen (unless otherwise noted, all co-firing hydrogen percentages are on a volume
basis) with an associated standard of 1,000 lb CO2/MWh-gross, compliance with which would be
required starting in 2032. For the base load subcategory, to elicit comment on both pathways, the
EPA is proposing to subcategorize further into base load units that are adopting the CCS
pathway and base load units that are adopting the low-GHG hydrogen co-firing pathway. For thesubcategory of base load units that are adopting the CCS pathway, 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-gross, compliance with which would be required starting in 2035. For thesubcategory of base load units that are adopting the low-GHG hydrogen co-firing pathway, the
EPA is proposing that the BSER includes co-firing 30 percent (by volume) low-GHG hydrogenwith an associated standard of 680 lb CO2/MWh-gross, compliance with which would be
required starting in 2032, and co-firing 96 percent (by volume) low-GHG hydrogen by 2038,
which corresponds to a standard of performance of 90 lb CO2/MWh-gross. In both cases, thesecond (and sometimes third) phase standard of performance would be applicable to all
combustion turbines that were subject to the first phase standards of performance.
2. Existing and Modified Fossil Fuel-Fired Steam Generating Units and ACE Repeal
With respect to existing coal-fired steam generating units, the EPA is proposing to repeal
and replace the existing ACE Rule emission guidelines. The EPA recognizes that, since it
promulgated the ACE Rule, the costs of CCS have decreased due to technology advancements aswell as new policies including the expansion of the Internal Revenue Code section 45Q tax credit
for CCS in the Inflation Reduction Act (IRA); and the costs of natural gas co-firing have
20
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

decreased as well, due in large part to a decrease in the difference between coal and natural gas
prices. As a result, the EPA considered both CCS and natural gas co-firing as candidates for
BSER for existing coal-fired steam EGUs.
Based on the latest information available to the Agency on cost, emission reductions, andother statutory criteria, the EPA is proposing that the BSER for existing coal-fired steam EGUs
that expect to operate in the long-term is CCS with 90 percent capture of CO2. The EPA has
determined that CCS satisfies the BSER criteria for these sources because it is adequately
demonstrated, achieves significant reductions in GHG emissions, and is highly cost-effective.
Although the EPA considers CCS to be a broadly applicable BSER, the Agency also
recognizes that CCS will be most cost-effective for existing steam EGUs that are in a position torecover the capital costs associated with CCS over a sufficiently long period of time. During theearly engagement process (see Docket ID No. EPA-HQ-OAR-2022-0723-0024), industry
stakeholders requested that the EPA “[p]rovide approaches that allow for the retirement of units
as opposed to investments in new control technologies, which could prolong the lives of higheremitting EGUs; this will achieve maximum and durable environmental benefits.” Industry
stakeholders also suggested that the EPA recognize that some units may remain operational for aseveral-year period but will do so at limited capacity (in part to assure reliability), and thenvoluntarily cease operations entirely (see Docket ID No. EPA-HQ-OAR-2022-0723-0029).
In response to this industry stakeholder input and recognizing that the cost effectivenessof controls depends on the unit’s expected operating time horizon, which dictates theamortization period for the capital costs of the controls, the EPA believes it is appropriate toestablish subcategories of existing steam EGUs that are based on the operating horizon of theunits. The EPA is proposing that for units that expect to operate in the long-term (i.e., those that
21This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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). As explained in detail in this proposal, CCS with 90 percent
capture of CO2 is adequately demonstrated, cost reasonable, and achieves substantial emissions
reductions from these units.
The EPA is proposing to define coal-fired steam generating units with medium-term
operating horizons as those that (1) Operate after December 31, 2031, (2) have elected to commit
to permanently cease operations before January 1, 2040, (3) elect to make that commitment
federally enforceable and continuing by including it in the state plan, and (4) do not meet thedefinition of near-term operating horizon units. For these medium-term operating horizon units,
the EPA is proposing that the BSER is co-firing 40 percent natural gas on a heat input basis withan associated degree of emission limitation of a 16 percent reduction in emission rate (lbCO2/MWh-gross basis). While this subcategory is based on a 10-year operating horizon (i.e.,
January 1, 2040), the EPA is specifically soliciting comment on the potential for a different
operating horizon between 8 and 10 years to define the threshold date between the definition of
medium-term and long-term coal-fired steam generating units (i.e., January 1, 2038 to January 1,2040), given that the costs for CCS may be reasonable for units with amortization periods asshort as 8 years. For units with operating horizons that are imminent-term, i.e., those that (1)Have elected to commit to permanently cease operations before January 1, 2032, and (2) elect tomake that commitment federally enforceable and continuing by including it in the state plan, the
EPA is proposing that the BSER is routine methods of operation and maintenance with anassociated degree of emission limitation of no increase in emission rate (lb CO2/MWh-grossbasis). The EPA is proposing the same BSER determination for units in the near-term operating
22
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

horizon subcategory, i.e., units that (1) Have elected to commit to permanently cease operations
by December 31, 2034, as well as to adopt an annual capacity factor limit of 20 percent, and (2)elect to make both of these conditions federally enforceable by including them in the state plan.
The EPA is also soliciting comment on a potential BSER based on low levels of natural gas cofiring for units in these last two subcategories.
The EPA is not proposing to revise the NSPS for newly constructed or reconstructedfossil fuel-fired steam generating units, which it promulgated in 2015 (80 FR 64510; October 23,2015). This is because the EPA does not anticipate that any such units will construct orreconstruct and is unaware of plans by any companies to construct or reconstruct a new coalfired EGU. The EPA is proposing to revise the standards of performance that it promulgated in
the same 2015 action for coal-fired steam generators that undertake a large modification (i.e., amodification that increases its hourly emission rate by more than 10 percent) to mirror theemissions guidelines, discussed below, for existing coal-fired steam generators. This will ensurethat all existing fossil fuel-fired steam generating sources are subject to the emission controls
whether they modify or not.
The EPA is also proposing emission guidelines for existing natural gas-fired and oil-fired
steam generating units. Recognizing that virtually all of these units have limited operation, the
EPA is, in general, proposing that the BSER is routine methods of operation and maintenancewith an associated degree of emission limitation of no increase in emission rate (lb CO2/MWhgross).
3. Existing Fossil Fuel-Fired Stationary Combustion Turbines
The EPA is also proposing emission guidelines for large (i.e., greater than 300 MW),frequently operated (i.e., with a capacity factor of greater than 50 percent), existing fossil fuel23
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

fired stationary combustion turbines. Because these existing combustion turbines are similar to
new stationary combustion turbines, the EPA is proposing a BSER that is similar to the BSER
for new base load combustion turbines. The EPA is not proposing a first phase efficiency-based
standard of performance; but the EPA is proposing that BSER for these units is based on either
the use of CCS by 2035 or co-firing of 30 percent (by volume) low-GHG hydrogen by 2032 andco-firing 96 percent low-GHG hydrogen by 2038.
For the emission guidelines for existing fossil fuel-fired steam generating units and large,
frequently operated fossil fuel-fired combustion turbines, the EPA is also proposing state planrequirements, 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, the EPA is proposing to allow states to include trading or
averaging in state plans so long as they demonstrate equivalent emissions reductions, and this
proposal discusses considerations related to the appropriateness of including such compliance
flexibilities.
Finally, the EPA is soliciting comment on a number of variations to the subcategories and
BSER determinations, as well as the associated degrees of emission limitation and standards ofperformance, summarized above. The EPA is soliciting comment on the capacity and capacity
factor threshold for inclusion in the subcategory of large, frequently operated turbines (e.g.,
capacities between 100 MW and 300 MW for the capacity threshold and a lower capacity factor
threshold (e.g., 40 percent). The EPA is also soliciting comment on BSER options and associateddegrees of emission limitation for existing fossil fuel-fired stationary combustion turbines for
24This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

which no BSER is being proposed (i.e., fossil fuel-fired stationary combustion turbines that are
not large, frequently operated turbines).
C. Recent Developments in Emissions Controls and the Electric Power Sector
Several recent developments concerning emissions controls and the state of the electric
power sector are relevant for the EPA’s determination of the BSER for existing coal-fired steam
generating EGUs and natural gas-fired combustion turbines. These include developments thathave led to significant reductions in the cost of CCS; expected increases in the availability andexpected reductions in the cost of low-GHG hydrogen; and announced and planned retirementsof coal-fired power plants.
In recent years, the cost of CCS has declined in part because of process improvements
learned from earlier deployments of CCS and other advances. In addition, the IRA, enacted in
2022, extended and significantly increased the tax credit for CCS under Internal Revenue Code(IRC) section 45Q. As explained in detail in the BSER discussions later in this preamble, thesechanges support the EPA’s proposed conclusion that CCS is the BSER for a number ofsubcategories in these proposals.
In addition, in both the Infrastructure Investment and Jobs Act (IIJA), enacted in 2021,
and the IRA, Congress provided extensive support for the development of hydrogen produced
through low-GHG methods. This support includes investment in infrastructure through the IIJA
and the provision of tax credits in the IRA to incentivize the manufacture of hydrogen throughlow GHG-emitting methods. These changes also support the EPA’s proposal that co-firing lowGHG hydrogen is BSER for certain subcategories of stationary combustion turbines.
The IIJA and IRA have also been part of the reason why many utilities and power
generating companies have recently announced plans to change the mix of their generating
25
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

assets. State legislation, technology advancements, market forces, consumer demand, and thefact that the existing fossil fuel-fired fleet is aging are also leading to, in most cases, decreased
use of the 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 toapproximately 60 percent, with coal generation dropping from 46 percent to 23 percent of net
generation during the period.
Many utilities and power generating companies have announced GHG reduction
commitments as they further analyze and consider the incentives of the IRA. These utilities andcompanies have also announced their intention to permanently cease operating many of theirremaining coal-fired EGUs. Some companies are planning to install combustion turbines withadvanced technologies to limit GHG emissions, including CCS and hydrogen co-firing 4 (withsome companies having announced plans to ultimately move to 100 percent hydrogen firing) andadvanced energy storage technologies. As more renewables come online and as thesetechnologies become more widely deployed, the utilization of natural gas-fired combustion
turbine EGUs will be impacted. The EPA’s post-IRA 2022 reference case modeling projects
lower utilization relative to current levels of stationary combustion turbines.
The power sector has also been influenced by the actions of state governments to reduce
GHG emissions. More than two-thirds of states have enacted policies to require utilities toincrease the amount of electricity generated from sources that emit no GHGs. Other states haverecently enacted significant legislation requiring the decarbonization of their utility fleets, using

4

See section VII.F.3.b of this preamble for discussion of CCS demonstrations and section
VII.F.3.c for discussion of hydrogen co-firing demonstrations. Also see the GHG Mitigation
Measures for Steam Generating Units TSD included in the rulemaking docket for this proposal.
26This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

devices such as carbon markets, low-GHG emission standards, carbon capture and storage
mandates, utility planning, or mandatory retirement schedules.
Additionally, Congress has recently enacted investments in GHG reductions. As noted
earlier, Congress enacted IRC section 45Q by section 115 of the Energy Improvement andExtension Act of 2008, to provide a credit for the sequestration of CO2; IRC section 45Q was
amended significantly by the Bipartisan Budget Act of 2018 and most recently by the IRA. The
IIJA provided more than $65 billion for infrastructure investments and upgrades for transmission
capacity, pipelines, and low-carbon fuels (including low-GHG hydrogen, as noted above). 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. 5
Finally, the EPA has carefully considered the importance of maintaining resource
adequacy and grid reliability in developing these proposals and is confident that these proposed
NSPS and emission guidelines—with the extensive lead time and compliance flexibilities they
provide—can be successfully implemented in a manner that preserves the ability of powercompanies and grid operators to maintain the reliability of the nation’s electric power system.
The EPA has evaluated the reliability implications of the proposal in the Resource Adequacy
Analysis TSD; conducted dispatch modeling of the proposed NSPS and proposed emission
guidelines in a manner that takes into account resource adequacy needs; and consulted with the
DOE and the Federal Energy Regulatory Commission (FERC) in the development of these5

https://www.congress.gov/bill/117th-congress/house-bill/4346.
27This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

proposals. Moreover, the EPA has included in these proposals the flexibility that powercompanies and grid operators need to plan for achieving feasible and necessary reductions of
GHGs from these sources consistent with the EPA’s statutory charge while ensuring gridreliability. Furthermore, the EPA is soliciting comment on localized impacts of these proposals
on resource adequacy and reliability, and on opportunities to enhance reliable integration of the
proposals into the power system.
D. How the EPA Considered Environmental Justice in the Development of These Proposals
Consistent with EO 12898, EO 13985 and the EPA’s commitment to upholding
environmental justice across its policies and programs, the EPA carefully considered the impactsof these proposals on communities with potential environmental justice concerns. As part of its
pre-proposal outreach to stakeholders, the EPA engaged on multiple occasions withenvironmental justice organizations and representatives of communities that are affected byvarious forms of pollution from the power sector. The EPA took this feedback and analysis into
account in its development of these proposals. The EPA’s consideration of environmental justicein these proposals is briefly summarized here and discussed in further detail in sections XIV.E
and XV.J of the preamble and section 6 of the RIA.
These proposals are focused on establishing NSPS and emission guidelines for GHGs,
and these proposed actions will, in conjunction with other policies such as the IRA, play asignificant role in reducing GHGs and move us a step closer to avoiding the worst impacts ofclimate change, which is already having a disproportionate impact on EJ communities. Beyond
the GHG reductions, the EPA also has conducted a thorough evaluation of the impacts that these
proposals would have on emissions of other health-harming air pollutants from EGUs, as well as
how these changes in emissions would affect air quality and public health, particularly for
28This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

historically overburdened populations including people of color, indigenous peoples, and people
with low incomes.
The EPA’s national-level analysis of emission reduction and public health impacts, which
is documented in sections 3 and 4 of the RIA and summarized in greater detail in section XIV.A
and XIV.D of this preamble, finds that these proposals would achieve nationwide reductions in
EGU emissions of multiple health-harming air pollutants including nitrogen oxides (NOx), sulfur
dioxide (SO2), and fine particulate matter (PM2.5). These reductions in health-harming pollution
would result in significant public health benefits including avoided premature deaths, reductions
in new asthma cases and incidences of asthma symptoms, reductions in hospital admissions andemergency department visits, and reductions in lost work and school days.
The EPA has also evaluated how the air quality impacts associated with these proposals
would be distributed, with particular focus on potentially vulnerable populations. As discussed in
section 6 of the RIA, these proposals are anticipated to lead to modest but widespread reductionsin ambient levels of PM2.5 for a large majority of the nation’s population, as well as reductions inambient PM2.5 exposures that are similar in magnitude across all racial, ethnic, income andlinguistic groups. Similarly, the EPA found that the proposed standards are anticipated to lead tomodest but widespread reductions in ambient levels of ground-level ozone for the majority of thenation’s population, and that in all but one of the years evaluated the proposed standards would
lead to reductions in ambient ozone exposures across all demographic groups. Although these
reductions in PM2.5 and ozone exposures are small relative to baseline levels, and althoughdisparities in PM2.5 and ozone exposure would continue to persist following these proposals, the
EPA’s analysis indicates that the air quality benefits of these proposals would be broadly
distributed.
29
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Where authorized under section 111 of the Clean Air Act, the EPA has also incorporated
provisions in these proposals to better address the needs and concerns of communities withenvironmental justice concerns. Specifically, the EPA’s proposed emission guidelines forexisting steam EGUs as well as existing fossil fuel-fired stationary combustion turbines would
require states to undertake meaningful engagement with affected stakeholders, including
communities that are most affected by and vulnerable to emissions from these EGUs. These
meaningful engagement requirements are intended to ensure that the perspectives, priorities, andconcerns of affected communities are included in the process of establishing and implementing
standards of performance for existing EGUs, including decisions about compliance strategies andcompliance flexibilities that may be included in a state plan.
In the Agency’s pre-proposal outreach, some environmental justice organizations andcommunity representatives raised strongly held concerns about the potential health,environmental, and safety impacts of CCS. The EPA believes that deployment of CCS can takeplace in a manner that is protective of public health, safety, and the environment, and should
include early and meaningful engagement with affected communities and the public. As stated in
the Council on Environmental Quality’s (CEQ) February 2022 Carbon Capture, Utilization, andSequestration Guidance, “the successful widespread deployment of responsible CCUS will
require strong and effective permitting, efficient regulatory regimes, meaningful public
engagement early in the review and deployment process, and measures to safeguard public healthand the environment.” See 87 FR 8808 (February 16, 2022).
The EPA gave close consideration to these concerns as it developed its proposed
determinations on the BSER for these proposed NSPS and emission guidelines, and addresses
certain of the substantive issues that were raised in pre-proposal discussions in sections
30
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

VII.F.3.b.iii(C) and X.D.1.a.iii of this preamble. As explained in these sections, the EPA is
proposing to determine that CCS is the BSER for certain subcategories of new and existing
EGUs based on its consideration of all of the statutory criteria for BSER, including emission
reductions, cost, energy requirements, and non-air health and environmental considerations. In
evaluating concerns raised by stakeholders in connection with CCS, the EPA is mindful thatfederal agencies have “taken actions in the past decade to develop a robust CCUS regulatory
framework to protect the environment and public health across multiple statutes.” 6This framework includes, among other things, the EPA regulation of geologic
sequestration wells under the Underground Injection Control (UIC) program of the Safe
Drinking Water Act; required reporting and public disclosure of geologic sequestration activity,
as well as implementation of rigorous monitoring, reporting, and verification of geologic
sequestration, under the EPA’s Greenhouse Gas Reporting Program; and safety regulations forCO2 pipelines administered by the Pipeline and Hazardous Materials and Safety Administration(PHMSA). With respect to air emissions, some CCS projects may also require pre-construction
permitting under the Clean Air Act’s New Source Review (NSR) program and the adoption of
additional emission limitations for non-GHG air pollutants based on applicable control
technology requirements. The EPA invites public comment and feedback from stakeholders on
all aspects of its proposed determination that CCS represents the BSER for certain new andexisting fossil fuel-fired EGUs, including its evaluation of the various regulatory frameworks
that apply to CCS.

6

Carbon Capture, Utilization, and Sequestration Guidance, 87 FR 8808, 8809 (February 16,2022), https://www.govinfo.gov/content/pkg/FR-2022-02-16/pdf/2022-03205.pdf.
31This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

CEQ’s guidance, and the EPA’s evaluation of BSER, recognizes that multiple federal
agencies have responsibility for regulating and permitting CCS projects, along with state andtribal governments. The EPA is committed to working with federal, state, and tribal partners toensure the responsible deployment of CCS, to protect communities from pollution, and to foster
meaningful engagement with communities. This can be facilitated through the existing detailed
regulatory framework for CCS projects and further supported through robust and meaningful
public engagement early in the project development process. Furthermore, the EPA is requesting
comment on what assistance states and pertinent stakeholders may need in conducting
meaningful engagement with affected communities to ensure that there are adequate
opportunities for public input on decisions to implement emissions control technology (including
but not limited to CCS or low-GHG hydrogen).
II. General Information
A. Action Applicability
The source category that is the subject of these actions is comprised of the fossil fuelfired 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 bedirectly applicable to affected facilities that began construction after January 8, 2014, andaffected 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 bedirectly applicable to affected facilities that begin construction or reconstruction after the date of
32
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 beapplicable 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 moredesignated 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 designatedpollutant and which would be subject to a standard of performance for that pollutant if theexisting facility were an affected facility.” See 40 CFR 60.21a(b). If a state fails to submit a planor 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 toa 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.

33
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

B. Where to Get a Copy of This Document and Other Related Information
In addition to being available in the docket, an electronic copy of this action is available
on the Internet at https://www.epa.gov/stationary-sources-air-pollution/greenhouse-gasstandards-and-guidelines-fossil-fuel-fired-power. 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 UUUUa 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/greenhouse-gas-standards-andguidelines-fossil-fuel-fired-power.
C. Organization and Approach for These Proposed Rules
This rulemaking includes several proposed actions: (1) The EPA’s proposed amendments
to the Standards of Performance for Greenhouse Gas Emissions From New, Modified, andReconstructed Stationary Sources: Electric Utility Generating Units (80 FR 64510; October 23,2015) (2015 NSPS) and (2) proposed requirements for GHG emissions from new andreconstructed fossil fuel-fired stationary combustion turbine EGUs. These actions also (3)propose to repeal the ACE Rule (84 FR 32523; July 8, 2019), (4) 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- and natural gas-fired steam
generating EGUs, and (5) propose new emission guidelines for states in developing plans to
reduce GHG emissions from existing fossil fuel-fired stationary combustion turbines. The EPA
34
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

proposes that each of these actions function independently and are therefore severable. The EPA
invites comment on the question of which portions of these proposed rules, if any, should beseverable.
Section III of this preamble provides updated information on the impacts of climatechange. In section IV, the EPA provides a summary of recent developments in emissions
controls and the electric power sector. Section V presents a summary of the statutory backgroundand regulatory history. In section VI, the EPA summarizes stakeholder outreach efforts. In
section VII, the EPA describes the proposed BSERs, standards of performance, and associatedrequirements for new and reconstructed fossil fuel-fired stationary combustion turbine EGUs. In
section VIII, the EPA presents proposed amendments to requirements for new, reconstructed,
and modified fossil fuel-fired steam generating units. In section IX, the EPA provides a summaryof 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 proposed emission guidelines forexisting fossil fuel-fired steam generating EGUs. In section XI, the EPA presents the proposed
BSERs, degree of emission limitation, and related requirements for the proposed emission
guidelines for existing natural gas-fired combustion turbines. Section XII presents therequirements for state plan development. In section XIII, the EPA describes the implications forthese proposals on 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.
III. Climate Change and Its Impacts
Elevated concentrations of GHGs are and have been warming the planet, leading tochanges 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
35This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

taking place in the atmosphere as a result of the well-documented buildup of GHGs due tohuman 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 relianceon fossil fuels, are causing serious and life-threatening environmental and health impacts.
Extensive additional information on climate change is available in the scientificassessments and the EPA documents that are briefly described in this section, as well as in thetechnical 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). 7 In the 2009 Endangerment Findings, the Administrator foundunder 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 andstrengthened the understanding and concerns regarding the climate risks considered in the
Finding. The 2009 Endangerment Findings, together with the extensive scientific and technicalevidence in the supporting record, documented that climate change caused by human emissionsof GHGs threatens the public health of the U.S. population. It explained that by raising averagetemperatures, climate change increases the likelihood of heat waves, which are associated withincreased 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 the7

In describing these 2009 Findings in these proposals, the EPA is neither reopening nor
revisiting them.
36

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 scientificand technical evidence in the supporting record, that climate change touches nearly every aspectof public welfare 8 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 incoastal areas and land loss due to inundation; increases in peak electricity demand and risks toelectricity infrastructure; predominantly negative consequences for biodiversity and theprovisioning of ecosystem goods and services; and the potential for significant agricultural
disruptions and crop failures (though offset to some extent by carbon fertilization). These

8

The CAA states in section 302(h) that “[a]ll language referring to effects on welfare includes,
but is not limited to, effects on soils, water, crops, vegetation, manmade materials, animals,
wildlife, weather, visibility, and climate, damage to and deterioration of property, and hazards totransportation, as well as effects on economic values and on personal comfort and well-being,whether caused by transformation, conversion, or combination with other air pollutants.” 42
U.S.C. 7602(h).
37This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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). 9 In the 2016 Endangerment Findings, the Administrator found that the body ofscientific 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 thatthe science assessments released between the 2009 and the 2016 Findings, “strengthen andfurther support the judgment that GHGs in the atmosphere may reasonably be anticipated toendanger 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 newrecords 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. 10 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 andwelfare both for current and future generations. These updated observations and projections

9

In describing these 2016 Findings in these proposals, the EPA is neither reopening nor
revisiting them.
10
See later in this section for specific examples. An additional resource for indicators can befound at https://www.epa.gov/climate-indicators.
38
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 11 and 2017–2018 Fourth National Climate Assessment (NCA4). 12 13

11USGCRP, 2016: The Impacts of Climate Change on Human Health in the United States: A
Scientific Assessment. Crimmins, A., J. Balbus, J.L. Gamble, C.B. Beard, J.E. Bell, D. Dodgen,
R.J. Eisen, N. Fann, M.D. Hawkins, S.C. Herring, L. Jantarasami, D.M. Mills, S. Saha, M.C.
Sarofim, J. Trtanj, and L. Ziska, Eds. U.S. Global Change Research Program, Washington, DC,
312 pp.
12
USGCRP, 2017: Climate Science Special Report: Fourth National Climate Assessment,
Volume I [Wuebbles, D.J., D.W. Fahey, K.A. Hibbard, D.J. Dokken, B.C. Stewart, and T.K.
Maycock (eds.)]. U.S. Global Change Research Program, Washington, DC, USA, 470 pp, doi:
10.7930/J0J964J6.
13USGCRP, 2018: Impacts, Risks, and Adaptation in the United States: Fourth National Climate
Assessment, Volume II [Reidmiller, D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M.
Lewis, T.K. Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research Program,
Washington, DC, USA, 1515 pp. doi: 10.7930/NCA4.2018.
39
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

•Intergovernmental Panel on Climate Change (IPCC) 2018 Global Warming of 1.5 °C, 14
2019 Climate Change and Land, 15 and the 2019 Ocean and Cryosphere in a Changing
Climate 16 assessments, as well as the 2021 IPCC Sixth Assessment Report (AR6). 17 18•

The National Academy of Sciences (NAS) 2016 Attribution of Extreme Weather Eventsin the Context of Climate Change, 19 2017 Valuing Climate Damages: Updating

14

IPCC, 2018: Global Warming of 1.5 °C. An IPCC Special Report on the impacts of global
warming of 1.5 °C above pre-industrial levels and related global greenhouse gas emission
pathways, in the context of strengthening the global response to the threat of climate change,sustainable development, and efforts to eradicate poverty [Masson-Delmotte, V., P. Zhai, H.-O.
Portner, D. Roberts, J. Skea, P.R. Shukla, A. Pirani, W. Moufouma-Okia, C. Pe´an, R. Pidcock,
S. Connors, J.B.R. Matthews, Y. Chen, X. Zhou, M.I. Gomis, E. Lonnoy, T. Maycock, M.
Tignor, and T. Waterfield (eds.)].
15
IPCC, 2019: Climate Change and Land: an IPCC special report on climate change,
desertification, land degradation, sustainable land management, food security, and greenhousegas fluxes in terrestrial ecosystems [P.R. Shukla, J. Skea, E. Calvo Buendia, V. MassonDelmotte, H.-O. Portner, D.C. Roberts, P. Zhai, R. Slade, S. Connors, R. van Diemen, M. Ferrat,
E. Haughey, S. Luz, S. Neogi, M. Pathak, J. Petzold, J. Portugal Pereira, P. Vyas, E. Huntley, K.
Kissick, M. Belkacemi, J. Malley (eds.)].
16
IPCC, 2019: IPCC Special Report on the Ocean and Cryosphere in a Changing Climate [H.-O.
Pörtner, D.C. Roberts, V. Masson-Delmotte, P. Zhai, M. Tignor, E. Poloczanska, K. Mintenbeck,
A. Alegrı´a, M. Nicolai, A. Okem, J. Petzold, B. Rama, N.M. Weyer (eds.)].
17
IPCC, 2021: Summary for Policymakers. In: Climate Change 2021: The Physical Science
Basis. Contribution of Working Group I to the Sixth Assessment Report of theIntergovernmental Panel on Climate Change [Masson-Delmotte, V., P. Zhai, A. Pirani, S.L.
Connors, C. Pe´an, S. Berger, N. Caud, Y. Chen, L. Goldfarb, M.I. Gomis, M. Huang, K.
Leitzell, E. Lonnoy, J.B.R. Matthews, T.K. Maycock, T. Waterfield, O. Yelekc¸i, R. Yu and B.
Zhou (eds.)]. Cambridge University Press.
18
IPCC, 2022: Summary for Policymakers [H.-O. Pörtner, D.C. Roberts, E.S. Poloczanska, K.
Mintenbeck, M. Tignor, A. Alegría, M. Craig, S. Langsdorf, S. Löschke, V. Möller, A. Okem
(eds.)]. In: Climate Change 2022: Impacts, Adaptation and Vulnerability. Contribution ofWorking Group II to the Sixth Assessment Report of the Intergovernmental Panel on Climate
Change [H.-O. Pörtner, D.C. Roberts, M. Tignor, E.S. Poloczanska, K. Mintenbeck, A. Alegría,
M. Craig, S. Langsdorf, S. Löschke, V. Möller, A. Okem, B. Rama (eds.)]. Cambridge
University Press, Cambridge, United Kingdom and New York, New York, USA, pp. 3–33,
doi:10.1017/9781009325844.001.
19
National Academies of Sciences, Engineering, and Medicine. 2016. Attribution of Extreme
Weather Events in the Context of Climate Change. Washington, DC: The National Academies
Press. https://dio.org/10.17226/21852.
40
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Estimation of the Social Cost of Carbon Dioxide, 20 and 2019 Climate Change andEcosystems 21 assessments.
•

National Oceanic and Atmospheric Administration’s (NOAA) annual State of the
Climate reports published by the Bulletin of the American Meteorological Society, 22most recently in August of 2022.

•

EPA Climate Change and Social Vulnerability in the United States: A Focus on Six
Impacts (2021). 23
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 atmosphericconcentrations of one of these GHGs, CO2, measured at Mauna Loa in Hawaii and at other sitesaround the world reached 415 parts per million (ppm) in 2020 (nearly 50 percent higher than pre-20

National Academies of Sciences, Engineering, and Medicine. 2017. Valuing Climate
Damages: Updating Estimation of the Social Cost of Carbon Dioxide. Washington, DC: The
National Academies Press. https://doi.org/10.17226/24651.
21
National Academies of Sciences, Engineering, and Medicine. 2019. Climate Change andEcosystems. Washington, DC: The National Academies Press. https://doi.org/10.17226/25504.
22
Blunden, J. and T. Boyer, Eds., 2022: “State of the Climate in 2021.” Bull. Amer. Meteor.
Soc., 103 (8), Si–S465, https://doi.org/10.1175/2022BAMSStateoftheClimate.1.
23
EPA. 2021. Climate Change and Social Vulnerability in the United States: A Focus on Six
Impacts. U.S. Environmental Protection Agency, EPA 430–R–21–003.
41
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

industrial levels) 24 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. 25 The years 2015–2021 were the warmest 7 years in the 1880–2020 record according to six different global surface temperature datasets. 26 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. 27 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 andthree times the rate of the 1901 to 2018 period. 28 The rate of sea level rise during the 20th
Century was higher than in any other century in at least the last 2,800 years. 29 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. 30 Arctic sea ice extent continues to decline in all months ofthe 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. 31 Humaninduced climate change has led to heatwaves and heavy precipitation becoming more frequent

24

Blunden, J. and T. Boyer, Eds., 2022: “State of the Climate in 2021.” Bull. Amer. Meteor.
Soc., 103 (8), Si–S465, https://doi.org/10.1175/2022BAMSStateoftheClimate.1.
25
IPCC, 2021.
26
Blunden, J. and T. Boyer, Eds., 2022.
27
IPCC, 2021.
28
IPCC, 2021.
29
USGCRP, 2018: Impacts, Risks, and Adaptation in the United States: Fourth National Climate
Assessment, Volume II [Reidmiller, D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M.
Lewis, T.K. Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research Program,
Washington, DC, USA, 1515 pp. doi: 10.7930/NCA4.2018.
30
IPCC, 2021.
31
IPCC, 2021.
42This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

and more intense, along with increases in agricultural and ecological droughts 32 in many
regions. 33
The assessment literature demonstrates that modest additional amounts of warming maylead 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. 34 If
concentrations exceed 450 ppm, they would likely be higher than at any time in the past 23
million years: 35 At the current rate of increase of more than 2 ppm per year, this will occur inabout 15 years. While buildup of GHGs is not the only factor that controls climate, it isillustrative 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 (thelast 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 thatlooks very different from today and from the conditions in which human civilization has
developed. 36

32

These are drought measures based on soil moisture.
IPCC, 2021.
34
IPCC, 2021.
35
IPCC, 2013.
36
Gulev, S.K., P.W. Thorne, J. Ahn, F.J. Dentener, C.M. Domingues, S. Gerland, D. Gong, D.S.
Kaufman, H.C. Nnamchi, J. Quaas, J.A. Rivera, S. Sathyendranath, S.L. Smith, B. Trewin, K.
von Schuckmann, and R.S. Vose, 2021: Changing State of the Climate System. In Climate
Change 2021: The Physical Science Basis. Contribution of Working Group I to the Sixth
Assessment Report of the Intergovernmental Panel on Climate Change [Masson-Delmotte, V., P.
Zhai, A. Pirani, S.L. Connors, C. Péan, S. Berger, N. Caud, Y. Chen, L. Goldfarb, M.I. Gomis,
M. Huang, K. Leitzell, E. Lonnoy, J.B.R. Matthews, T.K. Maycock, T. Waterfield, O. Yelekçi,
R. Yu, and B. Zhou (eds.)]. Cambridge University Press, Cambridge, United Kingdom and New
York, New York, USA, pp. 287–422, doi:10.1017/9781009157896.004.
43
33This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

If the Greenland and Antarctic ice sheets were to melt substantially, for example, sealevels would rise dramatically, with potentially severe consequences for coastal cities andinfrastructure. The IPCC estimated that during the next 2,000 years, sea level will rise by 7 to 10feet 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), andby 60 to 70 feet if warming is allowed to reach 5 °C (9 °F) above preindustrial levels. 37 For
context, almost all of the city of Miami is less than 25 feet above sea level, and the NCA4 statedthat 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 toacidification of a magnitude not seen in 65 million years, 38 putting many marine species—
particularly calcifying species—at risk. 39
The NCA4 found that it is very likely (greater than 90 percent likelihood) that by midcentury, the Arctic Ocean will be almost entirely free of sea ice by late summer for the first timein about 2 million years. 40 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 thistemperature, between 8 and 18 percent of animal, plant, and insect species could lose over half ofthe geographic area with suitable climate for their survival, and 7 to 10 percent of rangeland
livestock would be projected to be lost. 41 The IPCC similarly found that climate change has
caused substantial damages and increasingly irreversible losses in terrestrial, freshwater, andcoastal and open ocean marine ecosystems. 42

37

IPCC, 2021.
IPCC, 2018.
39
IPCC, 2021.
40
USGCRP, 2018.
41
IPCC, 2018.
42
IPCC, 2022.
38

44This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Every additional increment of temperature comes with consequences. For example, thehalf 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 tofrequent 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 accountduration 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”). This halfdegree temperature increase has been projected to lead to an increase in the frequency of sea-icefree Arctic summers from once in a hundred years to once in a decade. It could lead to 4 inchesof additional sea level rise by the end of the century, exposing an additional 10 million people torisks of inundation, as well as increasing the probability of triggering instabilities in either theGreenland or Antarctic ice sheets. Between half a million and a million additional square milesof permafrost is projected to thaw over several centuries. Risks to food security is projected toincrease from medium to high for several lower income regions in the Sahel, southern Africa, theMediterranean, central Europe, and the Amazon. In addition to food security issues, thistemperature increase is projected to have implications for human health in terms of increasingozone concentrations, heatwaves, and vector-borne diseases (for example, expanding the rangeof 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). 43 Moreover, every
additional increment in warming leads to larger changes in extremes, including the potential for

43

IPCC, 2018.

45

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

events unprecedented in the observational record. Every additional degree is projected tointensify 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 haveincreased coastal flooding, all of which make these tropical cyclones more damaging. 44
The NCA4 also evaluated a number of impacts specific to the U.S. Severe drought andoutbreaks of insects like the mountain pine beetle have killed hundreds of millions of trees in theWestern 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. 45
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. 46 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

44

IPCC, 2021.
USGCRP, 2018.
46
NIFC (National Interagency Fire Center). 2022. Total wildland fires and acres (1983–2020).
Accessed November 2022. https://www.nifc.gov/sites/default/files/documentmedia/TotalFires.pdf.
4645This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

armoring. Tens of billions of dollars of U.S. real estate could be below sea level by 2050 undersome 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. 47
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 thecase of beneficial species, but negative in terms of weeds and invasive species, and can also leadto a reduction in plant micronutrients) 48 and cause ocean acidification. Nitrous oxide depletes thelevels of protective stratospheric ozone. 49 The tropospheric ozone produced by the reaction of47

USGCRP, 2018.
Ziska, L., A. Crimmins, A. Auclair, S. DeGrasse, J.F. Garofalo, A.S. Khan, I. Loladze, A.A.
Perez de Leon, A.Showler, J. Thurston, and I. Walls, 2016: Ch. 7: Food Safety, Nutrition, andDistribution. The Impacts of Climate Change on Human Health in the United States: A Scientific
Assessment. U.S. Global Change Research Program, Washington, DC, 189– 216,
https://dx.doi.org/10.7930/J0ZP4417.
49
WMO (World Meteorological Organization), Scientific Assessment of Ozone Depletion: 2018,
Global Ozone Research and Monitoring Project— Report No. 58, 588 pp., Geneva, Switzerland,
2018.
47
48

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

methane in the atmosphere has harmful effects for human health and plant growth in addition toits climate effects. 50
Ongoing EPA modeling efforts can shed further light on the distribution of climatechange damages expected to occur within the U.S. Based on methods from over 30 peerreviewed climate change impact studies, the EPA’s Framework for Evaluating Damages andImpacts (FrEDI) model has developed estimates of the relationship between future temperaturechanges and physical and economic climate-driven damages occurring in specific U.S. regions
across 20 impact categories, which span a large number of sectors of the U.S. economy. 51 Recent
applications of FrEDI have advanced the collective understanding about how future climatechange impacts in these 20 sectors are expected to be substantial and distributed unevenly across
U.S. regions. 52 Using this framework, the EPA estimates that under a global emission scenario

50

Nolte, C.G., P.D. Dolwick, N. Fann, L.W. Horowitz, V. Naik, R.W. Pinder, T.L. Spero, D.A.
Winner, and L.H. Ziska, 2018: Air Quality. In Impacts, Risks, and Adaptation in the UnitedStates: Fourth National Climate Assessment, Volume II [Reidmiller, D.R., C.W. Avery, D.R.
Easterling, K.E. Kunkel, K.L.M. Lewis, T.K. Maycock, and B.C. Stewart (eds.)]. U.S. Global
Change Research Program, Washington, DC, USA, pp. 512–538. doi: 10.7930/NCA4. 2018.
CH13.
51
EPA. (2021). Technical Documentation on the Framework for Evaluating Damages andImpacts (FrEDI). U.S. Environmental Protection Agency, EPA 430-R-21-004, available athttps://www.epa.gov/cira/fredi. Documentation has been subject to both a public review
comment period and an independent expert peer review, following EPA peer-review guidelines.
52(1) Sarofim, M.C., Martinich, J., Neumann, J.E., et al. (2021). A temperature binningapproach for multi-sector climate impact analysis. Climatic Change 165.
https://doi.org/10.1007/s10584-021-03048-6, (2) Supplementary Material for the Regulatory
Impact Analysis for the Supplemental Proposed Rulemaking, “Standards of Performance for
New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources: Oiland Natural Gas Sector Climate Review,” Docket ID No. EPA-HQ-OAR-2021-0317, September
2022, (3) The Long-Term Strategy of the United States: Pathways to Net-Zero Greenhouse Gas
Emissions by 2050. Published by the U.S. Department of State and the U.S. Executive Office of
the President, Washington DC. November 2021, (4) Climate Risk Exposure: An Assessment of
the Federal Government’s Financial Risks to Climate Change, White Paper, Office ofManagement and Budget, April 2022.
48
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 fromregion to region: for example, the Southeast is projected to see some of the largest damages fromsea level rise, the West Coast will see higher damages from wildfire smoke than other parts ofthe country, and the Northern Plains states are projected to see a higher proportion of damages torail 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 assessmentof climate impacts relevant to U.S. interests in a number of ways. For example, FrEDI does notreflect increased damages that occur due to interactions between different sectors impacted byclimate 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 53
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.

53

EPA. (2021). Technical Documentation on the Framework for Evaluating Damages andImpacts (FrEDI). U.S. Environmental Protection Agency, EPA 430-R-21-004, available athttps://www.epa.gov/cira/fredi.
49This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

IV. Recent Developments in Emissions Controls and the Electric Power Sector
A. Introduction
In this section, we discuss background information about the electric power sector andthen discuss several recent developments that are relevant for many of the controls that the EPA
is proposing to determine qualify as the BSER for the fossil fuel-fired power plants that are thesubject of this proposed rulemaking. After giving some general background, we first discuss
CCS and explain that its cost has fallen significantly. Lower CCS costs are central for the EPA’s
proposals that CCS is the BSER for certain existing coal-fired EGUs and certain existing andnew natural gas-fired combustion turbines. Second, we discuss natural gas co-firing for coalfired EGUs and explain recent reductions in cost for this approach as well as its widespread
availability and current and potential deployment within this source category. Third, we discusshydrogen produced through low-emitting manufacturing, the availability of which is expected toincrease significantly and the cost of which is expected to decline significantly in the near future.
This increase in availability and decrease in cost is central for the EPA’s proposal that low-GHG
hydrogen is the BSER for certain existing and new natural gas-fired combustion turbines.
Finally, we discuss key developments in the electric power sector that underly the expected
operational methods for existing coal-fired EGUs and new and existing natural gas-fired
combustion turbines. These key developments, in turn, are relevant for the regulatory design.
B. Background
1. 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 thesubject of these proposed regulations still provide more than half of the electricity generated in
50
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

the U.S. These EGUs fill many roles that are important to maintaining a reliable supply ofelectricity. For example, certain EGUs generate base load power, which is the portion ofelectricity loads that are continually present and typically operate throughout all hours of theyear. Other EGUs provide complementary generation to balance variable supply and demand
resources. “Peaking units” provide capacity during hours of the highest daily, weekly, orseasonal net demand. Some EGUs also play important roles ensuring the reliability of the electricgrid, including facilitating the regulation of frequency and voltage, providing “black start”
capability in the event the grid must be repowered after a widespread outage, and providing
reserve generating capacity 54 in the event of unexpected changes in the availability of othergenerators.
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 areunavailable or insufficient to meet demand. Units are also unavailable during both routine andunanticipated 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 ofgenerating 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.

54

Generation and capacity are commonly reported statistics with key distinctions. Generation is
the production of electricity and is a measure of an EGU’s actual output while capacity is ameasure of the maximum potential production of an EGU under certain conditions. There areseveral methods to calculate an EGU’s capacity, which are suited for different applications of thestatistic. Capacity is typically measured in megawatts (MW) for individual units or gigawatts (1GW = 1,000 MW) for multiple EGUs. Generation is often measured in kilowatt-hours (kWh),megawatt-hours (MWh), or gigawatt-hours (1 GWh = 1 million kWh).
51
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Generated electricity must be transmitted over networks 55 of high voltage lines tosubstations where power is stepped down to a lower voltage for local distribution. Within each ofthese transmission networks, there are multiple areas where the operation of power plants ismonitored 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; 56 in others, individual utilities 57 coordinate the operations of theirgeneration and transmission to balance the system across their respective service territories.
2. Types of EGUs
In 2021, approximately 61 percent of net electricity was generated from the combustionof fossil fuels with natural gas providing 38 percent, coal providing 22 percent, and petroleum
products such as fuel oil providing an additional 1 percent. 58 Fossil fuel-fired EGUs include thesteam generating units and stationary combustion turbines that are the subject of these proposed
regulations.

55

The three network interconnections are the Western Interconnection, comprising the westernparts of both the U.S. and Canada (approximately the area to the west of the Rocky Mountains),
the Eastern Interconnection, comprising the eastern parts of both the U.S. and Canada (except
those parts of Eastern Canada that are in the Quebec Interconnection), and the Texas
Interconnection (which encompasses the portion of the Texas electricity system commonly
known as the Electric Reliability Council of Texas (ERCOT)). See map of all NERC
interconnections at
https://www.nerc.com/AboutNERC/keyplayers/PublishingImages/NERC%20Interconnections.pdf.
56
For example, PJM Interconnection, LLC, New York Independent System Operator (NYISO),
Midwest Independent System Operator (MISO), California Independent System Operator(CAISO), etc.
57
For example, Los Angeles Department of Power and Water, Florida Power and Light, etc.
58
U.S. Energy Information Administration (EIA). Electric Power Monthly, Table 1.1 and Form
EIA-860M, July 2022. https://www.eia.gov/electricity/data/php.
52This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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). While coal is the most common fuel for fossil fuel-fired utility boilers, natural gas
can also be used as a fuel in these EGUs and many existing coal- and oil-fired utility boilers haverepowered as natural gas-fired units. An IGCC unit gasifies fuel—typically coal or petroleumcoke—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 createdby these technologies produces high-pressure steam that is released to rotate turbines, which, inturn, 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) directlyfrom the heat of burning natural gas or other fuel. The second cycle reuses the waste heat fromthe combustion turbine engine, which is routed to a heat recovery steam generator (HRSG) thatgenerates steam, which is then used to produce additional power using a steam turbine (i.e., thesteam cycle). Combining these generation cycles increases the overall efficiency of the system.
Combined cycle units that fire mostly natural gas are commonly referred to as natural gas
combined cycle (NGCC) units, and, with greater efficiency, are utilized at higher capacity factors
to provide base load or intermediate 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
53
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

capacity factors and contribute to reliable operations of the grid during periods of peak demandor provide flexibility to support increased generation from variable energy sources. 59
Other generating sources produce electricity by harnessing kinetic energy from flowing
water, wind, or tides, thermal energy from geothermal wells, or solar energy primarily throughphotovoltaic solar arrays. Spurred by a combination of declining costs, consumer preferences,and government policies, the capacity of these renewable technologies is growing, and when
considered with existing nuclear energy, accounted for nearly 41 percent of the overall net
electricity supply in 2022. 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 theaccompanying RIA for additional discussion of projections for the power sector). These
projections are consistent with power company announcements. For example, as the Edison
Electric Institute (EEI) stated in pre-proposal public comments submitted to the regulatory
docket: “Fifty EEI members have announced forward-looking carbon reduction goals, two-thirds

59

Non-dispatchable renewable energy (electrical output cannot be used at any given time to meetfluctuating demand) is both variable and intermittent and is often referred to as intermittent
renewable energy. The variability aspect results from predictable changes in electric generation(e.g., solar not generating electricity at night) that often occur on longer time periods. Theintermittent aspect of renewable energy results from inconsistent generation due to unpredictable
external factors outside the control of the owner/operator (e.g., imperfect local weather forecasts)
that often occur on shorter time periods. Since renewable energy fluctuates over multiple time
periods, grid operators are required to adjust forecast and real time operating procedures. As
more renewable energy is added to the electric grid and generation forecasts improve, theintermittency of renewable energy is reduced.
54
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

of which include a net-zero by 2050 or earlier equivalent goal, and members are routinely
increasing the ambition or speed of their goals or altogether transforming them into net-zerogoals …. EEI’s member companies see a clear path to continued emissions reductions over the
next decade using current technologies, including nuclear power, natural gas-based generation,energy demand efficiency, energy storage, and deployment of new renewable energy—especiallywind and solar—as older coal-based and less-efficient natural gas-based generating units
retire.” 60
C. CCSOne of the key GHG reduction technologies upon which BSER determinations arefounded in this proposal is CCS—a technology that can capture and permanently store CO2 from
EGUs. CCS has three major components: CO2 capture, transportation, and sequestration/storage.
Generally, the capture processes most applicable to combustion turbines and utility boilers
remove CO2 from the exhaust gas after combustion. The exhaust gases from most combustion
processes are at atmospheric pressure with relatively low concentrations of CO2. Most postcombustion capture systems utilize liquid solvents (most commonly amine-based) in a scrubbercolumn to absorb the CO2 from the flue gas. 61 The CO2-rich solvent is then regenerated byheating the solvent to release the captured CO2. The high purity CO2 is then compressed andtransported, generally through pipelines, to a site for geologic sequestration (i.e., the long-term

60

Edison Electric Institute (EEI). (November 18, 2022). Clean Air Act Section 111 Standards
and the Power Sector: Considerations and Options for Setting Standards and Providing
Compliance Flexibility to Units and States. Pg. 5. Public comments submitted to the EPA’s preproposal rulemaking, Docket ID No. EPA-HQ-OAR-2022-0723.
61
Post-combustion CO2 capture is most common, but as discussed later in this preamble, there
are also pre-combustion CO2 capture options available and applicable to the power sector.
55
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

containment of CO2 in subsurface geologic formations). 62 Process improvements learned fromearlier deployments of CCS, the availability of better solvents, and other advances have resulted
in a decrease in the cost of CCS in recent years. The cost of CO2 capture, excluding any tax
credits, from coal-fired power generation is projected to fall by 50 percent by 2025 compared to2010. 63 In addition, new policies such as the IRA, enacted in 2022, support the deployment of
CCS technology and will further reduce the cost of implementing CCS by extending andincreasing the tax credit for CCS under Internal Revenue Code section 45Q.
There are several examples of the application of CCS at EGUs, some of which are noted
here with further detail provided in section VII.F.3.b.iii(A) of this preamble. These include
SaskPower’s Boundary Dam Unit 3, a 110-MW lignite-fired unit in Saskatchewan, Canada,
which has achieved CO2 capture rates of 90 percent using an amine-based post-combustion
capture system retrofitted to the existing steam generating unit. 64 Amine-based carbon capture
has also been demonstrated at AES’s Warrior Run (Cumberland, Maryland) and Shady Point(Panama, Oklahoma) coal-fired power plants. 65
CCS has also been successfully applied to an existing combined cycle combustion turbine
EGU at the Bellingham Energy Center in south central Massachusetts, and other projects are in

62

40 CFR 261.4(h).
Technology Readiness and Costs of CCS (2021). Global CCS Institute.
https://www.globalccsinstitute.com/wp-content/uploads/2021/03/Technology-Readiness-andCosts-for-CCS-2021-1.pdf.
64
Giannaris, S., et al. Proceedings of the 15th International Conference on Greenhouse Gas
Control Technologies (March 15–18, 2021). SaskPower’s Boundary Dam Unit 3 Carbon
Capture Facility–The Journey to Achieving Reliability.
https://papers.ssrn.com/sol3/papers.cfm?abstract_id=3820191.
65
Dooley, J. J., et al. (2009). “An Assessment of the Commercial Availability of Carbon Dioxide
Capture and Storage Technologies as of June 2009.” U.S. DOE, Pacific Northwest National
Laboratory, under Contract DE-AC05-76RL01830.
56
63

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

different stages of deployment. The 40-MW slipstream capture facility at the Bellingham Energy
Center operated from 1991 to 2005 and captured 85 to 95 percent of the CO2 in the slipstream. 66
In Scotland, the proposed 900-MW Peterhead Power Station combined cycle EGU with CCS isin the planning stages of deployment and will have the potential to capture 90 percent of its CO2
emissions. 67 Moreover, an 1,800-MW combined cycle 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 economic feasibility was partially credited to the expanded IRC section 45Q
tax credit for sequestered CO2 provided through the IRA. 68
In developing these proposals, the EPA reviewed the current state of CCS technology andcosts, including the use of CCS with both steam generating units and combustion turbines. This
review is reflected in the BSER discussions later in this preamble and is further detailed in theaccompanying RIA and technical support documents titled, GHG Mitigation Measures for SteamGenerating Units and GHG Mitigation Measures – Carbon Capture and Storage for Combustion
Turbines. The three documents are included in the rulemaking docket.
D. Natural Gas Co-firing
For a coal-fired steam generating unit, the substitution of natural gas for some of the coalso that the unit fires a combination of coal and natural gas is known as “natural gas co-firing.”

66

U.S. Department of Energy (DOE). Carbon Capture Opportunities for Natural Gas Fired
Power Systems. https://www.energy.gov/fecm/articles/carbon-capture-opportunities-naturalgas-fired-power-systems.
67
Buli, N. (2021, May 10). SSE, Equinor plan new gas power plant with carbon capture in
Scotland. Reuters. https://www.reuters.com/business/sustainable-business/sse-equinor-plan-newgas-power-plant-with-carbon-capture-scotland-2021-05-11/.
68
Competitive Power Ventures (2022). Multi-Billion Dollar Combined Cycle Natural Gas
Power Station with Carbon Capture Announced in West Virginia. Press Release. September 16,
2022. https://www.cpv.com/2022/09/16/multi-billion-dollar-combined cycle-natural-gas-powerstation-with-carbon-capture-announced-in-west-virginia/.
57
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Most existing coal-fired steam generating units can be modified to co-fire natural gas in any
desired proportion with coal. Generally, the modification of existing boilers to enable or increase
natural gas firing typically involves the installation of new gas burners and related boiler
modifications as well as the construction of natural gas supply pipelines. In recent years, the costof natural gas co-firing has declined because the expected difference between coal and gas prices
has decreased to about $1/MMBtu and recent analyses support lower capital costs for modifying
existing boilers to co-fire with natural gas, as discussed in section X.D.2 of this preamble.
In developing these proposals, the EPA reviewed in detail the current state of natural gas
co-firing technology and costs. This review is reflected in the BSER discussions later in thispreamble and is further detailed in the accompanying RIA and GHG Mitigation Measures for
Steam Generating Units TSD. Both documents are included in the rulemaking docket.
E. Hydrogen Co-firing
Industrial combustion turbines have been burning byproduct fuels containing large
percentages of hydrogen for decades, and recently, utility combustion turbines in the power
sector have begun to co-fire hydrogen as a fuel to generate electricity. Hydrogen contains nocarbon, and when combusted in a turbine, produces zero direct CO2 emissions. However, as
discussed in section IV.F.3 of this preamble, the manufacture of hydrogen, depending on themethod of production, can generate GHG emissions. As noted previously, there has been agrowing interest in the use of hydrogen as a fuel for combustion turbines to generate electricity.
Many models of new utility combustion turbines have demonstrated the ability to co-fire up to
30 percent hydrogen and developers are working toward models that will be ready to combust
100 percent hydrogen by 2030. Furthermore, several utilities are co-firing hydrogen in test burns;
and some have announced plans to move to combusting 100 percent hydrogen in the 2035–2045
58
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

timeframe. Specifically, the Los Angeles Department of Water and Power’s (LADWP)
Scattergood Modernization project includes plans to have a hydrogen-ready combustion turbine
in place when the 346-MW combined cycle plant (potential for up to 830 MW) begins initial
operations in 2029. LADWP foresees the plant running on 100 percent electrolytic hydrogen by2035. 69 In addition, LADWP also has an agreement in place to purchase electricity from theIntermountain Power Agency project (IPA) in Utah. IPA is replacing an existing 1.8-GW coalfired EGU with an 840-MW combined cycle turbine that developers expect to initially co-fire 30
percent electrolytic hydrogen in 2025 and 100 percent hydrogen by 2045. 70 In Florida, NextEra
Energy has announced plans to operate 16 GW of existing natural gas-fired combustion turbineswith electrolytic hydrogen as part of the utility’s Zero Carbon Blueprint to be carbon-free by2045. 71 Duke Energy Corporation, which operates 33 gas-fired plants across the Midwest, theCarolinas, and Florida, has outlined plans for full hydrogen capabilities throughout its future
turbine fleet: “All natural gas units built after 2030 are assumed to be convertible to fullhydrogen capability. After 2040, only peaking units that are fully hydrogen capable are assumed
to be built.” 72
In addition to those three utility announcements, several merchant generators operating inwholesale markets are also signaling their intent to ramp up hydrogen co-firing levels after initial
30 percent co-firing phases. The Cricket Valley Energy Center (CVEC) in New York is69https://clkrep.lacity.org/onlinedocs/2023/23-0039_rpt_DWP_02-03-2023.pdf.
https://www.forbes.com/sites/mitsubishiheavyindustries/2021/07/30/eager-to-becomehydrogen-ready-power-plants-turn-to-dual-fuel-turbines/?sh=38ddea053476.

70
71

https://www.nexteraenergy.com/content/dam/nee/us/en/pdf/NextEraEnergyZeroCarbonBlueprint.pdf.
72
https://www.duke-energy.com/_/media/PDFs/our-company/Climate-Report-2022.pdf.
59
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

retrofitting its combined cycle power plant starting in 2022 as a first step toward the conversion
to a 100 percent hydrogen fuel capable plant. CVEC announcements did not have specific dates
for 100 percent electrolytic hydrogen firing but indicated in its announcement that New York has
mandated achieving a zero-emission electricity sector by 2040. 73 The Long Ridge Energy
Terminal in Ohio, which is has successfully co-fired a 5 percent hydrogen blend at its 485-MW
combined cycle plant, noted its technology has the capability to transition to 100 percent
hydrogen over time as its low-GHG fuel supply becomes available. 74 Constellation Energy,
which owns 23 natural gas-fired or dual fuel generators (8.6 GW), is exploring electrolytichydrogen co-firing across its fleet. It estimated costs for blend levels in the range of 60-100
percent at approximately $100/kW for retrofits and noted that equipment manufacturers areplanning 100 percent hydrogen combustion-ready turbines before 2030. 75
In both the IIJA and the IRA, Congress provided extensive support for the developmentof hydrogen produced through low-GHG methods. This support includes investment ininfrastructure through the IIJA, and the provision of tax credits in the IRA to incentivize the
manufacture of hydrogen through low GHG-emitting methods. These incentives are fuelinginterest in co-firing hydrogen and creating expectations that the availability of low-cost and lowGHG hydrogen will increase in the coming years. These projections are based on a combinationof economies of scale as low-GHG production methods expand, the increasing availability of73

https://www.cricketvalley.com/news/cricket-valley-energy-center-and-ge-sign-agreement-tohelp-reduce-carbon-emissions-in-new-york-with-green-hydrogen-fueled-power-plant/.
74
GE-powered gas-fired plant in Ohio now burning hydrogen (power-eng.com).
75
Constellation Energy Corporation’s Comments on EPA Draft White Paper: Available andEmerging Technologies for Reducing Greenhouse Gas Emissions from Combustion Turbine
Electric Generating Units Docket ID No. EPA-HQ-OAR-2022-0289-0022.
60
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

low-cost electricity—largely powered by renewable energy sources and potentially nuclear
energy—and learning by doing as more turbine projects are developed.
In developing these proposals, the EPA reviewed in detail the current state of hydrogenco-firing technology and costs. This review is reflected in the BSER discussions later in thispreamble and is further detailed in the accompanying RIA and technical support document titled,
Hydrogen in Combustion Turbine Electric Generating Units. Both documents are included in therulemaking docket.
F. Recent Changes in the Power Sector
1. Overview
The electric power sector is experiencing a prolonged period of transition and structuralchange. Since the generation of electricity from coal-fired power plants peaked nearly two
decades ago, the power sector has changed at a rapid pace. Today, natural gas-fired power plants
provide the largest share of net generation, coal-fired power plants provide a significantly
smaller share than in the recent past, renewable energy provides a steadily increasing share, andas new technologies enter the marketplace, power producers continue to replace aging assets
with more efficient and lower cost alternatives.
These developments have significant implications for the types of controls that the EPA
proposes to determine qualify as the BSER for different types of fossil fuel-fired EGUs. For
example, many utilities and power plant operators have announced plans to voluntarily cease
operating coal-fired power plants in the near future, in some cases after operating them at low
levels for a several-year period. Industry stakeholders have requested that the EPA structure thisrule to avoid imposing costly control obligations on coal-fired power plants that have announcedplans to voluntarily cease operations, and the EPA proposes to accommodate those requests. In
61
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

addition, the EPA recognizes that utilities and power plant operators are building new natural
gas-fired combustion turbines with plans to operate them at varying levels of utilization, in
coordination with other existing and expected new energy sources. These patterns of operation
are important for the type of controls that the EPA is proposing as the BSER for these turbines.
This section discusses the recent trends in the power sector. It 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.
2. Broad Trends within the Power Sector
For more than a decade, the power sector has experienced substantial transition andstructural 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 inelectricity generation from both existing and new EGUs; changes in the prices and availability ofdifferent fuels; state and Federal policy; the preferences and purchasing behaviors of end-use
electricity consumers; and substantial growth in electricity generation from renewable sources.
One of the most important developments of this transition has been the evolving
economics of the power sector. Specifically, the existing fleet of coal-fired EGUs continues toage and become more costly to maintain and operate. At the same time, the supply andavailability 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 andsince that time has maintained its position as the primary fossil fuel for base load energy
62This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

generation, for peaking applications, and for balancing renewable generation. 76 Additionally,
there has been increased generation from investments in zero- and low-GHG emission energy
technologies spurred by technological advancements, declining costs, state and Federal policies,
and most recently, the IIJA and the IRA. For example, the IIJA provides investments and otherpolicies to help commercialize, demonstrate, and deploy technologies such as small modular
nuclear reactors, long-duration energy storage, regional clean hydrogen hubs, carbon capture andstorage and associated infrastructure, advanced geothermal systems, and advanced distributed
energy resources (DER) as well as more traditional wind and solar resources. The IRA provides
numerous tax and other incentives to directly spur deployment of clean energy technologies.
Particularly relevant to these proposals, the incentives in the IRA, 77 which are discussed in detaillater in this section of the preamble, support the expansion of technologies, such as CCS andhydrogen 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 coalaccounting for the largest single share. By 2021, fossil fuel net generation was approximately 60
percent, less than the share in 2010 despite electricity demand remaining relatively flat over thissame time period. Moreover, the share of fossil generation supplied by coal-fired EGUs fell from46 percent in 2010 to 23 percent in 2021 while the share supplied by natural gas-fired EGUs rose

76

U.S. Energy Information Administration (EIA). Monthly Energy Review and Short-Term
Energy Outlook, March 2016. https://www.eia.gov/todayinenergy/detail.php?id=25392.
77
U.S. Department of Energy (DOE). August 2022. The Inflation Reduction Act Drives
Significant Emissions Reductions and Positions America to Reach Our Climate Goals.
https://www.energy.gov/sites/default/files/202208/8.18%20InflationReductionAct_Factsheet_Final.pdf.
63This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 theincrease in natural gas capacity as well as an increase in the utilization of new and existing gasfired EGUs. The combination of wind and solar generation also grew from 2 percent of theelectric power sector mix in 2010 to 12 percent in 2021. 78
The broad trends throughout the power sector can also be seen in the number ofcommitments 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
XV of this preamble, in the accompanying RIA, and in the Power Sector Trends technicalsupport document (TSD). The latter two documents are available in the rulemaking docket.
Consistent with analyses done by other energy modelers, the RIA and TSD demonstrate that thesector trend of moving away from coal-fired generation is likely to continue and that nonemitting technologies may eventually displace certain natural gas-fired combustion turbines.
3. Trends in Coal-fired Generation
Coal-fired steam generating units have historically been the nation’s foremost source ofelectricity, but coal-fired generation has declined steadily since its peak approximately 20 years

78

U.S. Energy Information Administration (EIA). Annual Energy Review, table 8.2b Electricity
net generation: electric power sector. https://www.eia.gov/totalenergy/data/annual/.
64
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

ago. 79 Construction of new coal-fired steam generating units was at its highest between 1967 and1986, with approximately 188 GW (or 9.4 GW per year) of capacity added to the grid during that
20-year period. 80 The peak annual capacity addition was 14 GW, which was added in 1980.
These coal-fired steam generating units operated as base load units for decades. However,
beginning in 2005, the U.S. power sector―and especially the coal-fired fleet―began
experiencing a period of transition that continues today. Many of the older coal-fired steam
generating units built in the 1960s, 1970s, and 1980s have retired and/or have experienced
significant reductions in net generation due to cost pressures and other factors. Some of thesecoal-fired steam generating units repowered with combustion turbines and natural gas. 81 And
with no new coal-fired steam generating units commencing construction in more than a decade—and with the EPA unaware of any plans by any companies to construct a new coal-fired EGU—
much of the fleet that remains is aging, expensive to operate and maintain, and increasingly
uncompetitive relative to other sources of generation in many parts of the country.

79

U.S. Energy Information Administration (EIA). Today in Energy. Natural gas expected tosurpass coal in mix of fuel used for U.S. power generation in 2016. March 2016.
https://www.eia.gov/todayinenergy/detail.php?id=25392.
80
U.S. Energy Information Administration (EIA). Electric Generators Inventory, Form EIA860M, Inventory of Operating Generators and Inventory of Retired Generators, March 2022.
https://www.eia.gov/electricity/data/eia860m/.
81
U.S. Energy Information Administration (EIA). Today in Energy. More than 100 coal-fired
plants have been replaced or converted to natural gas since 2011. August 2020.
https://www.eia.gov/todayinenergy/detail.php?id=44636.
65This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Since 2010, the power sector’s total installed capacity 82 has increased by 144 GW (14percent), 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 installedwind capacity of 93 GW, natural gas capacity of 84 GW, and an increase in utility-scale solar
capacity of 60 GW during the same period. Additionally, significant amounts of DER solar (33GW) were also added. Two-thirds or more of these changes were in the most recent 6 years of
this period. From 2015–2021, coal capacity was reduced by 70 GW and this reduction incapacity was offset by a net increase of 60 GW of wind capacity, 52 GW of natural gas capacity,and 47 GW of utility-scale solar capacity. Additionally, 23 GW of DER solar were also addedfrom 2015 to 2021.
At the end of 2021, there were more than 500 EGUs totaling 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 in design and operation
across various facilities. For example, coal-fired steam generating units smaller than 100 MW
comprise 18 percent of the total number of coal-fired units, but only 2 percent of total coal-fired
capacity. 83 Moreover, average annual capacity factors for coal-fired steam generating units have82

This includes generating capacity at EGUs primarily operated to supply electricity to the gridand combined heat and power (CHP) facilities classified as Independent Power Producers andexcludes generating capacity at commercial and industrial facilities that does not operate
primarily as an EGU. Natural gas information reflects data for all generating units using natural
gas as the primary fossil heat source unless otherwise stated. This includes combined cycle,
simple cycle, steam, and miscellaneous (< 1 percent).
83
U.S. Environmental Protection Agency. National Electric Energy Data System (NEEDS) v6.
October 2022. https://www.epa.gov/power-sector-modeling/national-electric-energy-datasystem-needs.
66
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

declined from 67 to 49 percent since 2010, 84 indicating that a larger share of units are operating
in non-base load fashion.
Older power plants also tend to become uneconomic over time as they become morecostly to maintain and operate, 85 especially when competing for dispatch against newer and more
efficient generating technologies that have lower operating costs. The average coal-fired power
plant that retired between 2015 and 2021 was more than 50 years old, and 65 percent of theremaining fleet of coal-fired steam generating units will be 50 years old or more within adecade. 86 To further illustrate this trend, the existing coal-fired steam generating units older than
40 years represent 71 percent (154 GW) 87 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. 88 As discussed further in this section, projections anticipate that
this trend will continue.
The reduction in coal-fired generation by electric utilities is also evident in data forannual 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

84

U.S. Energy Information Administration (EIA). Electric Power Annual 2021, table 1.2.
U.S. Energy Information Administration (EIA). U.S. coal plant retirements linked to plants
with higher operating costs. December 2019.
https://www.eia.gov/todayinenergy/detail.php?id=42155.
86
eGRID 2020 (January 2022 release from EPA eGRID website). Represents data fromgenerators that came online between 1950 and 2020 (inclusive); a 71-year period. Full eGRID
data includes generators that came online as far back as 1915.
87
U.S. Energy Information Administration (EIA). Electric Generators Inventory, Form-860M,
Inventory of Operating Generators and Inventory of Retired Generators. August 2022.
https://www.eia.gov/electricity/data/eia860m/.
88
U.S. Environmental Protection Agency. National Electric Energy Data System (NEEDS) v6.
October 2022. https://www.epa.gov/power-sector-modeling/national-electric-energy-datasystem-needs.
67
85This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

declines in 2015 and 2020. 89 In 2015, less than 900 MMst were produced, and in 2020, the total
dropped to 535 MMst, the lowest output since 1965.
4. Trends in Natural Gas-fired Generation
In the lower 48 states, most combustion turbine EGUs burn natural gas, and some havethe capability to fire distillate oil as backup for periods when natural gas is not available, such as
when residential demand for natural gas is high during the winter. Areas of the country without
access to natural gas often use distillate oil or some other locally available fuel. Combustion
turbines have the capability to burn either gaseous or liquid fossil fuels, including but not limited
to kerosene, naphtha, synthetic gas, biogases, liquified natural gas (LNG), and hydrogen.
Natural gas consists primarily of methane, and after the raw gas is extracted from theground, it is processed to remove impurities and to separate the methane from other gases andnatural gas liquids to produce pipeline quality gas. 90 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

89

U.S. Energy Information Administration (EIA). Annual Coal Report. Table ES-1. October
2022. https://eia.gov/coal/annual/pdf/tableES1.pdf.
90
U.S. Energy Information Administration (EIA). Natural Gas Explained. December 2022.
https://www.eia.gov/energyexplained/natural-gas/.
68
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

billion cubic feet per day. 91 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. 92 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 coalfuel 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 notreflect 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 efficientthan 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

91

U.S. Energy Information Administration (EIA). Natural gas explained. Where our natural gas
comes from. https://www.eia.gov/energyexplained/natural-gas/where-our-natural-gas-comesfrom.php.
92
U.S. Energy Information Administration (EIA). Natural Gas Annual, September 2021.
https://www.eia.gov/energyexplained/natural-gas/prices.php.
69
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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. 93
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 todata 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. 94
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 capacityof combustion turbine EGUs totaled 413 GW, with 281 GW being combined cycle generationand 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

93

U.S. Energy Information Administration (EIA). Electric Monthly Update. September 23. 2022.
Report derived from Bloomberg Energy. EIA notes that the competition between coal andnatural gas to produce electricity is complex, involving delivered prices and emission costs, theterms of fuel supply contracts, and the workings of fuel markets.
94
U.S. Energy Information Administration (EIA). Electric Generators Inventory, Form EIA860M, Inventory of Operating Generators and Inventory of Retired Generators, July 2022.
https://www.eia.gov/electricity/data/eia860m/.
70This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 theage of the generating units, nearly 50 percent of the natural gas capacity has been in service lessthan 15 years. 95
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 inrecent historical trends. The largest source of new generation is from renewable energy andprojections show that total natural gas-fired combined cycle capacity is likely to decline after
2030 in response to increased generation from renewables, energy storage, and othertechnologies, as discussed in section IV.I. Approximately, 86 percent of capacity additions in
2023 are expected to be from non-emitting generation resources including solar, wind, nuclear,and energy storage. 96 The IRA is likely to accelerate this trend, which is also expected to impact
the operation of certain combustion turbines. For example, as the electric output from additional
non-emitting generating sources fluctuates daily and seasonally, flexible low and intermediateload combustion turbines will be needed to support these variable sources and provide reliability
to the grid. This requires the ability to start and stop quickly and change load more frequently.
5. 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 thetechnologies, supportive state and Federal policies, and increased consumer demand for low-95

National Electric Energy Data System (NEEDS) v.6.
U.S. Energy Information Administration (EIA). Today in Energy. More than half of new U.S.
electric-generating capacity in 2023 will be solar. February 2023.
https://www.eia.gov/todayinenergy/detail.php?id=55419.
71
96This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

GHG electricity. In 2021, renewable energy sources produced approximately 20 percent of thenation’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). 97
The costs of renewable energy sources have fallen over time due to technologicaladvances, improvements in performance, and increased demand for clean energy. For example,
the unsubsidized average levelized cost of wind energy from 1988 to 1999 was $106/MWh andhas since declined to $32/MWh in 2021. 98 The average levelized cost of energy for utility-scalesolar photovoltaics has fallen from $227/MWh in 2010 to $33/MWh in 2021. 99 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. 100
Local, state, and Federal incentives and tax credits have further reduced the cost of renewableenergy resources.
During the past 15 years, more than 122 GW of wind (primarily onshore) and 61 GW ofsolar capacity have been constructed, which represent a tripling of wind capacity and a 20-foldincrease in solar capacity. 101 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,

97

U.S. Energy Information Administration (EIA). Monthly Energy Review, table 7.2B
Electricity Net Generation: Electric Power Sector, May 2022.
https://www.eia.gov/totalenergy/data/monthly/.
98
U.S. Department of Energy (DOE), Land-Based Wind Market Report: 2022 Edition, 2022.
https://www.energy.gov/eere/wind/articles/land-based-wind-market-report-2022-edition.
99
Lawrence Berkeley National Laboratory (LBNL), Utility-Scale Solar Technical Brief, 2022
Edition, September 2022. https://emp.lbl.gov/utility-scale-solar.
100
https://www.nrel.gov/news/program/2021/documenting-a-decade-of-cost-declines-for-pvsystems.html.
101
U.S. Energy Information Administration (EIA), Electric Generators Inventory, Form-860M,
Inventory of Operating Generators and Inventory of Retired Generators, July 2022.
https://www.eia.gov/electricity/data/eia860m/.
72
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

the nation added 5.3 GW of total wind capacity and the annual average was 7.2 GW through2019. 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 renewableenergy 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 such as battery storage that have demonstrated theability to further support the development and integration of renewable energy to the grid bybalancing variable supply and demand resources. At the end of 2021, there were 331 large-scalebattery storage systems operating in the U.S. with a combined capacity of 4.8 GW (10.7
GWh). 102 In terms of small-scale battery storage, there were 781 MW of reported capacity in
2021, mostly in California. 103 Energy storage costs declined 72 percent between 2015 and2019, 104 and declining costs have led to additional capacity being installed at each facility, andthis increases the duration of each system when operating at maximum output. With 20.8 GW of

102

U.S. Energy Information Administration (EIA). Annual Electric Generator Report, 2021
Form EIA-860. https://www.eia.gov/electricity/data/eia860/.
103
U.S. Energy Information Administration (EIA). Annual Electric Power Industry Report, 2021
Form EIA-861. https://www.eia.gov/electricity/data/eia861/.
104
U.S. Energy Information Administration (EIA). Annual Electric Generator Report, 2019
Form EIA-860. https://www.eia.gov/analysis/studies/electricity/batterystorage/.
73
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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. 105
6. Trends in Nuclear Generation
The U.S. power sector continues to rely on nuclear sources of energy for a consistentportion of net generation. Since 1990, nuclear energy has provided about 20 percent of thenation’s electricity, and 92 reactors were operating at 54 nuclear power plants in 28 states in2022. 106
It should be noted that despite the consistent output from nuclear power plants over time,
the number of operating reactors has recently declined. The average retirement age for a nuclear
reactor is 44 years and the average age of the remaining nuclear fleet is currently 42 years,
although age is only one consideration for determining when a nuclear plant may retire. For
example, nuclear generating units at Dominion Generation’s Surry plant, Florida Power &Light’s Turkey Point plant, and Constellation Energy’s Peach Bottom plant applied to the
Nuclear Regulatory Commission (NRC) for second 20-year license renewals and subsequent
renewed licenses were granted for six units, although four of the six units have not had theirlicense terms extended beyond the periods of their first renewed licenses and are undergoingfurther environmental review. 107 Others who have applied to the NRC for a second 20-year

105

U.S. Energy Information Administration (EIA). Today in Energy. U.S. battery storage
capacity will increase significantly by 2025. December 2022.
https://www.eia.gov/todayinenergy/detail.php?id=54939.
106
U.S. Energy Information Administration (EIA). Electric Generators Inventory, Form-860M,
Inventory of Operating Generators and Inventory of Retired Generators. August 2022.
https://www.eia.gov/electricity/data/eia860m/.
107
U.S. Nuclear Regulatory Commission (NRC). Status of Subsequent License Renewal
Applications. April 2023. https://www.nrc.gov/reactors/operating/licensing/renewal/subsequentlicense-renewal.html.
74This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

license renewal include Dominion for its North Anna units 1 and 2; NextEra Energy for its Point
Beach units 1 and 2; Duke Energy Carolinas for its Oconee units 1, 2, and 3; Florida Power &Light for its St. Lucie units 1 and 2; and Northern States Power Company for its Monticello unit
1. If granted, these additional licenses would also extend the lifespans of these units well past the
42-year average. Recent state and Federal policies, including the DOE’s $6 billion Civilian
Nuclear Credit program enacted by the IIJA and the 45U tax credit (discussed below), areintended to support the continued operation of existing nuclear power plants.
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 variable renewable generation, could play a role in future energy
generation. The NRC has issued a final rule certifying the first small modular reactor design. 108
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 by 2050. 109 According
to one survey by the Nuclear Energy Institute, utilities are currently considering building morethan 90 GW of small modular nuclear reactors by 2050. 110
G. 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 the108

88 FR 3287 (January 19, 2023).
Stein, A., Messinger, J., Wang, S., Lloyd, J., McBride, J., Franovich, R. (July 6, 2022).
“Advancing Nuclear Energy: Evaluating Deployment, Investment, and Impact in America's
Clean Energy Future.” Breakthrough Institute. https://thebreakthrough.imgix.net/AdvancingNuclear-Energy_v3-compressed.pdf.
110Derr, E. (July 29, 2022). Energy Studies and Models Show Advanced Nuclear as the
Backbone of Our Carbon-Free Future. Nuclear Energy Institute (NEI).
https://www.nei.org/news/2022/studies-and-models-show-demand-for-adv-nuclear.
75
109This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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. 111
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 fuelis burned is a function of the carbon content of the fuel. The heat content, or the amount ofenergy produced when a fuel is burned, is mainly determined by the carbon and hydrogencontent 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. 112 113 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, andbituminous). 114 The value for petroleum products such as diesel fuel and heating oil is 161 lb
CO2/MMBtu.

111

U.S. Environmental Protection Agency (EPA). Overview of greenhouse gas emissions. July
2021. https://www.epa.gov/ghgemissions/overview-greenhouse-gases#carbon-dioxide.
112
Natural gas is primarily CH4, which has a higher hydrogen to carbon atomic ratio, relative toother fuels, and thus, produces the least CO2 per unit of heat released. In addition to a lower CO2
emission rate on a lb/MMBtu basis, natural gas is generally converted to electricity more
efficiently than coal. According to EIA, the 2020 emissions rate for coal and natural gas were2.23 lb CO2/kWh and 0.91 lb CO2/kWh, respectively.
www.eia.gov/tools/faqs/faq.php?id=74&t=11.
113
Values reflect the carbon content on a per unit of energy produced on a higher heating value(HHV) combustion basis and are not reflective of recovered useful energy from any particulartechnology.
114
Energy Information Administration (EIA). Carbon Dioxide Emissions Coefficients.
https://www.eia.gov/environment/emissions/co2_vol_mass.php.
76
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

The EPA prepares the official U.S. Inventory of Greenhouse Gas Emissions and Sinks 115(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, isorganized by industrial sectors. It presents total U.S. anthropogenic emissions and sinks 116 of
GHGs, including CO2 emissions, for the years 1990–2020.
According to the latest inventory, in 2021, total U.S. GHG emissions were 6,340 million
metric tons of carbon dioxide equivalent (MMT CO2e). The transportation sector (28.5 percent)was the largest contributor to total U.S. GHG emissions, followed by the power sector (25.0
percent) and industrial sources (23.5 percent). In terms of annual CO2 emissions, the power
sector was responsible for 30.6 percent (1,541 MMT CO2e) of the nation’s 2021 total.
CO2 emissions from the power sector have declined by 36 percent since 2005 (when the
power sector reached annual emissions of 2,400 MMT CO2, its historical peak to date). 117 The
reduction in CO2 emissions can be attributed to the power sector’s ongoing trends away fromcarbon-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. 118 This total
dropped to 1,351 MMT in 2015 and reached 974 MMT in 2019, the first time since 1978 thatcoal-fired CO2 emissions were below 1,000 MMT. In 2020, emissions of CO2 from coal-fired

115

U.S. Environmental Protection Agency (EPA). Inventory of U.S. Greenhouse Gas Emissions
and Sinks: 1990–2021. https://cfpub.epa.gov/ghgdata.
116
Sinks are a physical unit or process that stores GHGs, such as forests or underground or deepsea reservoirs of carbon dioxide.
117
U.S. Environmental Protection Agency (EPA). Inventory of U.S. Greenhouse Gas Emissions
and Sinks: 1990–2020.
https://cfpub.epa.gov/ghgdata/inventoryexplorer/#electricitygeneration/entiresector/allgas/category/all.
118
U.S. Energy Information Administration (EIA). Monthly Energy Review, table 11.6.
September 2022. https://www.eia.gov/totalenergy/data/monthly/pdf/sec11.pdf.
77
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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). 119 Instead, even in theabsence of Federal regulations for existing EGUs, annual CO2 emissions from sources coveredby 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, orapproximately 21 percent below 2005 levels. However, progress in emission reductions is not
uniform across all states and so Federal policies play an essential role. As discussed earlier inthis section, the power sector remains a leading emitter of CO2 in the U.S., and, despite theemission reductions since 2005, current CO2 levels continue to endanger human health andwelfare. 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.

119

80 FR 63662 (October 23, 2015).

78

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

H. The Legislative, Market, and State Law Context
1. Recent Legislation Impacting the Power Sector
On November 15, 2021, President Biden signed the IIJA 120 (also known as the Bipartisan
Infrastructure Law), which allocated more than $65 billion in funding via grant programs,
contracts, cooperative agreements, credit allocations, and other mechanisms to develop andupgrade infrastructure and expand access to clean energy technologies. Specific objectives of thelegislation are to improve the nation’s electricity transmission capacity, pipeline infrastructure,and increase the availability of low-GHG fuels. Some of the IIJA programs 121 that will impact
the utility power sector include: $16.5 billion to build and upgrade the nation’s electric grid; $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 existinghydroelectric fleet. The IIJA established the Carbon Dioxide Transportation Infrastructure
Finance and Innovation Program to provide flexible Federal loans and grants for building CO2
pipelines designed with excess capacity, enabling integrated carbon capture and geologic
storage. The IIJA also allocated $21.5 billion to fund new programs to support the development,
demonstration, and deployment of clean energy technologies, such as $8 billion for thedevelopment of regional clean hydrogen hubs. Other clean energy technologies with IIJA
funding include carbon capture, geologic sequestration, direct air capture, grid-scale energy
storage, and advanced nuclear reactors. States, tribes, local communities, utilities, and others are
eligible to receive funding.

120

https://www.congress.gov/bill/117th-congress/house-bill/3684/text.
https://gfoaorg.cdn.prismic.io/gfoaorg/0727aa5a-308f-4ef0-addf-140fd43acfb5_BUILDINGA-BETTER-AMERICA-V2.pdf.
79121This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

The IRA, which President Biden signed on August 16, 2022, 122 has the potential for evengreater 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 significant investments in non GHG-emitting generation. For example, one of
the conditions set by Congress for the expiration of the Clean Electricity Production Tax Creditsof 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 useof CAA regulatory authority. In particular, CAA section 135, added by IRA section 60107,
requires the EPA to conduct an assessment of the GHG emission reductions expected to occur
from changes in domestic electricity generation and use through fiscal year 2031 and, further,
provides the EPA $18 million “to ensure that reductions in [GHG] emissions are achieved
through use of the existing authorities of [the Clean Air Act], incorporating the assessment….”
CAA section 135(a)(6).
The IRA’s provisions also demonstrate an intent to support development and deploymentof low-GHG emitting technologies in the power sector 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 useof coal and natural gas as part of a low-GHG electricity grid. Finally, with provisions such as the122

https://www.congress.gov/bill/117th-congress/house-bill/5376/text.
80

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Methane Emissions Reduction Program, Congress demonstrated a focus on the importance ofactions to address methane emissions from petroleum and natural gas systems.
To assist states and utilities in their decarbonizing efforts, and most germane to these
proposed rulemakings, the IRA increased the tax credit incentives for capturing and storing CO2,
including from industrial sources, coal-fired steam generating units, and natural gas-fired
stationary combustion turbines. The increase in credit values, found in section 13104 (whichrevises 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
incidentally in conjunction with enhanced oil recovery (EOR). 123 The CCUS incentives include
12 years of credits that can be claimed at the higher credit value beginning in 2023 for qualifying
projects. These incentives will significantly cut costs and are expected to accelerate the adoptionof CCS in the utility power and other industrial sectors. Specifically for the power sector, theIRA requires that a qualifying carbon capture facility have a CO2 capture design capacity of notless than 75 percent of the baseline CO2 production of the unit and that construction must begin
before January 1, 2033. Tax credits under 45Q can be combined with other tax credits, in somecircumstances, and with state-level incentives, including California’s low carbon fuel standard
which is a market-based program with fuel-specific carbon intensity benchmarks. 124 The
magnitude of this incentive is driving investment and announcements, evidenced by theincreased number of permit applications for geologic sequestration.

123

26 U.S.C. 45Q.
Global CCS Institute. (2019). The LCFS and CCS Protocol: An Overview for Policymakers
and Project Developers. Policy report. https://www.globalccsinstitute.com/wpcontent/uploads/2019/05/LCFS-and-CCS-Protocol_digital_version-2.pdf.
81124This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 CO2equivalent 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 aremet). 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 are approximately $5/kg
H2. 125 These production costs could decline by 2025 to between $2.5 and $2.7/kg H2 (notincluding the production tax credits). 126
The clean hydrogen production tax credit is expected to incentivize the production of
low-GHG hydrogen and ultimately exert downward pressure on costs. 127 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.

125

U.S. Department of Energy (DOE). Hydrogen and Fuel Cell Technologies Office. Hydrogen
Shot. https://www.energy.gov/eere/fuelcells/hydrogen-shot.
126
U.S. Department of Energy (DOE). Pathways to Commercial Liftoff: Clean Hydrogen, March
2023. https://www.energy.gov/articles/doe-releases-new-reports-pathways-commercial-liftoffaccelerate-clean-energy-technologies.
127
Larsen, J., King, B., Kolus, H., Dasari, N., Hiltbrand, G., Herndon, W. (August 12, 2022). A
Turning Point for US Climate Progress: Assessing the Climate and Clean Energy Provisions in
the Inflation Reduction Act. Rhodium Group. https://rhg.com/research/climate-clean-energyinflation-reduction-act/.
82
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Both IRC 45Q and 45V are eligible for additional provisions that increase the value andusability of the credits. Certain tax-exempt entities, such as electric co-ops, may use direct pay
for the full 12- or 10-year lifetime of the credits to monetize the credits directly as cash refunds
rather than through tax equity transactions. Tax-paying entities may elect to have direct paymentof 45Q or 45V credits for five consecutive years. Tax-paying entities may also elect to transfer
credits to unrelated taxpayers, enabling direct monetization of the credits again without relying
on tax equity transactions.
The production tax credit is not the only provision in the IRA designed to incentivize
low-GHG hydrogen. Projects may also access an investment tax credit (ITC) under IRC section
48. For example, manufacturers of clean hydrogen production equipment, like electrolyzers, may
apply under IRC section 48C (the Advanced Manufacturing Tax Credit). And the manufacturing
facility for electrolyzers could receive credits under section 48C while the resulting hydrogenproduction facility could then earn credits under section 45V (this form of stacking is allowed bystatute). However, the same project may not claim ITC credits under section 48C while claiming
PTC credits under section 45V. Projects may not generally combine credits from IRC section
45V with credits in IRC section 45Q. Hydrogen production tax credits became available in
January 2023 for eligible new projects. Entities that commence construction between 2023 and2032 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 $1.5 billion for electrolyzer advancement—should accelerate the83This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

production of low-GHG hydrogen for use in a broad range of applications across many sectors,
including the utility power sector. 128
Many of the IRA tax credit incentives are directed toward low- and zero-emission 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, andthe energy efficiency tax credits are designed to reduce electricity demand. These financial tools
have been used historically and shown to be a principal policy driver, buttressed by state
renewable and clean energy standards, for incentivizing deployment of low- and zero-emitting
generation. 129 130
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 zero- or low-GHG
emissions energy sources. 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 thecredit amount to $27.50/MWh for facilities meeting certain wage and apprenticeshiprequirements. For context, the energy price in the nation’s largest wholesale energy market,
PJM, 131 is typically between $20/MWh and $90/MWh depending on timing, load, andtransmission congestion.

128

U.S. Department of Energy (DOE). Pathways to Commercial Liftoff: Clean Hydrogen, March
2023. https://www.energy.gov/articles/doe-releases-new-reports-pathways-commercial-liftoffaccelerate-clean-energy-technologies.
129
Impacts of Federal Tax Credit Extensions on Renewable Deployment and Power Sector
Emissions, National Renewable Energy Laboratory (NREL), February 2016.
130
A Retrospective Assessment of Clean Energy Investments in the Recovery Act, February 2016,
U.S. Executive Office of the President, Memorandum.
131
PJM Interconnection LLC (PJM) is a regional transmission organization (RTO) serving all orparts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina,
Ohio, Pennsylvania, Tennessee, Virginia, West Virginia, and the District of Columbia.
84
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

In parallel, the existing investment tax credits in section 13101 (IRC section 48) werealso expanded and extended in the IRA. Taxpayers must elect between the ITC and the PTC foreach applicable project. The ITC enables taxpayers to recoup up to 30 percent of project costs fortechnologies such as solar, geothermal, fiberoptic solar, fuel cells, microturbines, small wind,offshore wind, combined heat and power (CHP), and waste energy recovery for investments
meeting certain wage and apprenticeship requirements. There are also a range of bonus credits
available if certain criteria are met, for example for meeting domestic content and energy
communities’ requirements with each earning an additional 10 percent credit. The IRA expanded
eligibility to include storage technologies as well as some non-storage technologies.
The IRA also tied the availability of tax credits explicitly to reductions of GHG emissions
from the power sector. Sections 13701 and 13702 enacted technology-neutral production andinvestment tax credits for projects placed in service after 2025 that have GHG emissions rates ofzero or less. These credits are available until the phaseout is triggered when the power sector’s
GHG emissions fall below 25 percent of 2022 levels.
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 theircontribution to base load zero-carbon emitting electricity. When labor and apprenticeshiprequirements are met, the credit price is $15/MWh. The credit amount declines when grossreceipts of services provided with electricity rise above a specified level. The program begins in
2024 with credit streams available for nine years. This PTC is complementary to the $6 billion
for nuclear advancements the IIJA authorized and appropriated to the DOE. New nuclear plants,
including small modular reactors, would be eligible for either the technology-neutral Clean
Electricity Production or Investment Credit (IRC section 45Y and 48E).
85
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 notevaluated the new generation technologies that entities could employ as alternatives to fossil
fuel-fired EGUs in its assessment of the BSER. As the discussion of that assessment will makeclear later in this preamble, the EPA’s inquiry has focused on “measures that improve thepollution performance of individual sources.” 132 However, these overarching incentives andpolicies are important context for this rulemaking.
The following section (section IV.E.2) includes a review of integrated resource plans(IRPs) filed by public utilities that prioritize GHG reductions. IRPs demonstrate how utilities
plan to meet future forecasted energy demand while ensuring reliable and cost-effective service.
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 ofrenewable resources, energy storage, other non-emitting technologies, and natural gas-fired
combustion turbines. Many IRPs further demonstrate the realization of power companies that tomeet their GHG reduction targets, their natural gas-fired assets will need to occupy a muchsmaller 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 fossilrelated properties, the IRA created grant and loan funding sources for hard-to-abate energy
assets. Section 22004 of the IRA authorizes $9.7 billion in financing for rural electric cooperatives and providers to invest in cleaner technologies to achieve GHG reductions across132

West Virginia v. EPA, 142 S. Ct. 2587, 2615 (2022).
86This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

rural electric systems while buttressing resilience and reliability. Additionally, section 50144 of
the IRA, known as the Energy Infrastructure Reinvestment Financing provision, provides $5billion for backing $250 billion in low-cost loans for utilities to repower, repurpose, or replace
existing infrastructure that has ceased operations, or to enable operating energy infrastructure to
reduce air pollution or GHG emissions. The financing in this provision enables a utility torepurpose an existing fossil site, such as a retired coal-fired power plant, or add CCS, renewablegeneration, or hydrogen capability to an operating coal- or natural gas-fired power plant andretain community jobs while reducing GHG emissions.
2. 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 tovoluntarily cease operating coal-fired generation and move toward zero- and low-GHG energy
generation. Many utilities and other power generators have announced plans to increase theirrenewable 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 have announced CO2 reduction goals, two-thirds of which include netzero carbon emissions by 2050. 133 This trend is not unique to the largest owner-operators of coal-133

See Comments of Edison Electric Institute to EPA’s Pre-Proposal Docket on Greenhouse Gas
Regulations for Fossil Fuel-fired Power Plants, Docket ID No. EPA-HQ-OAR-2022-0723,
November 18, 2022 (“Fifty EEI members have announced forward-looking carbon reduction
goals, two-third of which include a net-zero by 2050 or earlier equivalent goal, and members areroutinely increasing the ambition or speed of their goals or altogether transforming them into netzero goals.”).
87

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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-freeby 2050. This includes a commitment to close or repower all remaining coal-fired EGUs
by 2030. 134•

DTE Energy: 65 percent reduction in CO2 emissions by 2028, 90 percent reduction by
2040, and net-zero carbon emissions by 2050. 135•

Ameren Energy: 60 percent reduction in CO2 by 2030, 85 percent reduction by 2040, andnet-zero carbon emissions by 2045. 136•

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. 137

134

Xcel Energy is based in Minnesota with operations in Colorado, Michigan, New Mexico,
North Dakota, South Dakota, Texas, and Wisconsin. 2018 Integrated Resource Plan athttps://www.xcelenergy.com/staticfiles/xeresponsive/Company/Rates%20&%20Regulations/Resource%20Plans/2018-SPS-NMIntegrated-Resource-Plan.pdf.
135
DTE Energy is based in Michigan. Our Bold Goal for Michigan’s Clean Energy Future athttps://dtecleanenergy.com/.
136
Ameren is based in Illinois and Missouri. 2022 Integrated Resource Plan athttps://www.ameren.com/missouri/company/environment-and-sustainability/integrated-resourceplan.
137
Consumers Energy is based in Michigan. Integrated Resource Plan athttps://s26.q4cdn.com/888045447/files/doc_presentations/2021/06/2021-Integrated-ResourcePlan.pdf.
88This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

•Southern Company: 50 percent reduction in CO2 by 2030 (relative to 2007 levels) andnet-zero carbon emissions by 2050. 138•

Duke Energy: 70 percent reduction in CO2 by 2030 and net-zero carbon emissions by
2050. All coal-fired units will retire by 2035. 139•

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. 140•

First Energy: 30 percent reduction in CO2 by 2030 (relative to 2019 levels) and net-zerocarbon emissions by 2050. 141•

American Electric Power: 80 percent reduction in CO2 by 2030 and net-zero carbon
emissions by 2045. 142•

Alliant Energy: 50 percent reduction in CO2 by 2030 and net-zero carbon emissions by
2050; will retire final coal-fired EGU by 2040. 143

138

Southern Company is based in Georgia with operations in Alabama and Mississippi.
https://www.southerncompany.com/sustainability/net-zero-and-environmental-priorities/netzero-transition.html.
139
Duke Energy is based in North Carolina with operations in South Carolina, Florida, Indiana,
Ohio, and Kentucky. NC IRP Fact Sheet at https://p-scapi.duke-energy.com/-/media/pdfs/ourcompany/202296-nc-irp-fact-sheet.pdf.
140
Allete Energy is based in Minnesota with operations in Wisconsin and North Dakota.
Integrated Resource Plan at:https://www.edockets.state.mn.us/EFiling/edockets/searchDocuments.do?method=showPoup&documentId=%7b70795F77-0000-C41E-A71C-FD089119967C%7d&documentTitle=20212170583-01.
141
First Energy is based in Ohio with operations in Pennsylvania, West Virginia, and New
Jersey. https://www.firstenergycorp.com/content/dam/environmental/files/climate-strategy.pdf.
142
American Electric Power (AEP) is based in Ohio with operations in Arkansas, Indiana,
Kentucky, Louisiana, Michigan, Oklahoma, Tennessee, Texas, Virginia, and West Virginia.
Clean Energy Future at https://www.aep.com/about/ourstory/cleanenergy.
143
Alliant Energy has operations in Iowa and Wisconsin. See Our Sustainable Energy Plan athttps://www.alliantenergy.com/cleanenergy/ourenergyvision/poweringwhatsnext/sustainableener
gyplan.
89
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

•Tennessee Valley Authority: 70 percent reduction in CO2 by 2030, 80 percent reduction by2035, and net-zero carbon emissions by 2050. 144•

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. 145
The geographic footprint of zero or net-zero carbon commitments made by utilities, theirparent companies, or in response to a state clean energy requirement, covers portions of 47 statesand includes 75 percent of U.S. customer accounts. 146 These statements are often made as part oflong-term planning processes with considerable stakeholder involvement, including regulators.
3. State Actions to Reduce Power Sector GHG Emissions
States across the country have taken the lead in efforts to reduce GHG emissions from thepower sector. These actions include commitments that require utilities to expand renewable andclean 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.
Twenty-nine states and the District of Columbia have enforceable RPS. 147 RPS require apercentage of electricity that utilities sell to come from eligible renewable sources like wind and144

Tennessee Valley Authority (TVA) is based in Tennessee with operations in Alabama,
Georgia, Kentucky, Mississippi, North Carolina, and Virginia. See
https://www.tva.com/newsroom/press-releases/tva-charts-path-to-clean-energy-future.
145
NextEra Energy. See https://newsroom.nexteraenergy.com/2022-06-14-NextEra-Energy-setsindustry-leading-Real-Zero-TM-goal-to-eliminate-carbon-emissions-from-its-operations,leverage-low-cost-renewables-to-drive-energy-affordability-for-customers.
146
Smart Electric Power Alliance Utility Carbon Tracker. See https://sepapower.org/utilitytransformation-challenge/utility-carbon-reduction-tracker/. Accessed January 12, 2023.
147
DSIRE, Renewable Portfolio Standards and Clean Energy Standards (2022).
https://ncsolarcen-prod.s3.amazonaws.com/wp-content/uploads/2022/11/RPS-CESNov2022.pdf.
90This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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, andVermont—have RPS targets greater than or equal to 70 percent but below 100 percent, and threestates—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 theDistrict 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 underan 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. RPS in some other states
include landfill gas, animal wastes, CHP, and energy efficiency. 148
States are also shifting their generating fleets away from fossil fuel generating resources
through the adoption of CES. A CES requires a percentage of retail electricity to come fromsources 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 those148

NCSL (2021). State Renewable Portfolio Standards and Goals.
https://www.ncsl.org/research/energy/renewable-portfolio-standards.aspx.
91

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 withmost 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 tostate. One key difference between an RPS and a CES is the extent to which a CES can allow forresources 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 economy-wide 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 renewablesources by 2030 and plan for 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 likemethane by 40 to 50 percent below 2013 levels by 2030. 149 Achieving California’s establishedgoal of carbon-free electricity by 2045 requires emissions to be balanced by carbon
sequestration, capture, or other technologies. Senate Bill 905, passed in 2022, requires the149

Berkeley Law. California Climate Policy Dashboard.
https://www.law.berkeley.edu/research/clee/research/climate/climate-policy-dashboard.
92

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

California Air Resources Board to establish programs for permitting CCS projects. 150 Senate Bill
905, also passed in 2022, prevents the use of captured CO2 for enhanced oil recovery within
California.
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 renewableenergy 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. 151
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. 152
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 nuclear plants facedownward economic pressures resulting from ultra-low natural gas spot prices combined withincreasing NGCC capacity. Between 2016 and 2021, New York, New Jersey, Connecticut, andIllinois took action to retain their nuclear power stations by providing state-level financial
incentives. Retention of nuclear power plants is another strategy that some states have used to150

Berkeley Law. California Climate Policy Dashboard.
https://www.law.berkeley.edu/research/clee/research/climate/climate-policy-dashboard.
151
New York State. Our Progress. https://climate.ny.gov/Our-Progress.
152
Department of Ecology Washington State. Greenhouse Gases. https://ecology.wa.gov/AirClimate/Climate-change/Tracking-greenhouse-gases.
93
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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. 153
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, andnatural gas-fired plants to reach zero carbon emissions by 2045. 154 On October 13, 2021, North
Carolina passed House Bill 951 that required the North Carolina Utilities Commission to “takeall 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.” 155
I. 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 ongoingtransition 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

153

http://uscode.house.gov/view.xhtml?req=(title:26%20section:45U%20edition:prelim).
State of Illinois General Assembly. Public Act 102-0662: Climate and Equitable Jobs Act.
2021. https://www.ilga.gov/legislation/publicacts/102/PDF/102-0662.pdf.
155
General Assembly of North Carolina, House Bill 951 (2021).
https://www.ncleg.gov/Sessions/2021/Bills/House/PDF/H951v5.pdf.
94154This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

regulation), provides projections out to 2050 on future outcomes of the electric power sector. For
more information on the details of this modeling, see the model documentation. 156
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 157 158 and participated inpublic events exploring modeling assumptions for the IRA. 159 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 andperformance assumptions about all relevant technologies, including carbon capture, renewables,
energy storage and other generation technologies.

156

U.S. Environmental Protection Agency. Post-IRA 2022 Reference Case
EPA's Power Sector Modeling Platform v6 Using IPM. April 2023. https://www.epa.gov/powersector-modeling/post-ira-2022-reference-case.
157
Bistline, et al. (2023). “Emissions and Energy System Impacts of the Inflation Reduction Act
of 2022,” Under Review.
158
Bistline, et al. (2023). “Power Sector Impacts of the Inflation Reduction Act of 2022,” In
Preparation.
159
Resource for the Future (2023). “Future Generation: Exploring the New Baseline forElectricity in the Presence of the Inflation Reduction Act.” https://www.rff.org/events/rfflive/future-generation-exploring-the-new-baseline-for-electricity-in-the-presence-of-theinflation-reduction-act/.
95This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

While much of the discussion below focuses on the EPA’s post-IRA 2022 reference case,many other analyses show similar trends, 160 and these trends are consistent with utility IRPs andpublic GHG reduction commitments, as well as state actions, both of which were described in
the previous sections.
1. Projections for Coal-fired Generation
In the post-IRA 2022 reference case, coal-fired steam EGU capacity is projected to fallfrom 210 GW in 2021 161 to 44 GW in 2035, of which 11 GW includes retrofit CCS. Generationfrom coal-fired steam generating units is projected to also fall from 898 thousand GWh in
2021 162 to 120 thousand GWh by 2035. This change in generation reflects the anticipatedcontinued decline in projected coal-fired steam generating unit capacity as well as a steadydecline in annual operation of those EGUs that remain online, with capacity factors falling fromapproximately 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 thecontinental U.S. These projections are driven by the eroding economic opportunities for coalfired 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, likenatural gas, renewable technologies, and energy storage.

160

A wide variety of modeling teams have assessed baselines with IRA. The baseline estimatedhere is generally in line with these other estimates. Bistline, et al. (2023). “Power Sector Impactsof the Inflation Reduction Act of 2022,” In Preparation.
161
U.S. Energy Information Administration (EIA), Electric Power Annual, table 4.3. November
2022. https://www.eia.gov/electricity/annual/.
162
U.S. Energy Information Administration (EIA), Electric Power Annual, table 3.1.A.
November 2022. https://www.eia.gov/electricity/annual/.
96
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

In 2020, there was a total of 1,439 million metric tons of CO2 from the power sector withcoal-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 tons by 2035,of which 8 percent is projected to come from coal-fired sources in 2035.
2. Projections for Natural Gas-fired Generation
As described in 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 comeonline by 2035 and 309 GW of new capacity by 2050. By 2035, the new natural gas capacity iscomprised 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 justfrom 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.
It should be noted that despite this increase in capacity, both overall generation andemissions from the natural gas-fired capacity are projected to decline. Generation from natural
gas units is projected to fall from 1,579 thousand GWh in 2021 163 to 1,402 thousand GWh by2035. Power sector related CO2 emissions from natural gas-fired EGUs were 615 million metrictons in 2021. 164 By 2035, emission levels are projected to reach 527 million metric tons, 93
percent of which comes from NGCC sources.

163

U.S. Energy Information Administration (EIA), Electric Power Annual, table 3.1.A.
November 2022. https://www.eia.gov/electricity/annual/.
164
U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emission Sources
and Sinks. February 2023. https://www.epa.gov/system/files/documents/2023-02/US-GHGInventory-2023-Main-Text.pdf
97This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 theseunits 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 theircapacity factors are already below 10 percent annually, their impact on generation and emissionschanges are less notable.
Some of the reasons for this continued growth in natural gas-fired capacity include
anticipated 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 withenergy storage technologies, support the expansion of renewable electricity by meeting demandduring peak periods and providing flexibility around the variability of renewable generation andelectricity demand. In the longer term, as renewables and battery storage grow, they are
anticipated to outcompete the need for natural gas-fired generation and the overall utilization ofnatural gas-fired capacity is expected to decline.
3. 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. 165 The EIA projects utility-

165

U.S. Energy Information Administration (EIA). Short-Term Energy Outlook, March 2023.
https://www.eia.gov/outlooks/steo/.
98
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

scale solar capacity to grow by approximately 29 GW in 2023 and by 35 GW in 2024 wind
generating capacity to grow by 7 GW in 2023 and by 7.5 GW in 2024. 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, shows that this short-term trend in
renewable capacity 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 caseshows 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. 166 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.
4. Projections for Energy Storage
According to EIA, the capacity of battery energy storage is expected to increase by 10times between 2019 and 2023, of which 6 GW of battery storage capacity is planned to be colocated with solar generation. 167 The benefit of paring energy storage systems with solar capacity
deployment is that the batteries can recharge throughout the middle of the day when surplus
energy is available. Then this stored energy can be discharged during peak hours, supporting grid

166

U.S. Energy Information Administration (EIA), Electric Power Annual, table 4.3. November
2022. https://www.eia.gov/electricity/annual/.
167
U.S. Energy Information Administration (EIA). Preliminary Monthly Electric Generator
Inventory, December 2020 Form EIA-860M.
https://www.eia.gov/analysis/studies/electricity/batterstorage/.
99
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

reliability and potentially displacing higher emitting 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 the
integration of renewable technologies 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.
5. 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 forthe next 5–10 years. 168 169 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 morethan 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,

168“Constellation Making Major Investments in Two Illinois Nuclear Plants to Increase Clean
Energy Output.” Constellation Energy Corporation. February 21, 2023.
https://www.constellationenergy.com/newsroom/2023/Constellation-Making-Major-Investmentin-Two-Illinois-Nuclear-Plants-to-Increase-Clean-Energy-Output.html.
169
Singer, S. (February 22, 2023). PSEG to consider nuclear plant investments, capitalizing on
the IRA’s production tax credits, CEO says. Utility Dive. https://www.utilitydive.com/news/psegira-nuclear-production-tax-credits/643221/.
100
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

output from advanced nuclear generation could range from negligible to as high as 3,600
terawatt-hours per year by 2050. 170
V. Statutory Background and Regulatory History for CAA Section 111
A. Statutory Authority to Regulate GHGs from EGUs under CAA Section 111
The EPA’s authority for and obligation to issue these proposed rules is CAA section 111,
which establishes mechanisms for controlling emissions of air pollutants from new and existingstationary sources. CAA section 111(b)(1)(A) requires the EPA Administrator to promulgate alist 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 toendanger 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 distinguishamong classes, types, and sizes within categories in establishing the standards.
1. Regulation of Emissions From New Sources
Once the EPA lists a source category, the EPA must, under CAA section 111(b)(1)(B),
establish “standards of performance” for 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 iscommenced after the publication of regulations (or, if earlier, proposed regulations) prescribing astandard 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),170“Advancing Nuclear Energy Evaluating Deployment, Investment, and Impact in America’s
Clean Energy Future” Breakthrough Institute, July 6, 2022.
101
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

“modification” means any physical change in, or change in the method of operation of, astationary 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 tomeet the applicable standards. Pursuant to CAA section 111(b)(1)(B), the standards ofperformance or revisions thereof shall become effective upon promulgation.
The standards of performance for new sources are referred to as new source performancestandards, 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 theapplication of the best system of emission reduction which (taking into account the cost ofachieving 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 theapplication 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
102
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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”—theNSPS—that reflect that level of stringency.
2. Regulation of Emissions From Existing Sources
When the EPA establishes a standard for emissions of an air pollutant from new sources
within a category, it must also, under CAA section 111(d), regulate emissions of that pollutant
from existing sources within the same category, unless the pollutant is regulated under the
National Ambient Air Quality Standards (NAAQS) program, under CAA sections 108–110, or
the National Emission Standards for Hazardous Air Pollutants (NESHAP) program, under CAA
section 112. See CAA section 111(d)(1)(A)(i) and (ii); West Virginia, 142 S. Ct. at 2601.
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 ofstringency. However, the states need not compel regulated sources to adopt the particular103
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

components of the BSER itself. The EPA’s emission guidelines must also permit a state, “inapplying 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 theplan 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 orsubmits a plan that the EPA does not find “satisfactory,” the EPA must promulgate a plan that
establishes Federal standards of performance for the state’s existing sources. CAA section
111(d)(2)(A).
3. EPA Review of Requirements
CAA section 111(b)(1)(B) requires the EPA to “at least every 8 years, review and, if
appropriate, revise” new source performance standards. However, the Administrator need notreview any such standard if the “Administrator determines that such review is not appropriate inlight of readily available information on the efficacy” of the standard. Id. When conducting areview 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 notby its terms require the EPA to review emission guidelines for existing sources, but the EPA
retains the authority to do so. See 81 FR 59276, 59277 (August 29, 2016) (explaining legal
authority to review emission guidelines for municipal solid waste landfills).
B. History of EPA Regulation of Greenhouse Gases From Electricity Generating Units Under
CAA Section 111 and Caselaw
The EPA has listed more than 60 stationary source categories under CAA section
111(b)(1)(A). See 40 CFR part 60, subparts Cb–OOOO. In 1971, the EPA listed fossil fuel-fired
104
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 fuelfired EGUs. The first promulgated standards of performance for new fossil fuel-fired EGUs.
“Standards of Performance for Greenhouse Gas Emissions From New, Modified, andReconstructed Stationary Sources: Electric Utility Generating Units; Final Rule,” (80 FR 64510;
October 23, 2015) (2015 NSPS). The second promulgated emission guidelines for existingsources. “Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility
Generating Units; Final Rule,” (80 FR 64662; October 23, 2015) (Clean Power Plan, or CPP).
1. 2015 NSPS
In 2015, the EPA promulgated an NSPS to limit emissions of GHGs, manifested as 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 reconstructedstationary 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 and105
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 lessthan 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 andreconstructed stationary combustion turbine EGUs. For newly constructed and reconstructedbase 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 multifuel-fired stationary combustion turbines, the EPA finalized a heat input-based standard based on
the use of lower emitting fuels (referred to as clean fuels in the 2015 NSPS). The EPA did not
promulgate final standards of performance for modified stationary combustion turbines due tolack 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.
106
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Multiple parties also filed petitions for judicial review of the 2015 NSPS in the D.C.
Circuit. These cases have been briefed and, on the EPA's motion, are being held in abeyance
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 adetermination that GHGs from EGUs contribute significantly to dangerous air pollution (apollutant-specific significant contribution finding), but in the alternative, the EPA did make thatfinding. It explained that “[greenhouse gas] air pollution may reasonably be anticipated toendanger public health or welfare,” 80 FR 64530 (October 23, 2015) and emphasized that power
plants are “by far the largest emitters” of greenhouse gases among stationary sources in the U.S.
Id. at 64522. In American Lung Ass’n v. EPA, 985 F.3d 977 (D.C. Cir. 2021), the court held thateven 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 thealternative 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 thosedeterminations 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 todangerous air pollution.

107
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

2. 2018 Proposal to Revise the 2015 NSPS
In 2018, the EPA proposed to revise the NSPS for new, modified, and reconstructedfossil fuel-fired steam generating units and IGCC units. “Review of Standards of Performancefor Greenhouse Gas Emissions From New, Modified, and Reconstructed Stationary Sources:
Electric Utility Generating Units; Proposed Rule,” (83 FR 65424; December 20, 2018) (2018
NSPS Proposal). The EPA proposed to revise the NSPS for newly constructed units, based on arevised BSER of a highly efficient SCPC, without partial CCS. The EPA also proposed to revise
the NSPS for modified and reconstructed units. The EPA has not taken further action on this
proposed rule. 171
3. Clean Power Plan
With the promulgation of the 2015 NSPS, the EPA also incurred a statutory obligation
under CAA section 111(d) to issue emission guidelines for GHG emissions from existing fossil
fuel-fired steam generating EGUs and stationary combustion turbine EGUs, which the EPA
initially fulfilled with the promulgation of the CPP. See 80 FR 64662 (October 23, 2015). The
EPA first determined that the BSER included three types of measures: (1) Improving heat rate(i.e., the amount of fuel that must be burned to generate a unit of electricity) at coal-fired steam
plants; (2) substituting increased generation from lower-emitting NGCC plants for generation

171

In the 2018 NSPS Proposal, the EPA solicited comment on whether it is required to make adetermination that GHGs from a source category contribute significantly to dangerous air
pollution as a predicate to promulgating a NSPS for GHG emissions from that source category
for the first time. 83 FR 65432 (December 20, 2018). The EPA subsequently issued a final rulethat provided that it would not regulate GHGs under CAA section 111 from a source category
unless the GHGs from the category exceed 3 percent of total U.S. GHG emissions, on grounds
that GHGs emitted in a lesser amount do not contribute significantly to dangerous air pollution.
86 FR 2652 (January, 13 2021). Shortly afterwards, the D.C. Circuit granted an unopposed
motion by the EPA for voluntary vacatur and remand of the final rule. California v. EPA, No.
21-1035, doc. 1893155 (D.C. Cir. April 5, 2021).
108
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 higheremitting 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 generationshifting, including its cost-effectiveness, against the relevant statutory criteria for BSER and on alegal interpretation that the term “system” in CAA section 111(a)(1) is sufficiently broad toencompass 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 limitationachievable 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 astate 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 theirstate 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, andultimately dismissed it, as the EPA reassessed its position. American Lung Ass’n, 985 F.3d at
937.
109This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

4. The CPP Repeal and ACE RuleIn 2019, the EPA repealed the CPP and replaced it with the ACE Rule. In contrast to its
interpretation of CAA section 111 in the CPP, in the ACE Rule the EPA determined that thestatutory “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 thelevel of the individual source,” (84 FR 32529; July 8, 2019); that is, the system must be limited
to control measures that could be applied at and to each source to reduce emissions at eachsource. See 84 FR 32523–24 (July 8, 2019). Specifically, the ACE Rule argued that therequirements 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 nodifference 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,

110
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

and the Emission Guidelines for Greenhouse Gas Emissions from Existing Electric Utility
Generating Units, 2-1 to 2-5. 172
In addition, the EPA promulgated in the ACE Rule a new set of emission guidelines forexisting 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 thestandard in the first place,” (84 FR 32556; July 8, 2019), and therefore must “apply at and to anindividual 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), andtrading (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).

172

https://www.epa.gov/sites/default/files/201906/documents/utilities_ria_final_cpp_repeal_and_ace_2019-06.pdf.
111This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

5. D.C. Circuit Decision in American Lung Association v. EPA Concerning the CPP Repeal and
ACE Rule
Numerous states and private parties petitioned for review of the CPP Repeal and ACE
Rule. In 2021, the D.C. Circuit vacated the ACE Rule, including the CPP Repeal. American
Lung Ass’n v. EPA, 985 F.3d 914 (D.C. Cir. 2021). The court held, among other things, that
CAA section 111(d) does not limit the EPA, in determining the BSER, to measures applied atand to an individual source. The court noted that “the sole ground on which the EPA defends its
abandonment of the [CPP] in favor of the ACE Rule is that the text of [CAA section 111] is clear
and unambiguous in constraining the EPA to use only improvements at and to existing sources in
its [BSER].” 985 F.3d at 944. The court found “nothing in the text, structure, history, or purposeof [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 thateach 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; andthe 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 thesystem 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 eachsource 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.

112
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 theindividual 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, thecourt 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 arelimited to measures applied at and to an individual source 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, regardlessof 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 at 995. The
court did not decide, however, “whether the approach of the ACE Rule is a permissible readingof the statute as a matter of agency discretion,” 985 F.3d at 944, and instead “remanded to the
EPA so that the Agency may ‘consider the question afresh,’” 985 F.3d at 995 (citations omitted).
The court also rejected the arguments that the EPA cannot regulate CO2 emissions from coalfired power plants under CAA section 111(d) at all because it had already regulated mercury
emissions from coal-fired power plants under CAA section 112. 985 F.3d at 988. In addition, thecourt held that that the 2015 NSPS included a valid determination that greenhouse gases from the
EGU source category contributed significantly to dangerous air pollution, which provided asufficient basis for a CAA section 111(d) rule regulating greenhouse gases from existing fossil
fuel-fired EGUs. Id. at 977.

113
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 specificdegree of emission limitation.
Upon a motion from the EPA, the D.C. Circuit agreed to stay its mandate with respect tovacatur of the CPP Repeal, American Lung Assn v. EPA, No. 19-1140, Order (February 22,2021), so that the CPP remained repealed. In its motion, the EPA explained that the CPP should
remain repealed because the deadline for states to submit their plans under the CPP had longsince 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.
6. 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 ofemission 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 ofelectricity generation,” and stated that the EPA’s claim that CAA section 111 authorized it to114
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

promulgate generation shifting as the BSER was “not only unprecedented; it also effected afundamental 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 morecleanly.” 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 theoverall power system by lowering the carbon intensity of power generation. And it would do thatby 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 emphasizedthat 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 shareof 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,” butemphasized 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 mustbe, 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 alsoemphasized “the magnitude and consequence” of the CPP. Id. at 2616. It noted “the magnitudeof this unprecedented power over American industry,” id. at 2612 (internal quotation marks and115
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

citation omitted), and added that the EPA’s adoption of generation shifting “represent[ed] atransformative expansion in its regulatory authority.” Id. at 2610 (internal quotation marks andcitation 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-tradescheme, 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, andtherefore, under the major questions doctrine, required “clear congressional authorization” as abasis. 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 ofclear authorization required” under the doctrine, id., and, on that basis, invalidated the CPP.
The Court declined to address the D.C. Circuit’s conclusion that the text of CAA section
111 did not limit the type of “system” the EPA could consider as the BSER to measures applied
at and to an individual source. See id. at 2615 (“We have no occasion to decide whether the
statutory phrase ‘system of emission reduction’ refers exclusively to measures that improve thepollution 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.
C. Detailed Discussion of CAA Section 111 Requirements
This section discusses in more detail the key requirements of CAA section 111 for both
new and existing sources that are relevant for these rulemakings.
116
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

1. Approach to the Source Category and Subcategorizing
CAA section 111 requires the EPA first to list stationary source categories that cause orcontribute 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 tosubcategorize 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).
Although CAA section 111(d)(1) does not by its terms address subcategorization, the
EPA interprets it to authorize the Agency to exercise discretion as to whether and, if so, how tosubcategorize, for the following reasons. CAA section 111(d)(1) provides a broad grant ofauthority to the EPA, directing it to “prescribe regulations which shall establish aprocedure…under which each State shall submit to the Administrator a plan [with standards ofperformance for existing sources.]” The EPA promulgates emission guidelines under thisprovision directing the states to regulate existing sources. The Supreme Court has recognized thebreadth 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 theStates, 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 bestsystem of emission reduction ... that has been adequately demonstrated for [existing
covered] facilities.”

117
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

West Virginia, 142 S. Ct. at 2601–02 (citations omitted). 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 implementing regulations under CAA section 111(d),promulgated in 1975, 40 FR 53340 (November 17, 1975), provide that the Administrator will
specify different emission guidelines or compliance times or both “for different sizes, types, andclasses of designated facilities when costs of control, physical limitations, geographical location,or [based on] similar factors.” 173 In promulgating this provision, the EPA made clear the purposeof subcategorization is to tailor the BSER for different sets of sources:
EPA’s emission guidelines will reflect subcategorization within source categories
where appropriate, taking into account differences in sizes and types of facilities
and similar considerations, including differences in control costs that may be
involved for sources located in different parts of the country. Thus, EPA’semission guidelines will in effect be tailored to what is reasonably achievable byparticular classes of existing sources….
Id. at 53343.
The EPA’s authority to “distinguish among classes, types, and sizes within categories,”
as provided under CAA section 111(b)(2), generally allows the Agency to place types of sources
into subcategories 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

173

40 CFR 60.22(b)(5), 60.22a(b)(5). Because the definition of subcategories depends on
characteristics relevant to the BSER, and because those characteristics can differ as between newand existing sources, the EPA may establish different subcategories as between new and existingsources.
118
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

“type” in CAA section 111(b)(2): “a particular kind, class, or group,” or “qualities common to anumber of individuals that distinguish them as an identifiable class.” See https://www.merriamwebster.com/dictionary/type. That is, subcategorization is appropriate for a set of sources thathave qualities in common that are relevant for determining what controls are appropriate forthose sources. And where the qualities in common are not relevant for determining what controls
are appropriate, subcategorization is not appropriate. This view is consistent with the D.C.
Circuit’s interpretation of CAA section 112(d)(1), which is a subcategorization provision that is
substantially similar 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. 174
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 fuelcombusted, see Sierra Cub, v. EPA, 657 F.2d 298, 318-19 (D.C. Cir. 1981) (upholding arulemaking 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 to174

See Chem. Mfrs. Ass’n v. NRDC, 470 U.S. 116, 131 (1985) (Court interprets similarsubcategorization provision under the Clean Water Act to grant the EPA broad discretion).
119

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

produce products, see 81 FR 35824 (June 3, 2016) (promulgating separate NSPS for many typesof oil and gas sources, such as centrifugal compressors, pneumatic controllers, and well sites);
types of manufacturing processes used to produce product, see 42 FR 12022 (March 1, 1977)(announcing availability of final guideline document for control of atmospheric fluoride
emissions from existing phosphate fertilizer plants) and “Final Guideline Document: Control of
Fluoride Emissions From Existing Phosphate Fertilizer Plants, EPA-450/2-77-005 1-7 to 1-9,
including table 1-2 (applying different control requirements for different manufacturing
operations for phosphate fertilizer); levels of utilization of the sources, see 2015 NSPS, 80 FR
64510, 64602 (table 15) (October 23, 2015) (dividing new natural gas-fired combustion turbines
into the subcategories of base load and non-base load); the activity level of the sources, see 81
FR 59276, 59278-79 (August 29, 2016) (dividing municipal solid waste landfills into thesubcategories of active and closed landfills); 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 new 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. It should also be noted that in some instances, the
EPA has declined to subcategorize. Lignite Energy Council, 198 F.3d at 933 (upholding EPA
decision not to subcategorize utility boilers for purposes of NOX NSPS on grounds that thedecision was not arbitrary and capricious).
120
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Regardless of whether the EPA subcategorizes within a source category for purposes ofdetermining the BSER and the emission performance level for the emission guideline, a stateretains certain flexibility in assigning standards of performance to its affected EGUs. The
statutory framework for CAA section 111(d) emission guidelines, and the flexibilities available
to states within that framework, are discussed below.
2. D.C. Circuit Order to Reinstate the ACE RuleOn October 27, 2022, the D.C. Circuit responded to the U.S. Supreme Court’s reversal byrecalling its mandate for the vacatur of the ACE Rule. American Lung Ass’n v. EPA, No. 191140, 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 theAgency from regulating CO2 from coal-fired electric power plants under CAA section 111, andthe 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
121
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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.
3. 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 the1970 CAAA. The current text of CAA section 111(a)(1) reads: “The term ‘standard of
performance’ means a standard for emission of air pollutants which reflects the degree ofemission 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 healthand environmental impact and energy requirements) the Administrator determines has beenadequately demonstrated.” The D.C. Circuit has reviewed CAA section 111 rulemakings on
numerous occasions since 1973, 175 and has developed a body of caselaw that interprets the term“standard of performance,” as discussed throughout this preamble.
The basis for standards of performance, whether promulgated by the EPA under CAA
section 111(b) or established by the states under CAA section 111(d), is that the EPA determinesthe “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

175

Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375 (D.C. Cir. 1973); Essex Chemical Corp.
v. Ruckelshaus, 486 F.2d 427 (D.C. Cir. 1973); Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir.
1981); Lignite Energy Council v. EPA, 198 F.3d 930 (D.C. Cir. 1999); Portland Cement Ass’n v.
EPA, 665 F.3d 177 (D.C. Cir. 2011); American Lung Ass’n v. EPA, 985 F.3d 914 (D.C. Cir.
2021), rev’d in part, West Virginia v. EPA, 142 S. Ct. 2587 (2022). See also Delaware v. EPA,
No. 13-1093 (D.C. Cir. May 1, 2015).
122
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

requirements,” and that the EPA determines to be the “best.” The D.C. Circuit has stated that indetermining the “best” system, the EPA must also take into account “the amount of air
pollution” 176 reduced and the role of “technological innovation.” 177 The determination of the“best” system entails weighing the various factors against each other, and the D.C. Circuit hasemphasized that the EPA has discretion in weighing the factors. 178 179
The EPA’s overall approach to determining the BSER and degree of emission limitationachievable, which incorporates the various elements, is as follows: The EPA identifies“system[s] of emission reduction” that have been “adequately demonstrated” for a particularsource category and determines the “best” of these systems after evaluating the amount of
reductions, costs, any nonair health and environmental impacts, and energy requirements. As
discussed below, for each of numerous subcategories, the EPA followed this approach to propose
the BSER on the basis that the identified costs are reasonable and that the proposed BSER is
rational in light of the statutory factors and other impacts, including the amount of emission
reductions, that the EPA examined in its BSER analysis, consistent with governing precedent.

176

See Sierra Club v. Costle, 657 F.2d 298, 326 (D.C. Cir. 1981).
See Sierra Club v. Costle, 657 F.2d at 347.
178
See Lignite Energy Council, 198 F.3d at 933.
179
Although CAA section 111(a)(1) may be read to state that the factors enumerated in theparenthetical are part of the “adequately demonstrated” determination, the D.C. Circuit’s caselaw may be read to treat them as part of the “best” determination. See Sierra Club v. Costle, 657
F.2d at 330 (recognizing that CAA section 111 gives the EPA authority “when determining thebest technological system to weigh cost, energy, and environmental impacts”). Nevertheless, itdoes not appear that those two approaches would lead to different outcomes. See, e.g., Lignite
Energy Council, 198 F.3d at 933 (rejecting challenge to the EPA’s cost assessment of the “bestdemonstrated system”). Regardless of whether the factors are part of the “adequately
demonstrated” determination or the “best” determination, our analysis and outcome would be the
same.
123
177

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

After determining the BSER, the EPA determines an achievable emission limit based on
application of the BSER. 180 For a CAA section 111(b) rule, we determine the standard of
performance that reflects the achievable emission limit. For a CAA section 111(d) rule, the states
have the obligation of establishing standards of performance for the affected sources that reflect
the degree of emission limitation that the EPA has determined. As discussed below, the EPA
proposed these determinations in association with each of the proposed BSER determinations.
The remainder of this subsection discusses each element in our general analytical
approach.
a. System of Emission Reduction
The CAA does not define the phrase “system of emission reduction.” In West Virginia v.
EPA, the Supreme Court recognized that historically, the EPA had looked to “measures that
improve the pollution performance of individual sources and followed a “technology-based
approach” in identifying systems of emission reduction. In particular, the Court identified “thesort of ‘systems of emission reduction’ [the EPA] had always before selected,” which included“'efficiency improvements, fuel-switching,’ and ‘add-on controls’.” 142 S. Ct. at 2611 (quoting
the Clean Power Plan). 181 Section 111 itself recognizes that such systems may include off-site
activities that may reduce a source’s pollution contribution, identifying “precombustion cleaning

180

See, e.g., Oil and Natural Gas Sector: New Source Performance Standards and National
Emission Standards for Hazardous Air pollutants Reviews (77 FR 49490, 49494; August 16,2012) (describing the three-step analysis in setting a standard of performance).
181
As noted in section V.B.4 of this preamble, the ACE Rule adopted the interpretation that
CAA section 111(a)(1), by its plain language, limits “system of emission reduction” to thosecontrol measures that could be applied at and to each source to reduce emissions at each source.
84 FR 32523–24 (July 8, 2019). The EPA has proposed to reject that interpretation as too
narrow. See “Implementing Regulations under 40 CFR Part 60 Subpart Ba Adoption andSubmittal of State Plans for Designated Facilities: Proposed Rule,” 87 FR 79176, 79208(December 23, 2022).
124
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

or treatment of fuels” as a “system” of “emission reduction.” 42 U.S.C. 7411(a)(7)(B). A“system of emission reduction” thus, at a minimum, includes measures that an individual source
applies that improve the emissions performance of that source. Measures are fairly characterized
as improving the pollution performance of a source where they reduce the individual source’s
overall contribution to pollution.
In West Virginia, the Supreme Court did not define the term “system of emissions
reduction,” and so did not rule on whether “system of emission reduction” is limited to thosemeasures that the EPA has historically relied upon. It did go on to apply the major questions
doctrine to hold that the term “system” does not provide the requisite clear authorization to
support the Clean Power Plan’s BSER, which the Court described as “carbon emissions caps
based on a generation shifting approach.” Id. at 2614. While the Court did not define the outerbounds of the meaning of “system,” systems of emissions reduction like fuel switching, add-on
controls, and efficiency improvements fall comfortably within the scope of prior practice as
recognized by the Supreme Court.
b. “Adequately Demonstrated”
Under CAA section 111(a)(1), an essential, although not sufficient, condition for a“system of emission reduction” to serve as the basis for an “achievable” emission limitation, isthat 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 ofpollution control without becoming exorbitantly costly in an economic or environmental

125
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

way.” 182 It does not mean that the system “must be in actual routine use somewhere.” 183 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.” 184 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.” 185 Ultimately, the analysis “is partially dependent on ‘lead time,’” that is, “the timein which the technology will have to be available.” 186 The caselaw is clear that the EPA maytreat 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.” Thecourt 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, 198 F.3d at 934(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” througha “reasonable extrapolation of [the control measures’] performance in other industries.” Id.
The D.C. Circuit’s view that the EPA may determine a “system of emission reduction” to

182

Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433 (D.C. Cir. 1973), cert. denied, 416 U.S.
969 (1974).
183
Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375, 391 (D.C. Cir. 1973) (citations
omitted) (discussing the Senate and House bills and reports from which the language in CAA
section 111 grew).
184
Ibid.
185
Sierra Club v. Costle, 657 F.2d 298, 364 (D.C. Cir. 1981).
186
Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375, 391 (D.C. Cir. 1973) (citations
omitted).
126
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

be “adequately demonstrated” if the EPA reasonably projects that it will be available by a futuredate certain, is well-grounded in the purposes of CAA section 111 to reduce dangerous air
pollutants. This view recognizes that pollution control systems may be complex and may requirea predictable amount of time for sources across the source category to be able to design, acquire,
install, and begin to operate them. In some instances, the control technology may be available,
but the installation may be a multi-year process. For example, an existing coal-fired steam
generating unit may require several years to plan, design, and install a Flue Gas Desulfurization(FGD) wet scrubber for the control of sulfur dioxide (SO2) emissions. Under thesecircumstances, common sense dictates that the EPA may promulgate a rulemaking that imposes a
standard on the sources, but establishes the date for compliance as a date-certain in the future,
consistent with the period of time the source needs to install and start operating the control
equipment. In other circumstances, a system of emission reduction may be well-recognized as
effective in controlling pollutants emitted by a large source category, but manufacturers may
require a predictable amount of time to manufacture enough control equipment to cover thesource category. In still other circumstances, the infrastructure needed to support the system sothat it will cover sources across the category – whether physical infrastructure such as pipelines
or human infrastructure such as skilled labor to install the equipment – may require a predictableamount of time to build out or develop in sufficient quantity to achieve such coverage. In all ofthese circumstances, adopting requirements under CAA section 111 at the time that the EPA isable to reasonably project the future deployment of the system of emission reduction, andestablishing the date of compliance as a date-certain in the future, serves the statutory purposesof protecting against dangerous air pollution by ensuring that sources take action to control theiremissions as soon as practicable. It should also be noted that because pollution control invariably
127
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

entails additional cost, in some cases, the EPA’s promulgation of regulatory requirements may
be an essential trigger for the sometimes lengthy process of implementing pollution controls. In
these cases, delaying the promulgation of the regulatory requirements until the pollution controls
can be immediately deployed would be futile.
c. Costs
Under CAA section 111(a)(1), in determining whether a particular emission control is the“best system of emission reduction … adequately demonstrated,” the EPA is required to take
into account “the cost of achieving [the emission] reduction.” By its terms, this provision makes
clear that the cost that the EPA must take into account is the cost to the affected source of thesystem of emission reduction. Although the Clean Air Act does not describe how the EPA is toaccount for costs, the D.C. Circuit has formulated the cost standard in various ways. 187 It has
stated that the EPA may not adopt a standard the cost of which would be “exorbitant,” 188“greater than the industry could bear and survive,” 189 “excessive,” 190 or “unreasonable.” 191 These
formulations appear to be synonymous, and for convenience, in these rulemakings, we aretreating them as synonymous with reasonableness as well, so that a control technology may beconsidered the “best system of emission reduction ... adequately demonstrated” if its costs arereasonable, but cannot be considered the best system if its costs are unreasonable. 192

187

79 FR 1430, 1464 (January 8, 2014).
Lignite Energy Council, 198 F.3d at 933.
189
Portland Cement Ass’n v. EPA, 513 F.2d 506, 508 (D.C. Cir. 1975).
190
Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981).
191
Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981).
192
These cost formulations are consistent with the legislative history of CAA section 111. The
1977 House Committee Report noted:
188128This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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.” 193 See Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427, 440(D.C. Cir. 1973); 194 Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375, 387–88 (D.C. Cir.
1973); Sierra Club v. Costle, 657 F.2d 298, 313 (D.C. Cir. 1981) (upholding NSPS imposing
controls on SO2 emissions from coal-fired power plants when the “cost of the new controls ... issubstantial. EPA estimates that utilities will have to spend tens of billions of dollars by 1995 on
pollution control under the new NSPS.”).
In its CAA section 111 rulemakings, the EPA has frequently used a cost-effectivenessmetric, which determines the cost in dollars for each ton or other quantity of the regulated air
pollutant removed through the system of emission reduction. See, e.g., 81 FR 35824 (June 3,

In the [1970] Congress [sic: Congress’s] view, it was only right that the costs ofapplying best practicable control technology be considered by the owner of a large
new source of pollution as a normal and proper expense of doing business.
1977 House Committee Report at 184. Similarly, the 1970 Senate Committee Report stated:
The implicit consideration of economic factors in determining whether technology
is “available” should not affect the usefulness of this section. The overriding
purpose of this section would be to prevent new air pollution problems, and towardthat end, maximum feasible control of new sources at the time of their construction
is seen by the committee as the most effective and, in the long run, the least
expensive approach.
S. Comm. Rep. No. 91-1196 at 16.
193
1977 House Committee Report at 184.
194
The costs for these standards were described in the rulemakings. See 36 FR 24876 (December
23, 1971), 37 FR 5767, 5769 (March 21, 1972).
129
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

2016) (NSPS for GHG and VOC emissions for the oil and natural gas source category); 71 FR
9866, 9870 (February 27, 2006) (NSPS for NOX, SO2, and PM emissions from fossil fuel-fired
electric utility steam generating units); 61 FR 9905, 9910 (March 12, 1996) (NSPS andemissions guidelines for nonmethane organic compounds and landfill gas from new and existing
municipal solid waste landfills); 50 FR 40158 (October 1, 1985) (NSPS for SO2 emissions fromsweetening and sulfur recovery units in natural gas processing plants). This metric allows the
EPA to compare the amount a regulation would require sources to pay to reduce a particularpollutant across regulations and industries. In rules for the electric power sector, a metric that
determines the dollar increase in the cost of a megawatt hour of electricity generated by theaffected sources due to the emission controls, shows the cost of controls relative to the output ofelectricity. See section VII.F.3.b.iii(B)(5) of this preamble, which discusses $/MWh costs of the
March 15, 2023 Good Neighbor Plan for the 2015 Ozone NAAQS and the Cross-State Air
Pollution Rule (CSAPR) 76 FR 48208 (August 8, 2011). This metric facilitates comparing costs
across regulations and pollutants. In this proposal, as explained herein, the EPA looks at both ofthese metrics to assess the cost reasonableness of the proposed requirements.
d. Non-air Quality Health and Environmental Impact and Energy Requirements
Under CAA section 111(a)(1), the EPA is required to take into account “any nonair
quality health and environmental impact and energy requirements” in determining the BSER.
Non-air quality health and environmental impacts may include the impacts of the disposal of
byproducts of the air pollution controls, or requirements of the air pollution control equipment
for water. Portland Cement Ass’n v. Ruckelshaus, 465 F.2d 375, 387–88 (D.C. Cir. 1973), cert.
denied, 417 U.S. 921 (1974). Energy requirements may include the impact, if any, of the air
pollution controls on the source’s own energy needs.
130This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

e. Sector or Nationwide Component of Factors In Determining the BSER
Another component of the D.C. Circuit’s interpretations of CAA section 111 is that the
EPA may consider the various factors it is required to consider on a national or regional leveland over time, and not only on a plant-specific level at the time of the rulemaking. 195 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 veryclearly 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. 196
The court has upheld EPA rules that the EPA “justified ... in terms of the policies of theAct,” including balancing long-term national and regional impacts. For example, the court
upheld a standard of performance for SO2 emissions from new coal-fired power plants on
grounds that it—reflects a balance in environmental, economic, and energy consideration by being
sufficiently stringent to bring about substantial reductions in SO2 emissions (3million tons in 1995) yet does so at reasonable costs without significant energy
penalties.... 197
The EPA interprets this caselaw to authorize it to assess the impacts of the controls it isconsidering as the BSER, including their costs and implications for the energy system, on asector-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 ina particular area or nationwide and, if they would, to reject those controls as the BSER.

195

See 79 FR 1430, 1465 (January 8, 2014) (citing Sierra Club v. Costle, 657 F.2d at 351).
Sierra Club v. Costle, 657 F.2d at 331 (citations omitted) (citing legislative history).
197
Sierra Club v. Costle, 657 F.2d at 327-28 (quoting 44 FR 33583-33584; June 11, 1979).
131

196

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

f. “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,” 198 and emphasizedthat “[t]he text gives the EPA broad discretion to weigh different factors in setting the standard,”
including the amount of emission reductions, the cost of the controls, and the non-air quality
environmental impacts and energy requirements. 199 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 eachof these factors, we have granted the agency a great degree of discretion inbalancing them…. EPA's choice [of the ‘best system’] will be sustained unless theenvironmental or economic costs of using the technology are exorbitant…. EPA[has] considerable discretion under section 111. 200
See AEP v. Connecticut, 564 U.S. 410, 427 (2011) (under CAA section 111, “The appropriate
amount of regulation in any particular greenhouse gas-producing sector cannot be prescribed in a
vacuum: … informed assessment of competing interests is required. Along with theenvironmental benefit potentially achievable, our Nation's energy needs and the possibility of

198

Sierra Club v. Costle, 657 F.2d at 319.
Sierra Club v. Costle, 657 F.2d at 321; see also New York v. Reilly, 969 F.2d at 1150 (because
Congress did not assign the specific weight the Administrator should assign to the statutory
elements, “the Administrator is free to exercise [her] discretion” in promulgating an NSPS).
200
Lignite Energy Council, 198 F.3d at 933 (paragraphing revised for convenience). See New
York v. Reilly, 969 F.2d 1147, 1150 (D.C. Cir. 1992) (“Because Congress did not assign thespecific weight the Administrator should accord each of these factors, the Administrator is free
to exercise his discretion in this area.”); see also NRDC v. EPA, 25 F.3d 1063, 1071 (D.C. Cir.
1994) (The EPA did not err in its final balancing because “neither RCRA nor EPA’s regulations
purports to assign any particular weight to the factors listed in subsection (a)(3). That being thecase, the Administrator was free to emphasize or deemphasize particular factors, constrained
only by the requirements of reasoned agency decisionmaking.”).
132
199

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

economic disruption must weigh in the balance. The Clean Air Act entrusts such complex
balancing to the EPA in the first instance, in combination with state regulators. Each "standard of
performance" the EPA sets must "tak[e] into account the cost of achieving [emissions] reduction
and any nonair quality health and environmental impact and energy requirements."(paragraphing revised; citations omitted)).
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 purpose of thestatute. In Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375 (D.C. Cir. 1973), the D.C.
Circuit held that under CAA section 111(a)(1) as it read prior to the enactment of the 1977 CAA
Amendments that added a requirement that the EPA take account of non-air quality
environmental impacts, the EPA must consider “counter-productive environmental effects” indetermining the BSER. Id. at 385. The court elaborated: “The standard of the ‘best system’ iscomprehensive, and we cannot imagine that Congress intended that ‘best’ could apply to asystem which did more damage to water than it prevented to air.” Id., n.42. In Sierra Club v.
Costle, 657 F.2d 298, 326, 346-47 (D.C. Cir. 1981), the court added that the EPA must consider
the amount of emission reductions and technology advancement in determining BSER.
The court’s view that “best” includes additional factors that further the purpose of CAA
section 111 is a reasonable interpretation of that term in its statutory context. The purpose of
CAA section 111 is to reduce emissions of air pollutants that endanger public health or welfare.
CAA section 111(b)(1)(A). The court reasonably surmised that the EPA’s determination ofwhether a system of emission reduction that reduced certain air pollutants is “best” should be
informed by impacts that the system may have on other pollutants that affect public or welfare.
Portland Cement Ass’n, 486 F.2d at 385. The Supreme Court confirmed the D.C. Circuit’s
133
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

approach in Michigan v. EPA 576 U.S. 743 (2015), explaining that administrative agencies must
engage in “reasoned decisionmaking” that, in the case of pollution control, cannot be based ontechnologies that “do even more damage to human health” than the emissions they eliminate. Id.
at 751-52. After Portland Cement Ass’n, Congress revised CAA section 111(a)(1) to makeexplicit that in determining whether a system of emission reduction is the “best,” the EPA should
account for non-air quality health and environmental impacts. By the same token, the EPA takes
the position that in determining whether a system of emission reduction is the “best,” the EPA
may account for the impacts of the system on air pollutants other than the ones that are thesubject of the CAA section 111 regulation. 201 We discuss immediately below other factors thatthe D.C. Circuit has held the EPA should account for in determining what system is the “best.”
g. Amount of Emissions Reductions
Consideration of the amount of emissions from the category of sources or the amount ofemission reductions achieved as factors the EPA must consider in determining the “best systemof emission reduction” is implicit in the plain language of CAA section 111(a)(1)—the EPA
must choose the best system of emission reduction. Indeed, consistent with this plain language
and the purpose of CAA section 111, the D.C. Circuit has stated that the EPA must consider thequantity 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 would201

See generally “Standards of Performance for New, Reconstructed, and Modified Sources andEmissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review –Supplemental Notice of Proposed Rulemaking,” 87 FR 74702, 74765 (December 6, 2022)(proposing the BSER for reducing methane and VOC emissions from natural gas-driven
controllers in the oil and natural gas sector on the basis of, among other things, impacts onemissions of criteria pollutants). In this preamble, for convenience, the EPA generally discusses
the effects of controls on non-GHG air pollutants along with the effects of controls on non-air
quality health and environmental impacts.
134This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

not incorporate the amount of air pollution as a relevant factor to be weighed when determining
the optimal standard for controlling … emissions”). 202 The fact that the purpose of a “system of
emission reduction” is to reduce emissions, and that the term itself explicitly incorporates theconcept of reducing emissions, supports the court’s view that in determining whether a “systemof 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 ofemission reductions, the EPA has the discretion to do so, on grounds that either the term “systemof emission reduction” or the term “best” may reasonably be read to allow that discretion.
h. Expanded Use and Development of Technology
The D.C. Circuit has long held that Congress intended for CAA section 111 to create
incentives for new technology and therefore that the EPA is required to consider technologicalinnovation as one of the factors in determining the “best system of emission reduction.” See
Sierra Club v. Costle, 657 F.2d at 346–47. The court has grounded its reading in the statutory
text of CAA 111(a)(1), defining the term “standard of performance”. 203 In addition, the court’s

202

Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. 1981) was governed by the 1977 CAAA
version of the definition of “standard of performance,” which revised the phrase “best system of
emission reduction” to read, “best technological system of continuous emission reduction.” As
noted above, the 1990 CAAA deleted “technological” and “continuous” and thereby returned thephrase to how it read under the 1970 CAAA. The court’s interpretation of the 1977 CAAA
phrase in Sierra Club v. Costle to require consideration of the amount of air emissions focusedon the term “best”, and the terms “technological” and “continuous” were irrelevant to its
analysis. It thus remains valid for the 1990 CAAA phrase “best system of emission reduction.”
203
Sierra Club v. Costle, 657 F.2d at 346 (“Our interpretation of section 111(a) is that the
mandated balancing of cost, energy, and nonair quality health and environmental factors
embraces consideration of technological innovation as part of that balance. The statutory factors
which EPA must weigh are broadly defined and include within their ambit subfactors such astechnological innovation.”).
135
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

interpretation finds support in the legislative history. 204 The legislative history identifies threedifferent ways that Congress designed CAA section 111 to authorize standards of performancethat promote technological improvement: (1) The development of technology that may be treatedas the “best system of emission reduction … adequately demonstrated;” under CAA section
111(a)(1); 205 (2) the expanded use of the best demonstrated technology; 206 and (3) the
development of emerging technology. 207 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.
i. Achievability of the Degree of Emission Limitation
For new sources, CAA section 111(b)(1)(B) and (a)(1) provides that the EPA must
establish “standards of performance,” which are standards for emissions that reflect the degree ofemission 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 to204

See S. Rep. No. 91-1196 at 16 (1970) (“Standards of performance should provide an incentive
for industries to work toward constant improvement in techniques for preventing and controllingemissions from stationary sources”); S. Rep. No. 95-127 at 17 (1977) (cited in Sierra Club v.
Costle, 657 F.2d at 346 n. 174) (“The section 111 Standards of Performance ... sought to assure
the use of available technology and to stimulate the development of new technology”).
205
Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375, 391 (D.C. Cir. 1973) (the best systemof emission reduction must “look[] toward what may fairly be projected for the regulated future,
rather than the state of the art at present”).
206
1970 Senate Committee Report No. 91-1196 at 15 (“The maximum use of available means ofpreventing and controlling air pollution is essential to the elimination of new pollution
problems”).
207
Sierra Club v. Costle, 657 F.2d at 351 (upholding a standard of performance designed topromote the use of an emerging technology).
136
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

meet the standard. 208 Moreover, according to the court, “[a]n achievable standard is one which iswithin the realm of the adequately demonstrated system’s efficiency and which, while not at alevel that is purely theoretical or experimental, need not necessarily be routinely achieved within
the industry prior to its adoption.” 209 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 orcannot be taken into account in determining the ‘costs’ of compliance.” 210 To show a standard isachievable, 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 representativeof potential industry-wide performance, given the range of variables that affect the achievabilityof the standard.” 211
Although the D.C. Circuit established these standards for achievability in cases
concerning CAA section 111(b) new source standards of performance, generally comparable
standards for achievability should apply under CAA section 111(d), although the BSER may
differ as between new and existing sources due to, for example, higher costs of retrofit. 40 FR
53340 (November 17, 1975). For existing sources, CAA section 111(d)(1) requires the EPA toestablish requirements for state plans that, in turn, must include “standards of performance.” As

208

Sierra Club v. Costle, 657 F.2d 298, 364, n. 276 (D.C. Cir. 1981).
Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433-34 (D.C. Cir. 1973), cert. denied, 416
U.S. 969 (1974).
210
Nat’l Lime Ass’n v. EPA, 627 F.2d 416, 433, n.46 (D.C. Cir. 1980).
211
Sierra Club v. Costle, 657 F.2d 298, 377 (D.C. Cir. 1981) (citing Nat’l Lime Ass’n v. EPA,
627 F.2d 416 (D.C. Cir. 1980). In considering the representativeness of the source tested, theEPA may consider such variables as the “‘feedstock, operation, size and age’ of the source.”
Nat’l Lime Ass’n v. EPA, 627 F.2d 416, 433 (D.C. Cir. 1980). Moreover, it may be sufficient to“generalize from a sample of one when one is the only available sample, or when that one isshown to be representative of the regulated industry along relevant parameters.” Nat’l Lime
Ass’n v. EPA, 627 F.2d 416, 434, n.52 (D.C. Cir. 1980).
137
209This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

the Supreme Court has recognized, this provision requires the EPA to promulgate emission
guidelines that determine the BSER for a source category and then identify the degree ofemission limitation achievable by application of the BSER. See West Virginia v. EPA, 142 S. Ct.
2587, 2601-02 (2022). 212
The EPA has promulgated emission guidelines on the basis that the existing sources canachieve the degree of emission limitation described therein, even though under the RULOF
provision of CAA section 111(d)(1), the state retains discretion to apply standards ofperformance to individual sources that are more or less stringent, which indicates that Congressrecognized that the EPA may promulgate emission guidelines that are consistent with CAA
section 111(d) even though certain individual sources may not be able to achieve the degree ofemission limitation identified therein by applying the controls that the EPA determined to be the
BSER. Note further that this requirement that the emission limitation be “achievable” based on
the “best system of emission reduction ... adequately demonstrated” indicates that the technology
or other measures that the EPA identifies as the BSER must be technically feasible.
4. 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 ofperformance” for emissions of certain air pollutants from sources which, if they were newsources, would be regulated under CAA section 111(b), and that implement and enforce thosestandards 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

212

40 CFR 60.21(e), 60.21a(e).

138This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 bestsystem 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 fromdesignated facilities. 213
Following the EPA’s promulgation of emission guidelines, each state must determine thestandards of performance for its existing sources, which the EPA’s regulations call “designatedfacilities.” 214 While the EPA specifies in emission guidelines the degree of emission limitationachievable through application of the best system of emission reduction, which it may express asa 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 particularsource ... to take into consideration, among other factors, the remaining useful life 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 threecircumstances under which states can invoke a particular source’s remaining useful life and otherfactors (RULOF), to apply a less stringent standard of performance. These proposed
clarifications provided:

213
214

40 CFR 60.21a(e).
40 CFR 60.21a(b), 60.24a(b).

139This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

The State may apply a standard of performance to a particular source that is lessstringent 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 degreeof emission limitation determined by the EPA, based on:(1) Unreasonable cost of control resulting from plant age, location, or basic
process design;(2) Physical impossibility or technical infeasibility of installing necessarycontrol equipment; or(3) Other circumstances specific to the facilities (or class of facilities) thatare fundamentally different from the information considered in thedetermination 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)). 215 In addition, under CAA sections 111(d) and 116, the state is authorized toestablish a standard of performance for any particular source that is more stringent than thepresumptive standards contained in the EPA’s emission guidelines. 216 Thus, for any particularsource, 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

215

The EPA intends to finalize the December 2022 proposed revisions to the CAA section 111
implementation regulations in 40 CFR part 60, subpart Ba, including any changes made in
response to public comments, prior to promulgating these emission guidelines. Thus, 40 CFRpart 60, subpart Ba, as revised, would apply to these emission guidelines.
216
40 CFR 60.24a(f). The EPA’s December 2022 proposed revisions to 40 CFR part 60, subpart
Ba reflect its current interpretation that the EPA has the authority to review and approve plansthat include standards of performance that are more stringent than the presumptive standards inthe EPA’s emission guidelines, thus making those more stringent requirements federally
enforceable. 87 FR 79204 (December 23, 2022), Docket ID No. EPA-HQ-OAR-2021-0527-0002(proposed 40 CFR 60.24a(m), (n)). In addition, CAA section 116 authorizes the state to set
standards of performance for all of its sources that, together, are more stringent than the EPA’semission guidelines.
140
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

the standards of performance in their state plans and submit the plans to the EPA for review. 217
Under CAA section 111(d)(2)(A), the EPA approves state plans that are determined to be“satisfactory.”
VI. Stakeholder Engagement
Prior to proposing these actions, the EPA conducted outreach to a broad range ofstakeholders. 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. 218 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 thefirst round of outreach, in early 2022, the EPA sought input in a variety of formats and settingsfrom states, tribal nations, and a broad range of stakeholders on the state of the power sector andhow the Agency’s regulatory actions affect those trends. This outreach included state energy andenvironmental 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 healthorganizations. A second round of outreach took place in August and September 2022, andfocused on seeking input specific to this rulemaking. The EPA asked to hear perspectives,

217

40 CFR 60.23a. In January 2021, the D.C. Circuit Court of Appeals vacated the three-year
deadline for state plan submissions of a final emission guideline in 40 CFR 60.23a(a)(1). The
EPA’s December 2022 proposed revisions to subpart Ba would revise 60.23a to, inter alia,
provide for a fifteen-month submission deadline. 87 FR 79182 (December 23, 2022), Docket ID
No. EPA-HQ-OAR-2021-0527-0002 (proposed 40 CFR 60.23a(a)).
218
Docket ID No. EPA-HQ-OAR-2022-0723.
141
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

priorities, and feedback around five guiding questions, and encouraged public input to thenonregulatory 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 expertiseand 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 evaluatedstructures in these proposals to address reliability considerations with the Department of Energy.
VII. Proposed Requirements for New and Reconstructed Stationary Combustion Turbine
EGUs and Rationale for Proposed Requirements
A. Overview
This section discusses and proposes requirements for stationary combustion turbine
EGUs that commence construction or reconstruction after the date of publication of this
proposed action. The EPA is proposing that those requirements will be codified in 40 CFR part60, 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 andcombined cycle turbines. It further explains how these technologies are used in the threesubcategories of low load turbines, intermediate load turbines, and base load turbines. Section
VII.C provides an overview of how stationary combustion turbines have been previously
regulated and how the EPA recently took comment on a proposed white paper on GHG
mitigation options for stationary combustion turbines. Section VII.D discusses the EPA’s
142
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 andsubcategories 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 thesubcategories of turbines. For low load combustion turbines, the EPA continues to believe thatuse of lower emitting fuels is the appropriate BSER. For intermediate load turbines, the EPA
believes that both highly efficient generation and co-firing low-GHG hydrogen are appropriatecomponents of the BSER, and that there will be enough low-GHG hydrogen at a reasonable priceto supply the combustion turbines that would need to use it in 2032. For this reason, the EPA is
proposing a two-component BSER for intermediate load combustion turbines, and a two-phasestandard of performance. The first component of the BSER would be highly efficient generation(based on the performance of a highly efficient simple cycle turbine), with a corresponding firstphase standard of performance. The second component of the BSER is co-firing 30 percent (byvolume) low-GHG hydrogen, along with continued use of highly efficient generation, with acorresponding second-phase standard of performance. The EPA is also soliciting comment onwhether intermediate load combustion turbines should be subject to a more stringent third-phasestandard based on higher levels of low-GHG hydrogen co-firing by 2038. Additionally, the EPA
is soliciting comment on whether the electric sales threshold used to define intermediate and baseload units should be reduced further.

143
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

For base load turbines, the EPA likewise believes that the BSER includes multiple
components that correspond to a multi-phase standard of performance. This is appropriate basedon 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 two BSER pathways withcorresponding standards of performance that new and reconstructed stationary combustion
turbines may take—one BSER pathway is based on the use of 90 percent CCS and a separate
BSER pathway is based on co-firing low-GHG hydrogen. The EPA proposes that the firstcomponent of the BSER for both pathways is highly efficient generation (based on theperformance of a highly efficient combined cycle unit) and the second component of the BSER
is based on the use of either 90 percent CCS in 2035 or co-firing 30 percent (by volume) lowGHG hydrogen in 2032, along with continued use of highly efficient generation for both
pathways. For base load turbines that are subject to a second phase standard of performancebased on a highly efficient combined cycle unit co-firing 30 percent (by volume) low-GHG
hydrogen, the EPA proposes that those units also meet a third phase component of the BSER
based on the co-firing of 96 percent (by volume) low-GHG hydrogen by 2038. These two BSER
pathways both offer significant opportunities to reduce GHG emissions even though they may beavailable on slightly different timescales. The EPA seeks comment specifically on thepercentages of hydrogen co-firing and CO2 capture, the dates that meet the statutory BSER
criteria for each pathway, whether the Agency should finalize both pathways as separate
subcategories with separate standards of performance, or whether it should finalize one pathway
with the option of meeting the standard of performance using either system of emission

144
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

reduction—e.g., a single standard of 90 lb CO2/MWh-gross based on the application of CCS
with 90 percent capture, which could also be met by co-firing 96 percent low-GHG hydrogen.
For both intermediate load and base load turbines, the standards of performancecorresponding to both components of the BSER would apply to all new and reconstructedsources 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, phase-2, or phase3 standards.
B. Combustion Turbine Technology
For purposes of 40 CFR part 60, subparts TTTT and TTTTa, stationary combustion
turbines include both simple cycle and combined cycle EGUs. Simple cycle turbines operate in
the Brayton thermodynamic cycle and include three primary components: a multistagecompressor, a combustion chamber (i.e., combustor), and a turbine. The compressor is used tosupply large volumes of high-pressure air to the combustion chamber. The combustion chamberconverts 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 theirhigh-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 heatrecovery 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 thethermal 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
145This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 baseload, respectively.
Low load combustion turbines provide reserve capacity, support grid reliability, andgenerally provide power during periods of peak electric demand. As such, the units may operate
at or near their full capacity, but only for short periods, as needed. Because these units only
operate occasionally, capital expenses are a major factor in the overall cost of electricity, andoften, the lowest capital cost (and generally less efficient) simple cycle EGUs are intended foruse only during periods of peak electric demand. Due to their low efficiency, these units require
more fuel per MWh of electricity produced and their operating costs tend to be higher. Becauseof 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, theirability 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 fullload is important to maximize revenue during periods of peak electric prices and to meet sudden146This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

shifts in demand. In contrast, under steady-state conditions, more efficient combined cycle EGUs
are dispatched ahead of low load turbines and often operate at higher capacity factors.
Highly efficient simple cycle turbines and fast-start combined cycle turbines both offerdifferent advantages and disadvantages when operating at intermediate loads. One of the roles ofthese intermediate or load-following EGUs is to provide dispatchable backup power to support
variable 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 predominantload 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/operatorof 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 orhour. 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 tobalance supply and demand and other requirements in an optimal manner, based on operating
costs, price bids, and/or operational characteristics. However, operating permits for simple cycle
turbines often contain restrictions on the annual hours of operation that owners/operators
incorporate into longer term operating plans and short-term dispatch decisions.
Intermediate load combustion turbines vary their generation, especially during transition
periods between low and high electric demand. Both high-efficiency simple cycle combustion
turbines and fast-start combined cycle combustion turbines can fill this cycling role. While theability to start and quickly ramp is important, efficiency is also an important characteristic. These
147
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

combustion turbines generally have higher capital costs than low load combustion turbines but
are generally less expensive to operate.
Base load combustion turbines are designed to operate for extended periods at high loads
with infrequent starts and stops. Quick start capability and low capital costs are less important
than low operating costs. High-efficiency combined cycle combustion turbines typically fill therole of base load combustion turbines.
The increase in generation from variable renewable energy sources during the past
decade has impacted the way in which firm dispatchable generating resources operate. 219 For
example, the electric output from wind and solar generating sources fluctuates daily andseasonally due to increases and decreases in the wind speed or solar intensity. Due to thisvariable nature of wind and solar, firm dispatchable electric generating units are used to ensure
the reliability of the electric grid. This requires technologies such as dispatchable power plants tostart and stop and change load more frequently than was previously needed. Importantcharacteristics of combustion turbines that provide firm backup capacity are the ability to startand 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 importantrole in ensuring electric supply and demand are in balance during the past decade.
As discussed in section IV.F.2 of this preamble and in the accompanying RIA, the postIRA 2022 reference case projects that natural gas-fired combustion turbines will continue to play
an important role in meeting electricity demand. However, that role is projected to evolve as

219

Dispatchable EGUs can be turned on and off and adjust the amount of power supplied to theelectric grid based on the demand for electricity. Variable (sometimes referred to as intermittent)
EGUs supply electricity based on external factors that are not controlled by the owner/operatorof the EGU.
148

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

additional renewable and non-renewable low-GHG generation and energy storage technologies
are added to the grid. Energy storage technologies can store energy during periods whengeneration from renewable resources is high relative to demand and provide electricity to thegrid during other periods. This could reduce the need for fossil fuel-fired firm dispatchable
power plants to start and stop as frequently. Consequently, in the future, natural 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.
C. 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 CFRpart 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 fornon-base load turbines. Base load turbines were defined as combustion turbines with electricsales greater than a site-specific electric sales threshold that is based on the design efficiency ofthe combustion turbine. Non-base load turbines were defined as combustion turbines with acapacity 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 lower emitting fuels that varied from 120 lb CO2/MMBtu to 160 lb
CO2/MMBtu depending upon whether the turbine burned primarily natural gas or other lower
emitting fuels.
149
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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. 220 The draft document included discussion of the basic types ofavailable 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; theongoing 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-durationenergy storage.
The EPA provided an opportunity for the public to comment on this white paper toinform 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, NGOs, and public health advocates. The information provided in the publiccomments 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.
D. Eight-Year Review of NSPS
CAA section 111(b)(1)(B) requires the Administrator to “at least every 8 years, review
and, if appropriate, revise [the NSPS] …” The provision further provides that “the Administrator

220

https://www.epa.gov/stationary-sources-air-pollution/white-paper-available-and-emergingtechnologies-reducing.
150
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 fuelfired combustion turbines and plan to continue building additional capacity. Because theemissions 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 ofcontrol 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.
E. Applicability Requirements and Subcategorization
This section describes the proposed amendments to the specific applicability criteria fornon-fossil fuel-fired EGUs, industrial EGUs, CHP EGUs, and combustion turbines EGUs notconnected to a natural gas pipeline. The EPA is also proposing certain changes to theapplicability requirements for stationary combustion turbines affected by this proposal ascompared 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-baseload combustion turbines into low and intermediate load subcategories, and lowering the electricsales threshold for base load combustion turbines.
1. Applicability Requirements
In general, the EPA refers to fossil fuel-fired EGUs that would be subject to a CAA
section 111 NSPS as “affected” EGUs or units. An EGU is any fossil fuel-fired electric utility
151This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

steam generating unit (i.e., a utility boiler or IGCC unit) or stationary combustion turbine (ineither 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: (1) 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 (2) serve a generator capable ofsupplying more than 25 MW net to a utility distribution system (i.e., for sale to the grid). 221
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 theuse 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 thatare not physically capable of combusting natural gas (e.g., those that are not connected to anatural gas pipeline); (4) utility boilers and IGCC units that have always been subject to afederally enforceable permit limiting annual net electric sales to one-third or less of theirpotential 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.

221

The EPA refers to the capability to combust 250 MMBtu/h of fossil fuel as the “base load
rating criterion.” Note that 250 MMBtu/h is equivalent to 73 MW or 260 GJ/h heat input.
152
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

a. Revisions to 40 CFR Part 60, Subpart TTTTThe EPA is proposing to amend 40 CFR 60.5508 and 60.5509 to reflect that 40 CFR part60, 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 thatstationary combustion turbines that commenced construction after January 8, 2014 orreconstruction 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.
b. 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.
i. Applicability to Non-fossil Fuel-fired EGUs
The current non-fossil applicability exemption in 40 CFR part 60, subpart TTTT is basedstrictly on the combustion of non-fossil fuels (e.g., biomass). To be considered a non-fossil fuelfired 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 nottake heat input from non-combustion sources (e.g., solar thermal) into account. Certain solar
153
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 arelimited to an annual capacity factor of 10 percent or less. These EGUs would readily comply
with the standard of performance, but the reporting and recordkeeping would increase costs forthese EGUs.
The EPA is proposing several amendments to align the applicability criteria with theoriginal 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 therequirements 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 ormore 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 noncombustion 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
154
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 theheat input from non-combustion sources is necessary to determine the relative heat input fromfossil fuel and non-fossil fuel sources.
ii. Industrial EGUs
(A) Applicability to Industrial EGUs
In simple terms, the current applicability provisions in 40 CFR part 60, subpart TTTT
require that an EGU be capable of combusting more than 250 MMBtu/h of fossil fuel and be
capable of selling 25 MW to a utility distribution system to be subject to 40 CFR part 60, subpart
TTTT. These applicability provisions exclude industrial EGUs. However, the definition of an
EGU also includes “integrated equipment that provides electricity or useful thermal output.” This
language facilitates the integration of non-emitting generation and avoids energy inputs from
non-affected facilities being used in the emission calculation without also considering theemissions 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 meetingthe 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 ismore than 250 MMBtu/h heat input and the electric sales exceed the applicability criteria, thenthe unit could be subject to 40 CFR part 60, subparts TTTT or TTTTa. This is potentiallyproblematic 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, the155This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

fossil fuel that is combusted might have a relatively high CO2 emissions rate on a lb/MMBtu
basis, making it potentially problematic to meet the standard of performance using efficient
generation. This could result in the owner/operator reducing the electric output of the industrial
facility to avoid the applicability criteria. Finally, the compliance costs associated with 40 CFRpart 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 thatexempts 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 isused outside the affected EGU. 222 Reducing the output or not developing industrial electric
generating projects where the majority of the heat input is derived from the industrial processitself would not necessarily result in reductions in GHG emissions from the industrial facility.
However, the electricity that would have been produced from the industrial project could still beneeded. Therefore, 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 could discourage project development, leading
to potential overall increases in GHG emissions.
(B) Industrial EGUs Electric Sales Threshold Permit Requirement
The current electric sales applicability exemption in 40 CFR part 60, subpart TTTT for
non-CHP steam generating units includes the provision that EGUs have “always been subject to222

Auxiliary equipment such as boilers or combustion turbines that provide heat or electricity tothe primary EGU (including to any control equipment) would still be considered integrated
equipment and included as part of the affected facility.
156

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

a federally enforceable permit limiting annual net electric sales to one-third or less of theirpotential 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 forthis 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 bypermit 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 theoperating permit. Under the current applicability language, some onsite EGUs could be coveredby 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 electricsales 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 isgreater, 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
157
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 sometime in the past. The proposed revisions would simply make it possible for an owner/operator ofan existing industrial EGU to provide evidence to the Administrator that the facility has neversold 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 capableof 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 toeliminate the requirement that existing industrial EGUs must have always been subject to apermit restriction limiting net electric sales.
iii. Determination of the Design Efficiency
The design efficiency (i.e., the efficiency of converting thermal energy to useful energy
output) of a combustion turbine is used to determine the electric sales applicability threshold andis relevant to both new and existing EGUs. 223 The sales criteria are based in part on theindividual EGU design efficiency. Three methods for determining the design efficiency are
currently provided in 40 CFR part 60, subpart TTTT. 224 Since the 2015 NSPS was finalized, the
EPA has become aware that owners/operators of certain existing EGUs do not have records ofthe 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

223

While the EPA could specifically allow different methods to determine the design efficiency
in the 111(d) existing source emission guidelines, the Agency is proposing to align the criteria
for regulatory clarity.
224
40 CFR part 60, subpart TTTT currently lists ASME PTC 22 Gas Turbines, ASME PTC 46
Overall Plant Performance, and ISO 2314 Gas turbines acceptance tests as approved methods todetermine the design efficiency.
158
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 notmeet the applicability criteria. However, the language in the 2015 NSPS would require them toconduct additional testing to demonstrate this. The requirement would result in burden to theregulated community without any environmental benefit. The electricity generating market haschanged, 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 comportwith the efficiency associated with current EGU configurations. As the three specified methods
would rely on documentation from the original EGU configuration performance guarantee
testing, and results from that documentation may no longer exist or be relevant, it is appropriate
to allow other means to demonstrate EGU design efficiency. To reduce compliance burden, the
EPA is proposing in 40 CFR part 60, subparts TTTT and TTTTa to allow alternative methods asapproved 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 forStandardization (ISO) methods as well as to operating data to demonstrate the design efficiencyof the EGU. The EPA is also proposing to change the applicability of paragraph 60.8(b) in table
159
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

3 of 40 CFR part 60, subpart TTTT from “no” to “yes” and that the applicability of paragraph60.8(b) in table 3 of 40 CFR part 60, subpart TTTTa is “yes.” This would allow theAdministrator to approve alternatives to the test methods specified in 40 CFR part 60, subparts
TTTT and TTTTa.
c. Applicability for 40 CFR Part 60, subpart TTTTa
This section describes 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.
i. 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 thisrulemaking will apply to EGUs that commence construction or reconstruction after the date ofthis 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 themethod of operation of, an existing source that increases the amount of any air pollutant emitted
to which a standard applies. 225 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. 226
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

225
226

40 CFR 60.2.
40 CFR 60.15(a).

160This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

combustion turbine must meet the following applicability criteria: The stationary combustion
turbine must: (1) 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 (2) serve a generator capable of supplying more than 25
MW net to a utility distribution system (i.e., for sale to the grid). 227 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 fromnon-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 othersteam 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 CFRpart 60, subpart Eb; (5) commercial or industrial solid waste incineration units subject to 40 CFRpart 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 noncontinental areas (i.e., Hawaii, the Virgin Islands, Guam, American Samoa, the Commonwealthof Puerto Rico, and the Northern Mariana Islands) and non-contiguous areas (non-continental

227

The EPA refers to the capability to combust 250 MMBtu/h of fossil fuel as the “base load
rating criterion.” Note that 250 MMBtu/h is equivalent to 73 MW or 260 GJ/h heat input.
161
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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.
ii. Applicability to CHP units
For 40 CFR part 60, subpart TTTT, owner/operators of CHP units calculate net electricsales 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 theapplicability 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 notclear 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 toeliminate the restriction that CHP units produce at least 20.0 percent electrical or mechanicaloutput 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 ofsources—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 multipliedby its potential electric output, or 219,000 MWh or less, whichever is greater. For CHP units, the162This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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. 228 However, as written in 40 CFR part 60, subpart
TTTT, each third-party CHP unit would subtract the entire electricity use of the thermal hostfacility 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 incounting the purchased power multiple times. In addition, it is not the intent of the provision toallow a CHP developer to provide a trivial amount of useful thermal output to multiple thermalhosts and then subtract all the thermal hosts’ purchased power when determining net electricsales 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 thepercentage of useful thermal output provided to the host facility by the specific CHP unit. Thisapproach 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

228

For contractual reasons, many developers of CHP units sell all the generated electricity to theelectricity distribution grid even though in actuality a significant portion of the generated
electricity is used onsite. Owners/operators of both the CHP unit and thermal host can subtract
the site purchased power when determining net electric sales. Third party developers that do not
own the thermal host can also subtract the purchased power of the thermal host when
determining net electric sales for applicability purposes.
163

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

determined based on the percentage of thermal power provided to the host facility by the specific
CHP facility.
iii. 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 thatare not connected to a natural gas pipeline). While combustion turbines not connected to anatural 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 andreconstructed combustion turbines that are not capable of combusting natural gas. As describedin 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 a standard of
performance based on the identified BSER. Therefore, the EPA is not including in 40 CFR part60, subpart TTTTa, the exemption for stationary combustion turbines that are not physicallycapable of combusting natural gas.
F. Determination of the Best System of Emission Reduction (BSER) for New and Reconstructed
Stationary Combustion Turbines
In this section, the EPA describes the technologies it is proposing to determine are the
BSER for each of the subcategories of new and reconstructed combustion turbines thatcommence construction after the date of this proposal, and explains its basis for proposing those164
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

controls, and not others, as the BSER. The controls that the EPA is evaluating include
combusting non-hydrogen lower emitting fuels (e.g., natural gas and distillate oil), using highly
efficient generation, using CCS, and co-firing with low-GHG hydrogen.
For the low-load subcategory, the EPA is proposing the use of lower emitting fuels as the
BSER. For the intermediate load subcategory, the EPA is proposing an approach under which the
BSER is made up of two components that each represent a different set of controls, and that form
the basis of standards of performance that apply in multiple phases. That is, affected facilities—
which are facilities that commence construction or reconstruction after the date of this proposed
rulemaking—must meet the first phase of the standard of performance, which is based on theapplication 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 co-firing 30 percent (by volume) low-GHG hydrogen by 2032. The EPA is
also soliciting comment on whether the intermediate load subcategory should apply a third
component of BSER, which is co-firing 96 percent (by volume) low-GHG hydrogen by 2038. In
addition, the EPA is also soliciting comment on whether the low load subcategory should apply
the second component of BSER, which is co-firing 30 percent (by volume) low-GHG hydrogenby 2032. These latter components of BSER would also include the continued application ofhighly efficient generation.
For the base load subcategory, the EPA is also proposing a multi-component BSER andan associated multi-phase standard of performance. The first component of the BSER, as withintermediate load combustion turbines, is highly efficient generation. New base load combustion
turbines would be required to meet a phase one standard of performance based on the applicationof the first component of the BSER upon initial startup of the source. Subsequently, EPA is
165
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

proposing two technology pathways as potential BSER for base load combustion turbines, withcorresponding standards of performance. The first technology pathway is based on 90 percent
CCS, which base load combustion turbines may install and begin to operate to meet the standardof performance by 2035. The second technology pathway is based on co-firing low-GHG
hydrogen, which EPA proposes base load combustion turbines may undertake in two steps – byco-firing 30 percent (by volume) low-GHG hydrogen to meet the second phase of the standard of
performance by 2032 and, then by co-firing 96 percent (by volume) low-GHG hydrogen to meet
the third phase of the standard of performance by 2038. Throughout, base load turbines, likeintermediate load turbines, would remain subject to the BSER of highly efficient generation.
This approach reflects the EPA’s view that the BSER for the intermediate load and baseload subcategories should reflect the deeper reductions in GHG emissions that can be achievedby implementing CCS and co-firing low-GHG hydrogen but recognizes that building theinfrastructure required to support widespread use of CCS and low-GHG hydrogen in the power
sector will take place on a multi-year time scale. Accordingly, newly constructed orreconstructed facilities must be aware of their need to ramp toward more stringent phases of thestandards, which reflect application of the more stringent controls in the BSER, either throughuse of co-firing a lower level of low-GHG hydrogen by 2032 and a higher level of low-GHG
hydrogen by 2038 or through use of CCS by 2035. The EPA is also soliciting comment on thepotential for an earlier compliance date for the second phase, for instance, 2030 for units cofiring 30 percent hydrogen by volume and 2032 for units installing CCS.
For the base load subcategory, the EPA is proposing both potential BSER pathways
because it believes there may be more than one viable BSER pathway for base load combustion
turbines to significantly reduce their CO2 emissions and believes there is value in receiving
166
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

comment on, and potentially finalizing, both BSER pathways to enable project developers toelect how they will reduce their CO2 emissions on timeframes that make sense for each BSER
pathway. The EPA recognizes that standards of performance are technology neutral and that if
the EPA finalizes a standard based on application of CCS, units could meet that standard using
co-firing of low-GHG hydrogen. The EPA solicits comment on whether co-firing of low-GHG
hydrogen should be considered a compliance pathway for sources to meet a single standard of
performance based on application of CCS rather than a separate BSER pathway. The EPA
believes that there will be earlier opportunities for units to begin co-firing lower amounts of lowGHG hydrogen than to install and begin operating 90 percent CCS systems. However, it will
likely take a longer timeframe for those units to then ramp up to co-firing significant quantities
of low-GHG hydrogen. Therefore, in this proposal, the EPA presents these pathways as separate
subcategories, while soliciting comment on the option of finalizing a single standard of
performance based on application of CCS.
Specifically, with respect to the first phase of the standards of performance, for both theintermediate load and base load subcategories, the EPA is proposing that the BSER is highly
efficient generating technology—combined cycle technology for the base load subcategories andsimple cycle technology for the intermediate load subcategory—as well as operating andmaintaining it efficiently. The EPA sometimes refers to highly efficient generating technology incombination 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 ofperformance, for base load combustion turbines adopting the CCS pathway, the BSER includes
the use of 90 percent CCS. These sources would be required to meet standards of performance
167
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 adopting the lowGHG hydrogen co-firing pathway and for intermediate load combustion turbines, the BSER
includes co-firing 30 percent by volume (12 percent by heat input) low-GHG hydrogen. Thesesources would be required to meet second phase standards of performance by 2032 that reflect
the application of both components of the BSER—in this case, highly efficient generation andco-firing 30 percent (by volume) low-GHG hydrogen—and that are, again, more stringent.
Finally, for base load combustion turbines adopting the low-GHG hydrogen co-firing pathway,
the BSER also includes a third component—co-firing 96 percent (by volume) low-GHG
hydrogen. These sources would be required to meet a third phase standard of performanceequivalent to that for the affected sources applying CCS as a second component of the BSER.
These sources would be required to meet that equivalent standard of performance reflecting theapplication of highly efficient generation and co-firing high levels of low-GHG hydrogen. Table
1 summarizes the proposed BSER for combustion turbine EGUs that commence construction orreconstruction after publication of this proposal. The EPA is also proposing standards ofperformance based on those BSER for each subcategory, as discussed in section VII.G.
Table 1—Proposed BSER for Combustion Turbine EGUs
Subcategory

Fuel

1st Component
BSER

Low Load*

All Fuels

Lower emitting
fuels

All Fuels

HighlyEfficient
Generation

Intermediate
Load

2nd
Component
BSER

3rd
Component
BSER

N/A

N/A

30 percent (byvolume) LowGHG
Hydrogen Cofiring by 2032

N/A

168
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Sources
adopting the
CCS pathway

90 percent CCS
by 2035

N/A

HighlySources
30 percent (by 96 percent (byEfficient
Base Loadadopting thevolume) Lowvolume) LowGeneration
low-GHG
GHG
GHG
hydrogen coHydrogen CoHydrogen Cofiring pathway
firing by 2032
firing by 2038
* The low load subcategory has a single-component BSER consisting of fuels that emit lower
GHG emissions.
1. BSER for Low Load Subcategory
This section describes the proposed BSER for the low load (i.e., peaking) subcategory,
which is the use of lower emitting fuels. For this proposed rule, the Agency proposes todetermine that the use of lower emitting fuels, which the EPA determined to be the BSER for the
non-base load subcategory in the 2015 NSPS, is the BSER for this low load subcategory in thestandards of performance proposed in this action. As explained above, the EPA is proposing tonarrow the definition of the low load subcategory by lowering the electric sales threshold (ascompared 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 intermediateload subcategory and therefore be subject to a more stringent standards based on the more
stringent component of the BSER. Unlike the proposals for intermediate and base load
combustion turbines, the proposed low load subcategory includes only a single-phase BSER
component.
a. Background: The Non-base Load Subcategory in the 2015 NSPSThe 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 orless than their design efficiency (not to exceed 50 percent) multiplied by their potential electric
169
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 isthe use of lower emitting fuels. Id. at 64515. These lower emitting fuels are primarily natural gas
with a small allowance for distillate oil (i.e., Nos. 1 and 2 fuel oils), which have been widelyused in stationary combustion turbine EGUs for decades.
The EPA also determined in the 2015 NSPS that the standard of performance for sourcesin this subcategory is a heat input-based standard of 120 lb CO2/MMBtu. The EPA establishedthis clean-fuels BSER for this subcategory because of the variability in the operation in non-baseload combustion turbines and the challenges involved in determining a uniform output-based
standard that all new and reconstructed non-base load units could achieve.
Specifically, in the 2015 NSPS, the EPA recognized that a BSER for the non-base load
subcategory based on the use of lower emitting fuels results in limited GHG reductions, but
further recognized that an output-based standard of performance could not reasonably be applied
to the subcategory. The EPA explained that a combustion turbine operating at a low capacity
factor could operate with multiple starts and stops, and that its emission rate would be highly
dependent on how it was operated and not its design efficiency. Moreover, combustion turbineswith 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 todetermine a standard of performance that could reasonably apply to all combustion turbines in

170
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

the subcategory. For that reason, the EPA further recognized, efficient design 229 and operation
would not qualify as the BSER; rather, the BSER should be lower emitting fuels and theassociated standard of performance should be based on heat input. Since the 2015 NSPS, allnewly constructed simple cycle turbines have been non-base load units and thus have become
subject to this standard of performance.
b. Proposed BSER
Consistent with the rationale of the 2015 NSPS, the EPA proposes that the use of fuelswith an emissions rate of less than 160 lb CO2/MMBtu (i.e., lower emitting fuels) meets the
BSER requirements for the low load subcategory. Use of these fuels is technically feasible for
combustion turbines. Natural gas comprises the majority of the heat input for simple cycle
turbines and is the lowest cost fossil fuel. In the 2015 NSPS, the EPA determined that natural gas
comprised 96 percent of the heat input for simple cycle turbines. See 80 FR 64616 (October 23,2015). Therefore, a BSER based on the use of natural gas and/or distillate oil would haveminimal, if any, costs to regulated entities. The use of lower emitting fuels would not have any
significant adverse energy requirements or non-air quality or environmental impacts, as the EPA
determined in the 2015 NSPS. Id. at 64616. In addition, the use of fuels meeting this criterion
would result in some emission reductions by limiting the use of fuels with higher carbon content,such as residual oil, as the EPA also explained in the 2015 NSPS. Id. Although the use of fuels
meeting this criterion would not advance technology, in light of the other reasons described here,

229

Important characteristics for minimizing emissions from low load combustion turbines
include the ability to operate efficiently while operating at part load conditions and the ability to
rapidly achieve maximum efficiency to minimize periods of operation at lower efficiencies.
These characteristics do not necessarily always align with higher design efficiencies that are
determined under steady state full load conditions.
171

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

the EPA proposes that the use of natural gas, Nos. 1 and 2 fuel oils, and other fuels 230 currently
specified in 40 CFR part 60, subpart TTTT, qualify as the BSER for new and reconstructedcombustion turbine EGUs in the low load subcategory. The EPA is also proposing to add lowGHG hydrogen to the list of fuels meeting the uniform fuels criteria in 40 CFR part 60, subpart
TTTTa. The addition of low-GHG hydrogen (and fuels derived from hydrogen) to 40 CFR part60, subpart TTTTa would simplify the recordkeeping and reporting requirements for low load
combustion turbines that elect to burn low-GHG hydrogen. As described in section VII.F, acomponent of the BSER for certain subcategories in subpart TTTTa is based on the use of lowGHG hydrogen. An owner/operator of a subpart TTTTa affected combustion turbine that
combusts hydrogen for compliance purposes 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, the EPA is not proposingthat efficient design and operation 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 necessarily cost reasonable andwould not necessarily result in emission reductions. High efficiency combustion turbines havehigher 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 ahigh-efficiency simple cycle turbine is 5 percent more than that of a comparable lower efficiency
simple cycle turbine. Assuming all other costs are the same and that the high-efficiency simple

230

The BSER for multi-fuel-fired combustion turbines subject to 40 CFR part 60, subpart TTTT
is also the use of fuels with an emissions rate of 160 lb CO2/MMBtu or less. The use of thesefuels would demonstrate compliance with the low load subcategory.
172
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

cycle turbine uses 6 percent less fuel, it would not necessarily be cost reasonable to use a highefficiency simple cycle turbine until the combustion turbine is operated at a 12-operating-monthcapacity factor of approximately 20 percent. At lower capacity factors, the CO2 abatement costs
on both a $/ton and $/MW basis increase rapidly. 231 Further, the emission rate of a low load
combustion turbine 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, acombustion 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 alower design efficiency.
The EPA solicits comment on whether, and the extent to which, high-efficiency designs
also operate more efficiently at part loads and can start more quickly and reach the desired load
more rapidly than combustion turbines with less efficient design efficiencies. If high-efficiency
simple cycle turbines do operate at higher part-load efficiencies and are able to reach theintended operating load more quickly, the use of highly efficient simple cycle turbines for low
load applications would result in lower GHG reductions. In addition, the EPA solicits commenton the cost premium of high-efficiency simple cycle turbines. If the use of highly efficient simple
cycle turbines results in GHG reductions at reasonable cost, their use could qualify as the BSER
for low load combustion turbines. The EPA is soliciting comment on whether the BSER for new
low load combustion turbines should be the use of high efficiency simple cycle technology.
However, since the method of operation has a substantial impact on the emissions rate, it may
not be feasible for to prescribe or enforce a single numerical standard of performance for

231

The cost effectiveness calculation is highly dependent upon assumptions concerning theincrease in capital costs, the decrease in heat rate, and the price of natural gas.
173

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

affected sources strictly based on design efficiency. Accordingly, the EPA solicits comment onwhether it would be appropriate to promulgate such a requirement as a design standard pursuant
to CAA section 111(h). Pursuant to such a design standard, compliance would be demonstrated(i) initially, through an emissions test and (ii) subsequently, based on the use of lower emitting
fuels. The initial full load performance test for natural gas-fired low load combustion turbines the
EPA is considering is 1,150 lb CO2/MWh-gross or 1,100 lb CO2/MWh-gross. 232 Combustion
turbine manufacturers conduct testing on their products and the initial performance test is
equivalent to a design efficiency of approximately 35 and 36 percent, respectively. According to
Gas Turbine World 2021, approximately three-fourths of simple cycle combustion turbines havedesign efficiencies of 35 percent or higher and half of simple cycle combustion turbines havedesign efficiencies of 36 percent or higher. The EPA is soliciting comment on if the initial
performance test for low load combustion turbines could be conducted by the manufacturer
certifying the design GHG emissions rate or if the owner or operator should be required to
conduct separate testing to verify the emissions rate. The EPA notes that even if the Agency
determines that a manufacturer design efficiency-based emissions requirement is appropriate for
new low load combustion turbines, owners/operators would also have the option to either comply
with the intermediate load standard of performance on a continuous basis or conduct an initial
performance test as an alternative to purchasing a combustion turbine that achieves the specified
design efficiency. For example, owners/operators could elect to cofire low-GHG hydrogen or
install integrated renewable generation as an alternative to purchasing a combustion turbine thatmeets the specified design efficiency.

232

The initial full load compliance test would be a 3-hour performance test and the measured
emissions rate would be corrected to ISO conditions.
174

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 acomponent of the BSER) for low load combustion turbines. 233 As described in the section
discussing the second component of BSER for the intermediate load subcategory, the EPA is notproposing that CCS is the BSER for simple cycle combustion turbines based on the Agency’s
assessment that CCS may not be cost-effective for such combustion turbines when operated atintermediate load. This rationale applies with even greater force for low load combustion
turbines. In addition, currently available post-combustion amine-based carbon capture systems
require that the exhaust from a combustion turbine be cooled prior to entering the carbon capture
equipment. The most energy efficient way to do this is to use a HSRG, which is an integral
component of a combined cycle turbine system but is not incorporated in a simple cycle unit. For
these reasons, the Agency is not proposing that CCS qualifies as the BSER for this subcategoryof sources.
The EPA is not proposing low-GHG hydrogen co-firing as the BSER for low load
combustion turbines because not all new combustion turbines can necessarily co-fire higher

233

The EPA will not finalize the use of CCS or hydrogen co-firing as the BSER (or as acomponent of the BSER) for low load combustion turbines unless it first issues a subsequent
notice of proposed rulemaking further evaluating such measures for that subcategory.
175

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

percentages of hydrogen, there are potential infrastructure issues specific to low load combustion
turbines, and at the relatively infrequent levels of utilization that characterize the low load
subcategory, a low-GHG hydrogen co-firing BSER would not necessarily result in cost-effective
GHG reductions for all low load combustion turbines. As discussed later in this section, theannounced hydrogen co-firing combustion turbine projects appear to be intermediate and baseload combustion turbines. Manufacturers may focus initial research and development forhydrogen co-firing on combustion turbines that operate at higher capacity factors and that canachieve higher levels of overall GHG reductions. The EPA is soliciting comment on whether thisdevelopment could limit the availability of low load combustion turbines that are capable ofburning higher percentages of hydrogen. The EPA is also soliciting comment on technologies toreduce potential costs and technical challenges for the transport and storage of hydrogen forowners/operators of low load combustion turbines. In particular, the EPA is soliciting comment
on approaches that could be used for owners/operators of low load combustion turbines locatedin high demand centers (e.g., dense urban areas). To the extent these factors are not significant,the EPA is soliciting comment, with the intention of determining whether it would be appropriate
to consider such a requirement in a future rulemaking, on whether the EPA should add a second
component of the BSER for low load combustion turbines, based on hydrogen co-firing thatwould begin in 2032. The hydrogen co-firing requirement would be a separate requirement inaddition to the proposed lower emitting fuels requirement. Based on simple cycle turbines thatrecently commenced operation, the average 12-operating-month capacity factor of low load
combustion turbines would be less than 8 percent. If hydrogen co-firing were to qualify as the
BSER, based on historical trends for construction of new simple cycle turbines and the operation

176
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

of those turbines in 2021, a BSER based on 30 percent low-GHG hydrogen co-firing by volume
for low load combustion turbines would result in annual reductions of 49,000 tons of CO2.
2. 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 firstcomponent of the BSER is the use of high-efficiency simple cycle turbine technology incombination with the best operating and maintenance practices. For combustion turbines in thebase load subcategory, the first component of the BSER is the use of high-efficiency combined
cycle technology in combination with the best operating and maintenance practices.
a. Lower Emitting Fuels
The EPA is not proposing lower emitting fuels as the BSER for intermediate load or baseload EGUs because, as described earlier in this section, it would achieve few GHG emission
reductions compared to highly efficient generation.
b. 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 aswell. Highly efficient generating technology is available and offered by multiple vendors forboth simple cycle and combined cycle combustion turbines. Both types of turbines can also
employ best operating and maintenance practices, which include routine operating andmaintenance practices that minimize fuel use.
For simple cycle combustion turbines, manufacturers continue to improve the efficiency
177
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

by increasing firing temperature, increasing pressure ratios, using intercooling on the aircompressor, 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 forowner/operators of combined cycle facilities using a turbine engine with an exhaust temperature
below 593 °C or a steam turbine engine smaller than 60 MW to incorporate a steam reheat cycle.
Smaller combustion turbine engines, less than those rated at approximately 2,000 MMBtu/h, tend
to have lower exhaust temperatures and are paired with steam turbines of 60 MW or less. These
smaller combined cycle units are limited to using 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 standards of performance 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 andblowdown heat recovery. Best operating and maintenance practices include, but are not limited
to, minimizing steam leaks, minimizing air infiltration, and cleaning and maintaining heattransfer surfaces.
178
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 toutilize supercritical steam conditions or to utilize supercritical CO2 as the working fluid insteadof 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 andother technologies that could reduce the emissions rate of new combustion turbines, see theEfficient Generation at Combustion Turbine Electric Generating Units TSD, 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 theextent commenters support the inclusion of emission reductions from the use of thesetechnologies, the EPA requests that cost information and potential emission reductions be
included.
i. Adequately Demonstrated
The EPA proposes that highly efficient simple cycle and combined cycle designs areadequately 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 how the combustion turbine is operated or maintained, and the levels of
efficiency that the EPA is proposing have been achieved by many recently constructed turbines.
Approximately 14 percent of simple cycle and combined cycle combustion turbines that havecommenced operation since 2015 have maintained emission rates below the proposed standards,
179
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

demonstrating that the efficient generation technology described in this BSER is commerciallyavailable and that the standards of performance the EPA is proposing are achievable.
ii. Costs
In general, advanced generation technologies enhance operational efficiency compared tolower efficiency designs. Such technologies present little incremental capital cost compared toother 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 increasein 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, thecost of combustion turbine engines is dependent upon many factors, but the EPA estimates thatthat 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 highefficiency 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 turbinesat a 12-operating-month capacity factor of approximately 20 percent. Therefore, a BSER basedon 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 berecovered 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. Furthermore, intermediate load combustion turbines
180
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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. 234 The reduction in fuel costs fully offset the capital costs at capacity factors of 40
percent or greater over the expected 30-year life of the facility. Therefore, a BSER based on theuse of high-efficiency combined cycle combustion turbines for base load combustion turbines
would have minimal, if any, overall compliance costs since the capital costs would be recovered
through reduced fuel costs over the expected 30-year life of the facility. For additional
information on costs, see the Efficient Generation at Combustion Turbine Electric Generating
Units TSD, which is available in the rulemaking docket.
iii. 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 lessefficient 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, the234

Cost And Performance Baseline for Fossil Energy Plants Volume 1: Bituminous Coal andNatural Gas to Electricity, Rev. 4A (October 2022),
https://netl.doe.gov/projects/files/CostAndPerformanceBaselineForFossilEnergyPlantsVolume1
BituminousCoalAndNaturalGasToElectricity_101422.pdf.
181

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 reconstructedbase load and intermediate load combustion turbines will not have significant impacts on thenationwide supply of electricity, electricity prices, or the structure of the electric power sector.
On a nationwide basis, the additional costs of the use of highly efficient generation will be small
because the technology does not add significant costs and at least some of those costs are offset
by reduced fuel costs. In addition, at least some of these new combustion turbines would be
expected to incorporate highly efficient generation technology in any event.
iv. Extent of Reductions in CO2 Emissions
The EPA estimated the potential emission reductions associated with a standard thatreflects the application of highly efficient generation as BSER for the intermediate load and baseload subcategories. As discussed in section VII.G, the EPA determined that the standards ofperformance 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.
Between 2015 and 2021, an average of 16 simple cycle turbines commenced operation
per year. Of these, the EPA estimates that an average of six operated at greater than a 20 percent
capacity factor on a 12-operating-month basis and thus would be considered intermediate load
combustion turbines. For recent intermediate load simple cycle turbines, the EPA determined

182
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

that the weighted average maximum 12-operating-month emissions rate 235 is 1,250 lb
CO2/MWh-gross. This is 8.3 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 8.3 percent annually. Based on
historical trends for construction of new simple cycle turbines and the operation of those turbines
in 2021, the proposed standards for intermediate load combustion turbines would result in annual
reductions of 44,000 tons of CO2 as well as 13 tons of NOX. For the base load subcategory, theweighted average maximum 12-operating-month emissions rate of large (base load ratings of
2,000 MMBtu/h or more) NGCC combustion turbines that commenced operation since 2015 has
been 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 593 MMBtu/h) reporting emissions that commenced
operation since 2015 has had a reported annual emissions rate of 870 lb CO2/MWh-gross, whichis slightly lower than the proposed standard of 875 lb CO2/MWh-gross for a small base load
combustion turbine with a base load rating of 593 MMBtu/h. Therefore, the EPA estimates thatthe proposed standards would require owners/operators to construct and maintain highly efficient
combined cycle combustion turbines that would result in reductions in emissions ofapproximately 5 percent for new large stationary combustion EGUs and maintaining best
performing emission rates for new small stationary combustion EGUs. Using historical trends for

235

The EPA is defining the achievable emissions rate as either the maximum 12-operatingmonth or the 99th percent confidence 12-operating-month emissions rate. The weighted average
maximum emissions rate is the heat input weighted overall average of the maximum emission
rates.
183

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

new combined cycle turbines and the operation of those combustion turbines in 2021, theproposed standards for base load combustion turbines would result in annual reductions of
940,000 tons of CO2 as well as 75 tons of NOX.
v. Promotion of the Development and Implementation of Technology
The EPA also considered the potential impact of selecting highly efficient generation
technology as the BSER in promoting the development and implementation of improved control
technology. This technology is more efficient than the average new generation technology anddetermining it to be a component of the BSER will advance its penetration throughout theindustry. Accordingly, consideration of this factor supports the EPA’s proposal to determine thistechnology to be the first component of the BSER.
c. Low-GHG Hydrogen and CCS
For reasons discussed in sections VII.F.3.b.v (CCS) and VII.F.3.c.vi (low-GHG
hydrogen), the EPA is not proposing either CCS or co-firing low-GHG hydrogen as the firstcomponent of the BSER for intermediate load or base load EGUs.
d. Proposed BSER
The EPA proposes that highly efficient generating technology in combination with thebest operating and maintenance practices is the first component BSER for base load andintermediate load combustion turbines and the phase 1 standards of performance are based on theapplication 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 componentof the BSER for base load combustion turbines.
184
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Highly efficient generation qualifies as a component of the BSER because it isadequately 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 ofadvanced 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.
3. BSER for Base Load and Intermediate Load Subcategories—Second and Third Components
This section describes the proposed second (and in some cases third) component of the
BSER for base load and intermediate load combustion turbines, which would be reflected in thesecond phase (and in some cases third phase) standards of performance. The proposed second
component of the BSER for base load combustion turbines that are adopting the CCS pathway is
the use of 90 percent CCS; and the corresponding standard of performance would apply
beginning in 2035. The second component of the BSER for base load combustion turbines thatare adopting the low-GHG hydrogen co-firing pathway and for intermediate load combustion
turbines is co-firing 30 percent (by volume) low-GHG hydrogen and the corresponding standardof performance would apply beginning in 2032. The third component of the BSER would apply
only to base load combustion turbines that are subject to a second phase standard that is based on
co-firing 30 percent (by volume) low-GHG hydrogen. For those sources, the third component of
the BSER is co-firing 96 percent (by volume) low-GHG hydrogen and the corresponding
standard of performance would apply beginning in 2038. The EPA is also soliciting comment onwhether intermediate load combustion turbines should be subject to a more stringent third phasestandard based on 96 percent low-GHG hydrogen co-firing by 2038. A BSER based on 96
185
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

percent co-firing would result in a standard of performance of 140 lb CO2/MWh-gross for anatural gas-fired intermediate load combustion turbine.
a. Authority to Promulgate a Multi-part BSER and Standard of Performance
The EPA’s proposed approach of promulgating standards of performance that apply inmultiple phases, based on determining the BSER to be a set of controls with multiple
components, is consistent with CAA section 111(b). That provision authorizes the EPA topromulgate “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 limitationachievable through the application of the [BSER].” CAA section 111(a)(1). CAA section
111(b)(1)(B) further provides, “[s]tandards of performance … shall become effective uponpromulgation.” In this rulemaking, the EPA is proposing to determine that the BSER is a set ofcontrols that, depending on the subcategory, include either highly efficient generation plus use of
CCS or highly efficient generation plus 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 co-firing 30 percent(by volume) low-GHG hydrogen and highly efficient generation in combination with 90 percent
CCS – in 2032 and 2035, respectively. The EPA is also proposing that certain sources can apply
the third component of the BSER – co-firing 96 percent (by volume) low-GHG hydrogen – by2038.
Accordingly, the EPA is proposing standards of performance that reflect the applicationof this multi-component BSER and that take the form of standards of performance that affectedsources must comply with in either two or three phases. Affected sources must comply with the186This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

first phase standards that are based on the application of the first component of the BSER upon
initial startup of the facility. The second phase standards are based on the application of both thefirst and second components of the BSER by 2032 (for those sources utilizing co-firing lowGHG hydrogen) and by 2035 (for those sources utilizing CCS). The third phase standards are
only applicable to those sources that are subject to a second phase standard of performance basedon the highly efficient generation in combination with co-firing 30 percent (by volume) lowGHG hydrogen. The third phase standards for those sources are based on the application of thefirst component of the BSER and on the third component, which is co-firing 96 percent (byvolume) low-GHG hydrogen by 2038. In this manner, this multi-phase standard of performance“become[s] effective upon promulgation.” CAA section 111(b)(1)(B). That is, uponpromulgation, affected sources become subject to a standard of performance that limits theiremissions immediately, which is the first phase of the standard of performance, and they also
become subject to more stringent standards beginning in 2032 or later, which are the second andin some cases third phase of the standard of performance.
D.C. Circuit caselaw supports the proposition that CAA section 111 authorizes the EPA
to determine that controls qualify as the BSER—including meeting the “adequately
demonstrated” criterion—even if the controls require some amount of “lead time,” which thecourt has defined as “the time in which the technology will have to be available.” 236 The
caselaw’s interpretation of “adequately demonstrated” to accommodate lead time accords with
common sense and the practical experience of certain types of controls, discussed below.
Consistent with this caselaw, the phased implementation of the standards of performance in this236

Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375, 391 (D.C. Cir. 1973) (citations
omitted).
187

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

rule ensures that 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 thestandards, and thereby ensures that the standards are achievable. Indeed, interpreting CAA
section 111 to preclude phased implementation of standards of performance would betantamount to interpreting the provision to preclude standards based on lead time, which would
be contrary to the D.C. Circuit caselaw and common sense.
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 oftechnology, which also serve as precedent for the two-phase implementation approach proposedin 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, withinterim milestones); 80 FR 13672, 13676 (March 16, 2015) (establishing stepped complianceapproach 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 fortrained personnel to perform installation); 77 FR 56422, 56450 (September 12, 2012)(establishing standards for petroleum refineries, with 3-year compliance timeframe for
installation of control devices); 71 FR 39154, 39158 (July 11, 2006) (establishing standards forstationary compression ignition internal combustion engines, with 2 to 3-year compliancetimeframe and up to 6 years for certain emergency fire pump engines); 70 FR 28606, 28617(March 18, 2005) (establishing two-phase caps for mercury standards of performance from newand existing coal-fired electric utility steam generating units based on timeframe when additional
188
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

control technologies were projected to be adequately demonstrated). 237 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). 238
In each action, the standards and compliance timelines were effective upon the final rule, withaffected facilities required to comply consistent with the phased compliance deadline specified ineach action.
It should be noted that the multi-phased implementation of the standards of performancethat 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 8year 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 andthird phases of the standard of performance, if finalized, would apply to affected facilities thatcommence 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, thenaffected 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.

237

Cf. New Jersey v. EPA, 517 F.3d 574, 583-584 (D.C. Cir. 2008) (vacating rule on othergrounds).
238
Cf. West Virginia v. EPA, 142 S. Ct. 2587 (2022) (vacating rule on other grounds).
189
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Similarly, the multi-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 existingsources 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.
b. BSER for Base Load Subcategory of Combustion Turbines Adopting the CCS Pathway—
Second Component
This section describes the second component of the BSER for the base load subcategoryof combustion turbines that are adopting the CCS pathway. This subcategory is expected toinclude highly efficient combined cycle combustion turbines that primarily combust fossil fuels,
and therefore have higher 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, as well as for large
and frequently operated existing stationary combustion turbines. Many aspects of CCS arecommon to new combined cycle combustion turbines, existing long-term steam generating units,
and existing stationary combustion turbines, and the following discussion details those common
aspects and considerations.

190
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

i. Lower Emitting Fuels
The EPA is not proposing lower emitting fuels as the second component of the BSER forbase load combustion turbines because it would achieve few emission reductions, compared tohighly efficient generation in combination with the use of CCS.
ii. 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 acomponent of the BSER that is reflected in the second phase of the standards of performance forbase load combustion turbine EGUs that are adopting the CCS pathway. 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, physically smaller carbon capture equipment may beused—potentially reducing capital, fixed, and operating costs.
iii. 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 autility 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 ofthat 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 fuelcombustion 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
191
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

in CO2 scrubber systems using chemical absorption (or chemisorption). In a chemisorption-based
separation process, the flue gas is processed through the CO2 scrubber and the CO2 is absorbedby the liquid solvent. The CO2-rich solvent is then regenerated by heating the solvent to release
the captured CO2.
Another technology, oxy-combustion, uses a purified oxygen stream from an air
separation unit (often diluted with recycled CO2 to control the flame temperature) to combust thefuel and produce a higher concentration of CO2 in the flue gas, as opposed to combustion withoxygen in air which contains 80 percent nitrogen. The high purity CO2 is then compressed andtransported, 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 tooversee geological sequestration projects and assure their safety and effectiveness. See 80 FR
64549 (October 23, 2015).
(A) 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 inorder 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. Higher capture rates may be possible –the 2022 NETL Baseline report evaluated capture rates at 90 and 95 percent with marginal
differences in cost. The Agency is soliciting comment on the range of the capture rate of CO2 at
192
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

the stack from 90 to 95 percent or greater. The EPA also notes that the operating availability (thefraction of time CCS equipment is operational relative to the operation of the combustion
turbine) may be less than 100 percent and is therefore soliciting comment on a range in emission
reduction from 75 to 90 percent, as further discussed in section VII.G.2 of this preamble.
The EPA previously determined “partial CCS” to be a component of the BSER (incombination 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). 239 As
described in that action, reiterated in this section of the preamble, and detailed further inaccompanying TSDs available in the docket for this rulemaking, numerous projects demonstrate
the feasibility and effectiveness of CCS technology.
In the 2015 NSPS, the EPA considered coal-fired industrial projects that had installed atleast some components of CCS technology. In doing so, the EPA recognized that some of thoseprojects had received assistance in the form of grants, loan guarantees, and federal tax credits forinvestment 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 recognizedthat the EPAct05 included provisions that constrained how the EPA could rely on EPAct05assisted projects in determining whether technology is adequately demonstrated for the purposesof CAA section 111. 240 The EPA went on to provide a legal interpretation of those constraints.

239

In the present action, the EPA is not re-opening any aspect of the CCS determinations in the2015 NSPS.
240
The relevant EPAct05 provisions include the following: Section 402(i) of the EPAct05,
codified at 42 U.S.C. 15962(a), provides as follows:
193
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Under that legal interpretation, “these provisions [in the EPAct05] … preclude the EPA fromrelying 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 otherinformation.” 241 Id. at 64541–42. In the present action, the EPA is applying the same legal
interpretation and is not reopening it for comment.
(1) 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 existingcoal-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 EPAct05assisted projects.

“No technology, or level of emission reduction, solely by reason of the use of the technology, or
the achievement of the emission reduction, by 1 or more facilities receiving assistance under thisAct, shall be considered to be adequately demonstrated [ ] for purposes of section 111 of the
Clean Air Act. . . .”IRC section 48A(g), as added by EPAct05 1307(b), provides as follows:“No use of technology (or level of emission reduction solely by reason of the use of thetechnology), and no achievement of any emission reduction by the demonstration of any
technology or performance level, by or at one or more facilities with respect to which a credit isallowed under this section, shall be considered to indicate that the technology or performancelevel is adequately demonstrated [ ] for purposes of section 111 of the Clean Air Act. . . .”Section 421(a) states:“No technology, or level of emission reduction, shall be treated as adequately demonstrated for
purpose [sic] of section 7411 of this title, . . . solely by reason of the use of such technology, or
the achievement of such emission reduction, by one or more facilities receiving assistance under
section 13572(a)(1) of this title.”
241
In the 2015 NSPS, the EPA adopted several other legal interpretations of these EPAct05
provisions as well, which it is not reopening in this rule. See 80 FR 64541 (October 23, 2015).
194
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Various technologies may be used to capture CO2, the details of which are described in
the GHG Mitigation Measures for Steam Generating Units TSD, which is available in therulemaking docket. 242 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. 243 Lastly, as noted above, oxy-combustion
uses a purified oxygen stream from an air separation unit (often diluted with recycled CO2 tocontrol 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 atcommercial 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 withpotential 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
and/or acid wash column to limit emission of amines or other byproducts. In the solvent

242

Technologies to capture CO2 are also discussed in the GHG Mitigation Measures – Carbon
Capture and Storage for Combustion Turbines TSD.
243
For pre-combustion capture (as is applicable to an IGCC unit), syngas produced bygasification passes through a water-gas shift catalyst to produce a gas stream with a higher
concentration of hydrogen and CO2. The higher CO2 concentration relative to conventional
combustion flue gas reduces the demands (power, heating, and cooling) of the subsequent CO2
capture process (e.g., solid sorbent-based or solvent-based capture), the treated hydrogen canthen be combusted in the unit.
195
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

regeneration column, the solution is heated (using steam) to release the absorbed CO2. The
released CO2 is then compressed and transported offsite, usually 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.
(2) Capture Demonstrations at Coal-fired Steam Generating Units and Industrial Processes
The function, design, and operation of post-combustion CO2 capture equipment issimilar, although not identical, for both steam generating units and combustion turbines. As aresult, 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 postcombustion 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 existingcoal-fired power plant. It uses the amine-based Shell CANSOLV process, with integrated heatand power from the steam generating unit. 244 While successfully demonstrating the commercialscale 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. 245

244

Giannaris, S., et al. Proceedings of the 15th International Conference on Greenhouse Gas
Control Technologies (March 15–18, 2021). SaskPower’s Boundary Dam Unit 3 Carbon
Capture Facility–The Journey to Achieving Reliability.
https://papers.ssrn.com/sol3/papers.cfm?abstract_id=3820191.
245
International CCS Knowledge Centre. The Shand CCS Feasibility Study Public Report.
https://ccsknowledge.com/pub/Publications/Shand_CCS_Feasibility_Study_Public_Report_Nov2018_(2021-05-12).pdf.
196This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 maintenanceand 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. 246 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 andthird quarters of 2022. 247 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 atelectricity generating plants and other industrial facilities, some of which were previously notedin 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 thefood processing industry. 248 At the 180-MW Warrior Run plant, approximately 10 percent of the246

S&P Global Market Intelligence (January 6, 2022). Only still-operating carbon capture
project battled technical issues in 2021. https://www.spglobal.com/marketintelligence/en/newsinsights/latest-news-headlines/only-still-operating-carbon-capture-project-battled-technicalissues-in-2021-68302671.
247
SaskPower (October 18, 2022). BD3 Status Update: Q3 2022.
https://www.saskpower.com/about-us/our-company/blog/2022/bd3-status-update-q3-2022.
248
Dooley, J. J., et al. (2009). “An Assessment of the Commercial Availability of Carbon
Dioxide Capture and Storage Technologies as of June 2009.” U.S. DOE, Pacific Northwest
National Laboratory, under Contract DE-AC05-76RL01830.
197
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 peryear) from 2001 through around 2019. 249 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 aminebased system to capture approximately 270,000 metric tons of CO2 per year from the flue gas ofa 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. 250
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. 251 The Quest facility has been operating since 2015 and capturesapproximately 1 million metric tons of CO2 per year.
(3) 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

249

Shady Point Plant (River Valley) was sold to Oklahoma Gas and Electric in 2019.
https://www.oklahoman.com/story/business/columns/2019/05/23/oklahoma-gas-and-electricacquires-aes-shady-point-after-federal-approval/60454346007/.
250
IEA (2009), World Energy Outlook 2009, OECD/IEA, Paris.
251
Quest Carbon Capture and Storage Project Annual Summary Report, Alberta Department ofEnergy: 2021. https://open.alberta.ca/publications/quest-carbon-capture-and-storage-projectannual-report-2021.
198
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

other projects are in development, as discussed immediately below. Currently available postcombustion amine-based carbon capture systems require that the flue gas be cooled prior toentering 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 notconsidering the use of CCS as a potential component of the BSER for them.
(a) CCS on Combined Cycle EGUs
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 PlusSM capture system and demonstrated thecommercial viability of carbon capture on a combined cycle combustion turbine EGU using firstgeneration technology. The 40-MW slipstream capture facility operated from 1991 to 2005 andcaptured 85 to 95 percent of the CO2 in the slipstream for use in the food industry. 252 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 fromthe combined cycle facility and sequester up to 1.5 million metric tons of CO2 annually. A
storage site being developed 62 miles off the Scottish North Sea coast might serve as a

252

U.S. Department of Energy (DOE). Carbon Capture Opportunities for Natural Gas Fired
Power Systems. https://www.energy.gov/fecm/articles/carbon-capture-opportunities-naturalgas-fired-power-systems.
199

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

destination for the captured CO2. 253 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. 254(b) Net Power Cycle
In addition, there are several planned projects using the NET Power Cycle. 255 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 isdesigned to achieve thermal efficiencies of up to 59 percent. 256 Potential advantages of this cycle
are that it emits no NOX and produces a stream of high-purity CO2 257 that can be delivered bypipeline 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, and several international
projects.

253

Buli, N. (2021, May 10). SSE, Equinor plan new gas power plant with carbon capture in
Scotland. Reuters. https://www.reuters.com/business/sustainable-business/sse-equinor-plan-newgas-power-plant-with-carbon-capture-scotland-2021-05-11/.
254
Competitive Power Ventures (2022). Multi-Billion Dollar Combined Cycle Natural Gas
Power Station with Carbon Capture Announced in West Virginia. Press Release. September 16,
2022. https://www.cpv.com/2022/09/16/multi-billion-dollar-combined cycle-natural-gas-powerstation-with-carbon-capture-announced-in-west-virginia/.
255
https://netpower.com/technology/. The Net Power Cycle was formerly referred to as theAllam-Fetvedt cycle.
256
Yellen, D. (2020, May 25). Allam Cycle carbon capture gas plants: 11 percent more efficient,
all CO2 captured. Energy Post. https://energypost.eu/allam-cycle-carbon-capture-gas-plants-11more-efficient-all-co2-captured/.
257
This allows for capture of over 97 percent of the CO2 emissions. www.netpower.com
200
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

(4) 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 thispreamble, adequate demonstration of CO2 capture technology is further corroborated by CO2
capture projects assisted by grants, loan guarantees, and Federal tax credits for “clean coaltechnology” authorized by the EPAct05. 80 FR 64541–42 (October 23, 2015).
(a) EPAct05-assisted CO2 Capture Projects at Coal-fired Steam Generating Units
Petra Nova is a 240 MW-equivalent capture facility that is the first at-scale application ofcarbon 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. 258 A final
report from National Energy Technology (NETL) details the success of the project and what waslearned from this first-of-a-kind demonstration at scale. 259 The project used Mitsubishi Heavy
Industry’s proprietary KM-CDR Process®, a process that is similar to an amine-based solvent
process but that uses a proprietary solvent 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 theCO2 from the slip stream of flue gas processed with 99.08 percent of the captured CO2

258“The World's Largest Carbon Capture Plant Gets a Second Chance in Texas” Bloomberg
News, February 8, 2023. https://www.bloomberg.com/news/articles/2023-02-08/the-world-slargest-carbon-capture-plant-gets-a-second-chance-in-texas?leadSource=uverify%20wall.
259
W.A. Parish Post-Combustion CO2 Capture and Sequestration Demonstration Project, Final
Scientific/Technical Report (March 2020). https://www.osti.gov/servlets/purl/1608572.
201
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

sequestered by EOR. Plant Barry in Mobile, Alabama, began using the KM-CDR Process® in2011 for a fully integrated 25-MW CCS project with a capture rate of 90 percent. 260 The CCS
project at Plant Barry captured approximately 165,000 tons of CO2 annually, which is thentransported via pipeline and sequestered underground in geologic formations. See 80 FR 64552(October 23, 2015).
(b) EPAct05-assisted CO2 Capture Projects at Stationary Combustion Turbines
There are several EPAct05-assisted projects related to NGCC units including: 261 262 263 264
265•

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.

260

U.S. Department of Energy (DOE). National Energy Technology Laboratory (NETL).
https://www.netl.doe.gov/node/1741.
261
General Electric (GE) (2022). U.S. Department of Energy Awards $5.7 Million for GE-Led
Carbon Capture Technology Integration Project Targeting to Achieve 95% Reduction of Carbon
Emissions. Press Release. February 15, 2022. https://www.ge.com/news/press-releases/usdepartment-of-energy-awards-57-million-for-ge-led-carbon-capture-technology.
262
Larson, A. (2022). GE-Led Carbon Capture Project at Southern Company Site Gets DOE
Funding. Power. https://www.powermag.com/ge-led-carbon-capture-project-at-southerncompany-site-gets-doe-funding/.
263
U.S. Department of Energy (DOE) (2021). DOE Invests $45 Million to Decarbonize the
Natural Gas Power and Industrial Sectors Using Carbon Capture and Storage. October 6, 2021.
https://www.energy.gov/articles/doe-invests-45-million-decarbonize-natural-gas-power-andindustrial-sectors-using-carbon.
264
DOE (2022). Additional Selections for Funding Opportunity Announcement 2515. Office ofFossil Energy and Carbon Management. https://www.energy.gov/fecm/additional-selectionsfunding-opportunity-announcement-2515.
265
DOE (2019). FOA 2058: Front-End Engineering Design (FEED) Studies for Carbon Capture
Systems on Coal and Natural Gas Power Plants. Office of Fossil Energy and Carbon
Management. https://www.energy.gov/fecm/foa-2058-front-end-engineering-design-feed-studiescarbon-capture-systems-coal-and-natural-gas.
202
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

•

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 postcombustion 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 withthe potential to reduce electricity costs by at least 15 percent.

•SRI International (Menlo Park, California) was awarded $1,499,759 to design, build, andtest 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 fluegas 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 anengineering 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.
203

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

•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 totest 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 toachieve a 95 percent capture rate.
There are also several announced NET Power Cycle based CO2 capture projects that are

EPAct05-assisted. These include the 280-MW Coyote Clean Power Project on the Southern Ute
Indian Reservation in Colorado and a 300-MW project located near Occidental’s Permian Basin
operations close to Odessa, Texas. Commercial operation of the facility near Odessa, Texas is
expected in 2026.
(5) CO2 Transport(a) Demonstration of CO2 Transport
The majority of CO2 transported in the U.S. is transported through pipelines. Pipelinetransport 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. 266
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 that266

For additional information on CO2 transportation infrastructure project timelines, costs andother details, please see the GHG Mitigation Measures for Steam Generating Units TSD.
204

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

5,339 miles of CO2 pipelines were in operation in 2021, a 13 percent increase in CO2 pipeline
miles since 2011. 267 Moreover, several major projects have recently been announced to expand
the CO2 pipeline network across the U.S. For example, the Midwest Carbon Express has
proposed to add more than 2,000 miles of dedicated CO2 pipeline in Iowa, Nebraska, North
Dakota, South Dakota, and Minnesota. The Midwest Carbon Express is projected to begin
operations in 2024. 268 Another example is the Heartland Greenway project, which has proposed
to add more than 1,300 miles of dedicated CO2 pipeline in Iowa, Nebraska, South Dakota,
Minnesota, and Illinois. The Heartland Greenway project is projected to start its initial systemcommissioning in the second quarter of 2025. 269 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 befeasible. 270 271 The IIJA also included substantial support for CO2 transportation infrastructure.

267

U.S. Department of Transportation, Pipeline and Hazardous Material Safety Administration,“Hazardous Annual Liquid Data.” 2021. https://www.phmsa.dot.gov/data-andstatistics/pipeline/gas-distribution-gas-gathering-gas-transmission-hazardous-liquids.
268
Beach, Jeff. “World’s Largest Carbon Capture Pipeline Aims to Connect 31 Ethanol Plants,
Cut across Upper Midwest.” Agweek, December 6, 2021.
https://www.agweek.com/business/worlds-largest-carbon-capture-pipeline-aims-to-connect-31ethanol-plants-cut-across-upper-midwest.
269
Navigator CO2, “NavCO2 Fact Sheet.” 2022. https://d3o151.p3cdn1.secureserver.net/wpcontent/uploads/2022/08/HG-Fact-Sheet-vFINAL.pdf.
270
For additional information regarding planned or announced pipelines please see section
4.6.1.2 of the GHG Mitigation Measures for Steam Generating Units TSD.
271
U.S. Department of Transportation, Pipeline and Hazardous Material Safety Administration,“Hazardous Annual Liquid Data.” 2021. https://www.phmsa.dot.gov/data-andstatistics/pipeline/gas-distribution-gas-gathering-gas-transmission-hazardous-liquids.
205
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

(b) Security of CO2 Transport
The safety of existing and new CO2 pipelines that transport CO2 in a supercritical state is
exclusively regulated by PHMSA. These regulations include standards related to pipeline design,
construction, and testing, operations and maintenance, operator reporting requirements, operator
qualifications, corrosion control and pipeline integrity management, incident reporting andresponse, and public awareness and communications. PHMSA has regulatory authority to
conduct inspections of supercritical CO2 pipeline operations and issue notices to operators in theevent of operator noncompliance with regulatory requirements. 272 Furthermore, PHMSA
initiated a rulemaking in 2022 to develop and implement new measures to strengthen its safety
oversight of supercritical CO2 pipelines following investigation into a CO2 pipeline failure in
Satartia, Mississippi in 2020. 273 Following that incident, PHMSA also issued a Notice ofProbable Violation, Proposed Civil Penalty, and Proposed Compliance Order (Notice) to theoperator related to probable violations of Federal pipeline safety regulations. The Notice wasultimately resolved through a Consent Agreement between PHMSA and the operator that
includes the assessment of civil penalties and identifies actions for the operator to take to address
the alleged violations and risk conditions. 274 PHMSA has further issued an updated nationwide
advisory bulletin to all pipeline operators, and solicited research proposals to strengthen CO2

272

See generally 49 CFR 190–199.
PHMSA, “PHMSA Announces New Safety Measures to Protect Americans From Carbon
Dioxide Pipeline Failures After Satartia, MS Leak.” 2022.
https://www.phmsa.dot.gov/news/phmsa-announces-new-safety-measures-protect-americanscarbon-dioxide-pipeline-failures.
274
Consent Order, Denbury Gulf Coast Pipelines, LLC, CPF No. 4-2022-017-NOPV (U.S. Dep’tof Transp. Mar. 24, 2023).
https://primis.phmsa.dot.gov/comm/reports/enforce/CaseDetail_cpf_42022017NOPV.html?noca
che=7208.
206
273

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

pipeline safety. 275 Additionally, certain states have authority delegated from the U.S. Departmentof Transportation to conduct safety inspections and enforce state and federal pipeline safety
regulations for intrastate CO2 pipelines. 276 277 These CO2 pipeline controls, in addition to the
PHMSA standards, ensure that captured CO2 will be securely conveyed to a sequestration site.
States are also directly involved in siting proposed CO2 pipeline projects. CO2 pipeline
siting authorities, landowner rights, and eminent domain laws reside with the states and varyfrom state to state. Pipeline developers may secure rights-of-way for proposed projects throughvoluntary agreements with landowners; pipeline developers may also secure rights-of-way
through eminent domain authority, which typically accompanies siting permits from state utility
regulators with jurisdiction over CO2 pipeline siting. 278
Transportation of CO2 via pipeline is the most viable and cost-effective method at thescale needed for sequestration of captured EGU CO2 emissions. However, CO2 can also be
liquified and transported via vessel (e.g., ship), highway (e.g., cargo tank, portable tank), ship, orrail (e.g., 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 ofliquified CO2 are not significantly different. 279 In fact, the food and beverage as well as specialty

275

Ibid.
New Mexico Public Regulation Commission. 2023. Transportation Pipeline Safety. New
Mexico Public Regulation Commission, Bureau of Pipeline Safety. https://www.nmprc.org/transportation/pipeline-safety.
277
Texas Railroad Commission. 2023. Oversight & Safety Division. Texas Railroad
Commission. https://www.rrc.texas.gov/about-us/organization-and-activities/rrcdivisions/oversight-safety-division.
278
Congressional Research Service. 2022. Carbon Dioxide Pipelines: Safety Issues, June 3,2022. https://crsreports.congress.gov/product/pdf/IN/IN11944.
279
Intergovernmental Panel on Climate Change. (2005). Special Report on Carbon Dioxide
Capture and Storage.
207
276This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

gas industries already have experience transporting CO2 by rail. 280 Highway road tankers and railtransportation can provide for the transport of smaller quantities of CO2 and can be used intandem with other modes of transportation to move CO2 captured from an EGU. 281(6) Geologic Sequestration of CO2(a) Security of Sequestration
Geologic sequestration (or storage), which is the long-term containment of a CO2 stream
in subsurface geologic formations, is well proven and broadly available in many locations acrossthe U.S. Independent analyses of the potential availability of geologic sequestration capacity in
the United States have been conducted by DOE, and the U.S. Geological Survey (USGS) has
also undertaken a comprehensive assessment of geologic sequestration resources in the U.S. 282
283

Geologic sequestration is based on a demonstrated understanding of the trapping processes

that retain CO2 in the subsurface; most importantly, geologic sequestration occurs securely when
the CO2 is trapped under a low permeability seal. There have been numerous efforts
demonstrating successful geologic sequestration projects 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.

280

EU CCUS Projects Network. (2019). Briefing on Carbon Dioxide Specifications forTransport. https://www.ccusnetwork.eu/sites/default/files/TG3_Briefing-CO2-Specifications-forTransport.pdf.
281
Ibid.
282
U.S. DOE NETL, Carbon Storage Atlas, Fifth Edition, September 2015.
https://www.netl.doe.gov/research/coal/carbon-storage/atlasv.
283
U.S. Geological Survey Geologic Carbon Dioxide Storage Resources Assessment Team,2013, National assessment of geologic carbon dioxide storage resources – Summary: U.S.
Geological Survey Factsheet 2013-3020. http://pubs.usgs.gov/fs/2013/3020/.
208
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

(i) Demonstration of Geologic Sequestration
Existing project and regulatory experience, along with other information, indicate thatgeologic sequestration is a viable long-term CO2 sequestration option. The effectiveness of longterm trapping of CO2 has been demonstrated by natural analogues in a range of geologic settings
where CO2 has remained trapped for millions of years. 284 For example, CO2 has been trapped formore than 65 million years in the Jackson Dome, located near Jackson, Mississippi.285 Other
examples of natural CO2 sources include the Bravo Dome and the McElmo Dome in New
Mexico and Colorado, respectively. 286 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 metrictons at Bravo Dome, and 530 million metric tons at McElmo Dome. 287 Between 2000 and 2020,
the Department of Energy-sponsored research totaling $1 billion to prove carbon storage
technologies and enable large-scale deployment. Research conducted through the Department ofEnergy’s Regional Carbon Sequestration Partnerships has demonstrated geologic sequestration
through a series of field research projects that increased in scale over time, injecting more than284

Holloway, S., et al. Natural Emissions of CO2 from the Geosphere and their Bearing on the
Geological Storage of Carbon Dioxide. 2007. Energy 32: 1194–1201.
285
Intergovernmental Panel on Climate Change. (2005). Special Report on Carbon Dioxide
Capture and Storage.
286
See K.J. Sathaye, M.A. Hesse, M. Cassidy, D.F. Stockli, “Constraints on the magnitude andrate of CO2 dissolution at Bravo Dome natural gas field.” Proceedings of the National Academyof Sciences 111, 15332–15337. 2014. and Kinder Morgan. “Carbon Dioxide (CO2) Operations;
CO2 Supply.” https://www.kindermorgan.com/Operations/CO2/Index.
287
DiPietro, P., et al. 2012. “A Note on Sources of CO2 Supply for Enhanced-Oil Recovery
Operations.” SPE Economics & Management.
209
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

11 million tons of CO2 with no indications of negative impacts to either human health or theenvironment. 288 Building on this experience, the Department of Energy launched the Carbon
Storage Assurance Facility Enterprise (CarbonSAFE) Initiative in 2016 to demonstrate howknowledge from the Regional Carbon Sequestration Partnerships can be applied to commercialscale safe storage. This initiative is furthering the development and refinement of technologies
and techniques critical to the characterization of potential sequestration sites greater than 50
million tons. 289
Numerous additional saline facilities are under development across the United States. The
Great Plains Synfuel Plant currently captures 2 million metric tons of CO2 per year, which isused 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 sequestrationand EOR) to 3.5 million metric tons of CO2 per year. 290 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. 291 292

288

Safe Geologic Storage of Captured Carbon Dioxide – DOE’s Carbon Storage R&D Program:
Two Decades in Review," National Energy Technology Laboratory, Pittsburgh, April 13, 2020.
https://www.netl.doe.gov/sites/default/files/Safe%20Geologic%20Storage%20of%20Captured%
20Carbon%20Dioxide_April%2015%202020_FINAL.pdf
289
https://netl.doe.gov/carbon-management/carbon-storage/carbonsafe.
290
Basin Electric Power Cooperative. “Great Plains Synfuels Plant Potential to Be Largest CoalBased Carbon Capture and Storage Project to Use Geologic Storage,” September 9, 2021.
https://www.basinelectric.com/News-Center/news-releases/Great-Plains-Synfuels-Plantpotential-to-be-largest-coal-based-carbon-capture-and-storage-project-to-use-geologic-storage.
291
UIC regulations for Class VI wells facilitate the injection of CO2 for geologic sequestration
while protecting human health and the environment by ensuring the protection of undergroundsources of drinking water. The major components to be included in UIC Class VI permits aredetailed further in section VII.F.3.b.iii.
292
U.S. EPA Class VI Underground Injection Control (UIC) Class VI Wells Permitted by EPA
as of January 12, 2023. https://www.epa.gov/uic/class-vi-wells-permitted-epa.
210This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Geologic sequestration has been proven to be successful and safe in projects
internationally. The oldest international facility has geologically sequestered CO2 for over twenty
years. In Norway, facilities conduct offshore sequestration under the Norwegian continental
shelf. 293 In addition, the Sleipner CO2 Storage facility in the North Sea, which began operationsin 1996, injects around 1 million metric tons of CO2 per year from natural gas processing. 294 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. 295 Other
international sequestration facilities in operation include Glacier Gas Plant MCCS (Canada), 296
Quest (Canada), and Qatar LNG CCS (Qatar).
(ii) 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 inthis preamble, adequate demonstration of geologic sequestration is further corroborated bygeologic sequestration currently operational and planned projects assisted by grants, loan

293

Intergovernmental Panel on Climate Change. (2005). Special Report on Carbon Dioxide
Capture and Storage.
294
Zapantis, Alex, Noora Al Amer, Ian Havercroft, Ruth Ivory-Moore, Matt Steyn, Xiaoliang
Yang, Ruth Gebremedhin, et al. “Global Status of CCS 2022.” Global CCS Institute, 2022.
https://status22.globalccsinstitute.com/2022-status-report/introduction/.
295
Boundary Dam Carbon Capture Project. https://www.saskpower.com/Our-PowerFuture/Infrastructure-Projects/Carbon-Capture-and-Storage/Boundary-Dam-Carbon-CaptureProject.
296
Zapantis, Alex, Noora Al Amer, Ian Havercroft, Ruth Ivory-Moore, Matt Steyn, Xiaoliang
Yang, Ruth Gebremedhin, et al. “Global Status of CCS 2022.” Global CCS Institute, 2022.
https://status22.globalccsinstitute.com.
211
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 areunder development. 297 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, 298 and, according to thefacility’s report to the EPA’s GHGRP, as of 2021, 2.5 million metric tons of CO2 had been
injected into the saline reservoir. 299 The Red Trail Energy CCS facility in North Dakota, which isthe 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. 300 This project is
expected to inject a total of 3.7 million tons of CO2 over its lifetime. 301
There are additional planned geologic sequestration facilities across the United States. 302
Project Tundra, a saline sequestration project planned at the lignite-fired Milton R. Young

297

Zapantis, Alex, Noora Al Amer, Ian Havercroft, Ruth Ivory-Moore, Matt Steyn, Xiaoliang
Yang, Ruth Gebremedhin, et al. “Global Status of CCS 2022.” Global CCS Institute, 2022.
https://status22.globalccsinstitute.com/.
298
Archer Daniels Midland, Monitoring, Reporting, and Verification Plan CCS#2, 2017.
https://www.epa.gov/sites/default/files/2017-01/documents/adm_mrv_plan.pdf.
299
EPA Greenhouse Gas Reporting Program. Data reported as of August 12, 2022.
300
Zapantis, Alex, Noora Al Amer, Ian Havercroft, Ruth Ivory-Moore, Matt Steyn, Xiaoliang
Yang, Ruth Gebremedhin, et al. “Global Status of CCS 2022.” Global CCS Institute, 2022.
https://status22.globalccsinstitute.com.
301
North Dakota Industrial Commission, NDIC Case No. 28848—Draft Permit Fact Sheet andStorage Facility Permit Application.” https://www.dmr.nd.gov/oilgas/GeoStorageofCO2.asp.
This injection well is permitted by North Dakota.
302
In addition, Denbury Resources injected CO2 into a depleted oil and gas reservoir at a rate
greater than 1.2 million tons/year as part of a DOE Southeast Regional Carbon Sequestration
Partnership study. The Texas Bureau of Economic Geology tested a wide range of surface andsubsurface monitoring tools and approaches to document sequestration efficiency andsequestration permanence at the Cranfield oilfield in Mississippi. Texas Bureau of Economic
Geology, “Cranfield Log.” https://www.beg.utexas.edu/gccc/research/cranfield.
212
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Station in North Dakota is projected to capture 4 million metric tons of CO2 annually. 303 Finally,
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. 304(iii) Security of Geologic Sequestration
Regulatory oversight of geologic sequestration is built upon an understanding of theproven 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 toproduce 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, thesecurity of sequestered CO2 is expected to increase over time after injection ceases. 305 This isdue to trapping mechanisms that reduce CO2 mobility over time, e.g., physical CO2 trapping by alow-permeability geologic seal or chemical trapping by conversion or adsorption. 306 In addition,

303

Project Tundra. “Project Tundra.” https://www.projecttundrand.com/.
Wyoming DEQ Class VI Permit Applications. https://deq.wyoming.gov/waterquality/groundwater/uic/class-vi/.
305“Report of the Interagency Task Force on Carbon Capture and Storage.” 2010.
https://www.osti.gov/servlets/purl/985209.
306
See, e.g., Intergovernmental Panel on Climate Change. (2005). Special Report on Carbon
Dioxide Capture and Storage.
213
304

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

site characterization, site operations, and monitoring strategies as required through theUnderground 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 placeand capable of reviewing and permitting CCS activities. 307
This regulatory framework includes the UIC Class VI well regulations, promulgatedunder the authority of the Safe Drinking Water Act (SDWA); and the GHGRP, promulgatedunder 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 humanhealth and the environment by ensuring the protection of underground sources of drinking water(USDW). These regulations are built upon nearly a half-century of Federal experience regulating
underground injection wells, and many additional years of state UIC program expertise. The IIJA
established a program to assist states and Tribal regulatory authorities interested in Class VI
primacy. 308 As the EPA considers Class VI primacy applications, it has indicated that it will
require approaches that balance the use of geologic sequestration with mitigation of impacts on

307

CEQ. “Council on Environmental Quality Report to Congress on Carbon Capture,
Utilization, and Sequestration.” 2021. https://www.whitehouse.gov/wpcontent/uploads/2021/06/CEQ-CCUS-Permitting-Report.pdf.
308
On April 27, 2023, the EPA Administrator signed a proposed rule to approve the State ofLouisiana’s request to have primacy for UIC Class VI wells within the state. Louisiana is thethird state to request primacy for UIC Class VI wells. https://www.epa.gov/uic/primaryenforcement-authority-underground-injection-control-program-0.
214This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

vulnerable communities. States and Tribes applying for Class VI primacy are asked to support
communities by implementing an inclusive public participation process, considering
environmental justice impacts on communities, enforcing Class VI regulatory protections andincorporating other mitigation measures. 309
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 aredesigned 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. 310
Major components to be included in UIC Class VI permits are site characterization, areaof review, 311 corrective action, 312 well construction and operation, testing and monitoring,

309

EPA. Letter from the EPA Administrator Michael S. Regan to U.S. State Governors.
December 9, 2022. https://www.epa.gov/system/files/documents/202212/AD.Regan_.GOVS_.Sig_.Class%20VI.12-9-22.pdf.
310
In 2022, EPA proposed a new GHGRP subpart, “Geologic Sequestration of Carbon Dioxidewith Enhanced Oil Recovery (EOR) Using ISO 27916” (or GHGRP subpart VV). For more
information on proposed GHGRP subpart VV, see section VII.K.2 of this preamble.
311
Per 40 CFR 146.84(a), the area of review is the region surrounding the geologic sequestration
project where USDWs may be endangered by the injection activity. The area of review isdelineated using computational modeling that accounts for the physical and chemical propertiesof all phases of the injected carbon dioxide stream and is based on available site characterization,
monitoring, and operational data.
312
UIC permitting authorities may require corrective action for existing wells within the area ofreview to ensure protection of underground sources of drinking water.
215
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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. 313 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. 314 315 316 317 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 isgenerally 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), tofurther ensure protection of USDWs. 318 The MRV plan includes five major components: adelineation of monitoring areas based on the CO2 plume location; an identification andevaluation 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

313

40 CFR 98.440.
40 CFR 98.446.
315
40 CFR 98.448.
316
40 CFR 98.446(f)(9) and (10).
317
40 CFR 98.446(f)(12).
318
See 75 FR 77263 (December 10, 2010).
314

216

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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. 319
Geologic sequestration efforts on Federal lands as well as those efforts that are directly
supported with Federal funds may need to comply with other regulations, depending on thenature of the project. 320(b) 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 canreadily 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 resources in
the U.S. The DOE estimates are compiled in the DOE’s National Carbon Sequestration Databaseand Geographic Information System (NATCARB) using volumetric models and are published in
its Carbon Utilization and Sequestration Atlas (NETL Atlas). 321 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

319

40 CFR 98.448(a).
CEQ. “Council on Environmental Quality Report to Congress on Carbon Capture,
Utilization, and Sequestration.” 2021. https://www.whitehouse.gov/wpcontent/uploads/2021/06/CEQ-CCUS-Permitting-Report.pdf.
321
U.S. DOE NETL, Carbon Storage Atlas, Fifth Edition, September 2015.
https://www.netl.doe.gov/research/coal/carbon-storage/atlasv.
217
320This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

gas reservoirs. 322 The USGS assessment estimates a mean of 3,000 billion metric tons ofsubsurface CO2 sequestration potential across the U.S. 323
With respect to deep saline formations, the DOE estimates a sequestration potential of atleast 2,200 billion metric tons of CO2 in these formations in the U.S. At least 37 states havegeologic 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. 324 325
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 unmineablecoal 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 ofcoal. When CO2 is injected, it is adsorbed to the coal surface and releases methane that can thenbe 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 andMissouri, which have little to no saline sequestration potential and have existing coal-fired

322

Ibid.
U.S. Geological Survey Geologic Carbon Dioxide Storage Resources Assessment Team,National assessment of geologic carbon dioxide storage resources–Summary: U.S. Geological
Survey Factsheet 2013-3020. 2013. https://pubs.usgs.gov/fs/2013/3020/.
324
Alaska has deep saline formation storage capacity, geology amenable to EOR operations, andpotential geologic sequestration capacity in unmineable coal seams.
325
The U.S. DOE NETL Carbon Storage Atlas, Fifth Edition did not assess deep saline
formation potential for Alaska, Connecticut, Hawaii, Maine, Massachusetts, Nevada, New
Hampshire, Rhode Island, and Vermont. We are assuming for purposes of our analysis here thatthey do not have storage potential in this type of formation.
218
323This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

EGUs. Unmineable coal seams have a sequestration potential of at least 54 billion metric tons ofCO2, or 2 percent of total potential in the U.S., and are located in 22 states. 326
The potential for CO2 sequestration in unmineable coal seams has been demonstrated insmall-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 unmineablecoal seams ranging from 90 tons to 16,700 tons, and completed site characterization, injection,and post-injection monitoring for sites. 327 328 DOE has judged unmineable coal seams worthy ofinclusion in the NETL Atlas. 329
Although the large-scale injection of CO2 in coal seams can lead to swelling of coal, theliterature also suggests that there are available technologies and techniques to compensate for the
resulting reduction in injectivity. 330 Further, the reduced injectivity can be anticipated andaccommodated in sizing and characterizing prospective sequestration sites.

326

U.S. DOE NETL, Carbon Storage Atlas, Fifth Edition, September 2015.
https://www.netl.doe.gov/research/coal/carbon-storage/atlasv.
327
M. Godec et al., “CO2-ECBM: A Review of its Status and Global Potential,” Energy Procedia
63: 5858–5869 (2014). https://doi.org/10.1016/j.egypro.2014.11.619.
328
N. Ripepi et al., “Central Appalachian Basin Unconventional (Coal/Organic Shale) Reservoir
Small Scale CO2 Injection,” US DOE/NETL Annual Carbon Storage and Oil and Natural Gas
Technologies Review Meeting (2017). https://www.netl.doe.gov/sites/default/files/eventproceedings/2017/carbon-storage-oil-and-natural-gas/thur/Nino-RipepiVirginiaTech.DOEMeeting.CoalShaleUpdate.8.3.2017.pdf.
329
U.S. DOE NETL, Carbon Storage Atlas, Fifth Edition, September 2015.
https://www.netl.doe.gov/research/coal/carbon-storage/atlasv.
330
Xiachun Li & Zhi-Ming Fang, “Current Status and Technical Challenges of CO2 Storage in
Coal Seams and Enhanced Coalbed Methane Recovery: An Overview,” International Journal of
Coal Science & Technology, 93, 99 (2014) (suggesting existing technologies that can be used toaddress injectivity reduction in unmineable coal seams).
219
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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. 331 Other types ofgeologic 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. 332
The EPA performed a geographic availability analysis in which the Agency examinedareas of the country with sequestration potential in deep saline formations, unmineable coalseams, 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 withsequestration potential. The distance of 100 km is consistent with the assumptions underlying the
NETL cost estimates for transporting CO2 by pipeline. 333 Overall, the EPA found that there are
43 states containing areas within 100 km from currently assessed onshore or offshore storage
resources in deep saline formations, unmineable coal seams, and depleted oil and gas reservoirs.

331Intergovernmental Panel on Climate Change. (2005). Special Report on Carbon Dioxide
Capture and Storage.
332
Goodman, A., et al. “Methodology for Assessing CO2 Storage Potential of Organic-Rich
Shale Formations.” Energy Procedia, 12th International Conference on Greenhouse Gas Control
Technologies, GHGT-12, 63 (2014): 5178–84. https://doi.org/10.1016/j.egypro.2014.11.548.
NETL DOE. “Big Sky Carbon Sequestration Partnership.” https://netl.doe.gov/coal/carbonstorage/atlas/bscsp. Schaef, T., and McGrail, P. “Sequestration of CO2 in Basalt Formations.”
Pacific Northwest National Laboratory, NETL, DOE, 2013.
https://www.netl.doe.gov/sites/default/files/event-proceedings/2013/carbon%20storage/8-00Schaef-58159-Task-1-082213.pdf.
333
Although a 100 km pipeline is used in this analysis, this does not represent a technicallimitation, but rather a standardization used for NETL cost estimates. As noted in the GHG
Mitigation Measures for Steam Generating Units TSD, large pipelines connect CO2 sources insouth central Colorado, northeast New Mexico, and Mississippi to Texas, Oklahoma, New
Mexico, Utah, and Louisiana. Additionally, as noted in section VII.F.3.b.iii.(5) of this preamble,
CO2 can by transported via other modes such as ship, road tanker, or rail tank cars.
220
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

There are additional areas that have not yet been assessed and may provide additional
infrastructure capability. 334
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. 335 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 reasonable access to geologic sequestration, utilities, electriccooperatives, and municipalities have a history of joint ownership of electricity generation
outside the region or contracting with electricity generation in outside areas to meet demand.
Some of the areas are in Regional Transmission Organizations (RTOs), 336 which engage inplanning 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, servesload in eight different states from the Midwest to the mid-Atlantic. 337 The Intermountain Power

334

GHG Mitigation Measures for Steam Generating Units TSD, chapter 4.6.2. As discussed in
the TSD, geologic sequestration potential has not yet been assessed for Connecticut, Hawaii,
Nevada, New Hampshire, Rhode Island, and Vermont, and may provide additional infrastructure
capability.
335
This was described as “coal-by-wire” in the 2015 NSPS.
336
In this discussion, the term RTO indicates both ISOs and RTOs.
337
https://prairiestateenergycampus.com/about/ownership/.
221
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Project, a coal-fired plant located in Delta, Utah, that is converting to burn hydrogen and naturalgas, serves customers in both Utah and California. 338(B) Costs
The EPA has evaluated the costs of CCS for new combined cycle units, including the costof installing and operating CO2 capture equipment as well as the costs of transport and storage.
The EPA has also compared the costs of CCS for new combined cycle units to other control
costs, in part derived from other rulemakings that the EPA has determined to be cost reasonable,
and the costs are comparable. Based on these analyses, the EPA is proposing that the costs of
CCS for new combined cycle units are reasonable. Certain elements of the transport and storage
costs are similar for new combustion turbines and existing steam generating units. In this section,
the EPA outlines these costs and identifies the considerations specific to new combustion
turbines. These costs are significantly reduced by the IRC section 45Q tax credit. For additional
details on the EPA’s CCS costing analysis see the GHG Mitigation Measures for SteamGenerating Units TSD, which is available in the rulemaking docket.
(1) Capture costs
According to the NETL Fossil Energy Baseline Report (October 2022 revision), before
accounting for the IRC section 45Q tax credit for sequestered 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 capacity338

https://www.ipautah.com/participants-services-area/.
222

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

available to generate useful output) by 11 percent. 339 For a base load combustion turbine, carbon
capture increases the LCOE by 61 percent (an increase of 27 $/MWh) and has an estimated costof $81/ton ($89/metric ton) of onsite CO2 reduction. 340 The NETL costs are based on the use of asecond 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 waysthat 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 isapproximately 3 times that of a coal-fired EGU. The higher amount of excess oxygen has thepotential 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 thecapture process and that the larger volumetric flow rates require a larger CO2 absorber, which
increases the capital cost of the capture process. Exhaust gas recirculation (EGR), also referred toas flue gas recirculation (FGR), is a process that addresses all of these issues. EGR diverts someof 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

339

CCS reduced the net output of the NETL F class combined cycle EGU from 726 MW to 645
MW.
340
These calculations use a service life of 30 years, an interest rate of 7.0 percent, a natural gas
price of $3.69/MMBtu, and a capacity factor of 65 percent. These costs do not include CO2transport, storage, or monitoring costs.
223
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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. 341
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 costsof CO2 capture, the DOE is funding multiple projects to advance CCS technology. 342 It should be
noted that these projects are EPAct05-assisted. The EPA proposes that the rest of the information
it has is sufficient to support a determination that the costs of capture systems are reasonable, andthat CCS is adequately demonstrated. These EPAct05-assisted projects provide additional
confirmation for this proposal because they will contribute to improvements in the costs of CCS.
These include projects falling under carbon capture research and development, engineering-scaletesting of carbon capture technologies, and engineering design studies for carbon capturesystems. 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 or greater capture of CO2, to lower the costs of the technologies, and to prove feasible
scalability at the industrial scale for these new technologies. Some projects are designed solely todevelop new carbon capture technologies, while others are designed to apply existing
technologies at the industrial scale. For a list of notable projects, see section
VII.F.3.b.iii(A)(4)(b) of this preamble.

341

Energy Procedia. (2014). Impact of exhaust gas recirculation on combustion turbines. Energy
and economic analysis of the CO2 capture from flue gas of combined cycle power plants.
https://www.sciencedirect.com/science/article/pii/S1876610214001234.
342
The DOE has also previously funded FEED studies for NGCC facilities. These include FEED
studies at existing NGCC facilities at Panda Energy Fund in Texas, Elk Hills Power Plant in
Kern County, California, Deer Park Energy Center in Texas, Delta Energy Center in Pittsburg,
California, and utilization of a Piperazine Advanced Stripper (PZAS) process for CO2 capture
conducted by The University of Texas at Austin.
224
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Although current post-combustion CO2 capture projects have primarily been based onamine capture systems, there are multiple alternate capture technologies in development—manyof 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 343 systems. It is expected that as CCS infrastructure increases, technologies from eachof these categories will become more economically competitive. For example, advancements insolvents, 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. 344 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. 345
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 thecosts of near-future CCS technologies. The Global CCS Institute has tracked publicly available

343

Molten carbonate fuel cells are configured for emissions capture through a process where theflue gas from an EGU is routed through the molten carbonate fuel cell that concentrates the CO2
as a side reaction during the electric generation process in the fuel cell. FuelCell Energy, Inc.
(2018). SureSource Capture. https://www.fuelcellenergy.com/recovery-2/suresource-capture/.
344
DOE. Carbon Capture, Transport, & Storage. Supply Chain Deep Dive Assessment. February
24, 2022. https://www.energy.gov/sites/default/files/202202/Carbon%20Capture%20Supply%20Chain%20Report%20-%20Final.pdf.
345International Energy Agency (IEA) (2020). CCUS in Clean Energy Transitions–A new era for
CCUS. https://www.iea.org/reports/ccus-in-clean-energy-transitions/a-new-era-for-ccus.
225
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

information on previously studied, executed, and proposed CO2 capture projects. 346 The cost of
CO2 capture from low-to-medium partial pressure sources such as coal-fired power generation
has been trending downward over the past decade, and is projected to fall by 50 percent by 2025
compared to 2010. This is driven by the familiar learning-processes that accompany the
deployment of any industrial technology. Studies of the cost of capture and compression of CO2
from power stations completed ten years ago averaged around $95/metric ton ($2020).
Comparable studies completed in 2018/2019 estimated capture and compression costs could fall
to approximately $50/metric ton CO2 by 2025. Current target pricing for announced projects at
coal-fired steam generating units is approximately $40/metric ton on average, compared to
Boundary Dam whose actual costs were reported to be $105/metric ton, noting that theseestimates do not include the impact of the 45Q tax credit as enhanced by the IRA. Additionally,
IEA suggests this trend will continue in the future as technology advancements “spill over” into
other projects to reduce costs. 347 Policies in the IIJA and IRA are further increasing investment
in CCS technology that can accelerate the pace of innovation and deployment.
(2) CO2 Transport and Sequestration Costs
NETL’s “Quality Guidelines for Energy System Studies; Carbon Dioxide Transport andSequestration Costs in NETL Studies” provides an estimation of transport costs based on the346Technology Readiness and Costs of CCS (2021). Global CCS Institute.
https://www.globalccsinstitute.com/wp-content/uploads/2021/03/Technology-Readiness-andCosts-for-CCS-2021-1.pdf.
347
International Energy Agency (IEA) (2020). CCUS in Clean Energy Transitions–CCUS
technology innovation. https://www.iea.org/reports/ccus-in-clean-energy-transitions/a-new-erafor-ccus.
226
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

CO2 Transport Cost Model. 348 The CO2 Transport Cost Model estimates costs for a single pointto-point pipeline. Estimated costs reflect pipeline capital costs, related capital expenditures, andoperations 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. 349
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

348

Grant, T., et al. “Quality Guidelines for Energy System Studies; Carbon Dioxide Transportand Storage Costs in NETL Studies.” National Energy Technology Laboratory. 2019.
https://www.netl.doe.gov/energy-analysis/details?id=3743.
349
National Energy Technology Laboratory (NETL), “FE/NETL CO2 Saline Storage Cost
Model (2017),” U.S. Department of Energy, DOE/NETL-2018-1871, 30 September 2017.
https://netl.doe.gov/energy-analysis/details?id=2403.
227
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

have lower testing and monitoring costs. NETL’s Quality Guidelines model costs for a given
cumulative storage potential. 350
In addition, provisions in the IIJA and IRA are expected to significantly increase the CO2
pipeline infrastructure and development of sequestration sites, which, in turn, are expected toresult in further cost reductions for the application of CCS at a new combined cycle EGUs. The
IIJA establishes a new Carbon Dioxide Transportation Infrastructure Finance and Innovation
program to provide direct loans, loan guarantees, and grants to CO2 infrastructure projects, suchas pipelines, rail transport, ships and barges. 351 The IIJA also establishes a new Regional Direct
Air Capture Hubs program which includes funds to support four large-scale, regional direct air
capture hubs and more broadly support projects that could be developed into a regional or interregional network to facilitate sequestration or utilization. 352 DOE is additionally implementing
IIJA section 40305 (Carbon Storage Validation and Testing) through its CarbonSAFE initiative,
which aims to further development of geographically widespread, commercial-scale, safe
storage. 353 The IRA increases and extends the IRC section 45Q tax credit, discussed next.
(3) IRC Section 45Q Tax Credit
In determining the cost of CCS, the EPA is taking into account the tax credit provided
under IRC section 45Q, as revised by the IRA. The tax credit is available at $85/metric ton

350

Details on CO2 transportation and sequestration costs can be found in the GHG Mitigation
Measures for Steam Generating Units TSD.
351
Department of Energy. “Biden-Harris Administration Announces $2 Billion from Bipartisan
Infrastructure Law to Finance Carbon Dioxide Transportation Infrastructure.” (2022).
https://www.energy.gov/articles/biden-harris-administration-announces-2-billion-bipartisaninfrastructure-law-finance.
352
Department of Energy. “Regional Direct Air Capture Hubs.” (2022).
https://www.energy.gov/oced/regional-direct-air-capture-hubs.
353
For more information, see the NETL announcement. https://www.netl.doe.gov/node/12405.
228
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

($77/ton) and offsets a significant portion of the capture, transport, and sequestration costs noted
above.
It is reasonable to take the tax credit into account because it reduces the cost of thecontrols 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 wellaware that the EPA may promulgate rulemaking under CAA section 111 based on CCS andexplicitly 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 astatement in the Congressional Record when the House adopted the IRA in which he explained:“The tax credit[] for CCUS … included in this Act may also figure into CAA Section 111 GHG
regulations for new and existing industrial sources[.] ... Congress anticipates that EPA may
consider CCUS … as [a] candidate[] for BSER for electric generating plants …. Further,
Congress anticipates that EPA may consider the impact of the CCUS … tax credit[] in lowering
the costs of [that] measure[].” 168 Cong. Rec. E879 (August 26, 2022) (statement of Rep. Frank
Pallone).
In the 2015 NSPS, in which the EPA determined partial CCS to be the BSER for GHGs
from new coal-fired steam generating EGUs, the EPA recognized that the IRC section 45Q tax
credit or other tax incentives could factor into the cost of the controls to the sources. Specifically,
the EPA calculated the cost of partial CCS on the basis of cost calculations from NETL, which
included “a range of assumptions including the projected capital costs, the cost of financing the
project, the fixed and variable O&M costs, the projected fuel costs, and incorporation of any

229This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

incentives such as tax credits or favorable financing that may be available to the project
developer.” 80 FR 64570 (October 23, 2015). 354
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 notaccount for potential EOR revenues for purposes of determining the BSER. Id. at 64563–64. Inother rules, the EPA has considered revenues from sale of the by-products of emission controls
to affect the costs of the emission controls. For example, in the 2016 Oil and Gas Methane Rule,the EPA determined that certain control requirements would reduce natural gas leaks andtherefore result in the collection of recovered natural gas that could be sold; and the EPA further
determined that revenues from the sale of the recovered natural gas reduces the cost of controls.
See 81 FR 35824 (June 3, 2016). 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). In the 2016 emission guidelines for landfill
gas from municipal solid waste landfills, the EPA reduced the costs of controls by accounting forrevenue from the sale of electricity produced from the landfill gas collected through the controls.
81 FR 59276, 19679 (August 29, 2016).
The amount of the IRC section 45Q tax credit that the EPA is taking into account is$85/metric ton for CO2 that is captured and geologically stored. This amount is available to the354

In fact, because of limits on the availability of the IRC section 45Q tax credit at the time of
the 2015 NSPS, the EPA did not factor it into the cost calculation for partial CCS. 80 FR 6455864 (October 23, 2015).
230

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 meetthose prevailing wage and apprenticeship requirements. 168 Cong. Rec. E879 (August 26, 2022)(statement of Rep. Frank Pallone). If prevailing wage and apprenticeship requirements are notmet, the value of the IRC section 45Q tax credit falls to $17/metric ton. The substantially higher
credit available provides a considerable incentive to meeting the prevailing wage andapprenticeship requirements. Therefore, the EPA assumes that investors maximize the value ofthe IRC section 45Q tax credit at $85/metric ton by meeting those requirements.
(4) Total Costs of CCS
In a typical NSPS analysis, the EPA amortizes costs over the expected life of the affectedfacility and assumes constant revenue and expenses over that period of time. This analysis isdifferent because the IRC section 45Q tax credits for the sequestration of CO2 are only available
for combustion turbines that commence construction by the end of 2032 and are available for 12
years. The construction timeframe is within the NSPS review cycle, and the EPA has determinedthat it is appropriate to include the credits as part of the CCS costing analysis. Since the durationof 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
231
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

operating life, the current overall CO2 abatement costs of CCS of a 90 percent capture aminebased post combustion capture system, accounting for the tax credit, are $44/ton ($49/metric ton)and the increase in the LCOE is $15/MWh. 355 These costs assume a stable 30-year operating life,transport, storage, and monitoring costs of $10/metric ton, and do not include any revenues fromsale 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 andwould 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 12year CO2 abatement costs are $19/ton ($21/metric ton) 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. 356 These costs could be higher for small units and lower forlarger units. For additional details on the CCS costing analysis see the GHG Mitigation
Measures – Carbon Capture and Storage for Combustion Turbines TSD, which is available in
the rulemaking docket. The EPA is soliciting comment on whether the CCS transport, storage,
and monitoring costs are appropriate for determining the BSER costs for combustion turbines.
(5) Comparison to Other Costs of Controls
In assessing cost reasonableness for the BSER determination for this rule, the EPA
compares the costs of GHG control measures to control costs that the EPA has previously

355

The EPA used 3.76 percent discount factor to levelized the 45Q tax credits to an annual valueof $45.4/metric ton. These calculations use a service life of 30 years, an interest rate of 7.0
percent, a natural gas price of $3.69/MMBtu, a capacity factor of 65 percent, and a transport,
storage, and monitoring cost of $10/metric ton.
356
The output of the model combined cycle EGU without CCS is 726 MW. The auxiliary load of
CCS reduces the net out to 645 MW.
232
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

determined to be reasonable. This includes comparison to the costs of controls at EGUs for otherair pollutants, such as SO2 and NOX, and costs of controls for GHGs in other industries. The
costs presented in this section of the preamble are in 2019 dollars. 357
At different times, many coal-fired steam generating units have been required to installand operate flue gas desulfurization (FGD) equipment—that is, wet or dry scrubbers—to reduce
their SO2 emissions or SCR to reduce their NOX emissions. The EPA compares these control
costs across technologies—steam generating units and combustion turbines—because these costs
are indicative of what is reasonable for the power sector in general. The fact that EPA required
these controls in prior rules, and that many EGUs subsequently installed and operated thesecontrols, provide evidence that these costs are reasonable, and as a result, the cost of thesecontrols provides a benchmark to assess the reasonableness of the costs of the controls in thispreamble. 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 existing coalfired steam generating units. Using those same cost equations and assumptions (i.e., a 63 percent
annual capacity factor – the average value in 2011) for retrofitting wet FGD on a representative
700 to 300 MW coal-fired steam generating unit results in annualized costs of $14.80 to$18.50/MWh of generation, respectively. 358 In the March 15, 2023 Good Neighbor Plan for the2015 Ozone NAAQs (2023 GNP), the EPA estimated the annualized costs to install and operate
SCR retrofits on existing coal-fired steam generating units. Using those same cost equations and357

The EPA used the NETL Baseline Report costs directly for the combustion turbine model
plant BSER analysis. Even though these costs are in 2018 dollars, the adjustment to 2019 dollars(1.018 using the U.S. GDP Implicit Price Deflator) is well within the uncertainty range of thereport and the minor adjustment would not impact the EPA’s BSER determination.
358
For additional details, see https://www.epa.gov/power-sector-modeling/documentationintegrated-planning-model-ipm-base-case-v410.
233
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

assumptions (including a 56 percent annual capacity factor – a representative value in thatrulemaking) to retrofit SCR on a representative 700 to 300 MW coal-fired steam generating unit
results in annualized costs of $10.60 to $11.80/MWh of generation, respectively. 359 Finally,using current cost equations and assumptions (including a 50 percent annual capacity factor, andotherwise consistent with the 2023 GNP) for retrofitting wet FGD on a representative 700 to 300
MW coal-fired steam generating unit results in annualized costs of $23.20 to $29.00/MWh ofgeneration, respectively. 360
Finally, the EPA compares costs to the costs for GHG controls in rulemakings for otherindustries. In the 2016 NSPS regulating GHGs for the Crude Oil and Natural Gas source
category, the EPA found the costs of reducing methane emissions of $2,447/ton to be reasonable(80 FR 56627; September 18, 2015). 361 Converted to a ton of CO2e reduced basis, those costs are
expressed as $98/ton of CO2e reduced. 362
The costs for CCS applied to a representative new base load stationary combustion
turbine EGU are generally lower than the above-described costs, which supports the EPA’s viewthat the CCS costs are reasonable. The CCS costs range from $6 to $15/MWh of generation or$19 to $44/ton of CO2 reduced (depending on the amortization period).

359

For additional details, see https://www.epa.gov/system/files/documents/202301/Updated%20Summer%202021%20Reference%20Case%20Incremental%20Documentation%
20for%20the%202015%20Ozone%20NAAQS%20Actions_0.pdf.
360
Ibid.
361
The EPA finalized the 2016 NSPS GHGs for the Crude Oil and Natural Gas source category
at 81 FR 35824 (June 3, 2016). The EPA included cost information in the proposed rulemaking,at 80 FR 56627 (September 18, 2015).
362
Based on the 100-year global warming potential for methane of 25 used in the GHGRP (40CFR 98 Subpart A, Table A-1).
234
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

(C) Non-air Quality Health and Environmental Impact and Energy Requirements
In this section of the preamble, the EPA explains that it does not expect the use of CCS
for new combined cycle combustion turbines to have unreasonable adverse consequences related
to non-air quality health and environmental impact and energy requirements to combined cycle
combustion turbines. The EPA first discusses energy requirements, and then considers non-GHG
emissions impacts and water use impacts, resulting from the capture, transport, and sequestrationof CO2.
With respect to energy requirements, including a 90 percent or greater carbon capturesystem in the design of a new NGCC will increase the parasitic/auxiliary energy demand andreduce its net power output. A utility that wants to construct an NGCC unit to provide 500 MWenet of power could build a 500 MWe-net plant knowing that it will be de-rated by 11 percent (toa 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 thegrid. Although the use of CCS imposes additional energy demands on the affected units, thoseunits are able to accommodate those demands by scaling larger, as needed.
Regardless of whether a unit is scaled larger, the installation and operation of CCS itself
does not impact the unit’s potential-to-emit any 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

235
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

criteria or hazardous air pollutants as a direct result of installing and using 90 percent or greater
CO2 capture CCS to meet the second phase standard of performance. 363
Scaling a unit larger to provide heat and power to the CO2 capture equipment would havethe potential to increase non-GHG air emissions. However, most of them would be mitigated oradequately controlled by equipment needed to meet other CAA requirements. In general, theemission rates and flue gas concentrations of most non-GHG pollutants from the combustion ofnatural gas in stationary combustion turbines are relatively low compared to the combustion of
oil or coal in boilers. As such, it is not necessary to use an FGD to pretreat the flue gas prior to
CO2 removal in the CO2 scrubber column. The sulfur content of natural gas is low relative to oilor coal and resulting SO2 emissions are therefore also relatively low. Similarly, PM emissions
from combustion of natural gas in a combustion turbine are relatively low. Furthermore, the highcombustion efficiency of combustion turbines results in relatively low organic-HAP emissions,and there are likely few, if any, metallic-HAP emissions from combustion of natural gas.
Additionally, combustion turbines at major sources of HAP are subject to the stationary
combustion turbine NESHAP, which includes limits for formaldehyde emissions for new sourcesthat may require installation of an oxidation catalyst (87 FR 13183; March 9, 2022). Regarding
NOX emissions, in most cases, the combustion turbines in new combined cycle units will beequipped with low-NOX burners to control flame temperature and reduce NOX formation.
Additionally, new combined cycle units may be subject to major NSR requirements for NOX
emissions, which may necessitate the installation of SCR to comply with a control technology
determination by the permitting authority. See section XIII.A of this preamble for additional

363

While the absolute onsite mass emissions would not increase from the second component of
the BSER, the emissions rate on a lb/MWh-net basis would increase by 13 percent.
236This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

details regarding implications for the NSR program. Although NOX concentrations may becontrolled by SCR, for some amine solvents NOX in the post-combustion flue gas can react in
the CO2 scrubber to form nitrosamines. A conventional multistage water wash or acid wash and a
mist eliminator at the exit of the CO2 scrubber is effective at removal of gaseous amine andamine degradation products (e.g., nitrosamine) emissions. 364 365
Stakeholders have shared with the EPA concerns about the safety of CCS projects andthat historically disadvantaged and overburdened communities may bear a disproportionate
environmental burden associated with CCS projects. 366 For the reasons noted above, the EPA
does not expect CCS projects to result in uncontrolled or substantial increases in emissions of
non-GHG air pollutants from new combustion turbines. The EPA is committed to working with
its fellow agencies to foster meaningful engagement with communities and protect communities
from pollution. This can be facilitated through the existing detailed regulatory framework for
CCS projects and further supported through robust and meaningful public engagement early inthe technological deployment process. Furthermore, the EPA is soliciting comment on additional
ways that may be identified to responsibly advance the deployment of CCS and ensure
meaningful engagement with local communities.

364

Sharma, S., Azzi, M., “A critical review of existing strategies for emission control in themonoethanolamine-based carbon capture process and some recommendations for improved
strategies,” Fuel, 121, 178 (2014).
365
Mertens, J., et al., “Understanding ethanolamine (MEA) and ammonia emissions from aminebased post combustion carbon capture: Lessons learned from field tests,” Int’l J. of GHG
Control, 13, 72 (2013).
366
In outreach with potentially vulnerable communities, residents have voiced two primaryconcerns. First, there is the concern that their communities have experienced historicallydisproportionate burdens from the environmental impacts of energy production, and second, thatas the sector evolves to use new technologies such as CCS and hydrogen, they may continue toface disproportionate burden. This is discussed further in section XIV.E of this preamble.
237
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

The use of water for cooling presents an additional issue. Due to their relatively highefficiency, combined cycle EGUs have relatively small cooling requirements compared to otherbase 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 bothto 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 amountsof 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 supercritical 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.
(D) Impacts on the Energy Sector
The EPA does not believe that determining CCS to be BSER for base load units willcause reliability concerns, for two independent reasons. First, the EPA is proposing that the costsof CCS are reasonable and comparable to other controls the electric power industry has usedwithout significant effects on reliability. Second, while CCS is adequately demonstrated and costreasonable, the current proposal allows companies that want to build a base load combined cycle
combustion turbine a second pathway to meet its requirements: building a unit that co-fires lowGHG hydrogen in the appropriate amount. In fact, companies are pursing both of these options,
238
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

including units with CCS, in various stages of development. The EPA also expects there to beconsiderable interest in building intermediate load and peaker units to meet market demand for
dispatchable generation. Indeed, the portion of the combustion turbine fleet that is operating atbase load is declining as shown in the EPA’s reference case modeling (post-IRA 2022 reference
case, see section IV.F of the preamble). Finally, combined cycle units are only one of many
options that companies have to build new generation. For instance, in 2023, combined cycle
units are only expected to represent 14 percent of all new generating capacity built in the US andonly a portion of that is natural gas combined cycle capacity. 367 Finally, several companies haverecently announced plans to move away from new combined cycle projects in favor of more nonbase load combustion turbines, renewables, and battery storage. For example, Xcel recently
announced plans to build new renewable power generation instead of the combined cycle plant it
had initially proposed to replace the retiring Sherco coal-fired plant. 368 For these reasons,determining CCS to be the BSER for base load units will not cause reliability concerns.
(E) 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. Useof 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

367

https://www.eia.gov/todayinenergy/detail.php?id=55419.
https://cubminnesota.org/xcel-is-no-longer-pursuing-gas-power-plant-proposes-morerenewable-power/.
239
368This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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.
(F) Promotion of the Development and Implementation of Technology
The EPA also considered whether determining CCS to be a component of the BSER for
new base load combustion turbines will advance the technological development of CCS andconcluded that this factor supports our BSER determination. A standard of performance based onhighly efficient generation in combination with the use of CCS—combined with the availabilityof 45Q tax credits and investments in supporting CCS infrastructure from the IIJA—should
incentivize additional use of CCS, which should incentivize cost reductions through thedevelopment 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 throughscaling.
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
2023 Annual Energy Outlook projects that almost 862 billion kWh of electricity will be
240This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

generated from natural gas-fired sources in 2040. 369 Much of that generation is projected to comefrom existing combined cycle EGUs and further development of carbon capture technologies
could facilitate increased retrofitting of those EGUs.
(G) Proposed BSER
The Agency proposes that for new natural gas-fired base load combustion turbines, anefficient stationary combined cycle combustion turbine utilizing CCS at a capture rate of 90
percent, beginning in 2035, qualifies as the BSER because it is adequately demonstrated; itentails reasonable costs 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 orenvironmental 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.
iv. Low-GHG hydrogen
As discussed, the EPA is proposing two BSER pathways that new stationary combustion
turbines may take—one that is based on the use of 90 percent CCS and a separate BSER
pathway based upon co-firing low-GHG hydrogen. In this section, the EPA explains why it
believes that CCS could form the basis of the BSER. In section VII.F.3.c, we discuss why webelieve burning low-GHG hydrogen could also form the basis of the BSER.
v. Basis for Proposal of 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

369

Does not include 114 billion kilowatt hours from natural gas-fired CHP projected in AEO
2023.
241

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

is proven, can be implemented at reasonable cost, and achieves emission reductions withoutcausing other significant environmental or energy issues. With regard 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, and that a well-sited individual new unit could meet thestandard of performance based on the application of 90 percent CCS on the startup date of the
facility. However, when looking at the technology from a nationwide basis, the EPA must takelarger system-wide impacts into consideration. For CCS, this includes questions about thedevelopment and availability of infrastructure for transportation and storage 370 as well as
considerations related to the lead time needed to scale manufacturing and the installation ofcarbon 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).
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 areother, non-power sector industries that will also be pursuing implementation of CCS in that370

For further information on timing associated with CO2 transport and storage design,
engineering, and construction, see GHG Mitigation Measures for Steam Generating Units TSD,
chapter 4.7.1.
242This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

timeframe. The EPA believes that while CCS poses low supply chain risk due to the required
infrastructure relying on common and readily available raw materials and CCS infrastructure canbe supplied in large part by domestic components, 371 the deployment of CCS infrastructure,including the demand for the manufacturing and installation of CCS equipment and CO2 pipeline
infrastructure, and the demand for 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 haveuseful information to provide to the record that would help to assess the demand for CCS.
Therefore, in consideration of these 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 thatcommenters 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 startdate 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 thestandards of performance should begin earlier than 2035, including as early as 2030.
c. BSER for Base Load Subcategory of Combustion Turbines Adopting the Low-GHG Hydrogen
Co-firing Pathway and Intermediate Load Subcategory—Second and Third Components
This section describes the second and third components of the EPA’s proposed BSER for
the subcategory of base load combustion turbines that are adopting the low-GHG hydrogen co-371

U.S. Department of Energy, Achieving American Leadership in the Carbon Capture,
Transport, and Storage Supply Chain, March 23, 2022 (DOE/OP-0001-1).
https://www.energy.gov/sites/default/files/2022-03/Carbon%20Capture%20factsheet.pdf.
243
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

firing pathway and the second component 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 and that sources meet acorresponding standard of performance beginning in 2032. For base load combustion turbines inthis subcategory of sources that adopt the low-GHG hydrogen co-firing pathway, the EPA is
proposing that the third component of the BSER is co-firing 96 percent (by volume) low-GHG
hydrogen and that sources meet a corresponding standard of performance beginning in 2038. The
EPA is also soliciting comment on whether, in lieu of providing a subcategory for base load
combustion turbines that adopt the low-GHG hydrogen co-firing pathway, a single BSER forbase load combustion turbines should be selected based on application of CCS with 90 percent
capture—which could also be met by co-firing 96 percent (by volume) low-GHG hydrogen. The
first part of this section is a background discussion concerning several key aspects of thehydrogen 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 cofiring as a viable decarbonization technology for the power sector. The EPA then discusses 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 and the third component of the
BSER, which, for certain units, is co-firing 96 percent (by volume) low-GHG hydrogen.
The EPA is also proposing a definition of low-GHG hydrogen. The EPA is proposingthat 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 (kg244This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

CO2e/kg H2) on a well-to-gate basis consistent with the system boundary established in IRC
section 45V (Credit for Production of Clean Hydrogen) of the IRA. Hydrogen produced byelectrolysis (splitting water into hydrogen and oxygen) using non-emitting energy sources suchas solar, wind, nuclear, and hydroelectric power, can produce hydrogen with carbon intensities
lower than 0.45 kg CO2e/kg H2, which could qualify as low-GHG hydrogen for the purposes ofthis proposed BSER. 372 However, the EPA is also soliciting comment on whether a specificdefinition of low-GHG hydrogen should be included in the final rule. The third part of thissection 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 (by volume) hydrogen istechnically feasible and well-demonstrated in new combustion turbines, it will be supported byan adequate supply of hydrogen by 2032, it will be of reasonable cost, it will ensure reductionsof 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 only low-GHG hydrogen is the “best” system of emission
reduction, taking into account the statutory considerations. This third part of this section also
explains why the EPA proposes that co-firing 96 percent (by volume) low-GHG hydrogenqualifies as a third component of the BSER for base load combustion turbines that are subject toa second phase standard of performance based on co-firing 30 percent (by volume) low-GHG
hydrogen. The EPA proposes that co-firing 96 percent (by volume) low-GHG hydrogen istechnically feasible and well-demonstrated in new combustion turbines, it will be supported by

372

U.S. Department of Energy (DOE). Pathways to Commercial Liftoff: Clean Hydrogen, March
2023. https://www.energy.gov/articles/doe-releases-new-reports-pathways-commercial-liftoffaccelerate-clean-energy-technologies.
245This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

an adequate supply of low-GHG hydrogen by 2038, it will be of reasonable cost, it will ensure
reductions of GHG emissions, and it will be consistent with the other BSER factors.
i. Lower Emitting Fuels
The EPA is not proposing lower emitting fuels as the second component of BSER forbase load or intermediate load combustion turbines because it would achieve few emission
reductions compared to co-firing low-GHG hydrogen.
ii. 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 acomponent of the BSER that is reflected in the second phase of the standards of performance forbase load turbines that are adopting the low-GHG hydrogen co-firing pathway and intermediateload combustion turbines. Highly efficient generation reduces fuel use as well as the absoluteamount and cost of low-GHG hydrogen that would be required to comply with the second phasestandards.
iii. CCS
The EPA is not proposing the use of CCS as a component of the BSER for base load
turbines combusting that are adopting low-GHG hydrogen co-firing or intermediate load
combustion turbines. As described previously, simple cycle technology is the most common
combustion turbine technology applicable to the intermediate load subcategory and the Agency
is limiting consideration of CCS to base load combined cycle EGUs. Intermediate load
combustion turbines tend to start and stop frequently and have relatively short periods ofcontinuous operation. CCS systems could have difficulty starting fast enough to get significant
levels of CO2 capture. The EPA solicits comment on flexible CCS technologies that could be
246
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

used by intermediate load combustion turbines. In addition, the CCS equipment could essentiallyremain idle for much of the time while these intermediate units are not running. For thesereasons, CCS would be less cost-effective for intermediate load combustion turbine EGUs —particularly at much lower capacity factors—as compared to base load combined cycle units thatare not on the pathway to combusting 96 percent (by volume) low-GHG hydrogen.
With respect to base load combustion turbine EGUs, as explained previously, the EPA is
proposing two BSER pathways that new base load stationary combustion turbines may take—one that is based on the use of 90 percent CCS and a separate BSER pathway based upon cofiring low-GHG. In this section, the EPA explains why it believes that co-firing with low-GHG
hydrogen could form the basis of the BSER. In section VII.C.3.b.iii, we discuss why we believe
CCS could also form the basis of the BSER.
iv. 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 and producing
fertilizer, with smaller amounts also used in sectors like metals treatment, processing foods, andproduction of specialty chemicals. 373 In recent years, applications of hydrogen have expanded toinclude 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

373

U.S. Department of Energy (DOE). National Clean Hydrogen Strategy and Roadmap.
September 2022. https://www.hydrogen.energy.gov/pdfs/clean-hydrogen-strategy-roadmap.pdf.
247This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

20 to 30 percent by volume are being tested and demonstrated; and new turbine designs that canaccommodate co-firing much greater percentages of hydrogen are being developed.
Several power producers made financial investments and began work on hydrogen cofiring projects prior to passage of the IRA in August 2022. For example, in early 2021, theIntermountain Power Agency (IPA) project in Utah began the transition away from operating an
1,800-MW coal-fired steam generating unit to an 840-MW combined cycle combustion turbinethat will integrate 30 percent by volume hydrogen co-firing at startup in 2025. 374 IPA and its
partners have announced plans to produce low-GHG hydrogen via solar-powered electrolysis
with storage in underground geologic formations en 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. 375 The 485-MW
combined cycle combustion turbine became operational in 2021 and is designed to transition to
100 percent hydrogen in the future 376. The unit successfully co-fired 5 percent by volume374

Intermountain Power Agency (2022). https://www.ipautah.com/ipp-renewed/.
Hering, G. (2021). First major US hydrogen-burning power plant nears completion in Ohio.
S&P Global Market Intelligence. https://www.spglobal.com/platts/en/market-insights/latestnews/electric-power/081221-first-major-us-hydrogen-burning-power-plant-nears-completion-inohio.
376
McGraw, D. (2021). World science community watching as natural gas-hydrogen power plantcomes to Hannibal, Ohio. Ohio Capital Journal.
https://ohiocapitaljournal.com/2021/08/27/world-science-community-watching-as-natural-gashydrogen-power-plant-comes-to-hannibal-ohio/.
248375This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

hydrogen in March 2022. 377 378 The planned next step for Long Ridge is to co-fire 20 percent by
volume hydrogen with the existing turbine design, which has been commercially available since2017 and can co-fire 15 to 20 percent by volume hydrogen without modification. 379 Furthermore,in June 2022, Southern Company successfully demonstrated the co-firing of a 20 percent by
volume hydrogen blend at Georgia Power’s Plant McDonough-Atkinson. The co-firingdemonstration was performed on a combustion turbine at partial and full loads and produced a 7
percent reduction in CO2 emissions. 380 In September 2022, the New York Power Authority(NYPA) successfully co-fired a 44 percent by volume blend of hydrogen 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

377

McGraw, D. (2021). World science community watching as natural gas-hydrogen power plantcomes to Hannibal, Ohio. Ohio Capital Journal.
https://ohiocapitaljournal.com/2021/08/27/world-science-community-watching-as-natural-gashydrogen-power-plant-comes-to-hannibal-ohio/.
378
Defrank, Robert (2022). Cleaner Future in Sight: Long Ridge Energy Terminal in Monroe
County Begins Blending Hydrogen.
https://www.theintelligencer.net/news/community/2022/04/cleaner-future-in-sight-long-ridgeenergy-terminal-in-monroe-county-begins-blending-hydrogen.
379
Patel, S. (April 22, 2022). First Hydrogen Burn at Long Ridge HA-Class Gas Turbine Marks
Triumph for GE. Power. https://www.powermag.com/nypa-ge-successfully-pilot-hydrogenretrofit-at-aeroderivative-gas-turbine/.
380
Patel, S. (2022). Southern Co. Gas-Fired Demonstration Validates 20% Hydrogen Fuel
Blend. https://www.powermag.com/southern-co-gas-fired-demonstration-validates-20-hydrogenfuel-blend/.
249
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

unit’s existing SCR controlled NOX emissions within permit limits.381 382 383 We note otherprojects to develop combustion turbines that co-fire hydrogen in section IV.E of this preamble.
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 emissions 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. 384 Also, NextEra’s Cavendish NextGen Hydrogen Hub will produce hydrogenwith a 25-MW electrolyzer system powered by solar energy and the hydrogen will then be cofired by combustion turbines at Florida Power and Light’s 1.75-GW Okeechobee power plant. 385
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 hydrogenproduction, storage, and transportation components. 386 In October 2022, Entergy and New

381

Palmer, W., & Nelson, B. (2021). An H2 Future: GE and New York power authority
advancing green hydrogen initiative. https://www.ge.com/news/reports/an-h2-future-ge-andnew-york-power-authority-advancing-green-hydrogen-initiative.
382
Van Voorhis, S. (2021). New York to test green hydrogen at Long Island power plant. Utility
Dive. https://www.utilitydive.com/news/new-york-to-test-green-hydrogen-at-long-island-powerplant/603130/.
383
Electric Power Research Institute (EPRI). (2022, September 15). Hydrogen Co-Firing
Demonstration at New York Power Authority’s Brentwood Site: GE LM6000 Gas Turbine. Low
Carbon Resources Initiative. https://www.epri.com/research/products/000000003002025166.
384
NextEra Energy (2022). Zero Carbon Blueprint.
https://www.nexteraenergy.com/content/dam/nee/us/en/pdf/NextEraEnergyZeroCarbonBlueprint
.pdf.
385
Clean Energy Group. Hydrogen Projects in the U.S. https://www.cleanegroup.org/cegprojects/hydrogen/projects-in-the-us/.
386
Mitsubishi Power Americas. (September 23, 2020). Mitsubishi Power and Entergy to
Collaborate and Help Decarbonize Utilities in Four States.
https://power.mhi.com/regions/amer/news/20200923.html.
250This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Fortress Energy announced plans to collaborate on a renewable energy and 120-MW hydrogenproduction plant in southeast Texas. 387 The partnership includes electricity transmission
infrastructure as well as the development of renewable energy resources and the offtake of lowGHG hydrogen. A feature of the agreement is the potential to supply hydrogen to Entergy’s
Orange County Advanced Power Station, which received approval from the Public Utility
Commission of Texas in November 2022. 388 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 hydrogenwith the ability to move to 100 percent hydrogen in the future. 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 variablegeneration. 389 These services can enhance the reliability of the power system while facilitating
the integration of variable renewable energy resources and supporting decarbonization of theelectric grid. Hydrogen has the potential to mitigate curtailment, which is the deliberate
reduction of electric output below what could have been produced. Curtailment often occurs
when RTOs need to balance the grid’s energy supply to meet demand. For example, in 2020, the387Entergy. (October 19, 2022). Entergy Texas and New Fortress Energy partner to advancehydrogen economy in Southeast Texas. https://www.entergynewsroom.com/news/entergy-texasnew-fortress-energy-partner-advance-hydrogen-economy-in-southeast-texas/.
388
Entergy. (November 28, 2022). Entergy Texas receives approval to build a cleaner, morereliable power station in Southeast Texas. https://www.entergynewsroom.com/news/entergytexas-receives-approval-build-cleaner-more-reliable-power-station-in-southeast-texas/.
389
For example, when the sun is not shining and/or the wind is not blowing.
251
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

California Independent System Operator (CAISO) curtailed an estimated 1.5 million MWh ofsolar generation. 390 Curtailment will likely increase as the capacity of variable generation
continues to expand. One technology with the potential to reduce curtailment is energy storage,
and some power producers envision a role for hydrogen to supplement natural gas as a fuel tosupport the balancing and reliability 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 longterm commitments to hydrogen co-firing and have identified the technology as a key componentof 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 verticallyintegrated states and merchant generators in wholesale markets rely on combustion turbines toprovide reliable, dispatchable power.
Hydrogen gas released into the atmosphere will also have climate and air quality effects
through atmospheric chemical reactions. In particular, hydrogen is known to react with thehydroxyl radical, reducing concentrations of the hydroxyl radical in the atmosphere. Because thehydroxyl radical is important for the destruction of many other gases, a reduction in hydroxyl
radical concentrations will lead to increased lifetimes of many other gases – including methaneand tropospheric ozone. This means that hydrogen gas emissions can also indirectly contribute towarming through increasing concentrations of methane and ozone. Hydrogen is not a greenhouse390

Walton, R. (August 25, 2021). CAISO forced to curtail 15% of California utility-scale solar in
March, 5% last year. Power Engineering. https://www.power-eng.com/solar/caiso-forced-tocurtail-15-of-california-utility-scale-solar-in-march-5-last-year/#gref.
252
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

gas as defined by the Framework Convention on Climate Change under the IPCC, and its
secondary impacts on warming should mitigate over time as methane emissions are controlled.
Even as hydrogen scales and much larger volumes are consumed, with the attendant potential foremissions of hydrogen to oxidize in the atmosphere, we expect the benefits of low-GHG
hydrogen as part of a BSER pathway to outweigh any such effects in the future.
v. 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 fromco-firing low-GHG hydrogen in a combustion turbine EGU, it is important to consider thedifferent processes of producing the hydrogen and the GHG emissions associated with eachprocess. 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 hydrogenproduction are well-recognized, and stakeholders routinely refer to hydrogen on the basis of thedifferent production processes and their different GHG intensities. 391
More than 95 percent of the dedicated hydrogen currently produced in the U.S. originatesfrom natural gas using steam methane reforming (SMR). This method produces hydrogen byadding steam and heat to natural gas in the presence of a catalyst. Methane reacts with the steam

391

Some organizations have developed a convention for labeling each hydrogen production
method, based on the GHG emissions associated with each method, according to a color scheme.
The color labels are insufficiently specific for the purposes of this proposed rule, so the EPA
generally does not refer to hydrogen using this color convention.
253

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 moresteam to create additional hydrogen and CO2. After these processes, the CO2 is removed from thegas stream, leaving almost pure hydrogen. 392 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 thethermal efficiency of SMR of natural gas is generally 80 percent or less, 393 less overall energy isin 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 morenatural 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. 394 The autothermal

392

U.S. Department of Energy (DOE) (n.d.). Hydrogen Production: Natural Gas Reforming.
https://www.energy.gov/eere/fuelells/hydrogen-production-natural-gas-reforming. For each kg
of hydrogen produced through SMR, 4.5 kg of water is consumed.
393
Thermal efficiency is the amount of energy in the production (e.g., hydrogen) compared to theenergy input to the process (e.g., natural gas). At an efficiency of 80 percent, the productcontains 80 percent of the energy input and 20 percent is lost.
394
Powell, D. (2020). Focus on Blue Hydrogen. Gaffney Cline.
https://www.gaffneycline.com/sites/g/files/cozyhq681/files/202108/Focus_on_Blue_Hydrogen_Aug2020.pdf.
254
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

reforming (ATR) of methane is a similar technology to SMR, but ATR utilizes natural gas in theprocess itself without an external heat source. 395 CCS can also be applied to ATR.
Another process to produce hydrogen is methane pyrolysis. Methane pyrolysis is thethermal decomposition of methane in the absence (or near absence) of oxygen, which produceshydrogen 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. 396
In contrast to the three methods discussed above, electrolysis does not use methane as afeedstock. In electrolysis, hydrogen is produced by splitting water into its components, hydrogenand oxygen (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 emit 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. 397 According to the DOE, electrolysis powered by fossil fuel395“Comparative assessment of blue hydrogen from steam methane reforming, autothermal
reforming, and natural gas decomposition technologies for natural gas production regions,”
Energy Conversion and Management, February 15, 2022.
396
In addition, methane extraction operations are known to contribute to air toxics including
benzene, ethylbenzene, and n-hexane. https://www.epa.gov/controlling-air-pollution-oil-andnatural-gas-industry/basic-information-oil-and-natural-gas.
397
Similarly, the overall GHG emissions associated with methane pyrolysis are dependent upon
the source of the energy used to decompose the methane and is a key factor to whether it
qualifies as low-GHG hydrogen.
255
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

energy supplied by the electric grid, based on a national average, would generate overall GHG
emissions double those of hydrogen produced via SMR without CCS.398 399 However,electrolysis powered by wind, solar, hydroelectric, or nuclear energy is generally considered tolower overall GHG emissions. 400 401 402 It should be noted that electrolytic systems utilizing evena small portion of grid-based electricity may not have lower overall GHG emissions and carbon
intensities than SMR without CCS. 403 This concern is likely to be mitigated over time as the
carbon intensity of the grid declines, given the influx of new renewable generation—the EPA’s
post-IRA 2022 reference case projects a lower carbon intensity of the grid-—coupled withexpected retirements of higher-emitting sources. Naturally occurring hydrogen stored in398

DOE (2022). DOE National Clean Hydrogen Strategy and Roadmap. Draft—September
2022. https://www.hydrogen.energy.gov/pdfs/clean-hydrogen-strategy-roadmap.pdf.
399
DOE Pathways to Commercial Liftoff: Clean Hydrogen, March 2023:
https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB-0329update.pdf. From the Liftoff report, “Carbon intensities are based on data from the Carnegie
Mellon Power Sector Carbon Index as well as national averages in grid mix carbon intensity – insome states, grid carbon intensity can be as high as 40 kg CO2e / kg H2.”
400
U.S. Department of Energy (DOE) (n.d.). Hydrogen Production: Electrolysis.
https://www.energy.gov/eere/fuelcells/hydrogen-production-electrolysis.
401
For each kg of hydrogen produced through electrolysis, 9 kg of byproduct oxygen are also
produced and 9 kg of purified water are consumed. To reduce the cost of hydrogen production,
this byproduct oxygen could be captured and sold. For each gallon of water consumed, 0.057
MMBtu of hydrogen is produced. According to the water use requirements for combined cycle
EGUs with cooling towers, if this hydrogen is later used to produce electricity in a combined
cycle EGU, overall water requirements would be greater than a combined cycle EGU with
CCUS.
402
Electrolysis and other technologies that break apart water to form hydrogen and oxygen
consume more water than SMR without CCS. Resource Assessment for Hydrogen Production.
National Renewable Energy Laboratory (NREL/TP-5400-77198, July 2020).
https://www.nrel.gov/docs/fy20osti/77198.pdf. Aside from methane pyrolysis and byproducthydrogen, other hydrogen production methods consume water during the production process andindirectly due to electricity generation upstream. The moisture present in coal and biomass could
be recovered and used in the water gas shift reaction to reduce (or eliminate) water requirements.
403
U.S. Department of Energy (DOE). Pathways to Commercial Liftoff: Clean Hydrogen. March
2023. https://www.energy.gov/articles/doe-releases-new-reports-pathways-commercial-liftoffaccelerate-clean-energy-technologies.
256
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

subsurface geologic formations is also gaining attention as a potential low-GHG source ofhydrogen.
vi. 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 hydrogenand that sources meet a corresponding standard of performance by 2032. The EPA is also
proposing that new base load combustion turbines that are subject to a standard of performancebased on co-firing 30 percent (by volume) low-GHG hydrogen in 2032 must also meet a more
stringent standard of performance based on a BSER of co-firing 96 percent (by volume) lowGHG hydrogen by 2038. 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 emission reductions at the
combustion turbines, 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 stackemissions 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
hydrogen yields a 12 percent CO2 reduction, co-firing 75 percent hydrogen yields a 49 percent
CO2 reduction, and at 100 percent hydrogen co-firing there are zero CO2 emissions at the stack.

257
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Importantly, co-firing 30 percent hydrogen by volume is consistent with existing
technologies across multiple combustion turbine designs and should be considered a minimallevel for evaluation as a system of emission reduction. While all major manufacturers aredeveloping combustion turbines that can co-fire higher volumes of hydrogen, some combustion
turbine models are already able to co-fire relatively high percentages. 404 Several currently
available new combustion turbine models can burn up to 75 percent hydrogen by volume. 405
Combustion turbine designs capable of co-firing 30 percent hydrogen by volume are available
from multiple manufacturers at multiple sizes. As such, a BSER that included co-firing 30
percent hydrogen by volume would not pose challenges for near-term implementation for the
EPA’s proposed second phase standards beginning in 2032. The EPA is soliciting comment onwhether 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 or more by
volume by 2030 or 2032. If such combustion turbines are sufficiently available, this would
support moving forward the starting compliance date of the second phase of the standards ofperformance and/or increasing the percent of hydrogen co-firing assumed in establishing thestandards.
Because the cost of natural gas is lower than the cost of hydrogen, most new combustion
turbines are not, at the present time, designed to burn 100 percent hydrogen when they are placed
into service. However, some turbines are available now that can combust 100 percent hydrogenin the future and there is significant evidence that such turbines will be more widely available by404

Mitsubishi Power Americas. https://power.mhi.com/special/hydrogen/article_1.
Overcoming technical challenges of hydrogen power plants for the energy transition.
https://www.nsenergybusiness.com.
258

405

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

the 2030s. 406 Multiple vendors have indicated that they intend to have turbines available that fire
100 percent hydrogen in that timeframe. 407 408,409 For example, as noted in section IV.E of thispreamble, the LADWP Scattergood Modernization project includes plans to have a hydrogenready combustion turbine in place when the 346-MW combined cycle plant (potential for up to830 MW) begins initial operations in 2029. LADWP foresees the plant running on 100 percent
electrolytic hydrogen by 2035. 410 The Intermountain Power Project, also noted in section IV.E of
this preamble, commenced construction in 2022 on an 840-MW M501 JAC Mitsubishi Hitachi
Power Systems combustion turbine designed to operate using 30 percent (by volume) hydrogen
upon startup. The plant is projected to be operational by July 2025 and to transition to 100
percent hydrogen by 2045. 411 Several existing gas turbine technologies are capable of operatingwith 100 percent hydrogen, including Siemens Energy’s SGT-A35 and General Electric’s B, E,
and F class gas turbines. 412 Comments submitted to the EPA’s non-regulatory docket confirm
that at the present time, existing units can be retrofitted to operate using 100 percent hydrogen.
DOE’s National Energy Technology Lab states: Based on data from a literature survey and input

406

https://www.dieselgasturbine.com/news/siemens-energy-explores-gas-turbines-future-in-netzero-energy-mix/8024799.article.
407
Mitsubishi highlights four hydrogen projects at CERAWeek. https://www.powereng.com/hydrogen/mitsubishi-power-highlights-four-hydrogen-projects/#gref.
408
Constellation Energy Corporation’s Comments on EPA Draft White Paper: Available andEmerging Technologies for Reducing Greenhouse Gas Emissions from Combustion Turbine
Electric Generating Units Docket ID No. EPA-HQ-OAR-2022-0289. Docket comments noted,“Retrofits using existing technology are available to achieve 50-100% hydrogen combustion by
volume at some generators.”
409
Siemens Energy to provide hydrogen-capable turbines to back up utility-scale solar
installation in Nebraska. https://press.siemens-energy.com/global/en/pressrelease/siemensenergy-provide-hydrogen-capable-turbines-back-utility-scale-solar-installation.
410
https://clkrep.lacity.org/onlinedocs/2023/23-0039_rpt_DWP_02-03-2023.pdf.
411
IPP Renewed – Intermountain Power Agency.ipautah.com.
412
ICF. Retrofitting Gas Turbine Facilities for Hydrogen Blending.
259This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

from manufacturers, NETL has found that today’s modern gas turbines can reliably combust 3060 percent hydrogen fuels with similar NOX emissions as compared to their pure natural gas
counterparts. Public and private research is underway to produce a 100 percent hydrogen-fueled
turbine. NETL anticipates that industry will achieve this technology by around 2030 based on
current research progress and publicly announced forecasts.” 413 Turbine projects that haverecently been built and that are currently under construction (such as the Longview turbine andthe Intermountain Power Project discussed elsewhere in this preamble) are being developed withthe understanding that these technology advances will be retrofittable to these types of turbines.
It is worth noting that in many cases, existing turbines are able to co-fire large amounts ofhydrogen without significant re-engineering. This is because their burners are developed
relatively simply and are able to combust large amounts of hydrogen. In retrospect almost all
new turbines are designed with more sophisticated burners that closely control the mixture of airand fuel to maximize efficiency while limiting nitrogen oxide generation. Because hydrogen hasvery different characteristics than natural gas such as higher flame temperature, these burners
need to be re-engineered to accommodate large amounts of hydrogen 414 415 For more information

413

National Energy Technology Laboratory, A Literature Review of Hydrogen and Natural GAS
Turbines: Current State of the Art With Regard to Performance and NOX Control (DOE/NETL2022/3812), August 12, 2022. https://netl.doe.gov/sites/default/files/publication/A-LiteratureReview-of-Hydrogen-and-Natural-Gas-Turbines-081222.pdf; Department of Energy, National
Energy Technology Laboratory, “Experts Discuss Use of Hydrogen-Fueled Turbines to Drive
Clean Energy” September 15, 2022. https://netl.doe.gov/node/12058.
414
Siemens Energy, “Ten Fundamentals to Hydrogen Readiness” September 2022.
https://www.siemens-energy.com/global/en/news/magazine/2022/hydrogen-ready.html.
415
General Electric, “Hydrogen-Fueled Gas Turbines”
https://www.ge.com/content/dam/gepower-new/global/en_US/downloads/gas-new-site/future-ofenergy/hydrogen-overview.pdf.
260This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

about the status of combustion turbines with respect to combusting hydrogen see the TSD,
“Hydrogen in Combustion Turbine EGUs,” in the docket for this rulemaking.
Access to low-GHG hydrogen, however, is also an important component of the BSER
analysis. Midstream infrastructure limitations and the adequacy and availability of hydrogenstorage 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 aspart 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. 416 As
noted later in a section of this preamble, based on industry announcements, many electrolytichydrogen 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
in use in Hawaii and under exploration in other areas of the country. 417 On-road distribution
methods include gas-phase trucking and liquid hydrogen trucking, the latter requiring coolingand compression prior to transport. Different regional distribution solutions may emerge initiallyin 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 H2Hubinvestments as low-GHG hydrogen develops from a localized fuel into a national commodity.

416

DOE Pathways to Commercial Liftoff: Clean Hydrogen, March 2023
https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB-0329update.pdf.
417
https://www.hawaiigas.com/clean-energy/decarbonization.
261
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 low-GHG hydrogen by volume in 2032 and to co-fire 96
percent low-GHG hydrogen by volume in 2038. The EPA is soliciting comment on the expected
low-GHG hydrogen availability by those dates. The EPA is also soliciting comment on whether
hydrogen infrastructure is likely to be sufficiently developed by 2030 to provide access to lowGHG 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 performance and/or increase
the percent of hydrogen co-firing assumed in establishing the standards.
Whether there will be sufficient volumes of low-GHG hydrogen for new sources to cofire 30 percent by volume between 2030 and 2032 and then for some base load sources to co-fire
96 percent by 2038 will 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 tolower 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 hydrogen to produce electricity, it is likely that only aspecific type of low-GHG hydrogen will be used in the power sector. Announcements of cofiring applications support this assertion, and as discussed in another section of this preamble, the262This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 cofiring by 2032 and 96 percent by 2038. The DOE’s estimates of clean hydrogen production
volumes of 10 MMT by 2030 and 20 MMT by 2040, referenced throughout this rulemaking, do
not apportion which type of hydrogen is likely to be produced, just that it is ‘clean.’ 418 The
available credits for the lowest GHG hydrogen production tier under IRC section 45V tax
subsidies going into effect in 2023, as outlined in another section of this preamble, are threetimes higher than the credit values allotted for other hydrogen production tiers in IRC section
45V. This incentive can be combined with additional monetization access through direct pay andtransferability, and therefore has the potential to drive significant volumes of electrolytichydrogen, which is likely to be considered as low-GHG hydrogen in this proposal. 419 The EPA’s
hydrogen co-firing BSER proposal, if finalized, would create a significant additional demand
driver for electrolytic hydrogen not considered in the DOE’s hydrogen production goals of 10
MMT by 2030 and 20 MMT by 2040. Indeed, high volumes of electrolytic hydrogen were
central to pathways enabling the power sector to achieve net-zero emissions by 2035 according
to analysis by the National Renewable Energy Laboratory (NREL). 420 These incentives will be

418

DOE, as required by the IIJA, proposed a Clean Hydrogen Production Standard (CHPS) of
having an overall emissions rate of 4 kg CO2e/kg H2. CHPS is not an actual standard, rather anon-binding tool for DOE’s internal use with selecting projects under the H2Hubs program.
DOE’s proposed CHPS can be found at https://www.hydrogen.energy.gov/pdfs/clean-hydrogenproduction-standard.pdf.
419“The Hydrogen Credit Catalyst: How US Treasury guidance on a new tax credit could shape
the clean hydrogen economy, the future of American industry, and orient the power sector for
full decarbonization,” Rocky Mountain Institute, February 27, 2023.
420
Denholm, Paul, Patrick Brown, Wesley Cole, et al. 2022. Examining Supply-Side Options toAchieve 100% Clean Electricity by 2035. Golden, CO: National Renewable Energy Laboratory.
NREL/TP[1]6A40-81644. https://www.nrel.gov/docs/fy22osti/81644.pdf.
263
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

multiplied by investments through the DOE’s H2Hub program. Electrolytic production costs,
inclusive of the 45V PTC, are estimated to fall to less than $0.40/kg by 2030; this could translate
to delivered cost of hydrogen for combustion turbines in 2030 between $0.70/kg and $1.15/kg
depending on storage and distribution costs.421 The EPA is soliciting comment on whether
sufficient quantities of low-GHG hydrogen are likely to 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 discussed earlier, an important feature of hydrogen as a potential fuel for combustion
turbines is the level of GHG emissions generated during the production process, with different
processes resulting in different levels of GHG emissions. The EPA proposes to conclude that cofiring with low-GHG hydrogen (but not other forms of hydrogen) appropriately considers thestatutory 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 programs to support the development of low-GHG hydrogen, including section
40314 of the IIJA which established a $8 billion Clean Hydrogen Hubs H2Hubs program, the$500 million Clean Hydrogen Manufacturing and Recycling Program, and a $1 billion Clean
Hydrogen Electrolysis Program to further electrolysis development. Section 40315 of the IIJA
required DOE to establish a non-regulatory Clean Hydrogen Production Standard (CHPS). Most
recently, in the IRA, section 13204, Congress authorized the clean hydrogen production tax

421

U.S. Department of Energy (DOE). Pathways to Commercial Liftoff: Clean Hydrogen. March
2023.https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB0329-update.pdf.
264
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

credit (45V). Several Federal agencies, including the EPA, are implementing those programs.
DOE consulted the EPA while developing its proposed CHPS, which included examining
various hydrogen production processes and the spectrum of resulting overall carbon intensities.
That collaborative process provided useful points of reference for the EPA to use in proposing adefinition in this 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. 422 Congress also provided a definitionof “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) andDOE’s funding programs to promote promising new hydrogen technologies.
Several Federal agencies are engaging in low-GHG hydrogen-related efforts, some ofwhich implement the IRA and IIJA provisions. As discussed earlier in this section, the DOE isworking on a Clean Hydrogen Production Standard, 423 an $8 billion Clean Hydrogen Hubsolicitation, 424 and several hydrogen-related research and development grant programs. 425 The

422

These amounts assume that wage and apprenticeship requirements are met.
U.S. Department of Energy (DOE). (September 22, 2022). Clean Hydrogen Production
Standard. Hydrogen and Fuel Cell Technologies Office.
https://www.energy.gov/eere/fuelcells/articles/clean-hydrogen-production-standard.
424
https://www.energy.gov/oced/regional-clean-hydrogen-hubs.
425
https://www.hydrogen.energy.gov/funding_opportunities.html.
265
423

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Department of the Treasury is taking public comment on examining appropriate parameters forevaluating overall emissions associated with hydrogen production pathways as it prepares toimplement IRC section 45V. 426 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.
The IIJA includes both a textual definition of “clean hydrogen” and requires the DOE todevelop a Clean Hydrogen Production Standard: these two references are related but distinct.
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 the purposes of this rule. As noted, this provision sets a non-binding goal for use
in the development of the DOE’s Clean Hydrogen Production Standard (CHPS) and the DOE’s
funding programs to promote promising new hydrogen technologies. The definition of cleanhydrogen in the IIJA is limited to GHGs emitted at the hydrogen production site and is therefore
not intended to consider overall GHG emissions associated with that production method.
According to the IIJA, clean hydrogen as defined as part of the CHPS is “… hydrogen producedwith 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 fromupstream methane emissions, which are not accounted for in the CHPS definition. 427 That
definition was taken into consideration, along with multiple other data points, for development of426

https://home.treasury.gov/news/press-releases/jy0993.
Infrastructure Investment and Jobs Act of 20211Law PUBL058.PS(https://www.congress.gov).
266

427

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

the CHPS. In CHPS draft guidance, a target of 4 kg CO2e/kg H2 on a well-to-gate basis, whichaligns with full range of the IRC section 45V definition in the IRA. 428
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 thehighest available amount of production tax credit for hydrogen produced through a process thathas 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 that meets this criterion qualifies as acomponent of the “best” system of emission reduction, taking into account the statutory
considerations. Thus, consistent with the tiered approach and system boundaries in the IRA
definition of clean hydrogen, 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, fromwell-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, andnuclear, appear most likely to produce hydrogen that would meet the 0.45 kg CO2e/kg H2 or less,from well-to-gate criteria. 429 Hydrogen production pathways using methane as a feedstock
induce upstream methane emissions associated with extraction, production, and transport of themethane. SMR and ATR also release heating and process-related CO2 emissions that are difficult

428

U.S. Department of Energy Clean Hydrogen Production Standard (CHPS) Draft Guidance429

DOE Pathways to Commercial Liftoff: Clean Hydrogen, March 2023.
https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB-0329update.pdf.
267
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

to capture at high rates economically. 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 wewill 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 lowGHG 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 necessary to provide a definition of
low-GHG hydrogen in this rule. Given the incentives provided in both the IRA and IIJA for lowGHG hydrogen production and the current trajectory of hydrogen use in the power sector, by2032, 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 ofhydrogen 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 ofgeneration 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 thatthe power sector is likely to have access to and will choose to utilize low-GHG hydrogen for its
co-firing applications. Some NGOs have expressed concern that existing non-emitting assets will
268
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

channel electricity from the grid toward electrolyzers, potentially increasing marginal electricity
generation from assets with higher carbon intensities. The EPA agrees these are important issues
that should be considered as levels of excess zero carbon-emitting generation vary diurnally andby region. The EPA notes that these concerns should mitigate over time as the carbon intensityof the grid is projected to decline.
Moreover, by the next decade, costs for low-GHG hydrogen are expected to becompetitive with higher-GHG forms of hydrogen given declines due to learning and the IRC
section 45V subsidies. Given the tax credits in IRC section 45V(b)(2)(D) of $3/kg H2 forhydrogen with GHG emissions of less than 0.45 kg CO2e/kg H2, and substantial DOE grant
programs to drive down costs of clean hydrogen, some entities project the delivered costs ofelectrolytic low-GHG hydrogen to range from $1/kg H2 to $0/kg H2 or less. 430 431 432 These
projections are more optimistic than, but still comparable to, DOE projections of 2030 fordelivered costs of electrolytic low-GHG hydrogen in the range of $0.70/kg to $1.15/kg for power
sector applications, given R&D advancements and economies of scale. 433 A growing number ofstudies are demonstrating more efficient and less expensive techniques to produce low-GHG
electrolytic hydrogen; and, tax credits and market forces are expected to accelerate innovation430“US green hydrogen costs to reach sub-zero under IRA: longer-term price impacts remain
uncertain,” S&P Global Commodity Insights, September 29, 2022.
431“DOE Funding Opportunity Targets Clean Hydrogen Technologies” American Public Power,
January 31, 2023.
432
With the 45V PTC, delivered costs of hydrogen are projected to fall in the range of $0.70/kg
to $1.15/kg for power sector applications.
433
DOE Pathways to Commercial Liftoff: Clean Hydrogen, March 2023.
https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB-0329update.pdf.
269This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

and drive down costs even further over the next decade. 434 435 436 The combination of competitive
pricing and widespread net-zero commitments throughout the utility and merchant electricity
generation market has the potential to drive future hydrogen co-firing applications to be lowGHG hydrogen. 437 The EPA is therefore soliciting comment on whether low-GHG hydrogenneeds to be defined as part of the BSER in this proposed rulemaking.
vii. Justification for Proposing 30 Percent Co-firing Low-GHG Hydrogen and 96 Percent Cofiring Low-GHG Hydrogen as Components of 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 2032, meets therequirements under CAA section 111(a)(1) to qualify as a component of the BSER. Similarly,
the EPA is proposing that co-firing 96 percent low-GHG hydrogen by new base load combustion
turbines in the relevant subcategory, by 2038, also meets the requirements under CAA section
111(a)(1) to qualify as a component of the BSER. As discussed below, co-firing 30 percent lowGHG hydrogen is adequately demonstrated because it is feasible and well-demonstrated for new
combustion turbines to co-fire that percentage of hydrogen and multiple combustion turbine
vendors have targets to have 100 percent hydrogen-capable combustion turbines available byaround 2030 and are selling combustion turbines today with the intention of those combustion

434“Sound waves boost green hydrogen production,” Power Engineering, January 4, 2023.
“Direct seawater electrolysis by adjusting the local reaction environment of a catalyst,”
Nature Energy, January 30, 2023.
436
https://h2new.energy.gov/.
437
DOE Pathways to Commercial Liftoff: Clean Hydrogen, March 2023.
https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB-0329update.pdf.
270435This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

turbines being retrofittable to 100 percent hydrogen firing. 438 439 Several project developers haveannounced plans to transition from lower levels of co-firing up to firing with 100 percent
hydrogen.
The EPA proposes that co-firing 30 percent low-GHG hydrogen by 2032 and 96 percent
by 2038 qualify as a BSER pathway for new baseload combustion turbines. For the reasons
discussed next, the EPA proposes that co-firing low-GHG hydrogen on that pathway isadequately demonstrated in light of the capability of combustion turbines to co-fire hydrogen andthe EPA’s reasonable expectation that adequate quantities of low-GHG hydrogen will beavailable by 2032 and 2038 and at reasonable cost. Moreover, combusting hydrogen will achieve
reductions because it does not produce GHG emissions and will not have adverse non-air quality
health or environmental impacts or energy requirements, including on the nationwide energy
sector. Because the production of low-GHG hydrogen generates the fewest GHG emissions, theEPA proposes that co-firing low-GHG hydrogen, and not other types of hydrogen, qualifies as
the “best” system of emission reduction. The fact that co-firing low GHG hydrogen createsmarket demand for, and advances the development of, low-GHG hydrogen, a fuel that is usefulfor reducing emissions in the power sector and other industries, provides further support for this
proposal.
(A) 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 fuel438

https://www.powermag.com/first-hydrogen-burn-at-long-ridge-ha-class-gas-turbine-markstriumph-for-ge/.
439
https://www.doosan.com/en/media-center/press-release_view?id=20172449.
271
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 beavailable for combustion turbine EGUs by 2032.
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 technicalchallenges of hydrogen co-firing are related to certain physical characteristics of the gas. Whenhydrogen fuel is combusted, it produces a higher flame speed than the flame speed producedwith the combustion of natural gas; and hydrogen typically combusts at a faster rate than naturalgas. 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. 440 Hydrogen also has a higher
flame temperature and a wider flammability range compared to natural gas. 441
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-440

Inoue, K., Miyamoto, K., Domen, S., Tamura, I., Kawakami, T., & Tanimura, S. (2018).
Development of Hydrogen and Natural Gas Co-firing Gas Turbine. Mitsubishi Heavy Industries
Technical Review. Volume 55, No. 2. June 2018.https://power.mhi.com/randd/technicalreview/pdf/index_66e.pdf.
441
Andersson, M., Larfeldt, J., Larsson, A. (2013). Co-firing with hydrogen in industrial gas
turbines. http://sgc.camero.se/ckfinder/userfiles/files/SGC256(1).pdf.
272This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

firing 30 percent hydrogen is technically feasible for new base load and intermediate load
stationary combustion turbine EGUs by 2032 and that co-firing higher levels—up to 96 percent
by volume—is feasible by 2038. The EPA solicits comment on these proposed findings.
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 forutility EGUs that can co-fire hydrogen. 442 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. 443 444
Several developers have announced installations with plans to initially co-fire lower percentagesof low-GHG hydrogen by volume before gradually increasing their co-firing percentages—to ashigh as 100 percent in some cases—depending on the pace of the anticipated expansion of lowGHG 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 load442

Siemens Energy (2021). Overcoming technical challenges of hydrogen power plants for theenergy transition. NS Energy. https://www.nsenergybusiness.com/news/overcoming-technicalchallenges-of-hydrogen-power-plants-for-energy-transition/.
443
Simon, F. (2021). GE eyes 100% hydrogen-fueled power plants by 2030.
https://www.euractiv.com/section/energy/news/ge-eyes-100-hydrogen-fuelled-power-plants-by2030/.
444
Patel, S. (2020). Siemens’ Roadmap to 100% Hydrogen Gas Turbines.
https://www.powermag.com/siemens-roadmap-to-100-hydrogen-gas-turbines/.
273
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

stationary combustion turbine EGUs by 2032 and that co-firing 96 percent hydrogen istechnically feasible for new base load stationary combustion turbine EGUs by 2038.
The combustion characteristics of hydrogen can lead to localized higher temperaturesduring the combustion process. These “hotspots” can increase emissions of the criteria pollutant
NOX. 445 NOX emissions resulting from the combustion of high percentage by volume blends ofhydrogen are also of concern in many regions of the country. For turbines using diffusion flame
combustion, water or steam 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 toaddress 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 andare designing combustion turbines that will be capable of combusting 100 percent hydrogen by
2030, with DLN designs that assure acceptable levels of NOX emissions. In addition, EGR in
diffusion flame combustion turbines reduces the oxygen concentration in the combustor andlimits combustion temperatures and NOx formation. Furthermore, while combustion controls canachieve low levels of NOX, many new intermediate load and base load combustion turbines using
DLN combustion also use selective catalytic reduction (SCR) to reduce NOX emissions evenfurther. 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

445

Guarco, J., Langstine, B., Turner, M. (2018). Practical Consideration for Firing Hydrogen
Versus Natural Gas. Combustion Engineering Association. https://cea.org.uk/practicalconsiderations-for-firing-hydrogen-versus-natural-gas/.
274This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

of the catalyst bed can be increased. 446 The EPA has concluded that any potential increases in
NOX emissions do not change the Agency’s view that on balance, co-firing low-GHG hydrogenqualifies as a component of the BSER.
As noted above, at present, most of the hydrogen produced in the U.S. is produced for theindustrial sector through SMR, which is a high GHG-emitting process. Limited quantities ofhydrogen 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, muchlarger facilities are under development.
However, as also noted above, incentives in recent Federal legislation are anticipated tosignificantly increase the availability of low-GHG hydrogen by 2032, 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. 447 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 thispreamble.)

446

Siemens Energy (2021). Overcoming technical challenges of hydrogen power plants for theenergy transition. NS Energy. https://www.nsenergybusiness.com/news/overcoming-technicalchallenges-of-hydrogen-power-plants-for-energy-transition/.
447
IIJA authorized a total of $9.5B for hydrogen related programs ($8 billion for Clean
Hydrogen Hubs H2Hubs, $1B for electrolyzer research and development and $500 million forhydrogen-related manufacturing incentives). See also: U.S. Dept. of Energy, Regional Clean
Hydrogen Hubs. https://www.energy.gov/oced/regional-clean-hydrogen-hubs.
275
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Programs from the IIJA and IRA have been successful in prompting the development of
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 annually, which
represents a 21 percent increase over current output. 448 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. 449 The facility will use 220 MW of electrolyzers powered by renewableenergy to produce low-GHG hydrogen. The hydrogen will be stored in salt caverns andserve as a long-term fuel supply for the combustion turbine at the Intermountain Power
Agency (IPA) project, which is described earlier in this section.

•

In January 2023, NextEra announced an 800-MW solar project in the central U.S. tosupport the development of low-GHG hydrogen as well as plans to produce its own lowGHG hydrogen at a facility in Arizona. 450•

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 to448

Energy Futures Initiative (February 2023). U.S. Hydrogen Demand Action Plan.
https://energyfuturesinitiative.org/reports/.
449
U.S. Department of Energy (DOE). (2022). Loan Office Programs. Advanced Clean Energy
Storage. https://www.energy.gov/lpo/advanced-clean-energy-storage.
450
Penrod, Emma. (January 30, 2023). NextEra charts path for renewables expansion, but
campaign finance allegations loom in the background. Utility Dive.
https://www.utilitydive.com/news/nextera-renewables-expansion-green-hydrogen-solar-allegedcampaign-finance-violation/641475/.
276This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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. 451•

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” forproducing cost-effective hydrogen, is expected to be operational in 2024 and is also
funded with a DOE grant. 452•

In California, Sempra subsidiary SoCalGas has announced plans to develop the nation’slargest hydrogen infrastructure system called “Angeles Link.” When operational, theproject 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. 453 454•

In December 2022, Air Products and AES announced plans to build a $4-billion lowGHG hydrogen production facility at the site of a former coal-fired power plant in451

https://www.exeloncorp.com/newsroom/Pages/DOE-Grant-to-Support-Hydrogen-ProductionProject-at-Nine-Mile-Point.aspx.
452
https://www.utilitydive.com/news/bloom-energy-hydrogen-xcel-nuclear-prairieisland/632148/.
453
https://www.socalgas.com/sustainability/hydrogen/angeles-link.
454
Penrod, Emma. (February 18, 2022). SoCalGas begins developing 100% clean hydrogenpipeline system. Utility Dive. https://www.utilitydive.com/news/socalgas-begins-developing-100clean-hydrogen-pipeline-system/619170/.
277
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Texas. 455 456 The plant is expected to be completed in 2027, and once operational, willproduce 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 anannouncement 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. 457•

The DOE National Clean Hydrogen Strategy and Roadmap identified a plausible pathforward 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 NREL Clean Grid 2035 analysis examined several pathways for the power sector toreach net-zero emissions by 2035: each of those pathways included at least 10 MMT ofelectrolytic hydrogen by 2035, demonstrating how electrolytic hydrogen technologies
support rapid grid decarbonization. 458

455

McCoy, Michael. (December 8, 2022). Air Products plans big green hydrogen plant in U.S.
Chemical and Engineering News. https://cen.acs.org/energy/hydrogen-power/Air-Productsplans-big-green/100/web/2022/12.
456
Air Products (December 8, 2022). Air Products and AES Announce Plans to Invest
Approximately $4 Billion to Build First Mega-scale Green Hydrogen Production Facility in
Texas. https://www.airproducts.com/news-center/2022/12/1208-air-products-and-aes-to-investto-build-first-mega-scale-green-hydrogen-facility-in-texas/.
457
Air Products (October 6, 2022). Air Products to Invest About $500 Million to Build Green
Hydrogen Production Facility in New York. https://www.airproducts.com/newscenter/2022/10/1006-air-products-to-build-green-hydrogen-production-facility-in-new-york.
458
Denholm, Paul, Patrick Brown, Wesley Cole, et al. 2022. Examining Supply-Side Options toAchieve 100% Clean Electricity by 2035. Golden, CO: National Renewable Energy Laboratory
NREL/TP[1]6A40-81644. https://www.nrel.gov/docs/fy22osti/81644.pdf.
278This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

•The H2@Scale is a DOE initiative that brings together stakeholders to advanceaffordable hydrogen production, transport, storage, and utilization to enabledecarbonization and revenue opportunities across multiple sectors.
These legislative actions, utility initiatives, and industrial sector production andinfrastructure projects indicate that sufficient low-GHG hydrogen and sufficient distribution
infrastructure can reasonably be expected to be available by 2032, when offtake scales after
2030, 459 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. To the extent low-GHG hydrogen might be less available in rural areas compared toareas with higher population densities, the EPA solicits comment if sufficient electrictransmission capacity is available, or could be constructed, such that electricity generated fromlow-GHG hydrogen could be transmitted to these rural areas.
By 2035, substantial additional amounts of renewable energy are expected to beavailable, which can support the production of low-GHG hydrogen through electrolysis.
(B) Costs
There are three sets of potential costs associated with co-firing hydrogen in combustion
turbines: (1) The capital costs of combustion turbines that have the capability of co-firinghydrogen; (2) pipeline infrastructure to deliver hydrogen; and (3) the fuel costs related to
production of low-GHG hydrogen.

459

DOE Pathways to Commercial Liftoff: Clean Hydrogen, March 2023.
https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB-0329update.pdf.
279This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

As stated previously, manufacturers are already developing combustion turbines that can
co-fire up to 100 percent hydrogen. Accordingly, this limits the amount of additional costs
needed to allow combustion turbines to co-fire 30 percent (by volume) hydrogen and, later, 96
percent (by volume). According to data from EPRI’s US-REGEN model, the heat rate of ahydrogen-fired combustion turbine model plant is 5 percent higher and the capital, fixed, andnon-fuel variable costs are 10 percent higher than a natural gas-fired combustion turbine. 460
However, the EPA is soliciting comment on what additional costs would be required to ensurethat combustion turbines are able to co-fire between 30 to 96 percent (by volume) hydrogen andif there are efficiency impacts from co-firing hydrogen.
With respect to pipeline infrastructure, there are approximately 1,600 miles of dedicatedhydrogen pipelines currently operating in the U.S. Existing natural gas infrastructure may becapable of accepting blends of hydrogen with modest investments, but the actual limits will varydepending on pipeline materials, age, and operating conditions. Due to the lower energy densityof 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.
These risks can be mitigated through deployment of new pipeline infrastructure designed forcompatibility with hydrogen in support of a new combustion turbine installation. The majority ofannounced 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 hydrogen without additional costs. Therefore, the EPA

460

https://us-regen-docs.epri.com/v2021a/assumptions/electricity-generation.html#newgeneration-capacity.
280
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

proposes that co-firing rates of 30 percent and up to 100 percent by volume would have limited,
if any, additional capital costs for new combustion turbine EGU projects. The EPA is soliciting
comment on if additional infrastructure costs, such as bulk hydrogen storage in salt caverns,
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 thecost 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 production at
approximately $5/kg. The DOE has established a goal of reducing the cost of low-GHG
hydrogen production to $1/kg (equivalent to $7.4/MMBtu) by 2030, which is approximately thesame as the current production 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 (by volume)
hydrogen in a combined cycle EGU operating at a capacity factor of 65 percent would increase
both the levelized cost of electricity (LCOE) by $2.9/MWh. 461 This is a 6 percent increase fromthe baseline LCOE. A 96 percent (by volume) co-firing rate increases the LCOE by $21/MWh, a
47 percent increase in the baseline LCOE. Regardless of the level of hydrogen co-firing, the CO2
abatement cost is $64/ton ($70/metric ton) at the affected facility. 462 For an aeroderivative simple
cycle combustion turbine operating at a capacity factor of 40 percent, co-firing 30 percent
hydrogen increases the LCOE by $4.1/MWh, representing a 5 percent increase from the baseline

461

The EIA long-term natural gas price for utilities is $3.69/MMBtu.
The abatement cost of co-firing low-GHG hydrogen is determined by the relative delivered
cost of the low-GHG hydrogen and natural gas.
281

462

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

LCOE. A 96 percent (by volume) co-firing rate increases the LCOE by $30/MWh, a 31 percent
increase in the baseline LCOE.
However, DOE’s projected goal of $1/kg production costs (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 would be$32/ton ($35/metric ton). For a combined cycle EGU, the LCOE increase would be $1.4/MWh
and $11/MWh for the 30 percent and 96 percent (by volume) cases, respectively. For a simple
cycle EGU, the LCOE would be $2.1/MWh and $15/MWh for the 30 percent and 96 percent (byvolume) cases, 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 low-GHG hydrogen is reasonable.
(C) Non-air Quality Health and Environmental Impact and Energy Requirements
The co-firing of hydrogen in combustion turbines in the amounts that the EPA proposes
as the BSER would not have adverse non-air quality health and environmental impacts. It would
result in NOx emissions, but those emissions can be controlled, as described in section
VII.F.3.c.vii.(A) of this preamble.

282
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

In addition, co-firing hydrogen in the amounts proposed would not have adverse impacts
on energy requirements, including either the requirements of the combustion turbines to obtain
fuel or on the energy sector more broadly, particularly with respect to reliability. As discussed in
sections VII.F.3.c.vii.(A)-(B), combustion turbines can be constructed to co-fire high volumes ofhydrogen in lieu of natural gas, and the EPA expects that low-GHG hydrogen will be available insufficient quantities and at reasonable cost. Any impact on the energy sector would be further
mitigated by the large amounts of existing generation that would not be subject to requirementsin this rule and the projected new capacity in the base case modeling.
(D) Extent of Reductions in CO2 Emissions
The site-specific reduction in CO2 emissions achieved by a combustion turbine co-firinghydrogen 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. 463 A source combusting 100
percent hydrogen would have zero CO2 stack emissions because hydrogen contains no carbon, as
previously discussed. A source co-firing 96 percent by volume hydrogen (approximately 89
percent by heat input) would achieve an approximate 90 percent CO2 emission reduction, which
is roughly equivalent to the emission reduction achieved by sources utilizing 90 percent CCS.
(E) Promotion of the Development and Implementation of Technology
Determining co-firing 30 percent (by volume) low-GHG hydrogen by 2032 and co-firing
96 percent (by volume) to be components of the BSER would generally advance technology

463

The energy density by volume of hydrogen is lower than natural gas.
283

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 andfacilitate 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 bealready leaning into based on the project announcements. Thus, co-firing low-GHG hydrogenfulfills the requirements of BSER to generally advance technology development. In addition, cofiring 30 percent (by volume) low-GHG hydrogen by 2032 would promote additional technology
development and infrastructure to facilitate co-firing at higher amounts of low-GHG hydrogen in
2038. As discussed in the preceding section, there are multiple combustion turbine projects
planned by industry to co-fire 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 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 variable generation is deployed.
(F) Basis For Proposing Co-firing Low-GHG Hydrogen, Not Other Types Of Hydrogen, As the“Best” System of Emissions Reduction
In this section, the EPA explains further why the type of hydrogen co-fired as acomponent of the BSER must be limited to low-GHG hydrogen, and not include other types ofhydrogen. 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

284This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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.
(1) 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 lowemitting fuels – sometimes referred to as clean fuels – is a traditional type of emissions control,
and recognized as a system of emission reduction under CAA section 111. In West Virginia v.
EPA, the Supreme Court noted that in the EPA’s prior CAA section 111 actions, the Agency hastreated “measures that improve the pollution performance of individual sources” as “system[s] ofemission reduction,” 142 S. Ct. at 2615, 464 and further 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 toremove sulfur, so that its combustion emits fewer SO2 emissions); 72 FR 32742 (June 13, 2007)(same); 80 FR 64510 (October 23, 2015) (natural gas and clean fuel oil). Co-firing hydrogen in a
combustion turbine in place of natural gas reduces GHG emissions at the source and therefore
plainly qualifies as a “system of emission reduction.” This is true even if that phrase is narrowly

464

As discussed in section V.B.4 of this preamble, the ACE Rule took the position that under
CAA section 111(a)(1), a “system of emission reduction” must be limited to measures that apply
at or to the source. 84 FR 32524 (July 8, 2019).
285

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

defined to be limited to controls measures that can be applied at and to the source and that reduce
emissions from the source, as the ACE Rule provided, or if it is defined more broadly. 465
In the present proposal, the EPA recognizes that even though the combustion of hydrogenis zero-GHG emitting, its production entails a range of GHG emissions, from low to high,depending on the method. As noted in VII.F.3.c.v of this preamble, these 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 theattendant 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 humanhealth and welfare to the extent achievable, CAA section 111(b), through promulgation ofstandards 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 hydrogenat combustion turbines when that hydrogen is produced with large amounts of GHG emissions
would ultimately result in increasing overall GHG emissions, compared to combusting solely

465

Co-firing hydrogen in place of fossil fuel (generally, natural gas in a combustion turbine) may
be contrasted with co-firing biomass in place of fossil fuel (generally, coal in a steam generating
unit). The ACE Rule rejected co-firing biomass as a potential BSER for existing coal-fired steam
generating units. The rule explained that co-firing biomass does not meet the definition of a“system of emission reduction,” under the ACE Rule’s interpretation of that term, because cofiring biomass in place of coal at a steam generating unit does not reduce emissions emitted fromthat source; rather, any emission reductions rely on accounting for activities that occur upstream.
84 FR 32546 (July 8, 2019). In contrast, as discussed in the accompanying text, co-firinghydrogen in place of natural gas at a combustion turbine achieves emission reductions at thesource. For that reason, co-firing hydrogen qualifies as a “system of emission reduction,” even as
the ACE Rule defined the term. As noted in section V.C.3.a of this preamble, the EPA has
proposed to reject that definition as too narrow.
286
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

natural gas at the combustion turbine. To avoid this anomalous outcome, in evaluating a “systemof emission reduction” of co-firing hydrogen, the GHG emissions from producing the hydrogenshould 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). The EPA recognizes that the
production of low-GHG hydrogen also results in fewer emissions of other air pollutants,
although it also requires the use of more water, compared to other methods of producing
hydrogen, in particular, ones involving methane, as discussed in section VII.F.3.c.v of thispreamble. All these factors, considered together, point towards co-firing low-GHG hydrogen,and not other types of hydrogen, as the “best” system of emission reduction.
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 notprovide that the EPA must consider non-air quality health and environmental impacts indetermining the BSER, 466 the court stated that the EPA must consider whether byproducts ofpollution control equipment could cause environmental damage in determining whether thepollution control equipment qualified as the best system of emission reduction. See Portland
Cement Ass’n 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

466

As enacted under the 1970 CAA Amendments, CAA section 111(a)(1) read as follows:
The term "standard of performance" means a standard for emissions of air
pollutants which reflects the degree of emission limitation achievable through theapplication of the best system of emission reduction which (taking into account thecost of achieving such reduction) the Administrator determines has been adequately
demonstrated.
In the 1977 CAA Amendments, Congress revised section 111(a)(1) to incorporate a reference to“non-air quality health and environmental impacts,” and Congress retained that phrase in the1990 CAA Amendments when it revised CAA section 111(a)(1) to read as it currently does.
287This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

imagine that Congress intended that ’best’ could apply to a system which did more damage towater 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 (inthe form of GHG emissions) 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 theaffected facility to lower its emissions—here, hydrogen—is consistent with considering theenvironmental impacts of the byproducts of pollution control technology used by the affectedfacility to lower its emissions.
In addition, the EPA’s proposed determination that co-firing low-GHG hydrogenqualifies as the BSER is supported by the IRA and its legislative history. In the IRA, Congressenacted or expanded tax credits to encourage the production and use of low-GHG hydrogen. 467
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 thatassessment. CAA section 135(a)(5)-(6). The legislative history of this provision makes clear that

467

These tax credits include IRC section 45V (tax credit for production of hydrogen throughlow- or zero-emitting processes), IRC section 48 (tax credit for investment in energy storage
property, including hydrogen production), IRC section 45Q (tax credit for CO2 sequestrationfrom industrial processes, including hydrogen production); and the use of hydrogen intransportation applications, IRC section 45Z (clean fuel production tax credit), IRC section 40B(sustainable aviation fuel credit).
288
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 statethat “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 toregulate 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 theregulation. The Court explained that if the EPA failed to consider cost, it could promulgate aregulation to eliminate power plant emissions harmful to human health but do so through the useof 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 haslong 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 standard of performance here

289
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

would ignore an important aspect of the problem being addressed, contrary to reasoned
decisionmaking.
The proposed standard of performance that is founded upon a BSER of burning hydrogenand the requirement that owners and operators seeking to burn hydrogen use low-GHG hydrogenare distinct requirements that could function independently. It may not be necessary to requirethat only low-GHG hydrogen be used to comply for owners and operators choosing this pathway
included in the BSER in order to be confident that low-GHG hydrogen will be used to meet thestandard. Incentives in the IRA may render production of low-GHG hydrogen less costly thanhigher-GHG hydrogen at some point, thus pushing the hydrogen market toward low-GHG
hydrogen. In addition, the EPA may also initiate a rulemaking to regulate GHG emissions fromhydrogen production under section 111 of the CAA. The EPA solicits comment on whether it isnecessary to define and require low-GHG in this rulemaking. Similarly, the EPA also solicits
comment as to whether the low-GHG hydrogen requirement could be treated as severable fromthe remainder of the standard such that the standard could function without this requirement.
(2) Definition of Low-GHG Hydrogen
As noted in section VII.F.3.c.vi of this preamble, the EPA proposes a definition for lowGHG hydrogen that aligns with the highest of the four tiers of tax credit available for hydrogenproduction, 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 and0.45 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).
290
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 insection 822 of the IIJA is appropriate for the EPA’s regulatory purposes. This definition isdesigned for a non-regulatory purpose. It sets out a non-binding goal, not a standard or aregulatory definition, intended for use in development of the DOE’s CHPS and funding
programs to promote promising new hydrogen technologies.
For the reasons discussed above, co-firing 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 hydrogen co-firing in combustion turbines provides additional 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 using other forms of hydrogen.
4. 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.

291
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

a. 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 toproduce 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 andthermal 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 beparticularly difficult to locate a thermal host with sufficiently large thermal demands such thatthe 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 tosupport a smaller EGU, approximately a maximum of several hundred MW. This would limit thegeographically available locations where new generation could be constructed in addition tolimiting 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 thethermal host for the life of the EGU. If the thermal host were to shut down, the EGU could beunable to comply with the standard of performance. This reality would likely result in difficulty
in securing funding for the construction of the EGU and could also lead the thermal host to
demand discount pricing for the delivered useful thermal output. For these reasons, the EPA is
not proposing CHP as the BSER.

292
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

b. 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 ofhybrid 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 dueto 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 ofthe 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 isrelatively low. In a hybrid power plant, the lower quality steam is heated to higher temperaturesand 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 thecosts of the mirrors, additional piping, and a steam turbine that is 10 to 20 percent larger thanthat 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 partloads and reduced efficiency when no steam is provided from the solar thermal panels (i.e., the293This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

night and cloudy weather). This limits the amount of solar thermal that can be integrated into thesteam cycle at a fossil fuel-fired EGU.
In the 2018 Annual Energy Outlook, 468 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 and67 percent compared to a stand-alone CSP EGU respectively. 469 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 andthe 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, thesecosts 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 standalone solar thermal plant. Similarly, while commenters stated that solar augmentation has beensuccessfully 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.

468

EIA, Annual Energy Outlook 2018, February 6, 2018. https://www.eia.gov/outlooks/aeo/.
B. Alqahtani and D. Patiño-Echeverri, Duke University, Nicholas School of the Environment,“Integrated Solar Combined Cycle Power Plants: Paving the Way for Thermal Solar,” Applied
Energy 169:927–936 (2016).
294
469

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

The EPA is soliciting comment on updated costs for hybrid power plants and if the use of hybrid
power plants could be incorporated as part of the BSER for base load combustion turbines.
In addition, solar thermal facilities require locations with abundant sunshine andsignificant 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 solaraugment 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 effecton 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 thehighest 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 gaps in the EPA’s
knowledge about costs, and concerns about the cost-effectiveness of the technology, as noted
above.

295
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

5. 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 threesubcategories for combustion turbines—natural gas-fired base load EGUs, natural gas-fired nonbase load EGUs, and multi-fuel-fired EGUs. Base load EGUs are those that sell electricity inexcess of the site-specific electric sales threshold to an electric distribution network on both a 12operating-month and 3-year rolling average basis. Non-base load EGUs are those that sellelectricity 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.
a. Legal Basis for Subcategorization
As noted in section V.C.1, CAA section 111(b)(2) provides that the EPA “maydistinguish among classes, types, and sizes within categories of new sources for the purpose of
establishing … standards [of performance].” The D.C. Circuit has held that the EPA has broad
discretion in determining whether and how to subcategorize under CAA section 111(b)(2).
Lignite Energy Council, 198 F3d at 933. 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, fueltype and load.
b. 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
296This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

combustion turbines. A combustion turbine qualifies as a non-base load turbine, and is thus
subject to a less stringent standard of performance, if it has net electric sales equal to or less thanthe design efficiency of the turbine (not to exceed 50 percent) multiplied by the potential electric
output (80 FR 64601; October 23, 2015). If the net electric sales exceed that level on both a 12operating month and 3 calendar year basis, then the combustion turbine is in the base load
combustion subcategory and is subject to a more stringent standard of performance. Subcategory
applicability can change on a month-to-month basis since applicability is determined each
operating month. For additional discussion on this approach, see the 2015 NSPS (80 FR 64609–
12; October 23, 2015). The 2015 NSPS non-base load subcategory is broad and includes
combustion turbines that assure grid reliability by providing electricity during periods of peakelectric 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 notconsidered base load EGUs. These intermediate load EGUs provide a variety of services,
including providing dispatchable power to support variable generation from renewable sourcesof electricity. The need for this service has been expanding as the amount of electricity fromwind and solar continues to grow. In the 2015 NSPS, the EPA determined the BSER for the nonbase load subcategory to be the use of lower emitting fuels (e.g., natural gas and Nos. 1 and 2
fuel oils). In 2015, the EPA explained that efficient generation did not qualify as the BSER due
in part to the challenge of determining an achievable output-based 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
297
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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.
i. Higher Heating Value as the Basis for Calculation of the Design Efficiency
The heat rate is the amount of energy used by an EGU to generate 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 inemissions of CO2 and other air pollutants. The electric energy output as a fraction of the fuelenergy 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 theefficiency 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 theheating 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 thanthe HHV. Consequently, the HHV efficiency for a given EGU is always lower than thecorresponding 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 thecorresponding LHV heating value and varies slightly based on the actual constituent composition
298
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

of the natural gas. 470 The EPA default is to reference all technologies on a HHV basis, 471 and the
Agency is proposing to base the heat input calculation of an EGU on HHV for purposes of thedefinition of design efficiency. However, it should be recognized that manufacturers of
combustion turbines typically use the LHV to express the efficiency of combustion turbines. 472
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 tooperate 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 interms of net output, which reflects the EGU gross output minus its parasitic load. 473
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

470

The HHV of natural gas is 1.108 times the LHV of natural gas. Therefore, the HHV
efficiency is equal to the LHV efficiency divided by 1.108. For example, an EGU with a LHV
efficiency of 59.4 percent is equal to a HHV efficiency of 53.6 percent. The HHV/LHV ratio isdependent on the composition of the natural gas (i.e., the percentage of each chemical species(e.g., methane, ethane, propane, etc.)) within the pipeline and will slightly move the ratio.
471
Natural gas is also sold on a HHV basis.
472
European plants tend to report thermal efficiency based on the LHV of the fuel rather than the
HHV for both combustion turbines and steam generating EGUs. In the U.S., boiler efficiency is
typically reported on a HHV basis.
473
It is important to note that net output values reflect the net output delivered to the electric gridand not the net output delivered to the end user. Electricity is lost as it is transmitted from thepoint of generation to the end user and these “line loses” increase the farther the power istransmitted. 40 CFR part 60, subpart TTTT provides a way to account for the environmental
benefit of reduced line losses by crediting CHP EGUs, which are typically located close to large
electric load centers. See 40 CFR 60.5540(a)(5)(i) and the definitions of gross energy output andnet energy output in 40 CFR 60.5580.
299
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

that all efficiencies are calculated using the same type of heating value (i.e., HHV or LHV) andthe 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 ongross output. However, to recognize the superior environmental benefit of minimizing
auxiliary/parasitic loads, the Agency is proposing to include optional equivalent standards on a
net output basis. To convert from gross to net-output based standards, the EPA used a 1 percent
auxiliary load for simple cycle turbines, a 2 percent auxiliary load for combined cycle turbines,
and a 7 percent auxiliary load for combined cycle EGUs using 90 percent CCS.
ii. Lowering the Threshold Between the Base Load and Non-Base Load Subcategories
The subpart TTTT distinction between a base load and non-base load combustion turbine
is determined by the unit’s actual electric sales relative to its potential electric sales, assuming
the EGU is operated continuously (i.e., percent electric sales). Specifically, stationary
combustion turbines are categorized as non-base load and are subsequently subject to a lessstringent 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 efficiencyof the EGU, more efficient combustion turbine EGUs can sell a higher percentage of theirpotential electric output while remaining in the non-base load subcategory. This approach
recognizes both the environmental benefit of combustion turbines with higher design efficiencies
and provides flexibility to the regulated community. In the 2015 NSPS, it was unclear how often
high-efficiency simple cycle EGUs would be called upon to support increased generation fromvariable renewable generating resources. Therefore, the Agency determined it was appropriate toprovide maximum flexibility to the regulated community. To do this, the Agency based the300
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 shareof 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 be based on the HHV efficiency instead of LHV efficiency and that the
50 percent maximum and 33 percent minimum restriction not be included. When determining thepotential electric output used in calculating the electric sales threshold in 40 CFR part 60, subpart
TTTT, design efficiencies of greater than 50 percent are reduced to 50 percent and design
efficiencies of less than 33 percent are increased to 33 percent for determining electric sales
threshold subcategorization criteria. The 50 percent criterion was established to limit non-baseload EGUs from selling greater than 55 percent of their potential electric sales. 474 The 33 percent
criterion is included to be consistent with applicability thresholds in the electric utility criteria
pollutant NSPS (40 CFR part 60, subpart Da). Neither of those criteria are appropriate for 40
CFR part 60, subpart TTTTa, and the EPA is not proposing that they be used to determine theelectric sales threshold. By basing the electric sales threshold on the HHV design efficiency, the50 percent restriction is no longer appropriate because currently available combined cycle
designs operating as intermediate load combustion turbines would be limited to selling 55
percent of their potential electric output. If this restriction were maintained, it would reduce theregulatory incentive for manufacturers to invest in programs to develop higher efficiency
combustion turbines. The EPA is also proposing to eliminate the 33 percent minimum design474

While the design efficiency is capped at 50 percent on a LHV basis, the base load rating(maximum heat input of the combustion turbine) is on a HHV basis. This mixture of LHV andHHV results in the electric sales threshold being 11 percent higher than the design efficiency.
The design efficiency of all new combined cycle EGUs exceed 50 percent on a LHV basis.
301

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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-baseload 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 thebase load electric sales threshold for combined cycle EGUs between 46 and 55 percent. 475 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 HHVwill have the effect of decreasing the electric sales threshold in relative terms by 19 percent andabsolute terms by 7 to 9 percent. 476 The EPA is soliciting comment on whether theintermediate/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). This475

The electric sales threshold for combined cycle EGUs with the highest design efficiencies
would remain at 55 percent.
476
The design efficiency appears twice in the equation used to determine the electric sales
threshold. Amending the design efficiency to use the HHV numeric value results in a larger
reduction in the electric sales threshold than the difference between the HHV and LHV design
efficiency.
302
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 theargument 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 thatcan 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 resultin 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 thedesign 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 ofelectricity (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
303
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

threshold of 40 percent for simple cycle turbines because it would be cost effective forowners/operators of simple cycle turbines to add heat recovery if they elected to operate theirunit 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 12operating-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 thestringency of the numeric standard. However, at 12-operating-month capacity factors of less thanapproximately 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 togenerate steam that can be used for additional electrical generation. To maximize overall
efficiency, combined cycle EGUs often use combustion turbine engines that are less efficientthan 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 perstart 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 Efficient Generation at

304
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Combustion Turbine Electric Generating Units TSD, which is available in the rulemaking
docket.
After the 2015 NSPS was finalized, some stakeholders expressed concerns about theapproach for distinguishing between base load and non-base load turbines. They posited ascenario in which increased utilization of wind and solar resources, combined with low natural
gas prices, would create the need for certain types of simple cycle turbines to operate for longer
time periods than had been contemplated when the 2015 NSPS was being developed.
Specifically, stakeholders have claimed that in some regional electricity markets with large
amounts of variable renewable generation, some of the most efficient new simple cycle
turbines—aeroderivative turbines—could be called on to operate at capacity factors greater thantheir design efficiency. However, if those new simple cycle turbines were to operate at thosehigher 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 existingturbines 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 thecountry with relatively large amounts of variable renewable generation and did not find a strong
correlation between the percentage of generation from the renewable sources and the 12operating-month capacity factors of simple cycle turbines. In addition, the vast majority ofsimple 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, theAgency does not believe that the concerns expressed by stakeholders necessitates any revisions
305
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 variable generation. The EPA believes that the
proposed threshold is not overly restrictive since a simple cycle turbine could operate on averagefor more than 8 hours a day.
iii. 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 electricdemand (i.e., peaking units) which would be separate from the intermediate load subcategory.
Low load combustion turbines also provide ramping capability and other ancillary serves tosupport grid reliability. The EPA evaluated the operation of recently constructed simple cycle
turbines to understand how they operate and to determine at what electric sales level or capacity
factor their emissions rate is relatively steady. (Note that for purposes of this discussion, we use
the terms “electric sales” and “capacity factor” interchangeably.) Peaking units only operate forshort periods of time and potentially at relatively low duty cycles. 477 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 areasonable output-based standard of performance for peaking units.
To determine the electric sales threshold—that is, to distinguish between the intermediateload and low load subcategories—the EPA evaluated capacity factor electric sales thresholds of477

The duty cycle is the average operating capacity factor. For example, if an EGU operates at
75 percent of the fully rated capacity, the duty cycle would be 75 percent regardless of how often
the EGU actually operates. The capacity factor is a measure of how much an EGU is operated
relative to how much it could potentially have been operated.
306

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

10 percent, 15 percent, 20 percent, and 25 percent. The EPA found the 10 percent levelproblematic for two reasons. First, simple cycle combustion turbines operating at that level orlower have highly variable emission rates, and therefore it would be difficult for the EPA toestablish a meaningful output-based standard of performance. In addition, only one-third of
simple cycle turbines that have commenced operation since 2015 have maintained 12-operatingmonth 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 standard of
performance 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 for many simple cycle combustion turbines begin tostabilize, see the Simple Cycle Stationary Combustion Turbine EGUs TSD, 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 steadystate operation. Approximately 60 percent of recently constructed simple cycle turbines havemaintained 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, theemission rates clearly stabilize for the majority of 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
307
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 andis soliciting comment on a range of 15 to 25 percent. The EPA is also soliciting comment onwhether the low load electric sales threshold should be determined by a site-specific thresholdbased on three quarters of the design efficiency of the combustion turbine. 478 Under thisapproach, 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 theapproach the EPA used in the 2015 NSPS to recognize the environmental benefit of installing themost 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 bequantified 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,478

The calculation used to determine the electric sales threshold includes both the design
efficiency and the base load rating. Since the base load rating stays the same when adjusting thenumeric value of the design efficiency for applicability purposes, adjustments to the design
efficiency has twice the impact. Specifically, using three quarters of the design efficiency
reduces the electric sales threshold by half.
308This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

owners/operators of combined cycle EGUs would be required to comply with the standards ofperformance for intermediate or peaking EGUs.
c. 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 12operating-month rolling average basis. The BSER for this subcategory is the use of lower
emitting fuels with a corresponding heat input-based standard of performance of 120 to 160 lb
CO2/MMBtu, depending on the fuel, for newly constructed and reconstructed multi-fuel-fired
stationary combustion turbines. 479 Lower emitting fuels for these units include natural gas,ethylene, propane, naphtha, jet fuel kerosene, Nos. 1 and 2 fuel oils, biodiesel, and landfill gas.
The definition of natural gas in 40 CFR part 60, subpart TTTT includes fuel that maintains agaseous 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, m3)(950 and 1,100 British thermal units (Btu) per dry standard cubic foot). Natural gas typicallycontains 95 percent methane and has a heating value of 1,050 Btu/lb. 480 A potential issue withthe 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 thatsubcategory, regardless of their electric sales. As a result, they would remain subject to the less479

Combustion turbines co-firing natural gas with other fuels must determine fuel-based sitespecific standards at the end of each operating month. The site-specific standards depend on theamount of co-fired natural gas. 80 FR 64616 (October 23, 2015).
480
Note that 40 CFR part 60, subpart TTTT combustion turbines co-firing 25 percent hydrogenby volume could be subcategorized as multi-fuel-fired EGUs because the percent methane byvolume could fall below 70 percent, the heating value could fall below 35 MJ/Sm3, and 10
percent of the heat input could be coming from a fuel not meeting the definition of natural gas.
309
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

stringent standard that applies to multi-fuel-fired sources, the lower emitting fuels standard. This
could allow less efficient combustion turbine designs to operate as base load units without
having to improve efficiency and could allow EGUs to avoid the need for efficient design or best
operating and maintenance practices. These potential circumventions would result in higher
GHG emissions.
To avoid these 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 ofelectric 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 thesubcategories to turbines burning fuels with higher GHG emission rates than natural gas. To beconsistent with the definition of lower emitting fuels in the 2015 Rule, the maximum allowable
heat input-based emissions rate would be 160 lb CO2/MMBtu. For example, a standard of
performance based on efficient generation would be 33 percent higher for a fuel oil-fired
combustion turbine compared to a natural gas-fired combustion turbine. This would assure thatthe BSER, in this case efficient generation, is applied, while at the same time accounting for theuse 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 2 summarizes the proposed electricsales subcategories for combustion turbines.
Table 2—Proposed Sales Thresholds for Subcategories of Combustion Turbine EGUs
310
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Subcategory
Low LoadIntermediate
Load
Base Load

Electric Sales Threshold(Percent of potential electric sales)≤ 20 percent> 20 percent and ≤ site-specific value determined based on the design efficiencyof the affected facility• Between ~ 33 to 40 percent for simple cycle combustion turbines• Between ~ 45 to 55 percent for combined cycle combustion turbines> Site-specific value determined based on the design efficiency of the affectedfacility• Between ~ 33 to 40 percent for simple cycle combustion turbines• Between ~ 45 to 55 percent for combined cycle combustion turbines

G. 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 thatreflect 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 fromcombustion turbines is advancing rapidly, a multi-phase set of standards of performance, whichreflect a multi-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 theeffective date the final rule, the BSER is highly efficient generation for both base load andintermediate load combustion turbines. During this phase, owners/operators of EGUs will be
subject to a numeric standard of performance that is representative of the performance of the best
performing EGUs in the subcategory. For the second phase of the standards, beginning in 2032
and 2035 respectively, the BSER for base load turbines includes either 30 percent low-GHG
hydrogen co-firing or 90 percent capture CCS, and beginning in 2032 the BSER for intermediateload 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
311
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

coupled with CCS, or one that reflects continued use of highly efficient generation coupled withco-firing low-GHG hydrogen. For the third phase of the standards, beginning in 2038 for baseload turbines that began co-firing 30 percent low-GHG hydrogen in 2032, the BSER includes cofiring 96 percent low-GHG hydrogen. In addition, the EPA is proposing a single component
BSER, applicable from the date of proposal, for low load combustion turbines.
1. Phase-1 Standards
The first component of the BSER is the use of highly efficient combined cycle
technology for base load EGUs in combination with the best operating and maintenancepractices, the use of highly efficient simple cycle technology in combination with the best
operating and maintenance practices for intermediate load EGUs, and the use of lower emitting
fuels for low load EGUs.
For new and reconstructed natural gas-fired base load combustion turbine EGUs, theEPA 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 greaterthan 2,000 MMBtu/h) and 900 lb CO2/MWh-gross for natural gas-fired small EGUs (i.e., thosewith a nameplate base load rating of 250 MMBtu/h). The proposed standard of performance fornatural 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

312This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

base load rating of the combustion turbine. 481 The EPA proposes to find that the most efficientavailable 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 thatthe use of lower emitting 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 12operating-month rolling average basis.
The EPA has determined that these standards of performance are achievable specificallyfor 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 andintermediate 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 thespecific fuel(s) burned to the heat input-based emissions rate of natural gas to determine a sitespecific standard of performance for the operating period. For example, the NSPS emissions rate

481

A new small natural gas-fired base load EGU would determine the facility emissions rate bytaking the difference in the base load rating and 250 MMBtu/h, multiplying that number by
0.0743 lb CO2/(MW * MMBtu), and subtracting that number from 900 lb CO2/MWh-gross. The
emissions rate for a NGCC EGU with a base load rating of 1,000 MMBtu/h is 900 lb CO2/MWhgross minus 750 MMBtu/h (1,000 MMBtu/h–250 MMBtu/h) times 0.0743 lb CO2/(MW *MMBtu), which results in an emissions rate of 844 lb CO2/MWh-gross.
313
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

for a large base load combustion turbine burning 100 percent distillate oil during the 12operaitng month period would be 1,070 lb CO2/MWh-gross. 482
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’semissions 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 andsimple cycle EGU fleets. Since an NSPS is a never-to-exceed standard, the EPA is proposingthat 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 theunits are properly maintained. While annual emission rates indicate a particular standard isachievable 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 byapplication of the BSER, the EPA calculated 12-month CO2 emission rates by dividing the sumof the CO2 emissions by the sum of the gross electrical energy output over the same period. The

482

The heat input-based emission rates of natural gas and distillate oil are 117 and 163 lb
CO2/MMBtu, respectively. The ratio of the heat input-based emission rates (1.39) is multipliedby the natural gas-fired standard of performance (770 lb CO2/MWh) to get the applicableemissions rate (1,070 lb CO2/MWh).
314
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

EPA did this separately for combined cycle EGUs and simple cycle EGUs to determine theemissions 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 bya 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 todetermine 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 thatboth the combustion turbine and steam turbine are arranged on one shaft and drive the samegenerator. This configuration has potential capital cost and maintenance costs savings and asmaller plant footprint that can be particularly important for combustion turbines enclosed in abuilding. In addition, a single shaft configuration has higher net efficiencies when operated atpart load than a multi-shaft configuration. Basing the standard of performance on theperformance of multi-shaft combined cycle EGUs could limit the ability of owners/operators toconstruct new combined cycle EGUs in space-constrained areas (typically urban areas 483) and483

Generating electricity closer to electricity demand can reduce stress on the electric grid,
reducing line losses and freeing up transmission capacity to support additional generation fromvariable renewable sources. Further, combined cycle EGUs located in urban areas could bedesigned as CHP EGUs, which have potential environmental and economic benefits.
315

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

combined cycle EGUs with the best performance when operated as intermediate load EGUs. 484
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 beinstalled initially and run as a simple cycle EGU, with the HRSG and steam turbines added at alater date, all of which allows for more flexibility for the regulated community. In addition, asingle 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. 485
The efficiency of the Rankine cycle (i.e., HRSG plus the steam turbine) is determined inpart by the ability to cool the working fluid (e.g., steam) after it has been expanded through theturbine. 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 waterrequirements and therefore could be the preferred technology in arid regions or in areas wherewater requirements could have significant ecological impacts. Therefore, the EPA proposes thatthe efficient generation standard for base load EGUs should account for the use of dry cooling.

484

Power sector modeling projects that combined cycle EGUs will operate at lower capacity
factors in the future. Combined cycle EGUs with lower base load efficiencies, but higher part
load efficiencies could have lower overall emission rates.
485
According to the data in Gas Turbine World 2021, while there is a design efficiency
advantage of going from a 1-on-1 configuration to a 2-on-1 configuration (assuming the same
turbine engine) there is no efficiency advantage of 3-on-1 configurations compared to 2-on-1
configurations.
316
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 notproposing 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 standard of performance for base load combustion turbines.
An emissions rate of 770 lb CO2/MWh-gross has been demonstrated by 14 percent ofrecently 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 longterm 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. 486 This 2-on-1 combined cycle facility,
uses a recirculating cooling tower, and has maintained an emissions rate of 765 lb CO2/MWhgross, 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 isachievable 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, the486

The Dresden Energy Facility is listed as being located in Muskingum county, Ohio, as being
owned by the Appalachian Power Company, as having commenced commercial operation in late
2011. The facility ID (ORISPL) is 55350 1A and 1B.
317

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

EPA proposes that while the Dresden combined cycle EGUs uses a 2-on-1 configuration with acooling 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 Efficient Generation at
Combustion Turbine Electric Generating Units TSD, 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 byallowing more available designs to operate as base load combustion turbines.
With respect to small combined cycle combustion turbines, the best performing unit is theHolland Energy Park facility in Holland, Michigan, which commenced operation in 2017 anduses a 2-on-1 configuration and a cooling tower. 487 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/MWhgross. This long-term data accounts for degradation and variable operating conditions anddemonstrates that a base load combustion turbine EGU with a turbine rated at 250 MMBtu/h487

The Holland Park Energy Center is a CHP system that uses hot water in the cooling system
for a snow melt system that uses a warm water piping system to heat the downtown sidewalks toclear the snow during the winter. Since this useful thermal output is low temperature, it does notmaterially reduce the electrical efficiency of the EGU. If the useful thermal output were
accounted for, the emissions rate of the Holland Energy Park would be lower. The facility ID(ORISPL) is 59093 10 and 11.
318

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

should be able to maintain an emissions rate of 900 lb CO2/MWh-gross. 488 In addition, there is acommercially 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. 489 When these efficiency improvements areaccounted for, a new small natural gas-fired combined cycle EGU would be able to maintain anemissions rate of 850 lb CO2/MWh-gross. Therefore, the Agency is soliciting comment onwhether the small natural gas-fired base load combustion turbine standard of performance shouldbe 850 lb CO2/MWh-gross.
In summary, the Agency solicits comment on the following range of potential standardsof 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 ofrecently constructed high efficiency natural gas-fired simple cycle EGUs. The EPA evaluatedthree emission rates for the intermediate load standard of performance: 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 have488

To estimate an achievable emissions rate for an efficient combined cycle EGU at 250
MMBtu/h the EPA assumed a linear relationship for combined cycle efficiency with turbine
engines with base load ratings of less than 2,000 MMBtu/h.
489
If the combustion turbine engine exhaust temperature is 500oC or greater, a HRSG using 3
pressure steam without a reheat cycle could potentially provide an even greater increase inefficiency (relative to a HRSG using 2 pressure steam without a reheat cycle).
319
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

maintained an emissions rate of 1,150 lb CO2/MWh-gross, and 6 percent have maintained anemissions rate of 1,100 lb CO2/MWh-gross. However, the units that have maintained anemissions 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 anintermediate load standard of performance 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 intermediateload simple cycle EGUs, see the Efficient Generation at Combustion Turbine Electric
Generating Units TSD, which is available in the rulemaking docket
The EPA is also soliciting comment on whether the use of steam injection is applicable tointermediate 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. 490 Advantages of steam injection include improved490

A steam injected combustion turbine would be considered a combined cycle combustion
turbine (for NSPS purposes) because energy from the turbine engine exhaust is recovered in a
HRSG and that energy is used to generate additional electricity.
320

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 andcombined cycle combustion turbines. They are more efficient, but more complex and havehigher 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 thistechnology would be applicable to intermediate load combustion turbines and could be part ofeither the first or second component of the BSER along with cost information. 491
2. 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, theseapproaches 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
Low loadIntermediate load

Base load adopting the CCS
pathway

BSER
Lower emitting fuels
Highly efficient simple cycle
technology coupled with cofiring 30 percent (by volume)
low-GHG hydrogen
Highly efficient combined
cycle technology coupledwith 90 percent CCS

Standard of Performance
120–160 lb CO2/MMBtu
1,000 lb CO2/MWh-gross

90 lb CO2/MWh-gross491

The second component of the BSER, 30 percent low-GHG hydrogen co-firing, would reduce
the emissions rate to 880 lb CO2/MWh-gross.
321
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Base load adopting the lowGHG hydrogen co-firing
pathway

Highly efficient combined
cycle technology coupledwith co-firing 30 percent (byvolume) 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 baseload units adopting the low-GHG hydrogen co-firing pathway subcategories, to determine thephase-1 standards. For the base load combustion turbines adopting the CCS subcategory, theEPA reduced the emissions rate by 89 percent to determine the CCS based phase-2 standards. 492
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. As noted in
section VII.F.3.b.iii(A)(2) of this preamble, 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 isusually less than 100 percent. Assuming that CO2 capture achieves 90 percent capture whenavailable to operate, that CCS is available to operate 90 percent of the time the combustion
turbine is operating, and that the combustion turbine operates the same whether or not CCS isavailable 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 availability492

The 89 percent reduction from CCS accounts for the increased auxiliary load of a 90 percent
post combustion amine-based capture system. Due to rounding, the proposed numeric standardsof performance do not necessarily match the standards that would be determined by applying thepercent reduction to the phase 1 standards.
322This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

relative to operation of the combustion turbine. If the combustion turbine were not permitted tooperate when CCS was unavailable, there may be local reliability consequences or issues during
startup or shutdown, and the EPA is soliciting comment on how to balance these issues.
Additionally, the EPA is soliciting comment on the range of reduction in emission rate of 75 to
90 percent.
The standards of performance for the intermediate and base load combustion turbines
would also be adjusted based on the uncontrolled emission rates of the fuels relative to naturalgas. 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.
3. Phase-3 Standards
The third component of the BSER is applicable to owner/operators of base load
combustion turbines that elect to implement early GHG reductions (i.e., comply with anemissions rate of 680 lb CO2/MWh-gross starting in January 2032). The phase 3 BSER standardof performance increases the GHG reduction requirements and is based on co-firing 96 percent
by volume low-GHG hydrogen in addition to the use of highly efficient combined cycle
technology in combination with the best operating and maintenance practices. The proposed
phase-3 standards are in table 4.
Table 4—Phase-3 Standards of Performance
Subcategory
Base load electing to
implement early GHG
reductions

BSER
Highly efficient combined
cycle technology coupledwith co-firing 89 percent (byStandard of Performance
90 lb CO2/MWh-gross323
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

heat input) low-GHG
hydrogenCo-firing 89 percent by heat input (96 percent by volume) low-GHG hydrogen reduces
GHG emissions by 89 percent. The EPA applied this percent reduction to the emission rates forbase load under phase 1 of the BSER. Similar to the phase 1 and 2 standards of performance, thenumeric standard would be adjusted based on the uncontrolled emission rates of the fuels relative
to natural gas. For 100 percent distillate oil-fired combustion turbines, the emission rates would
be 120 lb CO2/MWh-gross.
As a variation on proposing the date for meeting this standard as 2038, the EPA solicits
comment on proposing the date as 2035, coupled with authorizing an approach for crediting
early reductions, under which a source that achieves reductions due to co-firing low-GHG
hydrogen starting in 2032 may apply credit for those reductions to its emission rate beginning in
2035. Another, more stringent, variation of this approach would be to allow credit only for
reductions below the emission rate otherwise required by 2032. Other variations would allow
sources to generate credits from reductions from co-firing low-GHG hydrogen, or from any otherreductions below their standard of performance, in any year before 2035. In this manner, thesource would be authorized to comply with its 2035 standard in part through use of credits
generated by making reductions beginning in 2032. Under such an approach, early credits could
only be used by the unit that generated those credits. For instance, a unit co-firing 30 percent
low-GHG hydrogen prior to 2035 would be able to generate credits that it could use in 2035 andbeyond. This would allow a unit co-firing low-GHG hydrogen to ramp up the amount it co-fired
over time, while still achieving the same amount of emission reductions that would have beenachieved had the unit co-fired enough low-GHG hydrogen (e.g., 96 percent by volume) starting
324
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

in 2035. Another variation on this approach would be to treat such a crediting scheme as acompliance alternative to the CCS BSER by showing equivalent emission reductions, rather than
the standard itself.
The EPA proposes the following mechanism to ensure that affected sources in the baseload subcategory comply with the applicable standard of performance in the event that the EPA
finalizes both the CCS pathway (that is, the use of 90-percent-capture CCS by 2035) and the
low-GHG hydrogen pathway (that is, co-firing 30 percent low-GHG hydrogen by 2032 and 96
percent by 2038). The EPA proposes that affected sources must notify the EPA by January 1,
2031, which pathway they are selecting, and thus which standard they intend to comply with. Ifthey select the low-GHG hydrogen pathway, they must comply with the applicable standard
based on co-firing 30 percent hydrogen (by volume) in 2032 through 2037. In addition, in 2033
through 2037, they must be prepared to demonstrate that they complied with the applicablestandard based on co-firing 30 percent low-GHG hydrogen in the preceding years, beginning in
2032. In 2038, they must comply with the applicable standard based on co-firing 96 percent (byvolume) now-GHG hydrogen.
H. 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 reconstructedstationary combustion turbines, the Agency is proposing to use the same emissions analysis forboth 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
325
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

reconstructed turbines could likely incorporate technologies to co-fire hydrogen as part of thereconstruction 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 thecost 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. 493 Using a 12-year
amortization period, a 90 percent-capture amine-based post combustion CCS system increases
the LCOE by $8.5/MWh and has overall CO2 abatement costs of $25/ton ($28/metric ton).
A reconstructed stationary combustion turbine is not required to meet the standards if
doing so is deemed to be “technologically and economically” infeasible. 494 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 theidentified BSER, as well as technologies the EPA considered, but rejected, as BSER for anationwide 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, insome cases, equipment upgrades, and best operating practices would result in sufficient
reductions to achieve the reconstructed standards.

493

The kW value used as reference for the costs is the output from the combined cycle EGU
prior to the installation of the CCS.
494
40 CFR 60.15(b)(2).
326This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

I. Modified Stationary Combustion Turbines
CAA section 111(a)(4) defines a “modification” as “any physical change in, or change inthe 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 amodification. 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 several reasons for this determination: few sources had
undertaken NSPS modifications in the past, the EPA had little information concerning them, andavailable information indicated that few owners/operators of existing combustion turbines would
undertake NSPS modifications in the future; and since the Agency eliminated proposedsubcategories 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 performancestandard of 1,000 lb CO2/MWh-gross.
It continues to be the case that the EPA is aware of no evidence indicating thatowners/operators of combustion turbines intend to undertake actions that could qualify as NSPS
modifications in the future. EPA is not proposing, or soliciting comment on whether it should
propose, standards of performance for modifications of combustion turbines.
J. 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
327
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 notcontain 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 thatall 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 andshutdown 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 standards of performance
328
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

used CEMS data that includes all period of operation. Since periods of startup, shutdown, andmalfunction 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 ofemissions 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 performancereflect the degree of emission limitation achievable through “the application of the best system of
emission reduction” that the EPA determines is adequately demonstrated. While the EPA
accounts for variability in setting standards of performance, nothing in CAA section 111 requires
the Agency to consider malfunctions as part of that analysis. The EPA is not required to treat amalfunction 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 orusual 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 theanalogous 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).

329
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

K. Testing and Monitoring Requirements
Because the NSPS reflects the application of the best system of emission reduction underconditions 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.
1. 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 495 for EGUs firing uniform oil or gas or nonuniform 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 CFRpart 98, subpart C).
The EPA believes continuing the use of these familiar approaches already in use by otherprograms represents a cost-effective means of obtaining quality assured data requisite fordetermining carbon dioxide mass emissions. Therefore, no changes to the current ways ofcollecting carbon dioxide and associated data needed for mass determination, such as flow rates,

495

An F factor is the ratio of the gas volume of the products of combustion to the heat content of
the fuel.
330

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

fuel heat content, fuel carbon content, and the like, are proposed. Because no changes areproposed and because the cost and burden for EGU owners or operators are already accounted
for by other rulemakings, this aspect of the proposed rule is designed to have 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.
However, 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 gasfired or non-uniform fuel-fired calculation-based approaches for compliance. By way ofreference, the annualized cost associated with adoption and use of continuous carbon dioxide andflow measurements where none now exist is estimated to be about $52,000. To the extent that therule were to mandate continuous carbon dioxide and flow measurements in accordance withwhat is currently allowed as one option and that an EGU lacked this instrumentation, its owneror operator would need to incur this annual cost to obtain such information and to keep the
instrumentation calibrated.
2. Requirements for Sources Implementing CCS
The CCS process is also subject to monitoring and reporting requirements under the
EPA’s GHGRP (40 CFR part 98). The GHGRP requires reporting of facility-level GHG data andother 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 forcommercial applications or that capture and maintain custody of a CO2 stream in order to331
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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. 496 497
498

The current rule leverages the regulatory requirements under GHGRP subpart RR anddoes 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 thecaptured CO2 underground must report under GHGRP subpart RR or proposed GHGRP subpart
VV. If the emitting EGU sends the captured CO2 offsite, it must assure that the CO2 is managed
at a facility subject to the GHGRP requirements, and the facility injecting the CO2 undergroundmust report under GHGRP subpart RR or proposed GHGRP subpart VV. This proposal does not

496

87 FR 36920 (June 21, 2022).
International Standards Organization (ISO) standard designated as CSA Group (CSA) /American National Standards Institute (ANSI) ISO 27916:2019, Carbon Dioxide Capture,
Transportation and Geological Storage—Carbon Dioxide Storage Using Enhanced Oil Recovery(CO2-EOR) (referred to as “CSA/ANSI ISO 27916:2019”).
498
As described in 87 FR 36920 (June 21, 2022), both subpart RR and proposed subpart VV(CSA/ANSI ISO 27916:2019) require an assessment and monitoring of potential leakage
pathways; quantification of inputs, losses, and storage through a mass balance approach; anddocumentation of steps and approaches used to establish these quantities. Primary differences
relate to the terms in their respective mass balance equations, how each defines leakage, andwhen facilities may discontinue reporting.
332
497This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 thetons of CO2 captured by the emitting EGU. The tons of CO2 sequestered by the geologic
sequestration site are not part of that calculation, though the EPA anticipates that the quantity of
CO2 sequestered will be substantially similar to the quantity captured. However, to verify that theCO2 captured at the emitting EGU is sent to a geologic sequestration site, we are leveraging
regulatory reporting requirements under the GHGRP. The BSER is determined to be adequately
demonstrated based solely on geologic sequestration that is not associated with EOR. However,
EGUs also have the compliance option to send CO2 to EOR facilities that report under GHGRP
subpart RR or proposed 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. This will avoid duplicative monitoring, reporting, and verification requirements
between this proposal and the GHGRP, while also ensuring that the facility injecting andsequestering the CO2 (which may not necessarily be the EGU) maintains responsibility for theserequirements. Similarly, the existing regulatory requirements applicable to geologic
sequestration are not part of the proposed rule.
3. 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
333
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

whole or in part, the eligibility, monitoring, verification, and reporting protocols associated with
IRC section 45V(b)(2)(D) when finalized by Treasury for the production of low-GHG hydrogen,and apply those protocols, as applicable, to requirements the EPA establishes for thedemonstration by EGUs that they are using low-GHG hydrogen. 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 withoverall 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 andcertainty 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 thisrulemaking. The EPA is taking comment on what forms of acceptable mechanisms anddocumentary 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, andenergy 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 their sources of low-GHG hydrogen and the corresponding
quantities procured. The EPA is also seeking comment on requiring that EGUs using low-GHG
hydrogen demonstrate that their hydrogen is exclusively from facilities that only produce lowGHG hydrogen, as a means of reducing demonstration burden and opportunities for double
counting that could otherwise occur for hydrogen purchased from facilities that produce multiple
types of hydrogen and the complex recordkeeping and documentation that would be necessary to334This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

reliably verify that the hydrogen purchased from such facilities qualifies. The EPA solicits
comment on a mechanism to operationalize such a provision.
Treasury is currently developing implementing rules for IRC section 45V. Congress
specified that tax credit eligibility for the credit tiers (45V(b)(2)(A), 45(V)(b)(2)(B), 45(b)(2)(C),and 45V(b)(2)(D)) should be based on an assessment of the estimated well-to-gate 499 GHG
emissions of hydrogen production, determined based on the most recent Greenhouse gases,
Regulated Emissions, and Energy use in Transportation model (GREET model) or a successor
model as determined by the Secretary of Treasury. Consistent with its proposal to define lowGHG hydrogen consistent with IRC section 45V(b)(2)(D), the EPA is also proposing that, for the
purpose of demonstrating compliance with the requirement to combust low-GHG hydrogen
under this NSPS, the maximum extent possible the same methodology specified in IRC section
45V and requirements currently under development should apply. 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 ofincluding technological advances. The EPA solicits comment on whether the Agency should
consider unrelated or third-party verification as part of the standards required for EGUs to499

Well-to-gate analysis of lifecycle GHG emissions represents a smaller scope than cradle-tograve analysis. Well-to-gate emissions of hydrogen production include those associated withfossil fuel or electricity feedstock production and delivery to the hydrogen facility; the hydrogenproduction process itself; and any associated CCS applied at the hydrogen production facility.
Well-to-gate analysis does not consider emissions associated with the manufacture or end-of-lifeof the hydrogen production facility or facilities providing feedstock inputs to the hydrogenproduction facility. Nor does it consider emissions associated with transportation, distribution,and use of hydrogen beyond the production facility.
335
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

demonstrate 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 on
application of Treasury’s framework for IRC section 45V to this particular context. The EPA
requests comment on its proposal to adopt as much as possible the methodology specified in IRC
section 45V and any associated implementing requirements established by Treasury, once themethodology and implementing requirements are finalized, as part of the obligations for EGUs todemonstrate compliance with the requirement to combust low-GHG hydrogen under this NSPS.
Although proposing to incorporate as much as possible Treasury’s eligibility, monitoring,
reporting, and verification protocols, the EPA recognizes that Treasury protocols concern
hydrogen production, whereas the EPA’s proposed requirements apply to affected EGUs that use
the hydrogen to demonstrate compliance with the low-GHG hydrogen co-firing obligations. The
EPA is also taking comment on several underlying policy issues relevant to ensuring thathydrogen used to comply with this rule is low-GHG hydrogen. One reason that the EPA is
considering whether an alternative method to the Treasury guidance may be needed to determine
whether hydrogen meets the requirements to be considered low-GHG is because hydrogenproduction facilities that begin construction after 2032 will not be eligible for the tax credits. The
EPA wants to make sure a pathway exists for low-GHG hydrogen to be used for compliancepurposes even if the producer began construction after 2032 and is not receiving tax credits.
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 withthe 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 for ensuring compliance with the 0.45336This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 ensurethat EGUs are using only low-GHG hydrogen, i.e., hydrogen that results in GHG emissions ofless 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 hydrogenproduction from well-to-gate, and to what extent EGUs should be required to verify the accuracyof the energy inputs and conclusions of the GREET model for the hydrogen used by the EGU tocomply with this rule.
Several important considerations with respect to determining overall GHG emissions
rates for hydrogen production pathways have been raised by researchers and have been picked up
in trade press coverage. 500 501 Given the importance of these issues, the recent accumulation of
relevant research, and the range of stakeholder positions, the EPA is taking comment on the needfor (and design of) approaches and appropriate timeframes for allowing EGUs to meetrequirements for geographic and temporal alignment requirements to verify that the hydrogenused by the EGU is compliant with this rulemaking, recognizing that EPA’s low-GHG standard
for compliance would not begin until 2032. The EPA is soliciting comment on these issues, as
they relate to co-firing low-GHG hydrogen in combustion turbines and the requisite need to only
utilize the lowest-GHG hydrogen in these applications as specified in IRC section 45V,
specifically IRC section 45V(b)(2)(D). The EPA notes this is one of multiple forthcoming

500

Without Sufficient Guardrails, the Hydrogen Tax Credit Could Increase Emissions - Union ofConcerned Scientists. ucsusa.org.
501
Hydrogen’s Power Grid Demands Under Scrutiny in Tax Credit. bloomberglaw.com.
337
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 andmitigation 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 improveand 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 andconservatively estimated given the inherent uncertainties and wide range of basin-specificcharacteristics. 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 withthis 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 thisrulemaking, 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 amountof carbon captured by CCS is properly and consistently monitored and outage rates and times are
338
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

recorded and considered. The EPA is soliciting comment on providing EGUs with arepresentative 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 hydrogenproduction as part of this rulemaking, including what evidence would be necessary for the EGU
to deviate from that default assumption. These topics are particularly important to ensuring useof low-GHG hydrogen given the DOE estimate that by 2050, reformation-based production with
CCS may account for 50–80 percent of total U.S. hydrogen production. 502 The EPA is taking
comment on requiring substantiation of energy inputs used in any overall GHG emissions
assessment for hydrogen production used by EGUs for compliance with this requirement.
In comparison with petrochemical-based hydrogen production pathways discussed above,
electrolyzer-based hydrogen production has the potential for lower-GHG hydrogen because thetechnology is based on splitting water (H2O) molecules rather than splitting hydrocarbons (e.g.,CH4). 503 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 hydrogen production pathways forhydrogen used by the EGUs to comply with the low-GHG hydrogen standard in this rule. Energy
Attribute Certificates (EACs) (EACs from renewable sources are sometimes known as502

DOE Pathways to Commercial Liftoff: Clean Hydrogen, March 2023.
https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB-0329update.pdf.
503
DOE Pathways to Commercial Liftoff: Clean Hydrogen, March 2023.
https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB-0329update.pdf.
339This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 withspecific 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 is taking comment on requiring EGUs to provide EAC verification for lowGHG emission energy inputs into GHG emissions assessments for hydrogen used by that EGU tocomply 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 theuse of low-GHG hydrogen.
The EPA is taking comment on allowing EGUs to comply with the low-GHG hydrogenstandard in this rule if they demonstrate that the hydrogen used is produced from: (1) dedicatedlow-GHG emitting electricity from a generator sited on the utility side of a meter that iscontractually obligated to a electrolyzer, (2) a generator collocated with an electrolyzer and sited
behind a common utility meter, or (3) a generator whereby the electrolyzer and generator are
collocated but not interconnected to the grid and have no grid exchanges of power. The EPA is
also taking comment on approaches for EGUs to demonstrate that purchased hydrogen produced
from an electrolyzer could meet the low-GHG standard, in whole or part, through an allotment ofzero emitting electricity to a portion of the electrolyzer’s hydrogen output. Many announcedhydrogen production projects pair electrolyzers with renewable (including hydroelectric) or
nuclear energy, which are likely capable of producing low-GHG hydrogen. Wind and solar
renewable generation sources are variable, and nuclear units go offline for refueling purposes. In
these cases, and others, grid-based electricity, which often has a high carbon intensity might be340
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 that hydrogen used is
low-GHG hydrogen. 504 Some degree of alignment geographically, for example delivery of power
to the balancing authority in which the electricity is consumed by the electrolyzer, could ensurethat EACs used are representative of the allocation of the energy mix consumed by theelectrolyzers. However, alignment could also entail trade-offs, about which the EPA would likemore information.
In the case of temporal matching, the central issue is whether a producer must obtainsufficient EACs to match the total electricity demand of the electrolyzer on an annual basis
corresponding to an overall emissions rates of 0.45 kg CO2e/kg H2 or less, or whether the
producer must verify that it has obtained an EAC for low carbon generation on a more granulartimeframe, such as an hourly or monthly basis, for each time period the electrolyzer is running.
In other words, how can book and claim methods for grid-connected systems be developed toreliably claim total energy input emissions are equivalent to a pure off-grid zero-carbon emitting
system. Considerations around how grid-based electricity can effectively assure zero-carbon
emitting energy inputs as validated by EACs have received greater attention since passage of the
IRA. Solutions offered by researchers at Princeton University include requiring new grid-basedhydrogen producers to match 100 percent of electricity consumption on an hourly basis with newcarbon-free generation (substantiated through EACs with hourly attributes), with an estimated504“How Can Hydrogen Producers Show That They Are “Clean”?, Resources for the Future,
October 27, 2022.
341

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

cost impact of $1/kg. 505 Other research analyzing near-term emissions benefits of hourly EACalignment with respect to IRC section 45V implementation is growing, with some divergent
views about the emissions benefits of more precise alignment requirements. 506 Several research
papers have focused on the expense, trade-offs, and benefits of phasing in new and hourly EACalignment requirements. 507 An MIT Energy Initiative Working Paper examined emissions
benefits of hourly alignment and supported a “‘a phased approach’…annual matching in the nearterm with a re-evaluation leaning towards hourly matching later on in the decade”. 508 A
Rhodium Report found that while “[r]equiring a high degree of stringency across regional,
temporal, and additionality variables on day one…..increases the total subsidized cost ofhydrogen production” in the initial phase of the program, and concludes that ultimately“policymakers can’t ignore the long-term emissions risk” and recommends, “[t]o construct
emissions guardrails, the IRS can establish target dates for ratcheting up the certainty on key
implementation details like a transition to more temporally granular matching. Such phase-in
approaches give the hydrogen and power industries the signposts they need to develop the
tracking tools, calculation approaches, contract language, and other key elements to assure greenhydrogen contributes to decarbonization.” 509 This analysis did not consider potential system-

505

Princeton Citation: Minimizing emissions from grid-based hydrogen production in the UnitedStates - IOPscience January 2023
506
American Council on Renewable Energy (ACORE), “Analysis of Hourly & Annual GHG
Emissions: Accounting for Hydrogen Production”, April 2023. acore.org.
507
Energy Futures Initiative, “The Hydrogen Demand Action Plan”, February 2023.
https://energyfuturesinitiative.org/wp-content/uploads/sites/2/2023/02/EFI-Hydrogen-HubsFINAL-2-1.pdf.
508
MIT Energy Initiative, April 2023 “Producing hydrogen from electricity: How modeling
additionality drives the emissions impact of time-matching requirements” Anna Cybulsky,
Michael Giovanniello, Tim Schittekatte, Dharik S. Mallapragada.
509
Rhodium Group, “Scaling Green Hydrogen in a post-IRA World” March 16, 2023.
https://rhg.com/research/scaling-clean-hydrogen-ira/.
342
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

wide emissions impacts if costs present a near-term barrier to electrolytic hydrogen production,and reformation-based methods continue to dominate hydrogen production market share moving
forward. Other research, for example from Princeton, supports hourly time-matching,additionality, and location requirements—arguing that all three pillars are important in ensuring
low-GHG outcomes and that additional costs are not unreasonable. Research by Energy
Innovation aligns with the Princeton study with respect to locational and additionality
requirements and diverges in its recommendation of phasing in hourly EAC requirements by
2026. 510
The European Commission proposed a phased-in approach to defining what constitutes‘renewable hydrogen’ for the European Union (EU). The EU framework includes multiple
components including temporal alignment requirements: monthly EAC alignment is required at
the onset of the program, and hourly EAC alignment requirements are phased-in by 2030. 511 512
An impact assessment of the temporal alignment requirements is to be completed in 2028 andcould impact the timing of the hourly EAC phase-in requirements. The EU hydrogenrequirements and conditions will apply to domestic producers and imports and do not expire.
EAC alignment requirements impact both new and existing projects. Geographic alignment for
EACs is required at the onset of the EU program, whereas vintage requirements necessitating
new zero-carbon emitting energy source-based generation, often called ‘additional’, are phasedin after 2028. The EU proposal was released in February and must be approved by the European

510

https://energyinnovation.org/wp-content/uploads/2023/04/Smart-Design-Of-45V-HydrogenProduction-Tax-Credit-Will-Reduce-Emissions-And-Grow-The-Industry.pdf.
511
C_2023_1087_1_EN_ACT_part1_v8.pdf (europa.eu)
512
European Commission, “Commission sets out rules for renewable hydrogen” Brussels,
February 13, 2023. See: Hydrogen (europa.eu), Delegated regulation on Union methodology for
RFNBOs (europa.eu)
343This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Parliament and the Council of the EU within four months: amendments to the underlying policy
are not permitted. Notably, unlike the United States, the EU has a carbon policy for power sector
emissions that could help ensure that additional electricity demand from hydrogen production
does not result in additional power sector CO2 emissions. The EU and stakeholders examining
costs and benefits of temporal EAC alignment requirements generally find that hourly EACalignment is preferred before the 2032 proposed effective date of hydrogen co-firing
requirements in this proposed rule, with most converging on or before 2030. 513 514
The EPA is soliciting comment on requiring EGUs to use geographic and temporalalignment approaches for EAC-related requirements and the appropriate timing and trade-offs ofsuch approaches. The EPA is soliciting comment on the appropriateness of requiring geographicalignment for EACs used in conjunction with energy inputs at the balancing authority level at theonset of the compliance period for BSER in 2032. Similarly, the EPA is soliciting comments on
the appropriateness of requiring hourly EAC alignment requirements at the onset of thecompliance period for BSER in 2032. Relatedly, the EPA is taking comment on whether any
hourly EAC alignment requirements should affect both existing and new projects beginning in
2032, regardless of when a project became operational and a recipient of IRC section 45V
credits.

513

https://energyinnovation.org/wp-content/uploads/2023/04/Smart-Design-Of-45V-HydrogenProduction-Tax-Credit-Will-Reduce-Emissions-And-Grow-The-Industry.pdf.
514
April 12, 2023, memorandum, “How annual matching for the Inflation Reduction Act’s (IRA)
45V clean hydrogen tax credit can accelerate progress towards the Biden administration’s
decarbonization and clean hydrogen goals” signed by 23 companies, addressed to Treasury
Secretary Janet Yellen, Energy Secretary Jennifer Granholm and Senior Advisor to the President
for Clean Energy Innovation and Implementation Mr. John Podesta, indicated an openness to
examine hourly EAC requirements in 2032 or earlier and asserted, “recent studies warn thatoverly stringent temporal matching would hinder the development of clean hydrogen industry.”344This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Hourly tracking systems are evolving to meet this need in real time. For example, PJM
announced it would introduce EACs with hourly data stamping for low-GHG generators in
March 2023. M-RETS, a regional attribute tracking system headquartered in the Midwest, hasalso introduced the capability to track hourly energy attributes. While several tracking systems
are announcing or have started issuing hourly EACs, standardized methods, and nationwide
coverage is still developing. Recognizing that the timing of EPA’s proposed regulations would
not require such tracking systems to be fully functional until the 2030s, the EPA is taking
comment on the suitability of emerging and differentiated tracking systems to provide theinfrastructure for hourly energy attribute tracking for EGUs complying with low-GHG hydrogenstandards. The EPA is also taking comment on the need for energy attribute tracking systems touniformly approach the issuance, allocation, tracking and retirement of hourly EACs using
similar approaches to ensure a common and consistent national practice.
L. Mechanisms To Ensure Use of Actual Low-GHG Hydrogen
The EPA is soliciting comment on appropriate mechanisms to ensure that the low-GHG
hydrogen used by EGUs is actually low-GHG, and guard against EGU use of hydrogen that isfalsely claimed to be low-GHG hydrogen. The EPA solicits comment on whether EGUs should
be required to provide an independent third-party verification that hydrogen the EGU uses tocomply with this regulation meets the requirements for low-GHG hydrogen. EPA also solicits
comment on whether any such verifying third party must hold an active accreditation from anaccrediting body, such as the California Air Resources Board’s Low Carbon Fuels Standards
Program or the International Standards Organization 14064 Code. EPA seeks comment on any
other mechanisms to ensure that hydrogen used by EGUs meets the low-GHG standard and what

345
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

the remedy should be if an EGU uses hydrogen that is determined not to meet the definition of
low-GHG hydrogen.
M. 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 reportingare expected for this proposal. In the unlikely event that a specific EGU is not already covered byand 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; theEPA 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.

346
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

N. 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 onwith respect to the proposed CAA section 111(b) requirements.
1. CCS and Co-firing Low-GHG Hydrogen as BSER for the Base Load Subcategory
As described above, the EPA is proposing to establish two subcategories with different
standards for the base load subcategory, each based on a different BSER pathway. The first isbased on a BSER of CCS with 90 percent capture by 2035. The second is based on a BSER of
co-firing 30 percent (by volume) low-GHG hydrogen by 2032 and co-firing 96 percent (byvolume) by 2038. (Both pathways include efficient equipment and operation and maintenance as
an initial component of the BSER.) In other sections of this preamble, the EPA solicits comment
on variations in the amount of emissions reduction and the dates for compliance for eachpathway.
The EPA believes that if it finalizes a subcategory approach with different standards inwhich sources may choose between the two standards and BSER pathways, each must achieveenvironmentally comparable emission reductions. Thus, if the EPA determines based on all of
the statutory considerations that CCS with 90 percent capture qualifies as the BSER for base load
combustion sources, then co-firing hydrogen could qualify as well only if it also achieves
comparable reductions. Because the emissions standards are technology neutral, if the twopathways can achieve the same emissions reductions at the same time, there would be no need toestablish separate subcategories and standards as sources could adopt either BSER pathway tomeet the standard. But the EPA also believes that these two technologies may achieve
comparable emissions reductions at slightly different times, thus potentially necessitating two
347This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

alternate standards. The EPA solicits comment on the differences in emissions reductions in bothscale and time that would result from the two standards and BSER pathways, including how to
calculate the different amounts of emission reductions, how to compare them, and what
conclusions to draw from those differences. From the perspective of an individual turbine, theproposed co-firing with low-GHG hydrogen-based standard results in earlier emission reductions
because it takes effect in 2032, three years before the CCS-based standard, but the low-GHG
hydrogen-based standard could also result in fewer total emission reductions because the 90
percent emission rate reduction is not required until 2038, three years after the CCS-based
standard. Although early emission reductions have value in addressing climate change, it is the
cumulative impact of the emission reductions that is of primary importance given the short timescale over which those early reductions are occurring. The EPA also solicits comment on thepotential benefits of prescribing two separate standards for new base load combustion turbines.
Owners and operators of new combustion turbine EGUs are currently pursuing both CCS and cofiring with low-GHG hydrogen as approaches for reducing GHG emissions, and both require thedevelopment of infrastructure that may proceed at a different pace and scale and achieve
emissions reductions on different timelines with respect to each technology. Although both CCS
and co-firing with low-GHG hydrogen are, or are expected to be, broadly available throughout
the United States, the EPA solicits comment on whether individual locations where new baseload combustion turbines might be constructed might lend themselves more to one technology
than the other (based on pipeline availability, proximity to hydrogen production or geologic
sequestration sites, etc.). The EPA recognizes that the design of CAA section 111—whereby
sources decide which emissions controls they use to meet standards of performance —provides
sources with operational flexibility so long as they achieve the standard. A subcategory348This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

approach, however, may allow the EPA to consider the potentially differing scale and pace atwhich these technologies can achieve environmentally equivalent emissions reductions andwhether there are characteristics of units that make one or the other pathways “best” for those
types of units.
As an alternative to the proposed approach of two standards and BSER pathways for thebase load subcategory, the EPA is soliciting comment on having a single standard, which would
be based on CCS with 90 percent capture (along with efficiency as the initial component of theBSER). Under this alternative, the EPA would not establish a separate base load subcategory for
combustion turbines that adopt the low-GHG hydrogen co-firing pathway.
The EPA solicits comment on whether finalizing a single, CCS-based standard for thebaseload subcategory better reflects 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
adopt the low-GHG hydrogen co-firing in part because the Agency understands a number of
power companies are actively developing combustion turbines that are designed to co-firehydrogen. However, the Agency recognizes that power companies may ultimately come toutilize low-GHG hydrogen as a storage fuel reserved for intermediate load combustion turbinesthat support variable renewable generation, rather than for combustion turbines that generate atbase load. An approach in which the EPA establishes a single CCS-based second phase standard
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, wouldalign with this potential scenario. In addition, if an owner or operator of a new combustion
turbine does seek to utilize low-GHG hydrogen for base load generation, a single CCS-based
second phase standard for base load combustion turbines would not preclude owners and349
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

operators from utilizing low-GHG hydrogen as a means of compliance. Owners/operators could
also comply with a CCS-based standard by co-firing 96 percent (by volume) low-GHG hydrogenfrom the outset of the second phase—rather than the proposed approach that would delay
requirements for this level of co-firing until 2038.
2. 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 two components: (1) Highly
efficient generation (either combined cycle technology or simple cycle technology, respectively)and (2) co-firing 30 percent (by volume) low-GHG hydrogen, with the first component applying
when the source commences operation and the second component applying in the year 2032.
Dividing the intermediate load subcategory into these two subcategories would assure thatintermediate 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.
3. 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 toclarify 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 renewablegeneration is not included when determining the net electric sales for applicability purposes. In
350
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

the alternative, the EPA is soliciting comment on whether instead of exempting the generationfrom the integrated renewables from counting toward electric sales, the potential output from theintegrated 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 theimpact 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 tooperate 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 ofgreater than 20 percent that would reduce the ability of a peaking turbine engine to operate whilestill 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 anintermediate load combustion turbine when the output form the integrated renewables are
considered, the output from the integrated renewables could lower the emissions rate such thatthe affected facility would be in compliance with the intermediate load standard of performance.
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 affectedfacility. 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 ineither determining the NSPS emissions rate or as net electric sales for subcategorization
351
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

applicability purposes. While additional energy storage will allow for integration of additionalvariable 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.
4. 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 tooperate due to a system emergency is not counted toward the percentage electric sales
subcategorization threshold. 515 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 need to be determined and documented forcompliance 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 definitionof system emergency to clarify how it would be implemented. The current text is any abnormal
system condition that the RTO, Independent System Operators (ISO) or control area
Administrator determines requires immediate automatic or manual action to prevent or limit lossof transmission facilities or generators that could adversely affect the reliability of the powersystem and therefore call for maximum generation resources to operate in the affected area, orfor the specific affected EGU to operate to avert loss of load.

515

Electricity sold by units that are not called upon to operate due to a system emergency (e.g.,units already operating when the system emergency is declared) is counted toward thepercentage electric sales threshold.
352

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

5. 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 grosscalorific 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 fuelproduced 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. arenecessary of if they should be deleted. If landfill gas, coal-derived gas, or other gases areprocessed 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.
6. 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.
353

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

•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.

•

Applying a second component of BSER, co-firing 30 percent (by volume) lowGHG hydrogen by 2032.

For the intermediate load subcategory, the EPA is soliciting comment on:•

An efficiency-based standard of performance 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 by volume as the second
component of the BSER.

•

Beginning implementation of the second component of the BSER (i.e., hydrogenco-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.

•

Adding a third phase standard based on higher levels of low-GHG hydrogen cofiring by 2038.

For the base load subcategory, the EPA is soliciting comment on:
354
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

•An efficiency-based standard of performance of between 730 to 800 lb
CO2/MWh-gross for large combustion turbines.

•

An efficiency-based standard of performance 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 orhydrogen co-firing) as early as 2030.

•

Beginning implementation of the third component of the co-firing low-GHG
hydrogen-based BSER earlier than 2038.

•

Whether the third component of the hydrogen BSER should be 96 percent by
volume or a lower volume – note that if it is a lower volume that raises issues as
to whether the BSER would be appropriate if EPA found that a CCS BSER of
90% for NGCCs was generally applicable•

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 standard based on either a CCS-based BSER or a co-firing low-GHGhydrogen based BSER for all base load combustion turbines.

•

A carbon capture rate of 90 to 95 percent as the second component of the CCSbased BSER.

O. Compliance Dates
The EPA is proposing that affected sources that commenced construction orreconstruction 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
355
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

rule, whichever is later. This proposed compliance schedule is consistent with the requirements
in section 111 of the CAA.
VIII. Requirements for New, Modified, and Reconstructed Fossil Fuel-fired SteamGenerating Units
A. 2018 NSPS Proposal
The EPA promulgated NSPS for GHG emissions from fossil fuel-fired steam generating
units in 2015. 80 FR 64510 (October 23, 2015). 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; December 20, 2018). The EPA is notreopening for comment or soliciting comment on the 2018 NSPS Proposal, and intends to further
address it in a separate action.
1. 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 thefirst 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 turbinescomplying with a heat input-based standard. Third, the EPA is proposing to fix errors in thecurrent 40 CFR part 60, subpart TTTT regulatory text referring to part 63 instead of part 60.
356
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Fourth, as a practical matter owners/operators of stationary combustion turbines subject to theheat input-based standard of performance need to maintain records of electric sales todemonstrate that they are not subject to the output-based standard of performance. Therefore, the
EPA is proposing to add a specific requirement that owner/operators maintain records of electricsales 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 orusing 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.
B. Eight-year Review of NSPS for Fossil Fuel-fired Steam Generating Units
1. New construction and reconstruction
The EPA promulgated NSPS for GHG emissions from fossil fuel-fired steam generating
units in 2015. As noted in section IV.F, the EPA is not aware of any plans by any companies toundertake new construction of a new fossil fuel-fired steam generating unit, or to undertake areconstruction of an existing fossil fuel-fired steam generating unit, that would be subject to the2015 NSPS for steam generating units. Accordingly, the EPA does not consider it necessary, nora good use of agency resources, to review the NSPS for new construction or reconstruction. 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 the357
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

EPA to review an NSPS when no new construction, modification, or reconstruction is expectedin the source category). Should events change and the EPA learns that companies plan toundertake construction of a new fossil fuel-fired steam generating unit or reconstruction of an
existing fossil fuel-fired steam generating unit, the EPA would consider reviewing thesestandards.
2. Modifications
In the 2015 NSPS, the EPA issued final standards for a steam generating unit that
implements a “large modification,” defined as a physical change, or change in the method of
operation, that results in an increase in hourly CO2 emissions of more than 10 percent whencompared to the source’s highest hourly emissions in the previous 5 years. Such a modified
steam generating unit is required to meet a unit-specific CO2 emission limit determined by that
unit’s best demonstrated historical performance (in the years from 2002 to the time of themodification). The 2015 NSPS did not include standards for a steam generating unit that
implements a “small modification,” defined as a change that results in an increase in hourly CO2emissions of less than or equal to 10 percent when compared to the source’s highest hourly
emissions in the previous 5 years. 80 FR 64514 (October 23, 2015).
In the 2015 NSPS, the EPA explained its basis for promulgating this rule as follows. The
EPA has historically been notified of only a limited number of NSPS modifications involving
fossil steam generating units and therefore predicted that very few of these units would trigger
the modification provisions and be subject to the proposed standards. Given the limited
information that we have about past modifications, the agency has concluded that it lacks
sufficient information to establish standards of performance for all types of modifications at
steam generating units at this time. Instead, the EPA has determined that it is appropriate to358
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

establish standards of performance at this time for larger modifications, such as major facility
upgrades involving, for example, the refurbishing or replacement of steam turbines and otherequipment upgrades that result in substantial increases in a unit’s hourly CO2 emissions rate. The
agency has determined, based on its review of public comments and other publicly available
information, that it has adequate information regarding the types of modifications that could
result in large increases in hourly CO2 emissions, as well as on the types of measures available tocontrol emissions from sources that undergo such modifications, and on the costs andeffectiveness of such control measures, upon which to establish standards of performance formodifications with large emissions increases at this time. Id. at 64597-98. The EPA is notreopening any aspect of these determinations concerning modifications in the 2015 NSPS,
except, as noted below, for the BSER and associated requirements for large modifications.
Because the EPA has not promulgated a NSPS for small modifications, any existing
steam generating unit that undertakes a change that increases its hourly CO2 emissions rate by 10
percent or less would continue to be treated as an existing source that is subject to the CAA
section 111(d) requirements being proposed today.
With respect to large modifications, we explained in the 2015 NSPS that they are rare,
but there is record evidence indicating that they may occur. Id. at 64598. Because the EPA is
proposing requirements for existing sources that are, on their face, more stringent than therequirements for large modifications, the EPA believes it is appropriate to review and revise thelatter requirements to minimize the anomalous incentive that an existing source could have toundertake a large modification for the purpose of avoiding the more stringent requirements that it
would be subject to if it remained an existing source. Accordingly, the EPA is proposing torevise the BSER for large modifications to mirror the BSER for the subcategory of coal-fired359This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

steam generating units that plan to operate past December 31, 2039, that is, the use of CCS with
90 percent capture of CO2. The EPA believes that it is reasonable to assume that any existingsource that invests in a physical change or change in the method of operation that would qualify
as a large modification expects to continue to operate past 2039. Accordingly, the EPA proposesthat CCS with 90 percent capture qualifies as the BSER for such a source for the same reasonsthat it qualifies as the BSER for existing sources that plan to operate past December 31, 2039.
The EPA discusses these reasons in section X.D.1.a. The EPA is proposing to determine thatCCS with 90 percent capture qualifies as the BSER for large modifications, and not the controls
determined to be the BSER in the 2015 NSPS, due to the recent reductions in the cost of CCS.
The EPA does not believe there are any considerations relative to a source undertaking a large
modification that point towards a control system other than CCS with 90 percent capture
qualifying as the BSER. The Agency solicits comment on this issue.
By the same token, the EPA is proposing that the degree of emission limitation associatedwith CCS with 90 percent capture is an 88.4 percent reduction in emission rate (lb CO2/MWhgross basis), the same as proposed for existing sources with CCS with 90 percent capture. See
section X.D.1.a.iv. Based on this degree of emission limitation, the EPA is proposing that thestandard of performance for steam generating units that undertake large modifications after thedate of publication of this proposal is a unit-specific emission limit determined by an 88.4
percent reduction in the unit's best historical annual CO2 emission rate (from 2002 to the date of
the modification). The EPA is proposing that an owner/operator of a modified steam generating
unit comply with the proposed emissions rate upon startup of the modified affected facility or theeffective date of the final rule, whichever is later. The EPA is proposing the same testing,monitoring, and reporting requirements as are currently in 40 CFR part 60, subpart TTTT.
360
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

C. 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. 516 517 518
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. 519
The Holcomb 2 project was intended to be a single 895-MW coal-fired EGU andreceived 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.

516

https://www.gpb.org/news/2010/07/26/judge-rejects-coal-plant-permits.
https://www.southernenvironment.org/press-release/court-rules-ga-failed-to-set-safe-limitson-pollutants-from-coal-plant/.
518
https://permitsearch.gaepd.org/permit.aspx?id=PDF-OP-22139.
519
https://www.southernenvironment.org/wpcontent/uploads/legacy/words_docs/EPD_Plant_Washington_Denial_Letter.pdf.
361
517

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

For these reasons, the EPA is proposing to remove these projects under the applicability
exclusions in subpart TTTT.
IX. Proposed ACE Rule 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
repeal of the ACE Rule is intended to stand alone and be severable from the other aspects of thisrule. The EPA proposes to repeal the ACE Rule on three grounds that together, and eachindependently, justify the rule’s repeal. First, as a policy matter, the EPA believes that the suiteof heat rate improvements (HRI) the ACE Rule selected as the BSER should be reexamined andare no longer an appropriate BSER for existing coal-fired EGUs. The EPA concludes that thesuite of HRI set forth in the ACE Rule provide negligible CO2 reductions at best and, in manycases, could increase CO2 emissions because of the rebound effect, as explained in section
X.D.5.a. These concerns taken together, along with new evidence, and the EPA’s experience in
implementing the ACE Rule, cast doubt on the ACE Rule’s minimal projected emission
reductions and increase the likelihood that the ACE Rule could make CO2 pollution worse. As aresult, the EPA has determined it is appropriate to repeal the rule, and to reevaluate whether
other technologies constitute the BSER.
Second, the ACE Rule rejected CCS and natural gas co-firing as the BSER for reasonsthat no longer apply. This rule should be repealed so that EPA may determine the BSER basedon evaluating all the candidate technologies. Since the ACE Rule was promulgated, changes in
the power industry, developments in the costs of controls, and new federal subsidies have madethese other technologies more broadly available and less expensive. The EPA is now proposing

362This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

that these technologies are the BSER for certain subcategories of sources, as described in section
X of this preamble.
Third, the EPA concludes that the ACE Rule conflicted with CAA section 111 and the
EPA’s implementing regulations because it did not specifically identify the BSER or the “degreeof emission limitation achievable though application of the [BSER],” but set forth anindeterminate range of values. Thus, the rule did not provide the states with adequate guidanceon the degree of emission limitation that must be reflected in the standards of performance sothat a state plan would be approvable by the EPA. Along with this, the ACE Rule also
improperly departed from the statutory framework of CAA section 111(d) by categorically
precluding states from allowing their sources to comply with standards of performance bytrading or averaging. Properly construed, CAA section 111(d) gives states discretion to provide
sources with certain compliance flexibilities, including trading or averaging in appropriate
circumstances so long as the other requirements of section 111 are met as described below.
A. Summary of Selected Features of the ACE Rule
The ACE Rule determined that the BSER for coal-fired EGUs was a “list of ‘candidate
technologies,’” consisting of seven types of the “most impactful HRI technologies, equipment
upgrades, and best operating and maintenance practices,” (84 FR 32536; July 8, 2019),
including, among others, “Boiler Feed Pumps” and “Redesign/Replace Economizer.” Id. at32537 (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 explained that
363
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

states must review each of their designated facilities, on either a source-by-source or group-ofsources basis, and “evaluate the applicability of each of the candidate technologies.” Id. at
32550. States were to use the list of HRI technologies “as guidance but will be expected to
conduct unit-specific evaluations of HRI potential, technical feasibility, and applicability foreach of the BSER candidate technologies.” Id. at 32538.
The ACE Rule emphasized that states had “inherent flexibility” in undertaking this taskwith “a wide range of potential outcomes.” Id. at 32542. The ACE Rule provided that states
could conclude that it was not appropriate to apply some technologies. Id. at 32550. Moreover, if
a state 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 therange that the EPA had identified for that technology, or even outside that range. Id. at 32551.
The ACE Rule stated that after the state evaluated the technologies and calculated the amount of
HRI in this way, it should determine the standard of performance that the source could achieve,
Id. at 32550, and then adjust that standard further based on the application of source-specificfactors such as remaining useful life. Id. at 32551.
The ACE Rule then identified the process by which states had to take these actions.
States must “evaluat[e] each” of the seven candidate technologies and provide a summary, which“include[s] an evaluation of the … degree of emission limitation achievable through applicationof the technologies.” Id. at 32580. Then, the state must provide a variety of information about
each power plant, including, the plant’s “annual generation,” “CO2 emissions,” “[f]uel use, fuelprice, and carbon content,” “operation and maintenance costs,” “[h]eat rates,” “[e]lectric
generating capacity,” and the “timeline for implementation,” among other information. Id. at364This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

32581. The EPA explained that the purpose of this data was to allow the Agency to “adequately
and appropriately review the plan to determine whether it is satisfactory.” Id. at 32558.
The ACE Rule projected a very low level of overall emission reduction if states generally
applied the set of candidate technologies to their sources. The rule was projected to achieve aless-than-1-percent reduction in power-sector CO2 emissions by 2030. 520 Further, the EPA also
projected that it would increase CO2 emissions from power plants in 15 states and the District ofColumbia because of the “rebound effect” as sources implemented HRI measures and became
more efficient. This phenomenon is explained in more detail in section X.D.5.a. 521
The ACE Rule considered several other control measures as the BSER, including cofiring 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 thatgenerating electricity by co-firing natural gas in a utility boiler would be an inefficient use of thegas when compared to combusting it in a combustion turbine. Id. The ACE Rule rejected CCS on
grounds that it was too costly. Id. at 32548. The rule identified the high capital and operating
costs of CCS and noted the fact that the IRC 45Q tax credit, as it then applied, would provide
only limited benefit to sources. Id. at 32548-49.

520

ACE Rule RIA 3-11, table 3-3.
The rebound effect becomes evident by comparing the results of the ACE Rule IPM runs forthe 2018 reference case, EPA, IPM State-Level Emissions: EPAv6 November 2018 Reference
Case, EPA-HQ-OAR-2017-0355-26720, and for the “Illustrative ACE Scenario. IPM State-Level
Emissions: Illustrative ACE Scenario, EPA-HQ-OAR-2017-0355-26724.
365
521

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 standards of performance.
Id. at 32556–57.
B. Developments Undermining ACE Rule’s Projected Emission Reductions
The EPA’s first basis for proposing to repeal the ACE Rule is that there is doubt that therule would achieve even the limited emissions reductions projected at the time of promulgation if
it were implemented now, and implementation could increase CO2 emissions instead. Thus, theEPA concludes that as a matter of the Agency’s policy judgment it is appropriate to repeal therule and evaluate whether other technologies qualify as the BSER given new factual
developments. This action is consistent with the Supreme Court’s instruction in FCC v. Fox
Television Stations, Inc., 556 U.S. 502 (2009), where the Supreme Court explained that anagency issuing a new policy “need not demonstrate to a court’s satisfaction that the reasons forthe new policy are better than the reasons for the old one.” Instead, “it suffices that the newpolicy is permissible under the statute, that there are good reasons for it, and that the agency
believes it to be better, which the conscious change of course adequately indicates.” Id. at 514–
16 (emphasis in original; citation omitted).
Two factors, taken together, undermine the ACE Rule’s projected emission reductions
and create the risk that implementation of the ACE Rule could increase—rather than reduce—
CO2 emissions from coal-fired EGUs. First, HRI technologies achieve only limited GHG
emission reductions. The ACE Rule projected that if states generally applied the set of candidate
technologies to their sources, the rule would achieve a less-than-1-percent reduction in power-

366
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

sector CO2 emissions by 2030. 522 The EPA now doubts that even these minimal reductions
would be achieved. The ACE Rule’s projected benefits were premised in part on a 2009
technical report by Sargent & Lundy that evaluated the effects of HRI technologies. In 2023,
Sargent & Lundy issued an updated report which details that the HRI selected as the BSER in the
ACE Rule would bring fewer emissions reductions than estimated in 2009. The 2023 reportconcludes that, with few exceptions, HRI technologies are less effective at reducing CO2
emissions than assumed in 2009. And most sources had already optimized application of HRIs,
and so there are fewer opportunities to reduce emissions than previously anticipated.
Second, for a subset of sources, HRI are likely to cause a rebound effect leading to anincrease in GHG emissions for those sources for the reasons explained in section X.D.5.a. The
estimate of the rebound effect was quite pronounced in the ACE Rule’s own analysis – the ruleprojected that it would increase CO2 emissions from power plants in 15 states and the District ofColumbia. Specifically, the EPA prepared modeling projections to understand the impacts of the
ACE Rule. These projections assumed that, consistent with the rule, sources would impose asmall degree of efficiency improvements. The modeling showed that the rule would not result in
absolute emissions reductions across all affected sources, and some would instead increaseabsolute emissions. See EPA, IPM State-Level Emissions: EPAv6 November 2018 Reference
Case, EPA-HQ-OAR-2017-0355-26720 (providing ACE reference case); IPM State-Level
Emissions: Illustrative ACE Scenario, EPA-HQ-OAR-2017-0355-26724 (providing illustrative
scenario).

522

ACE Rule RIA 3-11, table 3-3.

367This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Despite the fact that the ACE Rule was projected to increase emissions in many states,
these states were nevertheless obligated under the rule to assemble detailed state plans that
evaluated available technologies and the performance of each existing coal-fired power plant, as
described in section IX.A of this preamble. For example, the state was required to analyze theplant’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. 84 FR 32581 (July 8, 2019). Thisevaluation and the imposition of standards of performance was mandated even though the stateplan would lead to an increase rather than decrease CO2 emissions.
In this context, the data undermining the ACE Rule’s limited, projected emission
reductions along with the risk that implementation of the rule could increase CO2 pollution raises
doubts that the HRI satisfies the statutory criteria to constitute the BSER for this category ofsources. The core element of the BSER analysis is whether the emission reduction technology
selected reduces emissions. See Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 441 (D.C. Cir.
1973) (noting “counter productive environmental effects” questioned whether the BSER selected
was in fact the “best”).
The EPA’s experience in implementing the ACE Rule reinforces these concerns. After
the ACE Rule was promulgated, one state drafted a state plan that set forth a standard of
performance that allowed the affected source to increase its emission rate. The draft partial plan
would have applied to one source, the Longview Power, LLC facility, and would haveestablished 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.

368This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Thus, the draft plan would not have achieved any emission reductions from the source, andinstead would have allowed the source to increase its emissions, if it was finalized. 523
Because there is doubt that the minimal reductions projected by the ACE Rule would beachieved, and because the rebound effect could lead to an increase in emissions for many sourcesin many states, the EPA concludes that it is appropriate to repeal the ACE Rule and reevaluate
the BSER for this category of sources.
C. Developments Showing that Other Technologies are the BSER for this Source Category
Since the promulgation of the ACE Rule in 2019, the factual underpinnings of the rule
have changed in several ways, and lead EPA to propose that HRI are not the BSER for coal-fired
power plants.
Along with changes in the anticipated reductions from HRI, it makes sense for the EPA
to reexamine the BSER because the costs of two control measures, co-firing with natural gas and
CCS, have fallen substantially for sources with longer-term operating horizons such that the EPA
may determine that these measures satisfy the requirements for the BSER for the source
categories identified below. As noted, the ACE Rule rejected natural gas co-firing as the BSER
on grounds that it was too costly and would lead to inefficient use of natural gas. But as
discussed in section X.D.2.b.ii of this preamble, the costs of natural gas co-firing havesubstantially 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, the523West Virginia CAA §111(d) Partial Plan for Greenhouse Gas Emissions from ExistingElectric Utility Generating Units (EGUs),
https://dep.wv.gov/daq/publicnoticeandcomment/Documents/Proposed%20WV%20ACE%20Stat
e%20Partial%20Plan.pdf.
369This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

changed circumstances, including that natural gas is available in greater amounts, and there arefewer coal-fired EGUs, mitigates the concerns the ACE Rule identified about inefficient use ofnatural 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. But
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 ahigher portion of the costs of CCS. Accordingly, for coal-fired EGUs that will continue tooperate past 2040, the EPA is proposing that the costs of CCS, which have fallen to
approximately $7– $12/MWh, are reasonable.
The reductions from these two technologies are substantial. For long-term coal-fired
steam generating units, the BSER of 90 percent capture CCS results in substantial CO2 emissions
reductions amounting to emission rates that are 88.4 percent lower on a lb/MWh-gross basis and87.1 percent lower on a lb/MWh-net basis compared to units without capture, as described in
section X.D.4 of this preamble. And for the BSER for medium-term units, 40 percent natural gas
co-firing achieves reductions of 16 percent, as described in section X.D.2.b.iv of this preamble.
Given the availability of more effective, cost-reasonable technology, the EPA concludes
that HRIs are not the BSER for all coal-fired EGUs.
The EPA is thus proposing to adopt a new policy and change its regulatory scheme forcoal-fired power plants. As discussed in section X.C.3 of this preamble, the EPA is proposing to
subcategorize coal-fired power plants according to the time that they will continue to operate.
For sources in the imminent-term and near-term subcategories – which include sources that, ingeneral, have federally enforceable commitments to permanently cease operations by 2032 or
370
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

2035, respectively – the EPA is proposing that the BSER is routine methods of operation andmaintenance, with associated presumptive standards of performance that do not permit anincreased emission rate and are not anticipated to have a rebound effect; and the EPA is
soliciting comment on whether co-firing some amount of natural gas should be part of the BSER.
For sources in the medium-term subcategory – which includes sources that are not in the othersubcategories 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 concludes this control measure is appropriate because it achieves substantial reductionsat reasonable cost. In addition, the EPA believes that because a large supply of natural gas isavailable, devoting part of this supply for fuel for a coal-fired steam generating unit in place of apercentage of the coal burned at the unit is an appropriate use of natural gas and will notadversely impact the energy system, as described in section X.D.2.b.iii(B) of this preamble.
For sources in the long-term subcategory – which includes sources that do not have afederally 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 thiscontrol measure is appropriate because it achieves substantial reductions at reasonable cost, as
described in section X.D.1.c of this preamble.
The EPA is not proposing HRI as the BSER for any coal-fired EGUs. As discussed in
section X.D.5.a, the EPA does not consider HRIs an appropriate BSER for the imminent-termand near-term subcategories because these technologies would achieve few, if any, emissions
reductions and may increase emissions due to 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 leadto a rebound effect. Most importantly, changed circumstances show that co-firing natural gas and371
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

CCS are available at reasonable cost, and will achieve more GHG emissions reductions.
Accordingly, the EPA believes that HRI do not qualify as the BSER for any coal-fired EGUs,
and that other approaches meet the statutory standard. For these reasons, the EPA proposes torepeal the ACE Rule.
D. Insufficiently Precise Degree of Emission Limitation Achievable from Application of the
BSER
The third independent reason why the EPA is proposing to repeal the ACE Rule is thatthe rule did not identify with sufficient specificity the BSER or the degree of emission limitationachievable through the application of the BSER. Thus, states lacked adequate guidance on the
BSER they should consider and level of emission reduction that the standards of performancemust achieve. The ACE Rule determined the BSER to be a suite of HRI “candidate
technologies,” but did not identify with specificity the degree of emission limitation states should
apply in developing standards of performance for their sources. As a result, the ACE Ruleconflicted with CAA section 111 and the implementing regulations, and thus failed to provide
states adequate guidance so that they could ensure that their state plans were satisfactory andapprovable by the EPA.
CAA section 111 and the EPA’s long-standing implementing regulations establish a clear
process for the EPA and states to regulate emissions of certain air pollutants from existingsources. “The statute directs EPA to (1) ‘determine[],’ taking into account various factors, the‘best system of emission reduction which . . . has been adequately demonstrated,’ (2) ascertain
the ‘degree of emission limitation achievable through the application’ of that system, and(3) impose an emissions limit on new stationary sources that ‘reflects’ that amount.” West
Virginia v. EPA, 142 S. Ct. 2587, 2601 (2022) (quoting 42 U.S.C. 7411(d)). Further, “[a]lthough372This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

the States set the actual rules governing existing power plants, EPA itself still retains the primary
regulatory role in Section 111(d) . . . [and] decides the amount of pollution reduction that must
ultimately be achieved.” Id. at 2602.
Once the EPA makes these determinations, the state must establish “standards ofperformance” 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 “standard of performance” as “a standard for emissions of air pollutants whichreflects the degree of emission limitation achievable through the application of the [BSER].”
After the EPA determines the BSER, 40 CFR 60.22(b)(5), and the degree of emission limitationachievable from application of the BSER, “the States then submit plans containing the emissions
restrictions that they intend to adopt and enforce in order not to exceed the permissible level ofpollution established by EPA.” 142 S. Ct. at 2602 (citing 40 CFR 60.23, 60.24; 42 U.S.C.
7411(d)(1)).
The EPA then reviews the plan and approves it if the standards of performance are“satisfactory,” under CAA section 111(d)(2)(A). The EPA’s 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 thecorresponding emission guideline(s).” 40 CFR 60.24(c). The EPA’s revised implementing
regulations contain the same requirement. 40 CFR 60.24a(c). In addition, under CAA section
111(d)(1), in “applying a standard of performance to any particular source” a state may consider,“among other factors, the remaining useful life of the existing source to which such standard
applies.” This is also known as the RULOF provision and is discussed in section XII.D.2.

373
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

In the ACE Rule, the EPA recognized that the CAA required it to determine the BSER
and identify the degree of emission limitation achievable through application of the BSER. 84
FR 32537 (July 8, 2019). But the rule did not make those determinations. Rather, the ACE Ruledescribed the BSER as a list of “candidate technologies.” And the rule described the degree ofemission limitation achievable by application of the BSER as ranges of reductions from the HRI
technologies. The rule thus shifted the responsibility for determining the BSER and degree ofemission limitation achievable from the EPA to the states. Accordingly, the ACE Rule did notmeet the CAA section 111 requirement that the EPA determine the BSER or the degree ofemission limitation from application of the BSER.
As described above, the ACE Rule identified the HRI in the form of a list of seven“candidate technologies,” accompanied by a wide range of percentage improvements to heat ratethat these technologies could provide. Indeed, for one of them, improved O&M practices (that is,operation and management practices), the range was “0 to >2%”, which is effectively
unbounded. 84 FR 32537 (table 1) (July 8, 2019). The ACE Rule was clear that this list was
simply the starting point for a state to calculate the standards of performance for its sources. Thatis, 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 amanner 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 Ruledid not determine the BSER or any degree of emission limitation from application of the BSER,
and so states had no guidance on how to craft approvable state plans. In this way, EPA
effectively abdicated its responsibilities, and directed 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
374
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

what intensity), and, based on that, what the degree of emission limitation achievable byapplication of the BSER. See 84 FR 32537-38 (July 8, 2019).
The only constraints that the ACE Rule imposed on the states were procedural ones, andthose did not give the EPA any benchmark to determine whether a plan could be approved orgive the states any certainty on whether their plan would be approved. As noted above, when astate submitted its plan, it needed to show that it evaluated each candidate technology for eachsource or group of sources, explain how it determined the degree of emission limitationachievable, and include data about the sources. But because the ACE Rule did not identify a
BSER or include a degree of emission limitation that the standards must reflect, the states lacked
specific guidance on how to craft adequate standards of performance, and the EPA had nobenchmark against which to evaluate whether a state’s submission was “satisfactory” under CAA
section 111(d)(2)(A). Thus, the EPA’s review of state plans was essentially a standardless
exercise, notwithstanding the Agency’s longstanding view that it was “essential” that “EPA
review … [state] plans for their substantive adequacy.” 40 FR 53342-43 (November 17, 1975).
In 1975, the EPA explained that it was not appropriate to limit its review based “solely on
procedural criteria” because otherwise “states could set extremely lenient standards . . . so longas EPA’s procedural requirements were met.” Id. at 53343.
Finally, the ACE Rule’s approach to determining the BSER and degree of emission
limitation departed from prior emission guidelines under CAA section 111(d), in which the EPA
included a numeric degree of emission limitation. See, e.g., 42 FR 55796, 55797 (October 18,1977) (limiting emission rate of acid mist from sulfuric acid plants to 0.25 grams per kilogram ofacid); 44 FR 29828, 29829 (May 22, 1979) (limiting concentrations of total reduced sulfur frommost of the subcategories of kraft pulp mills, such as digester systems and lime kilns, to 5, 20, or
375This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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). In the ACE Rule, the EPA did not grapple with this change in position as
required by FCC v. Fox Television Stations, Inc., 556 U.S. 502 (2009), or explain why it wasappropriate to provide a boundless degree of emission limitation achievable in this context.
For this reason, the EPA proposes to repeal the ACE Rule. Its failure to determine the
BSER and the associated degree of emission limitation achievable from application of the BSER
deviated from CAA section 111 and the implementing regulations. Without these determinations,
the ACE Rule lacked any benchmark that would guide the states in developing their state plans,
and by which the EPA could determine whether those state plans were satisfactory.
E. ACE Rule’s Preclusion of Emissions Trading or Averaging
While not an independent basis for repeal, the ACE Rule also interpreted CAA section
111(d) to bar states from allowing emissions trading or averaging among their sources in allcases, which further shows that the ACE Rule misconstrued section 111(d) and the appropriate
roles for the EPA and for the states. A trading program might allocate allowances authorizing aparticular level of emissions; a facility would not need to reduce its emissions so long as it tradedfor sufficient allowances. And an averaging program, for example, might require a group offacilities to reduce their average emissions to a particular level. So long as some facilities
reduced their emissions sufficiently below that level, it would not be necessary for every facility
to reduce its emissions. Cf. Chevron U.S.A., Inc. v. Natural Res. Def. Council, Inc., 467 U.S. 837,
863 n.37 (1984) (explaining the ‘“bubble’ or ‘netting’ concept). CAA section 111(d) accords
states discretion in developing state plans, and allows states to include compliance flexibilities
like trading or averaging in circumstances the EPA has determined are appropriate, as long as the376This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

plan achieves equivalent emissions reductions to the EPA’s emission guidelines. The ACE
Rule’s legal interpretation that CAA section 111(d) always precludes the state from adopting
those flexibilities was incorrect.
Under CAA section 111, EPA promulgates emission guidelines that identify the degreeof emission limitation achievable through the application of the BSER as determined by the
Administrator. Each State must then “submit to the Administrator a plan” to achieve the degreeof emission limitation identified by EPA. 42 U.S.C. 7411(d)(a). That plan must “establish[]standards of performance for any existing source” that emits certain air pollutants, and also
“provide[ ] 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 applicationof the [BSER].” Although such standards of performance must “reflect[ ] the degree of emission
limitation achievable through the application of the [BSER],” 42 U.S.C. 7411(a)(1), States neednot compel regulated sources to adopt the particular components of the BSER itself.
The ACE Rule interpreted CAA section 111(a)(1) and (d) to preclude states fromallowing their sources to trade or average to demonstrate compliance with their standards ofperformance. 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“measures that apply at and to an individual source and reduce emissions from that source.” Id.
at 32523–24. The ACE Rule also concluded that the compliance measures the states include in
their plans “should correspond with the approach used to set the standard in the first place,” andtherefore must also be limited to measures that apply at and to an individual source and reduce
emissions from that source. Id. at 32556.
377
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

In its recently published notice of proposed rulemaking to amend the CAA section 111(d)implementing regulations, the EPA has proposed to determine that the ACE Rule’s legal
interpretation as to the type of “system” that may be selected as a BSER, and the universal
prohibition of trading and averaging, was incorrect. “Implementing Regulations under 40 CFRPart 60 Subpart Ba Adoption and Submittal of State Plans for Designated Facilities: Proposed
Rule,” 87 FR 79176, 79207-79208 (December 23, 2022). As discussed in that notice, noprovision in CAA section 111(d), by its terms, precludes states from having flexibility indetermining which measures will best achieve compliance with the EPA’s emission guidelines.
Specifically, the plain language of section 111(d) does not affirmatively bar states fromconsidering averaging and trading as a compliance measure where appropriate for a particularemission guideline. Under section 111(d)(1), States must “establish[ ],” “implement[ ],” and“enforce[ ]” “standards of performance for any existing source.” A state plan that specifies what
each existing source must do to satisfy plan requirements is naturally characterized as
establishing “standards of performance for [each] existing source,” even if measures like trading
and averaging are identified as potential means of compliance. Trading and averaging programs
may be appropriate as a policy matter as well because, in some circumstances, they can help toensure that costs are reasonable by enabling market force to identify the facilities whose
emissions can be reduced most cost-effectively. Nothing in the text of section 111 precludes
states from considering a source’s acquisition of allowances in implementing and enforcing astandard of performance for that particular source, so long as the state plan achieves the required
level of emission reductions.
Further supporting this statutory interpretation, section 111(d) requires a “proceduresimilar to that provided by Section 7410.” Consideration of the section 110 framework reinforces
378
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

the absence of any mandate that states consider only compliance measures that apply at and to anindividual source. “States have ‘wide discretion’ in formulating their plans” under section 110.
Alaska Dep’t of Envtl. Conservation v. EPA, 540 U.S. 461, 470 (2004) (citation omitted); seeUnion Elec. Co. v. EPA, 427 U.S. 246, 269 (1976) (“Congress plainly left with the States, solong as the national standards were met, the power to deter-mine which sources would beburdened by regulation and to what extent.”); Train v. Natural Res. Def. Council, Inc., 421 U.S.
60, 79 (1975) (“[S]o long as the ultimate effect of a State’s choice of emission limitations iscompliance with the national standards for ambient air, the State is at liberty to adopt whatever
mix of emission limitations it deems best suited to its particular situation.”). Exercising that
discretion, States have included measures that do not apply at or to a source in their section 1410
plans. For example, states have employed NOX and SO2 trading programs to comply with section
7410(a)(2)(D)(i)(I), the “Good Neighbor Provision.” Section 110 thus does not distinguishbetween measures that do or don’t apply at or to a source for compliance, and there is no soundreason to read section 111’s comparably broad language differently.
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 andstate authorities, generally permitting each State to take the first cut at determining how best toachieve EPA emissions standards within its domain.” American Elec. Power Co. v. Connecticut,
564 U.S. 410, 428 (2011) (citations omitted).
To be sure, as discussed above, EPA retains an important role in reviewing state plans foradequacy. Under 111(d), each state must “submit to the Administrator a plan” to achieve thedegree of emission limitation identified by EPA. That plan must “establish[ ] standards of379
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

performance for any existing source for [the] air pollutant” and also “provide[ ] for the
implementation and enforcement of such standards of performance.” Id. If a state elects not tosubmit a plan, or submits a plan that EPA does not find “satisfactory,” EPA must promulgate aplan that establishes federal standards of performance for the State’s existing sources. 42 U.S.C.
7411(d)(2)(A). Thus, the flexibility that CAA section 111(d) grants to states in adopting
measures for their state plans is not unfettered. As the Supreme Court stated in West Virginia,“The Agency, not the States, decides the amount of pollution reduction that must ultimately beachieved.” 142 S. Ct. at 2602. State plans then must contain “emissions restrictions that they
intend to adopt and enforce in order not to exceed the permissible level of pollution establishedby EPA.” Id. Thus, EPA bears the burden of ensuring that the permissible level of pollution is
not exceeded by any state plan. When a compliance flexibility compromises the ability of thestate plan to achieve the necessary emission reductions, then the EPA may reasonably preclude
reliance on such measures, or otherwise conclude that the state plan is not satisfactory.
Thus, the EPA proposed to disagree with the ACE Rule’s conclusion that state plancompliance measures must always apply at and to an individual source and reduce emissions ofthat source. As noted in section V.B.6, the U.S. Supreme Court in West Virginia v. EPA, 142 S.
Ct. 2587 (2022), did not address the scope of the states’ compliance flexibilities in developing
state plans. The Court also declined to address whether CAA section 111 limits the type of“system” the EPA may consider to measures that apply substantially at and to an individual
source. See id. at 2615.
For these reasons, in its notice of proposed rulemaking to amend the CAA section 111(d)implementing regulations, EPA proposes to interpret CAA section 111 as permitting each state to
adopt measures that allow its sources to meet their emissions limits in the aggregate, when the380
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

EPA determines, in any particular emission guideline, that it is appropriate to do so, given, interalia, the pollution, sources, and standards of performance at issue. Thus, it is the EPA’s proposed
position that CAA 111(d) authorizes the EPA to approve state plans under particular emission
guidelines that achieve the requisite emission limitation through the aggregate reductions fromthose 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 XII.E, the EPA is proposing to allow trading and averaging under the
proposed emission guidelines and requesting comment on whether and how such compliancemechanisms could be implemented to ensure equivalency with the emission reductions thatwould be achieved if each affected source was achieving its applicable standard of performance.
The ACE Rule’s flawed legal interpretation that CAA section 111(d) universally
precludes states from emissions trading is incorrect and adds to EPA’s rationale for proposing torepeal the rule.
X. Proposed Regulatory Approach for Existing Fossil Fuel-fired Steam Generating Units
A. 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 applicationof each proposed BSER. The EPA is proposing subcategories for steam generating units basedon the type and amount of fossil fuel (i.e., coal, oil, and natural gas) fired in the unit.
For existing coal-fired steam generating units that plan to operate in the long-term, the
EPA is proposing CCS with 90 percent capture as BSER, based on a review of emission control
381
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

technologies detailed further in this section of the preamble and accompanying TSDs, available
in the docket. The EPA is soliciting comment on a range of maximum capture rates (90 to 95
percent or greater) 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 ofemission limitation (75 to 90 percent reduction in average annual emission rate, defined in termsof pounds of CO2 per unit of generation).
During the EPA’s engagement with stakeholders to inform this proposed rule, industry
stakeholders noted that many coal-fired sources have plans to permanently cease operation in the
coming years, and that GHG control technologies might not be cost reasonable for those units
operating on shorter timeframes. These stakeholders recommended that the emission guidelines
account for industry plans for permanently ceasing operation of coal-fired steam generating units
by establishing a “subcategory pathway” with less stringent requirements.
Consistent with this stakeholder input, the EPA proposes to provide subcategories forcoal-fired steam generating units planning to permanently cease operations in the 2030s. The
EPA recognizes that the cost reasonableness of GHG control technology options differ
depending on a coal-fired steam generating unit’s expected operating time horizon. Accordingly,
the EPA is proposing to divide the subcategory for coal-fired units into additional subcategories
based on operating horizon (i.e., dates for electing to permanently cease operation) and, for oneof those subcategories, load level (i.e., annual capacity factor), with a separate BSER and degreeof emission limitation corresponding to each subcategory. For long-term coal-fired units, the
EPA is proposing that CCS satisfies the BSER criteria, as noted above. For medium-term units,
the EPA is proposing natural gas co-firing at 40 percent of annual heat input as BSER. The EPA
is soliciting comment on the percent of natural gas co-firing from 30 to 50 percent and the degree382This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 noincrease in emission rate. For imminent-term and near-term coal-fired steam generating units, the
EPA is also soliciting comment on a potential BSER based on low levels of natural gas co-firing.
For natural gas- and oil-fired steam generating units, the EPA is proposing a BSER of
routine methods of operation and maintenance and a degree of emission limitation of no increasein emission rate. Further, the EPA is proposing to divide subcategories for oil- and natural gasfired units based on capacity and, in some cases, geographic location. Because natural gas- andoil-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/MWhgross 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 a BSER or degree ofemission limitation for those units in this action. However, the EPA is soliciting comment on apotential BSER of “uniform 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 noncontinental 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 a degree of emission limitation for those units of no increase in emission rate and383
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

presumptive standards based on unit-specific emission rates, as detailed in section XII of thispreamble. The EPA is soliciting comment on ranges of annual capacity factors to define thethresholds between the load levels and ranges in the degrees of emission limitation, as specified
in section X.E of this preamble.
It should be noted that the EPA is proposing a compliance date of January 1, 2030, as
discussed in section XII of this preamble on state plan development.
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 discussionof the systems and other options considered, and explanation and justification for thedetermination of BSER and degree of emission limitation. Subsection E contains, for natural gasand 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 thedetermination of BSER and degree of emission limitation.
B. Applicability Requirements for Existing Fossil Fuel-fired Steam Generating Units
For the emission guidelines, the EPA is proposing that a designated facility 524 is any
fossil fuel-fired electric utility steam generating unit (i.e., utility boiler or IGCC unit) that: (1)
Was in operation or had commenced construction on or before January 8, 2014; 525 (2) serves a

524

The term “designated facility” means “any existing facility…which emits a designatedpollutant and which would be subject to a standard of performance for that pollutant if theexisting facility were an affected facility.” See 40 CFR 60.21a(b).
525
Under CAA section 111, the determination of whether a source is a new source or an existingsource (and thus potentially a designated facility) is based on the date that the EPA proposes toestablish standards of performance for new sources.
384
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 theseemission guidelines. 526 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 theseemission guidelines. The rationale for this proposal concerning applicability is the same as thatfor 40 CFR part 60, subpart TTTT (80 FR 64543–44; October 23, 2015). The EPA incorporates
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 thatare new after January 8, 2014, or reconstructed after June 18, 2014, the applicability dates of 40
CFR part 60, subpart TTTT. Moreover, because the EPA is now proposing revised standards ofperformance for coal-fired steam generating units that undertake a modification, a modified
source would be considered “new,” and therefore not subject to these emission guidelines, if themodification occurs after the date this proposal is published in the Federal Register. Any sourcethat has modified prior to that date would be considered an existing source that is subject to theseemission guidelines.
In addition, the EPA is proposing to include in the applicability requirements of theemission guidelines the same exemptions as discussed for 40 CFR part 60, subpart TTTT in

526

The EPA recognizes, however, that the word “facility” is often understood colloquially torefer to a single power plant, which may have one or more EGUs co-located within the plant’s
boundaries.
385
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

section VII.E.1 of this preamble. Designated EGUs that may be excluded from a state plan are:
(1) Units that are subject to 40 CFR part 60, subpart TTTT, as a result of commencing aqualifying 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 baseload 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 ofthe 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 isused 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 this386
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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, in general, proposing the same emission guidelines for 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 noncontiguous 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 theiruniquely 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 noncontiguous 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.
The EPA notes that existing IGCC units are included in the proposed applicability
requirements and that, in section X.C.1 of this preamble, the EPA is proposing to include thoseunits in the subcategory of coal-fired steam generating units. IGCC units gasify coal or solid
fossil fuel (e.g., pet coke) to produce syngas (a mixture of carbon monoxide and hydrogen), andeither burn the syngas directly in a combined cycle unit or use a catalyst for water-gas shift(WGS) to produce a pre-combustion gas stream with a higher concentration of CO2 andhydrogen, which can be burned in a hydrogen turbine combined cycle unit. As described in
section X.D of this preamble, the proposed BSER for coal-fired steam generating units includes
co-firing natural gas and CCS, depending on their operating horizon. The few IGCC units thatnow operate in the U.S. either burn natural gas exclusively – and as such operate as natural gas
387
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

combined cycle units – or in amounts near to the 40 percent level of the natural gas co-firing
BSER. Additionally, IGCC units are suitable for pre-combustion CO2 capture. Because the CO2
concentration in the pre-combustion gas, after WGS, is high relative to coal-combustion flue gas,pre-combustion CO2 capture for IGCC units can be performed using either an amine-based
capture process or a physical absorption capture process. For these reasons, the EPA is notproposing to distinguish IGCC units from other coal-fired steam generating EGUs, so that the
BSER of co-firing for medium-term coal-fired units and CCS for long-term coal-fired units
apply to IGCC units. 527
C. 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 ofemission limitation may be applicable to different subcategories. Subcategorizing allows fordetermining 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 fueltype, 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 XII.B of this preamble
comment is solicited on the compliance deadline (i.e., January 1, 2030), for imminent-term andnear-term coal-fired steam generating units, and different subcategories of natural gas- and oilfired steam generating units.

527

For additional details on pre-combustion CO2 capture, please see the GHG Mitigation
Measures for Steam Generating Units TSD.
388
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

1. Subcategorization by Fossil Fuel TypeIn this action, the EPA is proposing definitions for subcategories of existing fossil fuelfired 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 percentof the average annual heat input during the 3 calendar years prior to the proposed compliancedeadline (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 thedefinition 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 firecoal 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 thatno longer retains the capability to fire coal after December 31, 2029.
389
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

2. 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 lessthan 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 thanor 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. Because noncontinental oil-fired units may operate differently, the EPA is proposing a separate subcategory
for intermediate and base load non-continental oil-fired units. The rationale for the proposed load
thresholds and other subcategories is detailed in the description of the BSER for oil- and natural
gas-fired steam generating units in section X.E of this preamble.
3. Subcategorization of Coal-fired Steam Generating Units by Operating Horizon and Load
Level
The EPA is proposing CCS with 90 percent capture as BSER for existing coal-fired
steam generating units that will operate in the long-term (i.e., those that intend to operate on orafter January 1, 2040), as detailed in section X.D of this preamble. CCS is adequately
demonstrated at coal-fired steam generating units, is cost reasonable, achieves meaningful
reductions in GHG emissions, and meets the other criteria for the BSER. The EPA is soliciting
comment on a range of maximum capture rates (90 to 95 percent or greater) and, to potentiallyaccount 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

390This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

reduction in average annual emission rate, defined in terms of pounds of CO2 per unit ofgeneration).
During the EPA’s engagement with stakeholders to inform this proposed rule, industry
commenters to the pre-proposal docket noted that many sources have plans to permanently cease
operation in the coming years, and that GHG control technologies might not be cost reasonable
for those units operating on shorter timeframes. Further, industry stakeholders recommended thatthe emission guidelines account for industry plans for permanently ceasing operation of coalfired steam generating units by establishing a “subcategory pathway.” Specifically, industry
stakeholders requested that, “[The] EPA should provide a subcategory pathway for units todecommission/repower into the early 2030s, which would include enforceable shutdown
obligations, as part of an approach to existing unit guidelines.” The stakeholders cited, as aprecedent, the EPA’s creation of –targeted subcategories for unit closures in other contexts, most notably thecessation of coal subcategory in the 2020 Clean Water Act (CWA) steam electriceffluent guidelines ... that allows for decommissioning/repowering by December
31, 2028. This subcategory allows those facilities that have already filed closurecommitments to continue on a path to decommission/repower these assets without
installing additional control equipment that could extend the lives of these units to
support cost recovery.
EPA-HQ-OAR-2022-0723-0024. In subsequent comment, industry stakeholders reiterated that,“[The] EPA should proactively include a subcategory that allows for units to opt-in to a federally
enforceable retirement commitment as part of compliance with regulations for existing sources
under CAA section 111(d).” EPA-HQ-OAR-2022-0723-0038. Thus, industry stakeholders
recommended that EPA allow existing sources that are on a path to near term retirement tocontinue on that path without having to install additional control equipment.
391
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

The proposed emission guidelines are aligned with this recommendation. Many fossil
fuel-fired steam generating units have plans to cease operations, are part of utilities withcommitments 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 hasplanned to cease operations by 2040. 528 These plans are part of the industry trend, described in
section IV.F and IV.I, in which owners and operators of the nation’s coal fleet, much of it aging,are replacing their units with natural gas combustion turbines and, increasingly, renewableenergy.
As industry stakeholders have pointed out, in previous rulemakings, the EPA has allowed
coal-fired EGUs with plans to voluntarily cease operations in the near future to continue with
their plans without having to install pollution control equipment. In addition to the 2020 CWA
steam electric effluent guidelines these stakeholders cite, the EPA has also approved regionalhaze state implementation plans in which coal-fired EGUs that voluntarily committed to cease
operations by a certain date were not subject to more stringent controls. 529
The EPA proposes to take the approach requested by industry stakeholders in thisrulemaking. The EPA recognizes that the cost reasonableness of GHG control technology
options differ depending on a coal-fired steam generating unit’s expected operating time horizon.
Certain technologies that are cost reasonable for EGUs that intend to operate for the long term

528

See the Power Sector Trends TSD.
See, e.g., 76 FR 12651, 12660-63 (March 8, 2011) (best available retrofit technology
requirements for Oregon source based on enforceable retirement that were to be made federally
enforceable in state implementation plan).
392
529This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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.
Accordingly, the EPA is proposing to divide the subcategory for coal-fired units into
additional subcategories based on operating horizon (i.e., dates for electing to permanently cease
operation) and, for one of those subcategories, load level (i.e., annual capacity factor), with aseparate BSER and degree of emission limitation corresponding to each subcategory. Coal-fired
steam generating units would be able to opt into these subcategories if they elect to commit topermanently ceasing operations by a certain date (and, in the case of one subcategory, elect tocommit to an annual capacity factor limitation), and also elect to make such commitments
federally enforceable and continuing by including them in the state plan.
Specifically, the EPA is proposing four subcategories for steam generating units by
operating horizon (i.e., 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 (1) Have elected to commit to permanently cease operations prior to January 1,
2032, and (2) elect to make that commitment federally enforceable and continuing by having it

393This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

included in the state plan. 530 “Near-term” steam generating units are those that (1) Have elected
to commit to permanently cease operations by December 31, 2034, as well as to adopt an annual
capacity factor limit of 20 percent, and (2) elect to make both conditions federally enforceable
and continuing by having them included in the state plan. “Medium-term” steam generating units
are those that (1) Operate after December 31, 2031, (2) have elected to commit to permanently
cease operations prior to January 1, 2040, (3) elect to make that commitment federally
enforceable and continuing by having it included in the state plan, and (4) do not meet thedefinition of near-term units. “Long-term” steam generating units are those that have not elected
to commit to permanently cease operations prior to January 1, 2040. Details regarding theimplementation of subcategories in state plans are available in section XII.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 XII.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

530

Operating conditions that are within the control of a source must, under a range of CAA
programs, be made federally enforceable in order for a source to rely on them as the basis for aless stringent standard. See, e.g., 76 FR 12651, 12660-63 (March 8, 2011) (best available retrofit
technology requirements for Oregon source based on enforceable retirement that were to bemade federally enforceable in state implementation plan); Guidance on Regional Haze State
Implementation Plans for the Second Implementation Period at 34, EPA-457/B-19-003, August
2019 (to the extent a state relies on an enforceable shutdown date for a reasonable progress
determination, that measure would need to be included in the SIP and/or be federally
enforceable); 84 FR 32520, 32558 (July 8, 2019) (to the extent a state relies on a source’s
retirement date for a standard of performance under 111(d), that date must be included in thestate plan and will thus be made federally enforceable); 87 FR 79176, 79200-01 (December 23,2022) (proposed revisions to CAA section 111(d) implementing regulations would require statesto include operating conditions, including retirements, in their state plans whenever the stateseeks to rely on that operating condition as the basis for a less stringent standard).
394This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 also solicits comment on whether the existence of the near-term
subcategory makes the imminent-term subcategory unnecessary. More specifically, the EPA
requests comment on the potential to remove the imminent-term subcategory, which as proposed
includes coal-fired steam generating units that have elected to commit to permanently cease
operations prior to January 1, 2032. The EPA is considering an option in which these units would
instead be included in the near-term subcategory (units that have elected to commit topermanently cease operations before January 1, 2035 and commit to adopt an annual capacity
factor limit of 20 percent) or the medium-term subcategory (units that have elected to commit topermanently cease operations before January 1, 2040 and that are not near-term units). The EPA
further requests comment on an alternative, modified approach for units in the imminent-term
subcategory that could take into account how units intending to cease operations operate inpractice in the period leading up to such cessation. For instance, in their last few years ofoperation, those units may operate less than they have historically operated, lowering their total
CO2 mass emissions, but at the same time raising their emission rate (because lower utilization
may result in lower efficiency). The EPA solicits comment on whether it would be appropriate
for the imminent-term units’ standards of performance to reflect the reduced utilization andhigher emission rates through the use of an annual mass emission limitation. Such a limitation
would account for lower utilization, but also allow greater flexibility with regard to hourly
emission rate.
395
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

The EPA is proposing the 10-year operating horizon (i.e., January 1, 2040) as thethreshold between medium-term and long-term subcategories because long-term units will havea longer amortization period and may be better able to fully utilize the IRC section 45Q tax
credit. For the analysis of BSER costs of CCS for long-term units, the EPA assumes a 12-year
amortization period as this is commensurate with the time period the IRC section 45Q tax credit
would be available. Based on the cost analysis performed under that assumption, the EPA is
proposing the costs of CCS for long-term coal-fired units are reasonable, as detailed in section
X.D.1.a.ii of this preamble. To support the 10-year operating horizon threshold, the costs for a
10-year amortization period are shown here. For a 10-year amortization period, assuming a 50
percent capacity factor, costs of CCS for a representative unit are $31/ton of CO2 reduced or$27/MWh of generation. Assuming a 70 percent capacity factor, costs of CCS for arepresentative unit are $6/ton of CO2 reduced or $5/MWh of generation. For the population ofunits planning to operate on or after January 1, 2030, the fleet average costs assuming a 50
percent capacity factor are $24/ton of CO2 reduced or $22/MWh. For the population of units
planning to operate on or after January 1, 2030, the fleet average costs assuming a 70 percent
capacity factor are -$3/ton of CO2 reduced or -$2/MWh. Costs vary depending on capacity factor
assumptions, but are in either case generally comparable to the costs detailed in section
VII.F.3.b.iii(B)(5) of this preamble of other controls on EGUs ($10.60 to $29.00/MWh) and lessthan the costs in the 2016 NSPS regulating GHGs for the Crude Oil and Natural Gas source
category of $98/ton of CO2e reduced (80 FR 56627; September 18, 2015). The EPA is soliciting
comment on the dates and load levels used to define the coal-fired subcategories and is seeking
data and analysis on the impact of those alternative dates and load levels on the compliancerequirements. As noted in section X.D.1.a.ii(C) of this preamble, the costs for CCS may be
396This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 longterm coal-fired steam generating units.
4. 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 “distinguishamong classes, types, and sizes within categories,” as provided under CAA section 111(b)(2) andas 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 thecontrols 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 thatsubcategorizing may be appropriate for sources based on the “costs of control.” 531
Subcategorizing on the basis of operating horizon is consistent with a central characteristic of thecoal-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 tocease operation affects what controls are “best” for different subcategories. Whether the costs ofcontrol are reasonable depends in part on the period of time over which the affected sources can

531

40 CFR 60.22(b)(5), 60.22a(b)(5).

397This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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. 532
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 thispreamble. 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 timeremaining to produce the product. In both cases, certain technologies may not be cost reasonablebecause of the capacity to produce product—i.e., because the costs are spread over less productproduced.
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 thecontrol depends on the type of fuel. In that way, it is similar to subcategorizing by operating

532

Steam Electric Reconsideration Rule, 85 FR 64650, 64679 (October 13, 2020) (distinguishes
between EGUs retiring before 2028 and EGUs remaining in operation after that time).
398
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 operatebecause 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 aparticular 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. Someprior EPA rules for coal-fired sources have made explicit the link between length of time forcontinued operation and type of fuel combusted by codifying federally enforceable retirement
dates as the dates by which the source must “cease burning coal.” 533
It should be noted that subcategorizing on the basis of operating horizon does notpreclude a state from considering RULOF in applying a standard of performance to a particularsource. EPA’s authority to set BSER for a source category (including subcategories) and a state’s
authority to invoke RULOF for individual sources within a category or subcategory are distinct.
EPA’s statutory obligation is to determine a generally applicable BSER for a source category,
and where that source category encompasses different classes, types, or sizes of sources, to set
generally applicable BSERs for subcategories accounting for those differences. By contrast,
states’ authority to invoke RULOF is premised on the state’s ability to take into account thecharacteristics of a particular source that may differ from the assumptions EPA made in
determining BSER generally. As noted above, the EPA is proposing these subcategories in533

See 79 FR 5031, 5192 (January 30, 2014) (explaining that “[t]he construction permit issued
by Wyoming requires Naughton Unit 3 to cease burning coal by December 31, 2017 and to be
retrofitted to natural gas as its fuel source by June 30, 2018” (emphasis added)).
399
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

response to requests by power sector representatives that this rule accommodate the fact that
there is a class of sources that plans to voluntarily cease operations in the near term. Although
the EPA has designed the subcategories to accommodate those requests, a particular source may
still present source-specific considerations – whether related to its remaining useful life or otherfactors—- that the state may consider relevant for the application of that particular source’s
standard of performance, and that the state should address as described in section XII.D.2 of thispreamble.
D. 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 sectionof 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 longterm, the EPA is proposing other measures as BSER for the other subcategories of existing coalfired steam generating units.
Specifically, for medium-term units, that is, ones that have elected to commit topermanently cease operations after December 31, 2031, and before January 1, 2040, and are notnear-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 operating horizon (i.e., between 8 and 10
years, instead of the proposed 10-year operating horizon) that defines the threshold date between
400This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 themedium-term subcategory as proposed.
For imminent-term and near-term units, that is, ones that have elected to commit topermanently cease operations before January 1, 2032, and between December 31, 2031, andJanuary 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.
The EPA is also soliciting comment on a potential BSER based on low levels of natural gas cofiring for imminent- and near-term units.
1. 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 theamount of capture of CO2 from 90 to 95 percent or greater. CCS achieves substantial reductions
in emissions and can capture and permanently sequester more than 90 percent of CO2 emitted bycoal-fired steam generating units. The technology is adequately demonstrated, as indicated by thefacts 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, the costs for CCS arereasonable, in light of recent technology cost declines and policies including the tax credit under
IRC section 45Q. Moreover, the non-air quality health and environmental impacts and energy
requirements of CCS are not unreasonably adverse. These factors provide the basis for proposing

401This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

CCS as BSER for these sources. In addition, determining CCS as the BSER promotes this useful
GHG emission 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 substantially 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.
a. CCSIn 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 theparts 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.
i. 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 proposethat 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. Indeed, even without the requirements
402This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

proposed here, the EPA projects that 9 GW of coal-fired steam generating units would apply
CCS by 2030. 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 isadequately 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) of this preamble.
(A) CO2 Capture Technology
The technology of CO2 capture, in general, is detailed in accompanying TSDs (available
in the docket) and 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 existingcoal-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, arediscussed in section X.D.1.a.iii of this preamble. As detailed in section VII.F.3.b.iii(A) of thispreamble, 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 influe 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 isadequately demonstrated on the basis of Boundary Dam Unit 3 alone, CO2 capture has beenfurther 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
403
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 thedemonstration 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 theadequate demonstration of CO2 capture.
(B) CO2 Transport
As discussed in section VII.F.3.b.iii of this preamble, CO2 pipelines are available andtheir network is expanding in the U.S., and the safety of existing and new supercritical CO2
pipelines is comprehensively regulated by PHMSA. 534 Other modes of CO2 transportation also
exist.
Based on data from DOE/NETL studies of storage resources, 77 percent of existing coalfired 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 (62miles) of potential sequestration sites. 535 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

534

PHMSA additionally 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. For more information, see:https://www.phmsa.dot.gov/news/phmsa-announces-new-safety-measures-protect-americanscarbon-dioxide-pipeline-failures.
535
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. For
details please see Chapter 6 of the IPM documentation available at:https://www.epa.gov/system/files/documents/2021-09/chapter-6-co2-capture-storage-andtransport.pdf.
404This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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.

536 537

As noted in section

VII.F.3.b.iii(A)(5) of this preamble, areas without reasonable access to pipelines for geologic
sequestration can transport CO2 to sequestration sites via other transportation modes such as
ship, road tanker, or rail tank cars.
(C) 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 VII.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. hasdeveloped 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 theauthority 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 fromthe DOE, the USGS, and the EPA, the EPA found that there are 43 states with access to, or are536

The pipeline diameter was sized for this to be achieved without the need for recompression
stages along the pipeline length.
537
Note that the determination that the BSER has been adequately demonstrated does not requirethat every source in the long-term coal-fired steam generating unit subcategory be within 100 km
of CO2 storage.
405This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

within 100 km from, onshore or offshore storage in deep saline formations, unmineable coalseams, 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. 538
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 arelocated within 40 miles (80 km) of the boundary of a saline reservoir, and 82 percent are locatedwithin 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. 539 540 As noted in section VII.F.3.b.iii(A)(5) of this preamble, areas without
reasonable access to pipelines for geologic sequestration can transport CO2 to sequestration sites
via other transportation modes such as ship, road tanker, or rail tank cars.
ii. 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 thisanalysis demonstrates that the costs of CCS for these sources are reasonable. The EPA also
evaluated costs assuming a higher capacity factor of 70 percent (resulting in lower costs) and538

For details, please see Chapter 6 of the IPM documentation.
https://www.epa.gov/system/files/documents/2021-09/chapter-6-co2-capture-storage-andtransport.pdf.
539
The distance of 100 km is consistent with the assumptions underlying the NETL costestimates for transporting CO2 by pipeline.
540
Note that the determination that the BSER has been adequately demonstrated does not requirethat every source in the long-term coal-fired steam generating unit subcategory be within 100 km
of CO2 storage.
406This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

different amortization periods, as discussed in section X.D.1.a.ii(C) of this preamble. The EPA is
soliciting comment on the assumptions in the cost analysis, particularly with respect to thecapacity factor assumption. As elsewhere in this section of the preamble, costs are presented in2019 dollars.
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. Included in these estimates is
the EPA’s assessment that the transport and storage costs are roughly $30/ton, on average for thereference unit. 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
and including source specific transport and storage costs, the average total costs of CCS are$8/ton of CO2 reduced and $7/MWh. 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 detailed in section VII.F.3.b.iii(B)(5) of thispreamble (i.e., emission control costs on EGUs of $10.60 to $29/MWh and the costs in the 2016
NSPS regulating GHGs for the Crude Oil and Natural Gas source category of $98/ton of CO2e
reduced (80 FR 56627; September 18, 2015)) the costs for CCS on long-term coal-fired steam
generating units are similar or better. Based on all of these analyses, the EPA is proposing thatfor the purposes of the BSER analysis, CCS is cost reasonable for long-term coal-fired steam
407
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

generating units. The EPA also evaluated costs of CCS under various other assumptions ofamortization 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 costof the technology.
(A) 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,” 541 and the “Pulverized Coal Carbon Capture Retrofit Database.” 542 In
addition, the EPA developed an independent engineering cost assessment for CCS retrofits, withsupport from Sargent and Lundy. 543(B) CO2 Transport and Sequestration Costs
As discussed in section VII.F.3.b.iii of this preamble, NETL’s “Quality Guidelines forEnergy 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-topoint pipeline. Estimated costs reflect pipeline capital costs, related capital expenditures, and541

https://netl.doe.gov/projects/files/CostAndPerformanceBaselineForFossilEnergyPlantsVolume1
BituminousCoalAndNaturalGasToElectricity_101422.pdf.
542
https://netl.doe.gov/energy-analysis/details?id=69db8281-593f-4b2e-ac68-061b17574fb8.
543
Detailed cost information, assessment of technology options, and demonstration of costreasonableness can be found in the GHG Mitigation Measures for Steam Generating Units TSD.
408
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

operations and maintenance costs. 544 These Quality Guidelines also provide an estimate ofsequestration costs reflecting the cost of site screening and evaluation, permitting andconstruction costs, the cost of injection wells, the cost of injection equipment, operation andmaintenance costs, pore volume acquisition expense, and long-term liability protection. NETL’s
Quality Guidelines model costs for a given cumulative storage potential. 545(C) 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 historicalfleet average. However, increases in utilization are likely to occur for units that apply CCS due tothe incentives provided by the IRC section 45Q tax credit. Therefore, the EPA also assessed thecosts 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 negative at -$8/ton of CO2 reduced and -$7/MWh. The
negative costs indicate that the value of the 45Q tax credit more than offsets the costs to installand operate CCS. For either capacity factor assumption, the $/MWh costs are comparable to orless than the costs for other controls ($10.60–$29.00/MWh) which are detailed in section
VII.F.3.b.iii(B)(5) of this preamble.

544

Grant, T., et al. “Quality Guidelines for Energy System Studies; Carbon Dioxide Transportand Storage Costs in NETL Studies.” National Energy Technology Laboratory. 2019.
https://www.netl.doe.gov/energy-analysis/details?id=3743.
545
Details on CO2 transportation and sequestration costs can be found in the GHG Mitigation
Measures for Steam Generating Units TSD.
409
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

As noted in section X.C.3 of this preamble, the EPA is also taking comment on theoperating horizon that defines the threshold date between the definition of medium-term andlong-term coal-fired steam generating units, specifically an operating horizon between 8 and 10
years (i.e., January 1, 2038 to January 1, 2040), instead of the proposed 10-year operating
horizon. For a 70 percent annual capacity factor and an 8-year amortization period, annualized
costs of applying CCS for the reference unit are $24/ton of CO2 reduced and $21/MWh, and it ispossible 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 $39/ton of CO2 reduced and $34/MWh. Additional details of the cost analysis are available in
the GHG Mitigation Measures for Steam Generating Units TSD.
(D) 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 thisconclusion: the costs of CCS technology have fallen and the extension and increase in the IRC
section 45Q tax credit, as included in the IRA, in effect provide a significant stream of revenue
for sequestered 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 incremental
levelized cost of CCS at a new pulverized coal facility relative to a new facility without CCS at

410
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

$74/MWh (2022$), 546 while the 2022 report estimated incremental levelized cost at $44/MWh(2022$). 547 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 IRA alsoenhanced the realized value of the tax credit through the direct pay and transferability
monetization options described in section IV.E.1. The combination of lower costs and higher tax
credits significantly improves the cost effectiveness of CCS for purposes of determining whether
it qualifies as the BSER.
iii. 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. The EPA has considered non-GHG emissions impacts, the water use impacts, thetransport 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.
As noted in section VII.F.3.b.iii(C) of this preamble, stakeholders have shared with the
EPA concerns about the safety of CCS projects and concerns that their communities may bear adisproportionate environmental burden associated with CCS projects. The EPA is committed to546

Cost And Performance Baseline for Fossil Energy Plants Volume 1: Bituminous Coal andNatural Gas to Electricity, Rev. 3 (July 2015).
https://www.netl.doe.gov/projects/files/CostandPerformanceBaselineforFossilEnergyPlantsVolu
me1aBitCoalPCandNaturalGastoElectRev3_070615.pdf.
547
Cost And Performance Baseline for Fossil Energy Plants Volume 1: Bituminous Coal andNatural Gas to Electricity, Rev. 4A (October 2022).
https://netl.doe.gov/projects/files/CostAndPerformanceBaselineForFossilEnergyPlantsVolume1
BituminousCoalAndNaturalGasToElectricity_101422.pdf.
411
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

working with its fellow agencies to foster meaningful engagement with communities and protect
communities from pollution through the responsible deployment of CCS. This can be facilitatedthrough the existing detailed regulatory framework for CCS projects and further supported
through robust and meaningful public engagement early in the technological deployment
process. CCS projects undertaken pursuant to these emission guidelines will, if the EPA finalizes
proposed revisions to the CAA section 111 implementing regulations, 548 be subject torequirements for meaningful engagement as part of the state plan development process. See
section XII.F.1.b of this preamble for additional details.
(A) 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 anenergy-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 andelectricity 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 CO2emissions from the connected auxiliary equipment need to be captured or they will increase thefacility’s emission rate.
Using integrated heat and power can reduce the capacity (i.e., the amount of electricity
that a unit can distribute to the grid) of an approximately 474 MW-net (501 MW-gross) coal-

548

87 FR 79176, 79190-92 (December 23, 2022).

412

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

fired steam generating unit without CCS to approximately 425 MW-net with CCS andcontributes to a reduction in net efficiency of 23 percent. 549 For retrofits of CCS on existingsources, the ductwork for flue gas and piping for heat integration to overcome potential spatialconstraints are a component of efficiency reduction. The EPA notes that slightly greater
efficiency reductions than in the 2016 NETL retrofit report are assumed for the BSER cost
analyses, as detailed in the GHG Mitigation Measures for Steam Generating Units TSD,
available in the docket. Despite decreases in efficiency, IRC section 45Q tax credits provide an
incentive for increased generation with full operation of CCS because the credits are proportional
to the amount of captured and sequestered CO2 emissions and not to the amount of electricity
generated. 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 andlong-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 ofcoal-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

549

DOE/NETL-2016/1796. “Eliminating the Derate of Carbon Capture Retrofits.” May 31,
2016. https://www.netl.doe.gov/energy-analysis/details?id=d335ce79-84ee-4a0b-a27bc1a64edbb866.
413
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

of the coal-fired steam generating unit capacity applying CCS. The time available before thecompliance 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 coalfired 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 coalfired 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 othersources. Additionally, for the long-term units applying CCS, the EPA is proposing the increasein 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.Fof 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.
(B) 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 haveor may need to install to meet other CAA requirements. Decreases in efficiency result in
414This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 ofelectricity generated. Additionally, increased utilization would otherwise result in increases intotal 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 needan 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 (e.g., heat exchangers)of the capture process. NOX emissions can cause solvent degradation and nitrosamine formationby chemical absorption of NOX, depending on the chemical structure of the solvent. The DOE’s
Carbon Management Pathway report notes that monitoring and emission controls for suchdegradation products are currently part of standard operating procedures for amine-based CO2
capture systems. 550 A conventional multistage water or acid wash and mist eliminator at the exitof the CO2 scrubber is effective at removal of gaseous amine and amine degradation products(e.g., nitrosamine) emissions. 551 552 NOX levels of the flue gas required to avoid solvent

550

U.S. Department of Energy (DOE). Pathways to Commercial Liftoff: Carbon Management.
https://liftoff.energy.gov/wp-content/uploads/2023/04/20230424-Liftoff-Carbon-ManagementvPUB_update.pdf.
551
Sharma, S., Azzi, M., “A critical review of existing strategies for emission control in themonoethanolamine-based carbon capture process and some recommendations for improved
strategies,” Fuel, 121, 178 (2014).
552
Mertens, J., et al., “Understanding ethanolamine (MEA) and ammonia emissions from aminebased post combustion carbon capture: Lessons learned from field tests,” Int’l J. of GHG
Control, 13, 72 (2013).
415
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 theexisting 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 regulatinginterstate transport of NOX (as an ozone precursors) from EGUs. See 87 FR 20036 (April 6,2022). For units not otherwise required to have SCR, an increase in utilization from a CO2
capture retrofit could result in increased NOX emissions at the source that, depending on thequantity of the emissions increase, may trigger major NSR permitting requirements. Under this
scenario, the permitting authority may determine that the NSR permit requires the installation of
SCR for those units, based on applying the requirements of major NSR. Alternatively, a state
could, as part of its state plan, develop enforceable conditions for a source expected to trigger
major NSR that would effectively limit the unit’s ability to increase its emissions in amounts thatwould trigger major NSR. Under this scenario, with no major NSR requirements applying due tothe limit on the emissions increase, the permitting authority may conclude for minor NSR
purposes that installation of SCR is not required for the units. See section XIII.A of thispreamble for additional discussion of the NSR program.
(C) 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

416This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

basis. 553 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 cooling system. For
example, the cooling system cited in the CCS feasibility study for SaskPower’s Shand Powerstation would rely entirely on water condensed from the flue gas and thus would not require any
increase in external water consumption. 554 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 physicalfootprint and a consequent land-use requirement. The EPA is proposing that the water use andsiting 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 andoperate CCS. However, the EPA is soliciting comment on these issues.
(D) Transport and Geologic Sequestration
As noted in section VII.F.3.b.iii of this preamble, PHMSA oversight of supercritical 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 theprotection of USDWs and the security of geologic sequestration.

553

DOE/NETL-2016/1796. “Eliminating the Derate of Carbon Capture Retrofits.” May 31,
2016. https://www.netl.doe.gov/energy-analysis/details?id=e818549c-a565-4cbc-94db442a1c2a70a9.
554International CCS Knowledge Centre. The Shand CCS Feasibility Study Public Report.
https://ccsknowledge.com/pub/Publications/Shand_CCS_Feasibility_Study_Public_Report_Nov2018_(2021-05-12).pdf.
417This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

iv. 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 alb/MWh-gross basis and 87.1 percent lower on a lb/MWh-net basis compared to units without
capture. 555 After capture, CO2 can be transported and securely sequestered. 556 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.
v. Technology Advancement
The EPA considered the potential impact of designating CCS as the BSER for long-termcoal-fired steam generating units on technology advancement, and the EPA is proposing thatdesignating CCS as the BSER will provide for meaningful advancement of CCS technology, formany of the same reasons as noted in section VII.F.3.b.iii(F) of this preamble.
vi. Comparison With 2015 NSPS For Newly Constructed Coal-fired EGUs
In the 2015 NSPS, the EPA determined that the BSER for newly constructed coal-fired
EGUs was based on CCS with 16-23 percent capture, based on the type of coal combusted, and555

DOE/NETL-2016/1796. “Eliminating the Derate of Carbon Capture Retrofits.” May 31,
2016. https://www.netl.doe.gov/energy-analysis/details?id=e818549c-a565-4cbc-94db442a1c2a70a9.
556Intergovernmental Panel on Climate Change. (2005). Special Report on Carbon Dioxide
Capture and Storage.
418This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

consequently, the EPA promulgated standards of performance of 1,400 lb CO2/MWh-g. 80 FR
64512 (Table 1), 64513 (October 23, 2015). The EPA made those determinations based on thecosts of CCS at the time of that rulemaking. In general, those costs were significantly higher thanat present, due to recent technology cost declines as well as related policies, including the IRC
section 45Q tax credit for CCS, which was not available at that time for purposes ofconsideration during the development of the NSPS. Id. at 64562 (Table 8). Based on of thesehigher costs, the EPA determined that 16 – 23 percent capture qualified as the BSER, and not asignificantly higher percentage of capture. Given the substantial differences in the cost of CCS
during the time of the 2015 NSPS and the present time, the capture percentage of the 2015 NSPS
necessarily differed from the capture percentage in this proposal, and, by the same token, theassociated degree of emission limitation and resulting standards of performance necessarily
differ as well.
b. Natural Gas Co-firing
The EPA also evaluated natural gas co-firing at 40 percent of the heat input as thepotential 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 mediumterm and long-term units are discussed in section X.D.2.b of the preamble. Based on thediscussion 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 notunreasonable. 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 40 percent natural gas co-firing achieves unit-level emission rate
reductions of 16 percent, those reductions are less than CCS with 90 percent capture. Therefore,
419
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

because CCS achieves more reductions at the unit level and is proposed as cost reasonable forlong-term units, the EPA is not proposing natural gas co-firing as the BSER for long-term coalfired steam generating units.
c. Conclusion
The EPA proposes that CCS at a capture rate of 90 percent is the BSER for long-termcoal-fired steam generating units because CCS is adequately demonstrated, as indicated by thefacts that it has been operated at scale and is widely applicable to sources and that there are vast
sequestration opportunities across the continental U.S. Additionally, accounting for recent
technology cost declines as well as policies including the tax credit under IRC section 45Q, thecosts 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 GHG emission reductionsat 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 longterm coal-fired power plants. In addition, determining CCS as the BSER promotes this usefulcontrol technology. Although the EPA believes that long-lived coal-fired power plants will
generally be able to implement and operate CCS within the cost parameters calculated as part ofthe BSER analysis, and therefore that they would be able to meet a standard of performancebased on CCS with 90 percent capture, the EPA solicits comment on whether particular plants
would be unable to do so, including details of the circumstances that might make retrofitting withCCS unreasonable or infeasible.

420
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

2. 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 isrelevant for medium-term units. However, because they have shorter operating horizons and, as aresult, 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 nothave adverse non-air quality health and environmental impacts or energy requirements, andachieves 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.
a. CCSIn 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 theevaluation 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 toevaluate the reasonableness of CCS costs employs a 12-year amortization period, which is421
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 have elected to commit to permanently
cease operations prior to 2040—ones in the medium-term subcategory, as well as in the nearterm, 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 thesesources, the cost effectiveness of CCS is less favorable. As noted in section X.D.1.a.ii(C) of thispreamble, for a 70 percent annual capacity factor and a 7-year amortization period, costs for thereference unit are $39/ton of CO2 reduced and $34/MWh. This $/MWh generation cost is lessfavorable relative to the representative cost ($/MWh) for wet FGD, the costs for which aredetailed 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 mediumterm units, the EPA is taking comment on the operating horizon (i.e., between 8 and 10 years,
instead of the proposed 10-year operating horizon) that most appropriately defines the thresholddate between medium-term and long-term units and the EPA is also taking comment on the levelof costs of CCS that should be considered reasonable.
b. 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 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.”
422This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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.
i. Adequately Demonstrated
The EPA is proposing to find that natural gas co-firing at the level of 40 percent ofannual heat input is adequately demonstrated for coal-fired steam generating units. Many
existing coal-fired steam generating units already use some amount of natural gas, and several
have co-fired at relatively high levels at or above 40 percent of heat input in recent years.
(A) Boiler Modifications
Most existing coal-fired steam generating units can be modified to co-fire natural gas inany desired proportion with coal, up to 100 percent natural gas. Generally, the modification ofexisting boilers to enable or increase natural gas firing typically involves the installation of newgas burners and related boiler modifications, including, for example, new fuel supply lines andmodifications 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 ofthem 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 atfull 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 cofired natural gas at considerably higher shares. Based on hourly reported CO2 emission rates
423
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

from the start of 2015 through the end of 2020, 29 coal-fired steam generating units co-fired withnatural gas at rates at or above 60 percent of capacity on an hourly basis. 557 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 technicallycapable of co-firing at least 60 percent natural gas on a heat input basis on average over thecourse 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 for
Steam Generating Units TSD.
(B) Natural Gas Pipeline Development
In addition to any potential boiler modifications, the supply of natural gas is necessary toenable 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 accessbeyond 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 ofpipelines 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 is557

U.S. Environmental Protection Agency (EPA). “Power Sector Emissions Data.” Washington,
DC: Office of Atmospheric Protection, Clean Air Markets Division. Available from EPA’s Air
Markets Program Data web site: https://campd.epa.gov.
424

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

necessary to connect the facility to the natural gas pipeline transmission network via theconstruction 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 for Steam Generating Units 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 averagebasis.
The EPA considered the availability of the upstream natural gas pipeline capacity tosatisfy 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-firingexpected under the proposed rule.
The maximum amount of pipeline capacity, if all coal-fired steam capacity in themedium-term subcategory implemented the proposed BSER by co-firing 40 percent natural gas,425This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

would be a fraction of the pipeline capacity constructed recently. The EPA estimates that thismaximum total capacity would be about 17.3 billion cubic feet per day, which would requirealmost 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 toindustry 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 through2035, which is similar to the approximately 1,670 miles that were built on average from 2013 to2017. 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

426This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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.
ii. Costs
The capital costs associated with the addition of new gas burners and other necessary
boiler modifications depend on the extent to which the current boiler is already able to co-firewith 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 orlower, depending on the equipment that is already installed and the expected impact on heat rateor steam temperature.
While fixed O&M (FOM) costs can potentially decrease as a result of decreasing theamount 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 thiscase, 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 asignificant 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 heatrate. The EPA’s post-IRA 2022 reference case projects that in 2030, the average delivered priceof 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, the427This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 ofgeneration and thus additional cost. In the GHG Mitigation Measures for Steam Generating
Units 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 forlateral 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, thetotal 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 thoseexisting 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
428This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

estimates, as explained in the GHG Mitigation Measures for Steam Generating Units 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 coalfired 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 thecharacteristics 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 apipeline 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 costestimate 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 for Steam Generating Units TSD.
As was described in section X.D.1 of this preamble, the EPA has compared the estimatedcosts 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. Compared to the429This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

representative costs of controls detailed in section VII.F.3.b.iii(B)(5) of this preamble (i.e.,emission control costs on EGUs of $10.60 to $29/MWh and the costs in the 2016 NSPS
regulating GHGs for the Crude Oil and Natural Gas source category of $98/ton of CO2e reduced(80 FR 56627; September 18, 2015)), both estimates of annualized costs of natural gas co-firing(approximately $53-$66/ton or $9-$12/MWh for a typical unit and $64-$78/ton or $11$14/MWh on average)) are comparable or lower. The range of cost effectiveness estimatespresented in this section is lower than previously estimated by the EPA in the proposed CPP, forseveral 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 costfor modifying existing boilers to co-fire with natural gas. The EPA also recently conducted ahighly detailed facility-level analysis of natural gas pipeline costs, the median value of which isslightly lower than the value used by the EPA previously to approximate the cost of co-firing at a
representative unit.
Based on the cost analysis presented in this section, the EPA is proposing that the costs ofnatural gas co-firing are reasonable for the medium-term coal-fired steam generating unit
subcategory.
iii. Non-air Quality Health and Environmental Impact and Energy Requirements
Natural gas co-firing for steam generating units is not expected to have any significant
adverse consequences related to non-air quality health and environmental impacts or energy
requirements.

430
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

(A) 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 thisreduction 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 thatassure 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 rulethat will improve the safety and strengthen the environmental protection of more than 300,000
miles of onshore gas transmission pipelines.558 PHMSA also recently promulgated a rule
covering natural gas transmission,559 as well as a rule that significantly expanded the scope ofsafety and reporting requirements for more than 400,000 miles of previously unregulated gas
gathering lines. 560 Additionally, FERC oversees the development of new natural gas pipelines.

558

Pipeline Safety: Safety of Gas Transmission Pipelines: Repair Criteria, Integrity Management
Improvements, Cathodic Protection, Management of Change, and Other Related Amendments(87 FR 52224; August 24, 2022).
559
Pipeline Safety: Safety of Gas Transmission Pipelines: MAOP Reconfirmation, Expansion ofAssessment Requirements, and Other Related Amendments (84 FR 52180; October 1, 2019).
560
Pipeline Safety: Safety of Gas Gathering Pipelines: Extension of Reporting Requirements,
Regulation of Large, High-Pressure Lines, and Other Related Amendments (86 FR 63266;
November 15, 2021).
431
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

(B) Energy Requirements
The introduction of natural gas co-firing will cause steam boilers to be slightly lessefficient 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 apositive 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 sitespecific analysis would be required to determine the overall net impact of these countervailingfactors, 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 ofnatural 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.

432
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 heatrate can vary within approximately plus or minus 2 percent, and therefore the net impact onoverall 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-termcoal-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 inthese sources would not have significant adverse effects on the price of natural gas or the price ofelectricity.
iv. 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. Whenshifting 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.

433
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

v. Technology Advancement
Natural gas co-firing is already well-established and widely used by coal-fired steam
boiler generating units. As a result, this proposed rule is not likely to lead to technologicaladvances 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 associatedequipment.
c. 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 costeffective, 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 operating horizons that define thethreshold date between medium-term and long-term units (i.e., between 8 and 10 years, insteadof the proposed 10-year operating horizon) and on what amount of costs should be consideredreasonable.

434This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

3. Imminent-term and Near-term Coal-fired Steam Generating Units
In this section of the preamble, the EPA evaluates CCS, natural gas co-firing, low levelsof 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 effectof a short operating horizon on the cost of controls for these units, the EPA proposes routine
methods of operation and maintenance as the BSER.
a. CCSAs noted in section X.D.2.a of this preamble, the EPA is not proposing CCS for mediumterm 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-termand near-term units are available in the GHG Mitigation Measures for Steam Generating Units
TSD.
b. Natural Gas Co-firing
i. Natural Gas Co-firing at 40 Percent
Much of the discussion of natural gas co-firing in section X.D.2.b of this preamble formedium-term units is relevant for imminent-term and near-term units, except that natural gas cofiring is less cost effective for the latter units because of their short operating horizons,particularly on a $/ton of CO2 reduced basis. 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.
435This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Additional details of cost are available in the GHG Mitigation Measures for Steam Generating
Units TSD.
ii. Natural Gas Co-firing at Low Levels of Heat Input
Although higher levels of natural gas co-firing may be less cost effective for imminentterm and near-term units, it is possible that lower levels of natural gas co-firing may be costreasonable. Many units have demonstrated the ability to co-fire with natural gas over shortperiods of time and operating with those same levels of natural gas co-firing over longer periodsof time (i.e., annually) may achieve emission reductions. A low level of natural gas co-firing (upto 10 percent of annual heat input) is adequately demonstrated and may be broadly achievable,
may achieve reductions in GHG emissions, may be of reasonable cost, and is unlikely to cause
unreasonable adverse non-air quality health and environmental impacts or result in substantial
energy requirements. Therefore, the EPA is soliciting comment on low levels of natural gas cofiring as a potential component of the BSER for imminent-term and near-term coal-fired steam
generating units.
The EPA recognizes that different coal-fired units may be already capable of different
natural gas co-firing rates (as discussed in section X.D.2.b.i of this preamble) and is therefore
soliciting comment on defining a potential BSER on the basis of the maximum hourly heat inputof natural gas fired in the unit (MMBtu/hr) relative to the maximum hourly heat input the unit iscapable of (i.e., the nameplate capacity on an MMBtu/hr basis). Alternatively, the EPA is
soliciting comment on a fixed value of annual heat input percentage that represents a low level ofnatural gas co-firing, as well as the definition of a low level of natural gas co-firing that is basedon the characteristics of an existing facility (e.g., the capacity of the existing pipeline). The EPA

436
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

is also soliciting comment on a degree of emission limitation resulting from low levels of natural
gas co-firing, as detailed in section X.D.4.c of this preamble.
(1) Adequately demonstrated
For many of the same reasons stated in section X.D.2.b.i of this preamble for natural gas
co-firing at higher levels, natural gas co-firing at low levels is adequately demonstrated. The
EPA also identified that 369 of the 565 EGUs operating at the end of 2021 have either reported
natural gas as a fuel source, are located at a plant with a natural gas generator, and/or are locatedat a plant with a natural gas pipeline connection. A large percentage of the existing fleet of coalfired steam generating units would therefore likely be able to co-fire natural gas at low levels
without having to make boiler modifications or build additional pipelines.
(2) Costs
The costs of low levels of natural gas co-firing may be reasonable because low levels ofnatural gas co-firing likely require little, if any, capital investment. Additionally, the relatively
small increase in natural gas fuel use would only result in a modest increase in total fuel cost.
(3) Non-air Quality Health and Environmental Impact and Energy Requirements
For many of the same reasons stated in section X.D.2.b.iii of this preamble, low levels ofnatural gas co-firing are unlikely to cause unreasonable adverse non-air quality health andenvironmental impacts or result in substantial energy requirements. Furthermore, low levels ofnatural gas co-firing may require only limited construction of additional infrastructure as existing
pipeline laterals to the units should be of sufficient size to achieve low levels of natural gas cofiring.

437
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

(4) Extent of reductions in CO2 Emissions
The emission reductions achieved at the unit from low levels of natural gas co-firing of 1
to 10 percent may be relatively low at around 0.4 to 4 percent, respectively. However, these arelikely on average greater than the emission reductions that could be achievable by othertechnologies, such as HRI. Furthermore, because the efficiency of the unit is not increased aswith HRI, the unit likely does not move up in dispatch order, and it is likely the unit would not
be subject to the rebound effect. See section X.D.5 of this preamble for a discussion of HRI.
(5) Technology Advancement
Low levels of natural gas co-firing do not advance useful control technology, for reasons
similar to those discussed in section X.D.2.b.v of this preamble.
c. Routine Methods of Operation and MaintenanceFor 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).
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 notadvance useful control technology, they do not have adverse impacts on the energy sector from anationwide or long-term perspective.

438
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

4. 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 ofemission limitation. Proposed presumptive standards of performance are detailed in section
XII.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 emissionrate, as follows:a. Long-term Coal-fired Steam Generating Units
As discussed earlier in this preamble, the EPA is proposing the BSER for long-term coalfired 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 rateof 88.4 percent on a lb CO2/MWh-gross basis, and this reduction in emission rate can beobserved 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 reductionin emission rate on a lb CO2/MWh-gross basis over an extended period (e.g., an annual calendaryear basis).
As noted in section X.D.1.a of this preamble, new CO2 capture retrofits on existing coalfired steam generating units may achieve capture rates greater than 90 percent, and the EPA is
439
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

taking comment on a range of capture rates that may be achievable. As noted in section
VII.F.3.b.iii(A)(2) of this preamble, 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 usuallyless than 100 percent. Assuming that CO2 capture achieves 90 percent capture when available tooperate, 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 isavailable 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 inemission rate of 75 to 90 percent when determined over an extended period (e.g., an annual
calendar-year basis).
b. Medium-term Coal-fired Steam Generating Units
As discussed earlier in this preamble, the BSER for medium-term coal-fired steam
generating units is 40 percent natural gas co-firing. The application of 40 percent natural gas cofiring 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).
c. 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
440
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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).
Because the EPA is soliciting comment on low levels of natural gas co-firing as apotential BSER for imminent-term and near-term units, the EPA is also soliciting comment on
the degree of emission limitation that may be achievable by application of low levels of natural
gas co-firing. The EPA is soliciting comment on degrees of emission limitation defined by
reductions in emission rate on a lb CO2/MWh-gross basis that are equal to the percent of heat
input times 0.4, the percent of reduction in emission rate that may be achieved for each percent
of natural gas heat input. For example, for natural gas co-firing at 1 to 10 percent, this results in adegree of emission limitation of 0.4 to 4 percent reduction in emission rate on a lb CO2/MWhgross basis (over an extended period of time). More specifically, the EPA solicits comment on
the degree of emission limitation based on the calculation method defined in the preceding text
up to a 4 percent reduction in emission rate (lb CO2/MWh-gross) over an extended period oftime. Alternatively, as the EPA is also soliciting comment on a fixed percent of low levels ofnatural gas co-firing, the EPA is additionally soliciting comment on a fixed degree of emission
limitation based on the same calculation method. Because the reductions in GHG emissions fromlow levels of natural gas co-firing are relatively low and may be challenging to measure, the
EPA is also soliciting comment on a degree of emission limitation defined on a percent of heat
input basis, although the EPA also recognizes that measurement of fuel flow may also havechallenges.

441This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

5. Other Emission Reduction Measuresa. Heat Rate Improvements
Heat rate is a measure of efficiency that is commonly used in the power sector. The heatrate 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 kWhgenerated 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 tobe 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.
i. 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 canachieve 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 thebuilding blocks to 2012 baseline data and quantified, in the form of CO2 emission rates, the442This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

reductions achievable in each interconnection in 2030, and then selected the least stringent as anational 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.
ii. 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), and other equipment upgrades (e.g., variable frequency drives). Some regular
practices that may recover degradation in heat rate to recent levels – but that do not result in
upgrades in heat rate over recent design levels and are therefore not HRI measures – include
practices such as in-kind replacements and regular surface cleaning (e.g., descaling, fouling
removal). Specific details of the HRI measures are described in the GHG Mitigation Measuresfor Steam Generating Units TSD and an updated 2023 Sargent and Lundy HRI report (Heat Rate
Improvement Method Costs and Limitations Memo), available in the docket. Most HRI upgrade
measures achieve reductions in heat rate of less than 1 percent. In general, the 2023 Sargent andLundy HRI report, which updates the 2009 Sargent and Lundy HRI report, shows that HRI
achieve less reductions than indicated in the 2009 report, and shows that several HRI either have
limited applicability or have already been applied at many units. Steam path overhaul andupgrade 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 inemission rate (e.g., intelligent sootblowing systems combined with neural network systems).
443
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Some of the HRI measures (e.g., variable frequency drives) only impact heat rate on a net
generation basis by reducing the parasitic load on the unit and would thereby not be observablefor emission rates measured on a gross basis. Assuming many of the HRI measures could beapplied to the same unit, adding together the upper range of some of the HRI percentages could
yield an emission rate reduction of around 5 percent. However, the reductions that the fleet could
achieve on average are likely much smaller. As noted, the 2023 Sargent and Lundy HRI reportnotes that, in many cases, units have already applied HRI upgrades or that those upgrades would
not be applicable to all units. The unit level reductions in emission rate from HRI are small
relative to CCS or natural gas co-firing. In the CPP and ACE Rule, the EPA viewed CCS andnatural gas co-firing as too costly to qualify as the BSER; those costs have fallen since thoserules and, as a result, CCS and natural gas co-firing do qualify as the BSER for the long-term andmedium-term subcategories, respectively.
iii. 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 reboundeffect 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 reboundeffect. Analysis for the ACE Rule, where HRI was the entire BSER, observed a rebound effect444This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

for certain sources in some cases. In this action, where different subcategories of units areproposed to be subject to different BSER measures, steam generating units in a hypotheticalsubcategory 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 expectedfrom this measure, the EPA is not proposing HRI as the BSER for any subcategory of existingcoal-fired steam generating units.
E. 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 thatstates 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 baseload, intermediate load, and low load. At this time, the EPA is not proposing requirements forlow load units but is taking comment on a BSER of lower emitting fuels for those units. The
EPA is proposing routine methods of operation and maintenance as BSER for intermediate andbase 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 thatdiffer between intermediate and base load units due to their differences in operation, as detailed
in section XII.D.1.b.v 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 XII.D.1.b.vi of this preamble.

445
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Natural gas- and oil-fired steam generating units combust natural gas or distillate fuel oilor 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 loadfollowing manner. There are approximately 200 natural gas-fired steam generating units andfewer than 30 oil-fired steam generating units in operation in the continental U.S. Fuel costs andinefficiency 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 thecontiguous 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 lessthan 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 lessefficient. 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 instandby mode requires combusting fuel to keep the boiler warm, and this further reduces theefficiency of natural gas combustion.
Unlike coal-fired steam generating units, the CO2 emission rates of oil- and natural gasfired 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 fuelused. However, the emission rates for units that have different annual capacity factors do varyconsiderably, 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
446
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 thispreamble: “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.
1. Options Considered for BSER
The EPA has considered various methods for controlling CO2 emissions from naturalgas- 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 acandidate for BSER. The utilization of most gas-fired units, and likely all oil-fired units, isrelatively low, and as a result, the amount of CO2 available to be captured is low. However, thecapture 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 tobe captured. Additionally, again due to lower utilization, the amount of IRC section 45Q tax
447
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

credits that owner/operators could claim would be low. Because of the relatively high costs andthe 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 technicallypossible, but, for the same reasons discussed in section VII of this preamble, the only hydrogenthat 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 ispossible 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 clarityand prevent backsliding in GHG performance. Therefore, the EPA is proposing BSER forintermediate 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 base448
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

load natural gas- and oil-fired steam generating units, regardless of the operating horizon of theunit.
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 andthere 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 longterm perspective. The EPA’s initial modeling, which supports this proposed rule, indicates thatby 2040, a number of natural gas-fired steam generating units have remained in operation since2030, although at reduced annual capacity factors. There are no CO2 reductions that may beachieved 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 lower emitting fuels
for low load natural gas- and oil-fired steam generating units. As noted earlier in this preamble,
non-coal fossil fuels combusted in utility boilers typically include natural gas, distillate fuel oil(i.e., fuel oil No. 1 and No. 2), and residual fuel oil (i.e., fuel oil No. 5 and No. 6). The EPA
previously established heat-input based fuel composition as BSER in the 2015 NSPS (termed“clean fuels” in that rulemaking) for new non-base load natural gas- and multi-fuel-fired
stationary combustion turbines (80 FR 64615–17; October 23, 2015), and the EPA is similarly
proposing lower emitting 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, the449This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 thehigh 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 thatwould reflect application of a BSER of routine operation and maintenance. On the other hand,for those units, a BSER of “uniform fuels” and an associated presumptive standard of
performance based on a heat input basis, as described in section XII.D of this preamble, may bereasonable. The EPA is soliciting comment on the fuel types that would constitute “uniform
fuels” specific to low load natural gas- and oil-fired steam generating units.
2. 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 applicationof 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).
F. Summary
The EPA has evaluated options for BSER for GHG emissions for fossil fuel-fired steam
generating units. The EPA is proposing subcategorization of steam generating units by the typeof fossil fuel fired in the unit, and, for each fuel type, further levels of subcategorization. For
each subcategory, the EPA is proposing a BSER and resulting degree of emission limitationachievable by application of that BSER, as summarized in table 5, with presumptively
approvable standards of performance for use in state plan development (see section XII of thispreamble for details) included for completeness. For coal-fired steam generating units that plan
450
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

to operate in the long-term, the EPA is proposing a BSER of CCS with 90 percent capture of
CO2. In response to industry stakeholder input and recognizing that the cost effectiveness ofcontrols depends on a unit’s expected operating time horizon, which dictates the amortization
period for the capital costs of the controls, the EPA is proposing other BSER for coal-fired units
with shorter operating horizons while taking comment on what dates most appropriately define
the thresholds between these different subcategories. For the different subcategories of naturalgas- and oil-fired units, the EPA is proposing BSERs based on routine methods of operation andmaintenance. The EPA solicits comment on the proposed BSER and degrees of emission
limitation, as well as the proposed subcategorization, including the potential to remove theimminent-term subcategory and include units with earlier commitments to permanently cease
operations in either the near-term or medium-term subcategory. It is noted that for imminentterm and near-term coal-fired steam generating units, the EPA is also soliciting comment on
potential BSERs based on co-firing low levels of natural gas.

451
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Table 5—Summary of Proposed BSER, Subcategories, and Degrees of Emission Limitation for
Affected EGUs

Affected
EGUs
Long-term
existing
coal-fired
steam
generating
units

Subcategory
Definition
Coal-fired steam
generating units
that have notelected to commit
to permanently
cease operations
by January 1,
2040

Mediumterm
existing
coal-fired
steam
generating
units

Coal-fired steam
generating units
that have elected
to commit topermanently cease
operations after
December 31,
2031, and before
January 1, 2040,
and that are notnear-term units

BSER
CCS with
90 percent
capture of
CO2

Degree ofEmission
Limitation
88.4 percent
reduction inemissionrate (lb
CO2/MWhgross)Naturalgas cofiring at 40
percent of
the heat
input tothe unit

A 16
percent
reduction inemissionrate (lb
CO2/MWhgross)

Presumptively
ApprovableStandard of
Performance
561

88.4 percent
reduction in
annualemission rate(lb
CO2/MWhgross) fromthe unitspecificbaseline

A 16 percent
reduction in
annualemission rate(lb
CO2/MWhgross) fromthe unitspecificbaseline

Ranges inValues on
Which theEPA isSoliciting
Comment
The achievablecapture ratefrom 90 to 95
percent or
greater and theachievable
degree ofemission
limitation
defined by areduction inemission ratefrom 75 to 90
percent
The percent of
natural gas cofiring from 30
to 50 percent
and the degreeof emission
limitation from12 to 20
percent

561

Presumptive standards of performance are discussed in detail in section XII of the preamble.
While states establish standards of performance for sources the EPA provides presumptively
approvable standards of performance based on the degree of emission limitation achievablethrough application of the BSER for each subcategory. Inclusion in this table is forcompleteness.
452

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Affected
EGUs
Near-term
existing
coal-fired
steam
generating
units

Imminentterm
existing
coal-fired
steam
generating
units

Subcategory
Definition
Coal-fired steam
generating units
that have elected
to commit topermanently cease
operations after
December 31,
2031, and before
January 1, 2035,and commit toadopt an annual
capacity factor
limit of 20 percent
Coal-fired steam
generating units
that have elected
to commit topermanently cease
operations before
January 1, 2032

Degree ofEmission
BSER
Limitation
RoutineNo increase
methods of in emission
operation
rate (lb
CO2/MWhgross)RoutineNo increase
methods of in emission
operation
rate (lb
CO2/MWhgross)Ranges in
Presumptively
Values on
Approvable
Which theStandard of
EPA isPerformance
Soliciting
561
Comment
An emission
The
rate limit (lbpresumptive
CO2/MWhstandard: 0 to 2
gross) defined standard
deviations inby the unitspecificannualemission ratebaseline
above or 0 to
10 percent
above the unitspecificbaseline
An emission
rate limit (lbCO2/MWhgross) definedby the unitspecificbaselineThe
presumptive
standard: 0 to 2
standard
deviations inannualemission rate
above or 0 to
10 percent
above the unitspecificbaseline

453
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Affected
EGUs
Base load
continenta
l existing
oil-firedsteam
generating
units

Subcategory
Definition
Oil-fired steam
generating units
with an annual
capacity factor
greater than orequal to 45
percent

Intermedi
ate load
continenta
l existing
oil-firedsteam
generating
units
Low load(continent
al andnoncontinental) existing
oil-firedsteam
generating
units

Oil-fired steam
generating units
with an annual
capacity factor
greater than orequal to 8 percent
and less than 45
percent
Oil-fired steam
generating units
with an annual
capacity factor
less than 8 percent

Degree ofEmission
BSER
Limitation
RoutineNo increase
methods of in emission
operation
rate (lbandCO2/MWhmaintenan gross)ceRoutinemethods ofoperation
andmaintenance

No increasein emission
rate (lb
CO2/MWhgross)None
proposed-

Ranges in
Presumptively
Values on
Approvable
Which theStandard of
EPA isPerformance
Soliciting
561
Comment
An annual
The thresholdemission rate between
limit of 1,300 intermediatelb CO2/MWh- and base load
grossfrom 40 to 50
percent annual
capacity factor;
the degree ofemission
limitation from1,250 lb
CO2/MWhgross to 1,800
lb CO2/MWhgrossAn annual
The degree ofemission rate emission
limit of 1,500 limitation fromlb CO2/MWh- 1,400 lb
gross
CO2/MWhgross to 2,000
lb CO2/MWhgross
The threshold
between low
andintermediateload from 5 to20 percent
annualcapacity factor

454This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Degree ofEmission
BSER
Limitation
RoutineNo increase
methods of in emission
operation
rate (lbandCO2/MWhmaintenan gross)ceAffected
EGUs
Intermedi
ate andbase load
noncontinenta
l existing
oil-firedsteam
generating
units

Subcategory
DefinitionNon-continental
oil-fired steam
generating units
with an annual
capacity factor
greater than orequal to 8 percent

Base load
existing
naturalgas-firedsteam
generating
units

Natural gas-fired
steam generating
units with anannual capacity
factor greater thanor equal to 45
percent

Routinemethods ofoperation
andmaintenance

No increasein emission
rate (lb
CO2/MWhgross)Intermedi
ate load
existing
naturalgas-firedsteam
generating
units

Natural gas-fired
steam generating
units with anannual capacity
factor greater thanor equal to 8
percent and lessthan 45 percent

Routinemethods ofoperation
andmaintenance

No increasein emission
rate (lb
CO2/MWhgross)Ranges in
Presumptively
Values on
Approvable
Which theStandard of
EPA isPerformance
Soliciting
561
Comment
An emission
The
rate limit (lbpresumptive
CO2/MWhstandard: 0 to 2
gross) defined standard
deviations inby the unitspecificannualemission ratebaseline
above or 0 to
10 percent
above the unitspecificbaseline
An annual
The thresholdemission rate between
limit of 1,300 intermediatelb CO2/MWh- and base load
grossfrom 40 to 50
percent annual
capacity factor;
The acceptable
standard from1,250 lb
CO2/MWhgross to 1,400
lb CO2/MWhgrossAn annual
The acceptableemission rate standard fromlimit of 1,500 1,400 lb
lb CO2/MWh- CO2/MWhgross
gross to 1,600
lb CO2/MWhgross455This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Affected
EGUs
Low load
existing
naturalgas-firedsteam
generating
units

Subcategory
Definition
Natural gas-fired
steam generating
units with anannual capacity
factor less than 8
percent

BSER
None
proposed-

Degree ofEmission
Limitation

Ranges in
Presumptively
Values on
Approvable
Which theStandard of
EPA isPerformance
Soliciting
561
Comment
The threshold
between low
andintermediateload from 5 to20 percent
annualcapacity factor

XI. Proposed Regulatory Approach for Emission Guidelines for Existing Fossil Fuel-fired
Stationary Combustion Turbines
A. 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). Existing fossil fuel-fired stationary combustion turbines
already represent a significant share of GHG emissions from EGUs and are quickly becoming
the largest source of GHG emissions from the power sector. As other fossil fuel-fired EGUs
reduce utilization or retire, at least some of this generation may shift to the existing combustion
turbine fleet with significant GHG emission implications, particularly if the latter is not subject
to limits on GHG emissions. For these reasons, the EPA intends to discharge its obligation toprescribe emission guidelines for these sources as expeditiously as practicable. In this notice, the
EPA is proposing emission guidelines for certain existing fossil fuel-fired stationary combustion

456
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

turbines and soliciting comment on approaches that could be used to establish emission
guidelines for the remaining units in the fleet.
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 thisgrowing portion of the inventory. The second is related to the size of the affected fleet and theimplications 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 byowners and operators of these sources. Although the EPA believes that these technologies areavailable 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.
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 thatplays a key role in fulfilling resource adequacy and operational reliability needs. Althoughadvancements in energy storage and accelerated development and deployment of zero-emitting
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 thata 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
457This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

implemented at a scale commensurate with the size of the regulated fleet, and provide sufficient
operational flexibility and 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 todevelop CCS and hydrogen-related infrastructure, the EPA believes the BSER for this category
entails significant lead time for application of CCS or low-GHG hydrogen co-firing. As a result,the EPA is planning to break the existing combustion turbine category into two segments, and is
focusing this proposal on the largest and most frequently operated (e.g., base load) existing
combustion turbines that have the highest GHG emissions on an annual basis. For these large andfrequently operated existing combustion turbines, the EPA is proposing to determine that the
BSER consists of either application of CCS by 2035, or application of low-GHG hydrogen cofiring beginning in 2032, based on an evaluation of the statutory BSER criteria that mirrors
EPA’s evaluation of the BSER for new base load combustion turbines. This focused approach
will limit GHG emissions from the highest-emitting existing natural gas combustion turbines,
while allowing sufficient lead time for application of CCS or low-GHG hydrogen co-firing andlimiting the amount of affected capacity to a degree that is consistent with the availability ofthese two GHG mitigation technologies. The EPA intends to undertake a separate rulemaking as
expeditiously as practicable that addresses emissions from the remaining combustion turbines.
In this notice, the EPA is soliciting comment on both the scope of these proposedemission guidelines (in other words, the applicability thresholds that would determine which
existing combustion turbines are in the first segment) as well as the BSER for units covered inthis rulemaking. In section XII of this preamble, the EPA is also taking comment on the458This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

associated state plan requirements associated with the BSER for existing fossil fuel-fired
turbines.
As described in more detail below, the EPA is proposing to determine that the BSER forlarge and frequently operated existing stationary combustion turbines is the same as for the
proposed second phase of requirements for new base load combustion turbines. Accordingly, the
EPA is proposing emission guidelines for these existing stationary combustion turbines thatwould require either that these sources achieve a degree of emission limitation consistent withthe use of CCS by 2035, or achieve a degree of emission limitation reflecting the utilization of 30
percent low-GHG hydrogen by volume by 2032 (increasing to 96 percent low-GHG hydrogen by
volume by 2038).
The EPA believes that it is important to stagger CCS requirements for existing coal-fired
units and new and existing fossil fuel-fired turbines to allow time for both deployment of CCS
infrastructure and to accommodate increased demand for specialized engineering andconstruction labor needed to build CCS equipment. The EPA also believes that because coalfired units emit more CO2/MWh, that to the extent that there are limitations to the amount of
CCS that can be installed by 2030 it makes sense to focus a CCS BSER on those coal-fired units
first. A 2035 compliance timeframe would allow for staggering of resources needed to install
CCS while still allowing existing turbines to take advantage of the IRC section 45Q tax credits tomake CCS controls more cost-effective or to use hydrogen, produced at facilities eligible for the
45V tax credits, making hydrogen co-firing more cost effective. 562 In the rest of this section, theEPA proposes regulations for the first segment and solicits comment on specific elements of the562

CCS projects that commence construction as late as December 31, 2032 can qualify for the
45Q tax credit.
459

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

approach. This section also briefly discusses what BSER might look like for units in the second
rulemaking, and requests comments that could inform the development of a rulemaking defining
BSER, degrees of emission limitation, compliance deadlines and other elements of an emission
guideline for those units at a later date.
As explained in more detail later in this section, the EPA is proposing that the first
segment it would cover would be units greater than 300 MW with an annual capacity factor ofgreater than 50 percent. The EPA projects that 37 GW of capacity would meet these criteria in
2035, representing 14 percent of the projected existing combustion turbine capacity and 23
percent of the projected generation from existing combustion turbines in 2035. As is explained
further below, the EPA is proposing this capacity factor and capacity threshold after weighing
the quantity of emissions from these units and considerations about the feasibility of installingsignificant amounts of CCS and/or hydrogen co-firing. In short, these units offer the best
opportunity to achieve significant emissions reduction consistent with what the EPA believes
these technologies will be capable of on a national scale. Similar to its proposal for new baseload turbines, the EPA is proposing that BSER for those existing sources be both pathways, thatis CCS with 90 percent capture in 2035 and clean hydrogen combusting 30 percent by volume in2032 and 96 percent by volume in 2038. Alternatively, as with the proposal for new base load
turbines, the EPA is taking comment on whether to finalize a BSER with a single pathway basedon application of CCS with 90 percent capture, which could also be met by co-firing with lowGHG hydrogen as a compliance option, or vice-versa. The EPA is also taking comment onwhether the compliance date should begin earlier, including as early as 2030. 563

563

If we finalize one of these variations, the state plan requirements may change accordingly.
460

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

The EPA has promulgated several prior rulemakings under both CAA section 111(b) andsection 111(d) that provide the regulated sector with lead time to accommodate the time needed
to deploy control technology. Section VII.F.3.a of this preamble discusses, in the section 111(b)context, precedent for rulemakings that provide such lead time. For additional examples under
CAA section 111(d), see 70 FR 28606, 28619 (May 18, 2005) (establishing emission guidelines
for electric utility steam generating units, with a 13-year compliance timeframe for a second
control phase); 61 FR 9905, 9919 (March 12, 1996) (establishing emission guidelines formunicipal solid waste landfills, with a 2.5-year compliance timeframe); 62 FR 48348, 48381(September 15, 1997) (establishing emission guidelines for hospital/medical/infectious waste
incinerators, with up to 3 years after state plan approval for facilities to install control
equipment). Section XI.B provides background information concerning the composition of thecurrent fossil fuel-fired stationary combustion turbine fleet and how it is expected to change in
the near future. In section XI.C, the EPA proposes an approach for units covered in thisrulemaking and in section XI.D, the EPA summarizes the key topics for which we are soliciting
comment relative to existing combustion turbines. Finally, section XI.E, outlines a potential
approach for units covered in a second rulemaking
B. The Existing Stationary Combustion Turbine Fleet
In 2021, existing combustion turbines represented 37 percent of the GHG emissions fromthe 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 74 percent of the GHG emissions and 25
percent of the generation in 2035. In EPA’s modeling of the 2035 control case, in which both
existing fossil fuel-fired EGUs and new stationary combustion turbine EGUs are subject to theemissions limitations proposed in this action but existing combustion turbine EGUs are left
461
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

uncontrolled, load shifting from those two categories of sources to the existing combustion
turbines results in an increase in the share of the emissions from existing combustion turbines(including combined cycle and simple cycle combustion turbines) to 82 percent while their shareof generation remains 25 percent. Moreover, in that control case, existing combined cycle
combustion turbines are responsible for 71 percent of the CO2 emissions from the power sector.
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 inthese rules) projects a long-term decline in generation and emissions from existing combustion
turbines relative to current generation and emissions. 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. While generation
falls from turbines, this is primarily caused by declining capacity factors, not throughretirements.
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 somecorrelation between units with low-GHG emission rates (e.g., more efficient units) andutilization, some low efficiency combined cycle units have historically operated at very high462This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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.
C. BSER for Base Load Turbines Over 300 MW
As noted earlier, the EPA is adopting an approach in which existing combustion turbines
would be regulated in two segments. The proposed emission guidelines presented in this noticefocus on the first segment, which comprises the base load units (e.g., those operated at capacity
factors of greater than 50 percent) over 300 MW. The EPA intends to undertake a separate
rulemaking to address the second segment, comprising the remainder of the existing fossil fuelfired stationary combustion fleet, as expeditiously as practicable.
Because the first segment would be focused on the largest most frequently used units, the
EPA is proposing that the BSER for these units would be CCS or a BSER based upon burning
low-GHG hydrogen. As is the case for new base load combustion turbines, each of these sets ofcontrols is adequately demonstrated, of reasonable cost, and consistent with the other criteria toqualify as the BSER.
Because the second segment would include both smaller more frequently used units andless frequently used units, in that action, the EPA anticipates considering a broader range oftechnologies including heat rate improvements. This approach recognizes the imperatives (theurgent 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 need for infrastructure for CCS and co-firing low-GHG hydrogen to
be deployed at a broader scale if these BSER technologies are to be deployed broadly at smaller
and less frequently operated existing combustion turbines.

463
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

The EPA is proposing emission guidelines for units with a capacity factor greater than 50
percent and a capacity of greater than 300 MW, but is also taking comment on whether thatcapacity factor threshold or capacity threshold should be lower (for instance 40 percent for thecapacity factor and 200 MW or 100 MW for the capacity). The EPA is proposing that 300 MW
is the appropriate threshold for applicability because it focuses on the units with the highest
emissions where CCS is likely to be most cost effective. As an important first step towards
abating emissions from the existing turbine fleet and recognizing that at least some project
developers are considering the use of clean hydrogen in base load turbines 564 and recognizingthat there are likely limits to the clean hydrogen supply in the mid-term, the EPA believes that it
is appropriate to also propose a clean hydrogen BSER for the same set of units. Table 6 provides
information from IPM detailing the amount of capacity and generation from the 2035 IPM
projected control case that would be covered under various capacity thresholds.
Table 6—Key Characteristics for Baseload Combined Cycle Units of Various Capacities
NGCC Units
Projected to Run at a
Capacity Factor ofGreater than 50
percent and at a
capacity size greaterthan
100 MW
200 MW
300 MW
400 MW
500 MW

Capacity (GW)

Percentage of total
NGCC Capacity (%)

Percentage of Total
NGCC Generation
(%)

134
85
37
12
6

49
31
14
4
2

78
51
23
10
7

564

As one developer notes, “the plant will be capable of supporting a balanced and diverse
power generation portfolio in the future; from energy storage capable of accommodating
seasonal fluctuations from renewable energy, to cost effective, dispatchable intermediate andbaseload power.” https://www.longridgeenergy.com/news/2020-10-13-long-ridge-energyterminal-partners-with-new-fortress-energy-and-ge-to-transition-power-plant-to-zero-carbonhydrogen.
464
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 begreatest.
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 firstrulemaking. Those controls are heat rate/efficiency improvements, co-firing low-GHG hydrogen,and use of CCS. We discuss each of these below, and in the course of each discussion explain
why we are proposing that the following controls qualify as the BSER: co-firing with low-GHG
hydrogen in the amounts of 30 percent (by volume) by 2032 and 96 percent (by volume) by
2038, and the use of CCS with 90 percent capture by 2035.
1. Heat-Rate Improvements
The EPA believes that heat rate improvements for existing combustion turbines arebroadly 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 andinlet 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 6465
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

percent. 565 These small-scale efficiency improvements 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. An
upgrade to the combustion turbine can result in a heat rate improvement of 3.0 percent and acapacity increase of 13 percent for $172/kW, while an upgrade to the steam turbine can result ina heat rate improvement of 3.2 percent with a capacity increase of 3 percent for $130/kW. These
more comprehensive efficiency improvements would likely result in an average efficiency
improvement of 6 percent for affected existing stationary combustion turbines. The EPA is notproposing HRI improvements for units greater than 300 MW because they achieve significantly
less emission reductions than either CCS or co-firing hydrogen, but believes that some units may
choose to make these upgrades as part of their response to installing CCS and/or co-firinghydrogen. The EPA is taking comment on whether HRI should be considered BSER (or acomponent of BSER) for combined cycle units with a capacity factor of greater than 50 percent
and a capacity of less than 300 MW as part of this initial rulemaking.
2. Co-firing low-GHG hydrogena. Overview
The EPA is proposing that for existing combined cycle combustion turbines that operate
at capacity factors of greater than 50 percent and that are greater than 300 MW, co-firing 30
percent low-GHG hydrogen by 2032 and 96 percent by 2038 qualifies as the BSER, for largely
the same reasons that apply to new combined cycle turbines, as discussed in section VII.F.3.c.viiof this preamble. Co-firing hydrogen at these levels is adequately demonstrated, as indicated by565

https://www.andovertechnology.com/wp-content/uploads/2021/03/C_18_EDF_FINAL.pdf.
466This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

announced plans of manufacturers and generators to undertake retrofit projects for hydrogen cofiring. These plans also indicate that the costs of retrofitting are reasonable. The analysis
concerning the costs of low-GHG hydrogen for existing turbines is comparable to the analysis
for new turbines. See section VII.F.3.c.vii.(B) of this preamble. Co-firing with low-GHG
hydrogen at existing turbines also has comparable non-air quality environmental impacts andenergy requirements, and comparable emissions reductions as co-firing with low-GHG hydrogenat new turbines. See sections VII.F.3.c.vii.(C)-(D) of this preamble. For these reasons, the EPA is
proposing that co-firing with low-GHG hydrogen qualifies as the BSER. The fact that doing so
will also advance the development and deployment of this low-emitting technology further
supports this proposal.
b. Adequately Demonstrated
Co-firing with low-GHG hydrogen is feasible in combustion turbines that are currently
being produced. Manufacturers have developed retrofits to allow existing combustion turbines tocombust up to 100 percent hydrogen, and some companies have announced plans to retrofit their
existing turbines to combust hydrogen. In section VII.F.3.c of this preamble, the EPA proposes
co-firing of low-GHG hydrogen as BSER for certain new base load combustion turbines. A
number of the examples that the EPA cites as evidence that companies are developing combined
cycle turbines to co-fire hydrogen either are existing turbines that companies are planning toretrofit to burn hydrogen or are already under construction, and would, therefore, be classified asexisting turbines under this rule. Because new combined cycle turbines that operate at capacity
factors of greater than 50 percent are similar to existing combined cycle turbines that operate at
capacity factors of greater than 50 percent, the EPA is proposing a similar BSER pathway for

467
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

existing combustion turbines, based upon co-firing 30 percent (by volume) low-GHG hydrogenin 2032 and ramping up thereafter to 96 percent (by volume) low-GHG hydrogen in 2038.
There are two key questions related to whether co-firing low-GHG hydrogen in existing
combustion turbines is adequately demonstrated. The first question is whether existing
combustion turbines are capable of co-firing significant amounts of hydrogen and/or if they canbe retrofitted to do so. The second question is whether there will be an adequate supply of lowGHG hydrogen. These points are discussed below.
i. Capability of Existing Turbines to Co-fire Hydrogen
There are at least three lines of evidence that demonstrate that co-firing low-GHG
hydrogen in existing turbines is possible today (with a number of them already able to fire 100
percent hydrogen) and that by approximately 2030, many additional turbine models will have thecapability to co-fire 100 percent hydrogen. First, information from turbine vendors indicates thatthey already have significant experience in operating turbines with hydrogen; some of their
existing turbine models can co-fire hydrogen; and/or they are currently engaged in projects to
upgrade existing turbines to co-fire hydrogen. Second, test burns have been completed on several
existing utility turbines. Third, several utilities have indicated plans to retrofit existing turbines toco-fire hydrogen.
Existing turbine vendors including GE, Mitsubishi, and Siemens have indicated that their
turbines can currently co-fire some amounts of hydrogen; and, they have plans to expand thosecapabilities. GE has indicated that most of their product line can currently be configured to co-

468
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

fire significant amounts of hydrogen. 566 Siemens is currently offering retrofit packages for manyof its existing turbines that will allow them to combust up to 75 percent hydrogen. 567 Mitsubishi
also offers retrofit packages that could allow for up to 100 percent firing of hydrogen. 568
Section VII.F.3.c.vii(A) of this preamble includes discussion of how retrofitting existingturbines to co-fire with increasing amounts of hydrogen is adequately demonstrated. Several
turbines currently in operation have the capability to co-fire hydrogen up to 30 percent without
modifications. Other existing turbine models would need modifications to enable co-firing
between 50 and 100 percent.
Moreover, several existing combined cycle turbines have demonstrated the ability to cofire some amounts of hydrogen. The Long Ridge Energy Terminal tested 5 percent hydrogen cofiring at the 485-MW combined cycle plant on a GE HA-class (GE 7HA.02) in 2022. The turbine
is designed to enable a transition to 100 percent hydrogen fuel. This example is particularly
salient given the large capacity of the unit. No modifications should be required for this turbine
model, which has been available since 2017, to operate with between 5 and 20 percent hydrogenco-firing. Higher hydrogen co-firing concentrations will require some modification. 569
Southern Company has also demonstrated hydrogen co-firing on a Mitsubishi, M501G
turbine. The demonstration involved co-firing 20 percent hydrogen (by volume), was successful

566

https://www.ge.com/gas-power/future-of-energy/hydrogen-fueled-gasturbines?utm_campaign=h2&utm_medium=cpc&utm_source=google&utm_content=eta&utm_t
erm=Ge%20gas%20turbine%20hydrogen&gad=1&gclid=EAIaIQobChMIqMaL6IXG_gIVhsjjB
x2gPgb-EAAYASAAEgK61PD_BwE and https://www.ge.com/content/dam/gepowernew/global/en_US/downloads/gas-new-site/future-of-energy/hydrogen-overview.pdf.
567
https://assets.siemens-energy.com/siemens/assets/api/uuid:66b2b6a3-7cdc-404d-9ab0ddcfbe4adf02/hydrogenflyer.pdf?ste_sid=81945e06dd4f27fd626614f9b954e3f4.
568
https://solutions.mhi.com/clean-fuels/hydrogen-gas-turbine/.
569
https://www.powermag.com/first-hydrogen-burn-at-long-ridge-ha-class-gas-turbine-markstriumph-for-ge/.
469
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

at both full and partial load, and demonstrated compliance with emissions requirements without
impacting maintenance intervals. 570 Other test burns have demonstrated the ability to fire up to
80 percent hydrogen without emissions excursions. 571
Several utilities are exploring the use of hydrogen in their existing turbine fleet. For
example, Constellation Energy, which owns a fleet of 23 gas-fired turbines with a combined total
capacity of 8.6 GW, asserts that retrofitting existing turbines to co-fire hydrogen is technicallyfeasible with existing turbine models: “Based on our assessments, retrofits using available
technology can allow hydrogen blending at 50-100 percent by volume in select generators. These
retrofits, which include burner and additional balance-of-plant modifications, allow for more
substantial CO2 emissions reductions.” 572 Florida Power and Light (FPL) intends to convert 16
GW of existing turbine capacity to run on 100 percent hydrogen by 2045. 573 They are currently
developing a 25 MW electrolyzer project at the Cavendish Energy Center. 574
One concern with hydrogen co-firing is that, because it burns at a higher temperature, it
has the potential to generate more thermal NOx. The most 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 have570

https://www.powermag.com/southern-co-gas-fired-demonstration-validates-20-hydrogenfuel-blend/.
571
https://www.ccj-online.com/real-world-experience-firing-hydrogen-natural-gas-mixtures/.
572
Constellation Energy Corporation’s Comments on EPA Draft White Paper: Available andEmerging Technologies for Reducing Greenhouse Gas Emissions from Combustion Turbine
Electric Generating Units.
573
https://cleanenergy.org/blog/nextera-sets-goal-to-decarbonize-proposes-big-transition-forflorida-power-light/.
574
https://dailyenergyinsider.com/news/34040-florida-power-light-taps-cummins-for-its-greenhydrogen-facility/.
470
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

developed DLN combustors for utility EGUs that can co-fire hydrogen. 575 Moreover, the major
combustion turbine manufacturers are designing combustion turbines that will be capable ofcombusting 100 percent hydrogen by approximately 2030, with DLN designs that assure
acceptable levels of NOX emissions. 576 577
ii. Availability of Low-GHG Hydrogen
The EPA is proposing that the BSER for existing combustion turbines includes co-firing
30 percent (by volume) low-GHG hydrogen by 2032 and 96 percent (by volume) by 2038. The
EPA is proposing to define low-GHG hydrogen as hydrogen that is produced with overall carbon
emissions of less than 0.45 kg CO2e/kgH2 from well-to-gate. Electrolytic hydrogen produced
using zero-carbon emitting energy sources is the most likely, but not the only, form of hydrogen
anticipated to meet this proposed definition. 578
Suitable volumes of low-GHG hydrogen are expected to be produced by the 2032 and2038 timeframes to satisfy the demand driven by this proposed rule. As referenced throughout
this proposal, DOE’s clean hydrogen production estimates are 10 MMT annually of cleanhydrogen by 2030, and 20 MMT annually by 2040. There is reason to believe actual produced
low-GHG hydrogen will exceed those levels. Announced clean hydrogen production projects

575

Siemens Energy (2021). Overcoming technical challenges of hydrogen power plants for theenergy transition. NS Energy. https://www.nsenergybusiness.com/news/overcoming-technicalchallenges-of-hydrogen-power-plants-for-energy-transition/.
576
Simon, F. (2021). GE eyes 100% hydrogen-fueled power plants by 2030.
https://www.euractiv.com/section/energy/news/ge-eyes-100-hydrogen-fuelled-power-plants-by2030/.
577
Patel, S. (2020). Siemens’ Roadmap to 100% Hydrogen Gas Turbines.
https://www.powermag.com/siemens-roadmap-to-100-hydrogen-gas-turbines/.
578
DOE, Pathways to Commercial Liftoff: Clean Hydrogen (March 2023).
471
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

total 12 MMT annually for 2030. 579 In fact, hydrogen production could outpace DOE’s
projections if demand markets across sectors, including the power sector, grow rapidly andemerge simultaneously with cost declines across the value chain. 580 Over time, the emergence ofthe self-sustaining low-GHG hydrogen markets are predicted to be established as demand for
low-GHG solidifies and anchors the market, ensuring low-GHG production even after the PTC
sunsets. Given the magnitude of the PTC for low-GHG hydrogen, $3/kg, electrolytic hydrogenproduction is expected to accelerate, accounting for between 70 and 95 percent of hydrogenproduction in 2030, and between 30 and 50 percent in 2040. 581
Further, multiple utilities are pursuing projects to secure supplies of electrolyzer-basedhydrogen for their power projects. As mentioned earlier in this proposal, Intermountain Power isworking with partners to develop an integrated hydrogen turbine, a hydrogen production facility,
and a hydrogen storage facility in Delta, Utah. All three components of the project are underconstruction and are scheduled to be operational by 2025, with the turbine combusting 30

579

DOE Pathways to Commercial Liftoff: Clean Hydrogen, March 2023.
https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB-0329update.pdf. Figure 8 of the Liftoff Report represents compiled clean hydrogen projects withaggregated 2030 production exceeding 12 MMT annually.
580
DOE Pathways to Commercial Liftoff: Clean Hydrogen, March 2023.
https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB-0329update.pdf. Figure 13 presents modeling of hydrogen production volumes under various
scenarios, including projections of 20MMT in 2030, and 42 MMT in 2040 based on high end of
ranges for end use demand which assumes additional ramp up in policy support for
decarbonization – which is consistent with this proposal to reduce emissions from the power
sector, as well as EPA’s proposed Greenhouse Gas Emissions Standards for Heavy-Duty
Vehicle.
581
DOE Pathways to Commercial Liftoff: Clean Hydrogen, March 2023.
https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB-0329update.pdf. Figure 14 of the Liftoff report projects the split of hydrogen production in futureyears between electrolytic and SMR.
472
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

percent (by volume) low-GHG hydrogen at startup. 582 FPL has announced plans to build 30 GW
of excess solar to supply clean hydrogen production to power its turbines and to sell to othercustomers. 583 Entergy has entered into multiple agreements to explore the use of existing andnew renewable generating assets and transmission to supply zero GHG electricity to developersof hydrogen production plants. 584 Multiple US utilities are collaborating to develop hydrogenhubs. 585
c. Costs
The fact that existing sources are already planning to combust low-GHG hydrogen, evenin the absence of a regulatory requirement, is an indication that the costs of co-firing arereasonable.
The EPA has also developed a more specific description of the costs, which follows. It
incorporates some components of the analysis of costs of co-firing low-GHG hydrogen for new
turbines, as discussed in section VII.F.3.c.vii(B) of this preamble.
There are three sets of potential costs associated with retrofitting combustion turbines toco-fire hydrogen: (1) Capital costs of retrofitting combustion turbines to have the capability of
co-firing hydrogen; (2) pipeline infrastructure to deliver hydrogen; and (3) the fuel costs related
to production of low-GHG hydrogen. While many combustion turbines are able to fire lower582

https://www.ipautah.com/ipp-renewed/.
https://cleanenergy.org/blog/nextera-sets-goal-to-decarbonize-proposes-big-transition-forflorida-power-light/.
584
https://www.entergynewsroom.com/news/entergy-texas-new-fortress-energy-partneradvance-hydrogen-economy-in-southeast-texas/ andhttps://www.entergynewsroom.com/news/entergy-texas-monarch-energy-collaborate-advancesoutheast-texas-energy-infrastructure-1323187465/.
585
https://news.duke-energy.com/releases/major-southeast-utilities-establish-hydrogen-hubcoalition.
473
583

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

volume blends of hydrogen with natural gas, not all have the capacity or on-site infrastructurenecessary to blend higher volumes of hydrogen. The primary costs that combustion turbines
would incur would be the fuel costs for low-GHG hydrogen, along with limited capital retrofit
costs, in order to co-fire hydrogen at the 30 percent and 96 percent levels that the EPA is
proposing as the BSER.
One company, Constellation Energy Corporation, has estimated the costs to retrofit
existing plants to co-fire hydrogen and has indicated that they are reasonable: “We expect $10$60/kW in retrofit costs to achieve 30-60% hydrogen blending by volume at our power plants. At
blend levels in the range of 60-100%, OEMs have suggested pricing of roughly $100/kW.” 586
The EPA estimates that if low-GHG hydrogen is available at a delivered price of $1/kg, 587 cofiring 30 percent hydrogen in a combined cycle EGU operating at a capacity factor of 65 percent
would increase the levelized cost of electricity (LCOE) by $2.9/MWh and a 96 percent co-firing
rate would increase the LCOE by $21/MWh. 588 Regardless of the level of hydrogen co-firing, theCO2 abatement cost is $64/ton ($70/metric ton) at the affected facility. 589 For an aeroderivative
simple cycle combustion turbine operating at a capacity factor of 40 percent, the EPA estimatesco-firing 30 percent low-GHG hydrogen would increase the LCOE by $4.1/MWh, and a 96
percent co-firing rate would increase the LCOE by $30/MWh. At a delivered price of $0.75/kg,
the CO2 abatement costs for co-firing hydrogen would be $32/ton ($35/metric ton). For a

586

Constellation Energy Corporation’s Comments on EPA Draft White Paper: Available andEmerging Technologies for Reducing Greenhouse Gas Emissions from Combustion Turbine
Electric Generating Units Docket ID No. EPA-HQ-OAR-2022-0289, June 6, 2022).
587
The delivered price includes the purchase cost of the fuel and its transportation costs and the
45V tax credit.
588
The EIA long-term natural gas price for utilities is $3.69/MMBtu.
589
The abatement cost of co-firing low-GHG hydrogen is determined by the relative delivered
cost of the low-GHG hydrogen and natural gas.
474
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

combined cycle EGU, the EPA estimates the LCOE increase would be $1.4/MWh and $11/MWh
for the 30 percent and 96 percent cases, respectively. For a simple cycle EGU, the EPA estimates
the LCOE increase would be $2.1/MWh and $15/MWh for the 30 percent and 96 percent cases,
respectively.
The EPA is soliciting comment on what additional costs would be required to ensure that
combustion turbines are able to co-fire between 30 to 96 percent low-GHG hydrogen and if there
are efficiency impacts from co-firing hydrogen. Retrofits to add the capacity to combust higher
volumes of hydrogen could include retrofitting the combustor, increasing the size of the fuelpiping, and upgrades to minimize fuel leakage, hydrogen storage and blending equipment,
upgraded control systems, modification to the continuous emissions monitoring system, safety
upgrades and leakage detectors, modification of the HRSG to accept higher temperature exhaust,and NOx control modifications (e.g., upgraded premix combustion technologies). 590 According
to model plant estimates in EPRI’s US-REGEN model, the heat rate of a hydrogen-fired
combustion turbine is 5 percent higher than a comparable natural gas-fired combustion turbine.
Furthermore, for hydrogen-fired combustion turbines relative to a comparable natural gas-fired
combustion turbine, the capital costs are approximately $70/kW higher, the fixed operating costs
are approximately $1/year per kW higher, and the non-fuel variable operating costs areapproximately $0.5/MWh higher. 591 While these costs are for new combustion turbines, theamounts could be higher for retrofits to combustion turbines. To the extent it is appropriate toaccount for additional costs associated with a hydrogen co-firing BSER for existing combustion

590

Simon, Nima, Retrofitting Gas Turbine Facilities for Hydrogen Blending. November 2, 2022.
https://www.icf.com/insights/energy/retrofitting-gas-turbines-hydrogen-blending.
591
https://us-regen-docs.epri.com/v2021a/assumptions/electricity-generation.html#newgeneration-capacity.
475This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

turbines, the EPA is soliciting comment on whether capital and fixed costs should be increasedby 9 percent, consistent with the NETL estimated retrofit costs of CCS relative to new
combustion turbines.
The EPA is proposing to determine that the increase in operating costs from a BSER
based on low-GHG hydrogen is reasonable.
d. Non-Air Quality Health and Environmental Impact and Energy Requirements
The co-firing of hydrogen in combustion turbines in the amounts that the EPA proposes
as the BSER would not have adverse non-air quality health and environmental impacts. It would
potentially result in increased production of NOx, but those NOx emissions can be controlled, as
described in sections VII.F.3.c.vii.(A) and XI.C.2.b.i of this preamble.
In addition, co-firing hydrogen in the amounts proposed would not have adverse impacts
on energy requirements, including either the requirements of the combustion turbines to obtain
fuel or on the energy sector more broadly, particularly with respect to reliability. As discussed in
sections VII.F.3.c.vii.(A)-(B) and XI.C.2.b.-c. of this preamble, combustion turbines can beconstructed to co-fire high volumes of hydrogen in lieu of natural gas, and the EPA expects that
low-GHG hydrogen will be available in sufficient quantities and at reasonable cost. Any impact
on the energy sector would be further mitigated by the large amounts of existing generation thatwould not be subject to requirements in this rule and the projected new capacity in the base casemodeling.
e. Extent of Reductions in CO2 Emissions
The site-specific reduction in CO2 emissions achieved by a combustion turbine co-firinghydrogen 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
476This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

30 percent by volume hydrogen with natural gas would achieve approximately a 12 percent
reduction in CO2 emissions versus firing 100 percent natural gas. 592 A source combusting 100
percent hydrogen would have zero CO2 stack emissions because hydrogen contains no carbon, as
previously discussed. A source co-firing 96 percent by volume hydrogen (approximately 89
percent by heat input) would achieve an approximate 90 percent CO2 emission reduction, which
is roughly equivalent to the emission reduction achieved by sources utilizing 90 percent CCS.
f. Promotion of the Development and Implementation of Technology
Determining co-firing 30 percent (by volume) low-GHG hydrogen by 2032 and co-firing
96 percent (by volume) to be components of the BSER would generally advance technology
development in both the production of low-GHG hydrogen and the use of hydrogen in
combustion turbines, for the same reasons discussed with respect to new combustion turbines in
section VII.F.3.c.vii.(E) of this preamble.
g. Summary
The EPA proposes that co-firing 30 percent low-GHG hydrogen by 2032 and 96 percent
by 2038 qualify as a BSER pathway for large and frequently-used existing combustion turbines.
For the reasons discussed above, the EPA proposes that co-firing low-GHG hydrogen on thatpathway is adequately demonstrated in light of the capability of combustion turbines to co-firehydrogen and the EPA’s reasonable expectation that adequate quantities of low-GHG hydrogen
will be available by 2032 and 2038 and at reasonable cost. Moreover, combusting hydrogen willachieve reductions because it does not produce GHG emissions and will not have adverse non-air
quality health or environmental impacts or energy requirements, including on the nationwide592

The energy density by volume of hydrogen is lower than natural gas.
477

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

energy sector. Primarily because the production of low-GHG hydrogen generates the fewest
GHG emissions, the EPA proposes that co-firing low-GHG hydrogen, and not other types ofhydrogen, qualify as the “best” system of emission reduction. See section VII.F.3.c.vii(F) of thispreamble. The fact that co-firing low GHG hydrogen creates market demand for, and advances
the development of, low-GHG hydrogen, a fuel that is useful for reducing emissions in the power
sector and other industries, provides further support for this proposal.
Similar to new base load combined cycle turbines, the EPA is also taking comment on analternative approach in which the BSER for these units would be based on CCS with 90 percent
capture, for the reasons discussed next, but units could follow a pathway that would enable themto achieve the same reductions using low-GHG hydrogen.
3. CCSa. Overview
The EPA believes that CCS is an effective mitigation measure for existing combustion
turbines and that it would be most cost-effective for units that are frequently operating. As
discussed in section VII.F.3.b.iii.(A) of this preamble, multiple companies are considering
adding CCS to existing fossil fuel-fired power plants and multiple companies have performed
FEED studies evaluating the feasibility of installing CCS on an existing combined cycle unit. As
also discussed there, CO2 pipelines are available and their network is expanding in the U.S., thesafety of existing and new supercritical CO2 pipelines is comprehensively regulated by PHMSA,
and areas without reasonable access to pipelines for geologic sequestration can transport CO2 tosequestration sites via other transportation modes. As also discussed there, geologic
sequestration of CO2 is well proven, broadly available throughout the U.S., and there is adetailed set of regulatory requirements to ensure the security of sequestered CO2. For these478This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

reasons, the EPA proposes that CCS with 90 percent capture is adequately demonstrated forexisting combustion turbines.
The EPA further proposes that CCS is cost-reasonable for existing turbines that are
greater than 300 MW and operate at greater than 50 percent capacity. The EPA believes thatmany existing combined cycle units are likely to be able to install and operate CCS within thecosts that the EPA found to be reasonable for new stationary combustion turbines and existingcoal-fired steam generating units. Certain parts of the cost calculation should be much the same
as for new sources, including the costs for transportation and sequestration as well as theavailability of the IRC section 45Q tax credit, although the costs for retrofitting capture
equipment may in some cases be higher. See section VII.F.3.b.iii.(B) of this preamble. NETL
estimates that the capital cost of CCS retrofits on combined cycle EGUs is 9 percent higher thanfor new combined cycle EGUs. 593 The additional capital costs increase the LCOE of the retrofit
CCS by an additional $1.5/MWh compared to an installation at a new combined cycle EGU,
which is consistent with control costs that EPA has found to be reasonable in other rulemakings,
as noted in section VII.F.3.b.iii.(B)(5).
The ability to cost-effectively apply CCS was a significant consideration in the EPA’s
selection of proposed capacity and utilization thresholds to determine which existing turbines
would be covered by these proposed emission guidelines. The EPA considered two primaryfactors in evaluating an appropriate capacity threshold. The first is emission reduction potential.
As the capacity threshold decreases a larger amount of the existing fleet is covered and overall

593

Tommy Schmitt, Sally Homsy, National Energy Technology Laboratory, Cost andPerformance of Retrofitting NGCC Units for Carbon Capture – Revision 3, March 17, 2023
(DOE/NETL-2023/3848).
479

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

emission reduction potential increases. For instance, at a 500 MW threshold, only 2 percent of
the capacity and 7 percent of the emissions are covered. The second factor the EPA considered
was capacity to build CCS. In 2030, the EPA projects that approximately 12 GW of coal-fired
generation will likely install CCS (including both CCS being installed to meet requirements ofthis rule and CCS that EPA projects would occur even without the requirements proposed here).
There are likely to also be a number of other CCS projects for other industries developed in the2023 through 2030 timeframe. Multiple industries including the ethanol industry and thehydrogen production sector have announced post combustion CCS projects in response to the
IRA.
The EPA believes it is reasonable to assume therefore that by 2035 there will be a larger
capability to build CCS retrofits than in 2030. Had the EPA proposed capacity thresholds of 400
MW or 500 MW, they would have only resulted in the need for a maximum of 12 GW or 6 GW
of CCS capacity respectively by 2035 for existing gas turbines covered by this proposal, which isless than the CCS capacity the EPA projects in 2030 to meet the existing coal BSER. That would
likely mean foregoing feasible, cost-effective emissions reductions. By contrast, the 300 MW
cutpoint that EPA is proposing would require up to 37 GW of CCS in 2035. While this isapproximately 3 times the amount of CCS that the EPA is projecting for coal-fired units in 2030,
the EPA believes that 300 MW is a reasonable threshold primarily because there will besignificant time to deploy the needed infrastructure, a total of eleven years from the likely
finalization of these guidelines. In addition, it is unlikely that all of the units that EPA projects
would be affected in 2035 would choose to install CCS; some would likely choose to co-fire

480This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

low-GHG hydrogen. 594 For these reasons, the EPA believes that there will be adequate capability
to build enough CCS for the existing combustion turbine EGUs subject to a CCS BSER at a
capacity threshold of 300 MW, given the amount of time provided.
The EPA also considered a capacity threshold of 200 MW and of 100 MW. According to
the EPA’s projections, a threshold of 200 MW would affect a total of 85 GW, and a threshold of
100 MW would affect 134 GW of existing combustion turbine capacity. While the EPA believes
that it is possible that the industry could install that amount of CCS on this timeline, the EPA
believes it is important to gather more information on the question of how quickly CCS can be
deployed and is therefore taking comment on, but not proposing, a lower capacity threshold of
200 MW or 100 MW, and taking comment on whether it would be feasible to install CCS and or
co-fire hydrogen for the 85 GW or 134 GW of units it projects would be covered under thosethresholds and a capacity factor of greater than 50 percent.
Historical rates of emission control technology retrofits at existing coal-fired power
plants, such as flue gas desulfurization (FGD), indicate that rapid deployments of suchtechnologies in response to regulatory requirements have proven feasible historically in the
United States and elsewhere. FGD was rapidly deployed in the United States in response tovarious regulatory requirements, including the 1971 NSPS addressing SO2 emissions. Althoughother compliance options were available, FGD—a wholly new technology—was installed on 48
GW of coal-fired power plants between 1973 and 1984 595, while the number of technology

594

Approximately 6 GW of the capacity projected to operate at a capacity factor of greater than
50 percent in the EPA’s modeling is owned by NextERA who has already announced intentions
to convert much of their combined cycle turbines to co-fire increasing amounts of hydrogen.
595
van Ewijk, S., McDowall, W. Diffusion of flue gas desulfurization reveals barriers andopportunities for carbon capture and storage. Nat Commun 11, 4298, Figure 1 and Source Data
(2020), available at https://doi.org/10.1038/s41467-020-18107-2
481
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

vendors went from 1 to 16. 596 Similarly, Germany subsequently increased its share of FGD from10 to 79 percent in four years. 597 598 It should be noted that as FGD became a more familiar
technology, installation rates accelerated, reaching nearly 30 GW a year in the United States. 599
A very rapid ramp up happened after the Clean Air Interstate Rule, for example, where theinstalled capacity increased from 131 GW in 2007 to 200 GW in under four years. 600 There aremany differences between FGD and CCS, but the history of the rapid build-out of FGD generally
supports the EPA’s view that companies with the expertise to install complex emission control
equipment can rapidly ramp up capacity in response to a regulatory driver.
The EPA seeks comment on the feasibility of setting a threshold of 100 or 200 MW anda 40 percent capacity factor in light of these examples and other relevant considerations. As
further described below, the EPA further proposes that CCS with 90 percent capture for existing
combustion turbines greater than 300 MW and operating at more than 50 percent capacity meetsthe other criteria to qualify as the BSER, for the same reasons as it does for new combustion
turbines in the baseload subcategory:

596

Taylor, et al, Regulation as Mother of Innovation, 27 Law & Pol’y 348, 356 (2005).
van Ewijk, S., McDowall, W. Diffusion of flue gas desulfurization reveals barriers andopportunities for carbon capture and storage. Nat Commun 11, 4298 (2020).
https://doi.org/10.1038/s41467-020-18107-2
598
Similarly, in response to regulatory requirements over 100 GW of coal-fired generation
installed selective catalytic reduction (SCR) between 1999 and 2009, ramping from very low
levels. Healey, Scaling and Cost Dynamics of Pollution Control Technologies, at 7, Figure 3(2013). https://core.ac.uk/download/pdf/44737055.pdf.
599
Markussan, Scaling up and Deployment of FGD in the US (CCS - Releasing the
Potential) (2012) at v, 24.
600
Electric Power Annual 2015,
https://www.eia.gov/electricity/annual/archive/pdf/03482015.pdf.
482
597

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

b. Adequately Demonstrated
Section VII.F.3.b of this preamble includes discussion of how CCS with a 90 percent
capture rate has been adequately demonstrated and is technically feasible based on thedemonstration of the technology at existing coal-fired steam generating units and industrial
sources in addition to combustion turbines. Notably, the function, design, and operation of postcombustion 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 show that it is adequately demonstrated for combustion turbines as
well.
In the retrofit context, 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. 601 Other references detailed in section VII.F.3.b.iii.(A).(2)provide additional support for the demonstration of CO2 capture retrofits.
Moreover, section VII.F.3.b.iii.(A)(3) of this preamble describes how CCS has beensuccessfully applied to a combined cycle EGU (the Bellingham Energy Center in south central
Massachusetts) and how several other projects are in development. Both section
VII.F.3.b.iii.(A)(3) of this preamble and the TSD on GHG Mitigation Measures – Carbon

601

Giannaris, S., et al. Proceedings of the 15th International Conference on Greenhouse Gas
Control Technologies (March 15–18, 2021). SaskPower’s Boundary Dam Unit 3 Carbon
Capture Facility–The Journey to Achieving Reliability.
https://papers.ssrn.com/sol3/papers.cfm?abstract_id=3820191.
483

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Capture and Storage for Combustion Turbines discuss several CCS projects under development
involving retrofits to existing NGCC units.
In addition to CO2 capture, the CO2 transport and geologic storage aspects of CCS
systems are also adequately demonstrated, as discussed in section VII.F.3.b and section X.D.1.aof this preamble and in the GHG Mitigation Measures for Steam Generating Units TSD.
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 coalseams, and oil and gas reservoirs. Additionally, the U.S. CO2 pipeline network has steadily
expanded (with 5,339 miles in operation in 2021, a 13 percent increase in CO2 pipeline miles
since 2011), and appears primed to continue expanding, with several major projects recently
announced across the country. Areas without reasonable access to pipelines for geologic
sequestration can transport CO2 to sequestration sites via other transportation modes such as
ship, road tanker, or rail tank cars.
c. Costs
The EPA is proposing that the costs of CCS are reasonable for existing combustion
turbines that are large and frequently used. As further discussed in the Regulatory Impact
Analysis and the GHG Mitigation Measures – Carbon Capture and Storage for Combustion
Turbines TSD, the EPA’s approach relies on cost and performance assumptions consistent with
the IPM post-IRA 2022 reference case. 602 The EPA’s baseline shows that 7 GW of existing
natural gas combined cycle capacity retrofits with CCS in 2030, rising to 10 GW in 2035. The

602

These assumptions are detailed at: https://www.epa.gov/system/files/documents/202303/Chapter%206%20-%20CO2%20Capture%2C%20Storage%2C%20and%20Transport.pdf.
484This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

significant deployment of CCS on combined cycle natural gas EGUs in the absence of emission
standards reinforces the cost reasonableness and feasibility of the proposed standards.
Section VII.F.3.b.iii.(B) and section X.D.1.a.ii of this preamble discuss the costreasonableness of CCS technology in the context of new combustion turbines and existing coalfired steam generating units. Additionally, a March 2023 NETL report estimates that the capital
cost of CCS retrofits on combined cycle EGUs is 9 percent higher than for installation of CCS
equipment on new greenfield combined cycle EGUs. 603 The higher retrofit costs account for thecost premium for design, construction, and tie-in constraints imposed by existing plant layout
and operation. The additional capital costs increase the LCOE of the retrofit CCS by anadditional $2.2/MWh compared to an installation at a new combined cycle EGU. 604 Assuming
the same model plant, a 90 percent-capture retrofit amine-based post combustion CCS systemincreases the LCOE by $8.6/MWh and has overall CO2 abatement costs of $26/ton ($28/metricton). Similar to NETL estimates for greenfield CCS projects, costs at a specific plant would be
expected to vary somewhat from this estimate, as it does not include site and plant-specificconsiderations such as seismic conditions, local labor costs, or local environmental regulations.
d. Non-Air Quality Health and Environmental Impact and Energy Requirements
As in the context of new NGCC units and existing coal-fired steam generating units(discussed in section VII.F.3.b.iii.(C) and section X.D.1.a.iii of this preamble), the EPA does not

603

Cost and Performance of Retrofitting NGCC Units for Carbon Capture – Revision 3(DOE/NETL-2023/3848, March 17, 2023).
https://www.netl.doe.gov/projects/files/CostandPerformanceofRetrofittingNGCCUnitsforCarbon
CaptureRevision3_031723.pdf.
604
These calculations use the NETL F-Class turbine, a service life of 12 years, an interest rate of
7.0 percent, a natural gas price of $3.69/MMBtu, a capacity factor of 75 percent, a transport,
storage, and monitoring cost of $10/metric ton, and a 45Q tax credit of $85/metric ton.
485
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

expect the use of CCS at large, frequently used existing combustion turbines to haveunreasonable adverse consequences related to non-air quality health and environmental impact or
to energy requirements.
Regarding energy requirements, upon retrofitting an NGCC plant with CCS, a derate in
the net plant electrical output will be incurred due to the parasitic/auxiliary energy demandrequired to run the CCS system, as well as steam extraction from the steam cycle to satisfy the
CCS reboiler duty. 605 As discussed in the TSD on GHG Mitigation Measures – Carbon Captureand Storage for Combustion Turbines, a recent NETL report has estimated that the resulting
derates for 90 percent CO2 capture retrofits range from an 11.5 to 11.8 percent loss of net MWe.
Despite decreases in efficiency, IRC section 45Q tax credits provide an incentive forincreased generation with full operation of CCS because the credits are proportional to theamount of captured and sequestered CO2 emissions and not to the amount of electricity
generated. The EPA is proposing that the energy penalty is relatively minor compared to the
GHG benefits of CCS. The EPA does not believe that determining CCS to be BSER for large,
frequently operated combustion turbines will cause reliability concerns. This is because of thelimited increase in costs and energy penalty due to CCS, coupled with the amounts of smaller orlower capacity generation that would not be subject to these requirements and the projected newcapacity in the base case modeling. For the estimated 37 GW of facilities that would facerequirements under this proposal, if they all installed CCS retrofit the reduction in available
capacity would be approximately 4.3 GW, or less than 1% of the total modeled available natural
gas capacity in 2035. Grid planners, operators, and market participants can address the potential,

605

Cost and Performance of Retrofitting NGCC Units for Carbon Capture – Revision 3(DOE/NETL - 2023/3848, March 17, 2023). https://www.osti.gov/biblio/1961845.
486

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

marginal impact, through development of a similarly small increment of accredited capacity,
whether from new natural gas simple cycle turbine deployment, new energy storage, or new
sources of clean energy.
Regarding non-air quality health and environmental impact, criteria or hazardous air
pollutant emissions would in general be mitigated or adequately controlled by equipment needed
to meet other CAA requirements, and the EPA’s assessment is that the additional cooling waterrequirements from CCS at NGCC units are reasonable, as discussed in section VII.F.3.v.iii.(C).
The EPA is committed to working with its fellow agencies to foster meaningful engagement with
communities and protect communities from pollution. This can be facilitated through the existingdetailed regulatory framework for CCS projects and further supported through robust andmeaningful public engagement early in the technological deployment process. CCS projects
undertaken pursuant to these emission guidelines will, if the EPA finalizes proposed revisions to
the CAA section 111 implementing regulations, 606 be subject to requirements for meaningful
engagement as part of the state plan development process. See section XII.F.1.b of this preamble
for additional details.
e. Extent of Reductions in CO2 Emissions
Designating CCS with 90 percent capture as a component of the BSER for large andfrequently-operated combustion turbines prevents large amounts of CO2 emissions. According to
the NETL baseline report, adding a 90 percent CO2 capture system increases the EGU’s grossheat rate by 7 percent and the unit’s net heat rate by 13 percent. Since more fuel would be

606

87 FR 79176, 79190-92 (December 23, 2022).

487

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

consumed in the CCS case, the gross and net emissions rates are reduced by 89.3 percent and88.7 percent respectively.
f. Promotion of the Development and Implementation of Technology
The EPA also considered whether determining CCS to be a component of the BSER for
existing large and frequently operated combustion turbines will advance the technologicaldevelopment of CCS and concluded that this factor supports our BSER determination. Combinedwith the availability of 45Q tax credits and investments in supporting CCS infrastructure fromthe IIJA, this requirement should incentivize additional use of CCS, which should, in turn,incentivize cost reductions through the development and use of better performing solvents orsorbents. While solvent-based CO2 capture has been adequately demonstrated at the commercial
scale, a determination of the BSER for certain existing combustion turbines (along with newbaseload combustion turbines 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 EPA seeks comment on the feasibility of setting a threshold for inclusion in theexisting combustion turbine segment to be addressed by the emission guidelines proposed hereof 100 or 200 MW and a 40 percent capacity factor in light of the examples of other historic
deployment of pollution controls and other relevant considerations. DOE recently released areport discussing the state of carbon management technology. 607 In that report, DOE states that607

DOE Carbon Management Demonstration and Deployment Pathway, April 2023,
https://liftoff.energy.gov/.
488

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

with policy support (either via regulation or incentives) or technology premiums for low-carbon
products (e.g., low embodied carbon steel and concrete) the scale up of CCS technologies andpipeline and storage infrastructure would proceed much faster for the power sector than willproceed absent additional policy support or market demand. 608 In the report, DOE states that
regulatory developments, in particular, could play a dramatic role in accelerating the pathways
described for industries with lower-purity CO2 streams such as power plants. The report statesthat absent additional incentives, CCS technology for the power sector is likely to significantly
scale between 2030-2040 with pilot and demonstration technologies occurring now. As detailed
in the report, several incentives have recently become available or been significantly increased
that will accelerate the deployment of CCS for the power sector. The 45Q tax credit for CCS is astrong incentive, and DOE is already investing heavily through the Bipartisan Infrastructure Law
at further demonstrating lower-purity CCS technologies such as those used in the power sector,
which will help to decrease costs and establish repeatable commercial arrangements.
As the DOE report discusses, CO2 pipelines also need to be further built out for CCS
technologies to scale. CO2 pipelines are the most mature, and often the most cost-effective CO2transport technology for high volumes and will likely form the backbone of CO2 transport.
PHMSA reported that 5,339 miles of CO2 pipelines were in operation in 2021. 609 Analogous
historical build out of inter- and intrastate natural gas transmission pipelines demonstrates thatsimilar levels of CO2 pipeline deployment are feasible. Data reported by EIA indicates that from608

The Federal Buy Clean Task Force and the First Mover’s Coalition are both seeking toprovide a clear demand signal for low embodied emissions products.
609
U.S. Department of Transportation, Pipeline and Hazardous Material Safety Administration,“Hazardous Annual Liquid Data.” 2021. https://www.phmsa.dot.gov/data-andstatistics/pipeline/gas-distribution-gas-gathering-gas-transmission-hazardous-liquids.
489
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

1997 to 2008 over 25,000 miles of natural gas transmission pipeline was constructed, averaging
over 2,000 miles per year. 610 Other analyses indicate that the size of CO2 pipeline network
necessary to capture over 1,000 million metric tons per year of CO2 emissions from large,
frequently operated coal and natural gas EGUs ranges from 20,000 miles to 25,000 miles. 611 This
is in line with the historical maximum deployment of natural gas transmission pipelines, and also
does not account for any economies of scale from pipeline systems developed for capture fromother non-power CO2 sources.
D. Areas that the EPA is Seeking Comment on Related to Existing Combustion Turbines
The EPA is seeking comment on four general areas related to selecting the BSER for
existing combustion turbines. First, the EPA is soliciting comment on general assumptions about
potential future utilization of combustion turbines. Second, the EPA is soliciting comment on
assumptions about the appropriate group of existing combustion turbine units to be addressed inthis rulemaking. Third, the EPA is requesting comment on the appropriate BSER for thoseturbines. Fourth, the EPA is requesting comment on the timing of BSER requirements forexisting combustion turbines.
The EPA is seeking comment on a number of issues related to how its consideration ofprojected 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
combustion turbines will operate in the future and the key factors that influence those changes in

610

https://www.eia.gov/naturalgas/pipelines/EIA-NaturalGasPipelineProjects.xlsx.
Middleton, Richard and Bennett, Jeffrey and Ellett, Kevin and Ford, Michael and Johnson,
Peter and Middleton, Erin and Ogland-Hand, Jonathan and Talsma, Carl, Reaching Zero:
Pathways to Decarbonize the US Electricity System with CCS (August 30, 2022). Proceedings ofthe 16th Greenhouse Gas Control Technologies Conference (GHGT-16) 23-24 Oct 2022.
https://ssrn.com/abstract=4274085 or http://dx.doi.org/10.2139/ssrn.4274085
490

611

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

operation. While the EPA modeling shows that there is some increase in emissions from theseunits 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 thelater 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 IIJA. 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).
With regard to the size and definition of the category to be covered in a first rulemaking
covering only part of the existing turbine category, the EPA is also taking comment on how its
assumptions about the potential operation of combustion turbines in future years coupled withconsiderations about the availability of infrastructure should inform which units should becovered in a first rulemaking. 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. If, for instance, increased renewablegeneration and storage capacity were to lead to a smaller number of units operating at capacity
factors of greater than 50 percent, the proposed BSER would not affect as many units and asmaller size threshold might be possible without expanding the amount of infrastructure needed.
Conversely, if more units were likely to operate at a higher capacity factor, a higher capacity
threshold might be appropriate. If the number of units likely to be covered by a 50 percent
threshold were sufficiently small, it might be reasonable to include units in the intermediate
category (e.g., units with capacity factors of between 20 percent and 50 percent) in a first
491
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

rulemaking addressing the existing fossil fuel-fired turbine category. The EPA is also taking
comment on a lower capacity factor threshold (e.g., 40 percent) and a lower capacity threshold(200 MW or 100 MW, and capacities between 100 and 300 MW). With regards to units with acapacity factor of greater than 50 percent that are under 300 MW and units with a capacity factorof 50 percent or less the EPA is taking comment on the appropriateness of CCS and/or hydrogenas a BSER. With regards to hydrogen, the EPA is taking comment on the appropriate level ofand timing for hydrogen co-firing. More generally, EPA is requesting comment on any
feasibility issues related to broader CCS deployment should those thresholds be adjusted suchthat more coal capacity is affected, and how such issues could be addressed.
With regards to the BSER itself, the EPA is soliciting comment on the applicability of
CCS retrofits to existing combustion turbines and its focus on base load turbines (e.g., those witha capacity factor of greater than 50 percent). This solicitation includes comment on whether
particular plants would be unable to retrofit CCS, including details of the circumstances thatmight make retrofitting with CCS unreasonable or infeasible.
The EPA is also taking comment on the role of low-GHG hydrogen as part of BSER.
More specifically, the EPA is requesting comment on the appropriateness of low-GHG hydrogenas a BSER for combustion turbines larger than 300 MW with capacity factors of greater than 50
percent. While, as has been noted earlier in this section, a number of turbines already exist or are
under construction that owners of combustion turbines have indicated may burn large amounts ofhydrogen in a base load mode, the EPA is also aware that other proponents of low-GHG
hydrogen use in turbines focus on it primarily as an energy storage device, storing renewableenergy to provide electricity in times where renewable energy was not available. The EPA isinterested in the question of whether, in this case, it would be likely that a combined cycle
492This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

turbine burning low-GHG hydrogen would operate near base load, and whether it be prudent tohave an alternative BSER or an alternative compliance pathway for units combusting low-GHG
hydrogen and solicits comments on these questions. Similar to the NSPS for base load
combustion turbines, the EPA is also taking comment on whether to finalize both the proposed
low-GHG hydrogen BSER and the proposed CCS with 90 percent capture BSER, or finalize a
BSER with a single pathway, such as based on application of CCS with 90 percent capture,
which could also be met by co-firing with low-GHG hydrogen.
With regard to the timing for BSER, the EPA is taking comment on a 2035 CCS based
BSER standard and whether that standard could reasonably be applied earlier. Similarly, the
EPA is taking comment on the timing of a low-GHG hydrogen based BSER and whether a 30
percent low-GHG hydrogen standard could be implemented earlier than 2032, or if low-GHG
hydrogen supply infrastructure development suggests it should be later. The EPA is taking
comment on the same questions with regard to a 96 percent low-GHG hydrogen co-firing BSER
in 2038.
E. BSER for Remaining Combustion Turbines
While the EPA believes that emission guidelines for units covered in the first rulemaking,proposed above, can achieve important emission reductions from the most frequently operating
combustion turbines, the EPA believes that limits to infrastructure and capability to build carbon
capture systems or co-fire large amounts of hydrogen caution against a first rulemaking
addressing emissions from existing turbines covering all combustion turbines. In this section, theEPA discusses how developing a BSER for units in a second rulemaking could address units that
do not meet the applicability requirements for the first rulemaking.

493
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

As noted above, the EPA is taking comment on what units should be part of whateveraction the EPA finalizes as a result of the proposal. Based on the units that the EPA has proposed
be included, units that might remain uncovered include smaller baseload units (e.g., those lessthan or equal to 300 MW) and all units operating less than or equal to a capacity factor of 50
percent. Particularly for the remainder of the baseload units, the EPA is interested in whether any
other units should have a BSER based on CCS. The EPA is also interested in the timing of such arequirement recognizing the tensions between an earlier requirement that would both achieveearlier reductions and the need to allow time for infrastructure to develop to support growing
amounts of CCS.
For intermediate turbines, the EPA is taking comment on a BSER similar to that for new
turbines. In particular, the EPA is interested in comment about an appropriate pathway andtiming for a BSER that would ultimately require 96 percent low-GHG hydrogen by volume.
Finally, for peaking turbines, the EPA is interested in comment about whether a clean hydrogen
BSER would be appropriate, what the timing of such a requirement should be and whether there
should be any phasing.
The EPA is also interested in any comments related to: potential changes in operational
patterns for turbines, particularly as more renewables and storage enter the grid. For instance, the
EPA is interested in comments as to whether improvements in energy storage will reducereliance on intermediate and peaking turbines. The EPA is also interested in comments on any
potential technology developments that could impact its determination of BSER. For instance,
the EPA is aware that in addition to electrolyzer based hydrogen and natural gas based hydrogen,there are other means of hydrogen production receiving significant attention such as naturally
occurring hydrogen, and solicits comments on whether any of these potential technology
494This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

developments should impact the EPA’s consideration of the appropriate BSER for the remaining
turbines.
XII. State Plans for Proposed Emission Guidelines for Existing Fossil Fuel-fired EGUs
A. Overview
State plan submissions under these emission guidelines are governed by the requirementsof 40 CFR part 60, subpart Ba (subpart Ba). 612 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). 613 The Agency intends to finalize revisions to 40 CFR part 60, subpart
Ba, before promulgating these emission guidelines. Therefore, state plan development and stateplan submissions under these proposed emission guidelines would be subject to the requirementsof 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 particularemission guidelines, those proposals are explicitly addressed in this section of the preamble.
Unless expressly amended or superseded in these proposed emission guidelines, the provisionsof 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. In sections

612

40 CFR 60.20a–60.29a.
See 87 FR 79176 (December 23, 2022); see also id., Docket ID No. EPA-HQ-OAR-20210527-0002 (memorandum to docket containing proposed revisions to 40 CFR part 60, subpart
Ba).
495
613

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

X and XI of this preamble, the EPA is soliciting comment on ranges for dates and values fordefining subcategories, BSER, and degrees of emission limitation; those solicitations forcomment extend to the proposed values and dates discussed in this section of the preamble. In
section XII.B, the EPA proposes and explains its reasoning for compliance deadlines for affectedsteam generating units and affected combustion turbines. In section XII.C, the EPA describes its
requirement that state plans achieve equivalent stringency to the EPA’s BSER. Section XII.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 lessstringent standard of performance than results from the EPA’s presumptive methodology.
Section XII.D also describes proposed requirements for increments of progress for affected
EGUs in certain subcategories and milestones for affected EGUs, as well as testing andmonitoring requirements. In section XII.E, the EPA proposes that states would be permitted toinclude trading and averaging as compliance measures for affected EGUs in their state plans, solong as plans demonstrate equivalence to the stringency that would result if each affected EGU
was individually achieving its standard of performance. Finally, section XII.F describes whatmust be included in state plans, including plan components specific to these emission guidelines
and requirements for conducting meaningful engagement.
In this section of the preamble, the term “affected EGU” means any existing fossil fuelfired steam generating unit or existing fossil fuel-fired combustion turbine EGU that meets theapplicability criteria described in sections X and XI of this preamble. Affected EGUs would becovered by the proposed emission guidelines under 40 CFR part 60 subpart UUUUb.

496
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

B. Compliance Deadlines
The EPA is proposing a compliance date of January 1, 2030, for affected steam
generating units. The proposed compliance date for the CCS combustion turbine subcategory is
January 1, 2035. The proposed compliance dates for the first phase and second phase for theaffected hydrogen co-fired combustion turbine subcategory are January 1, 2032, and January 1,
2038, respectively. This means that starting on the applicable compliance date, affected EGUs
would be subject to standards of performance and other state plan requirements under theseemission guidelines and would be required to start demonstrating compliance with thoserequirements.
The EPA is proposing that January 1, 2030, is the soonest that affected steam generating
units could reasonably commence compliance with standards of performance given the proposed
state plan submission timeline (24 months; see section XII.F.2 of this preamble) and the amountof time affected EGUs in the long-term and medium-term coal-fired steam generating unit
subcategories will need to install CCS or natural gas co-firing, respectively. For consistency, the
EPA is also proposing a January 1, 2030, compliance date for imminent- and near-term coalfired units as well as the different subcategories of natural gas- and oil-fired steam generating
units.
However, the EPA recognizes that the BSERs for some subcategories of affected steamgenerating EGUs are routine methods of operation and maintenance, which do not require theinstallation of any or significant control equipment and can thus be applied earlier. 614 Therefore,

614

The EPA is also taking comment in section X.D.3.b.ii on potential BSER options for
imminent- and near-term affected coal-fired steam generating units based on low levels ofnatural gas co-firing.
497
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

the EPA is soliciting comment on compliance dates defined by the date of approval of the stateplan 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 gasand oil-fired steam generating units.
The proposed compliance timeframe for affected steam-generating EGUs in these
proposed emission guidelines is based on the amount of time the EPA believes is needed tocomply 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 XII.F.2 of this preamble, the EPA is proposing to adjust the stateplan submission deadline so that certain necessary planning and design steps for natural gas cofiring or CCS implementation can take place as part of the state plan development process. Thatis, 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,
submission, 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 for Steam Generating Units TSD discusses thetimeframes for implementation of natural gas co-firing and CCS at existing coal-fired steam
generating EGUs. Based on this analysis, it is clear that 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 the carbon capture system and498
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

the transport and storage system; the EPA believes that all of these steps can be completed withinroughly 5 years. 615
Deployment of a carbon capture system starts with a technical and economic feasibility
evaluation, including a Front End Engineering Design (FEED) study. The owner/operator of anaffected 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 completed in 3 years or less. As noted above, the EPA also believes thatat 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. The EPA believes thatthe commencement of CCS project implementation activities, including more detailed
engineering work and procurement, construction of the carbon capture system, and startup andtesting, will overlap with the final steps of the initial project design and development phase.
These project implementation steps take approximately 3 years to complete.
In addition to planning and implementing a carbon capture system, the owners/operatorsof 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 of captured CO2 canbe undertaken simultaneously with development of the CO2 capture system, and some of thesteps necessary for transport and storage can additionally overlap with each other. The EPA thus
believes design and implementation of CO2 transport and storage can be completed within 5
years.

615

GHG Mitigation Measures for Steam Generating Units TSD, chapter 4.7.1. See Table 5 inchapter 4.7.1 for visual representation of the CCS and co-firing project timelines described inthis section.
499
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

The EPA believes that the initial phases of planning and design for CO2 transport andstorage, including site characterization and pipeline feasibility and design activities, can and will
occur prior to state plan submission, i.e., as part of the state plan development process. First, theowner/operator of an affected EGU would undertake a feasibility analysis associated with CO2transport and storage, as well as site characterization and permitting of potential storage areas.
These steps can overlap with each other and the EPA anticipates that, in total, feasibility
analyses, site characterization, and permitting of potential storage areas will take 2–3 years tocomplete. The EPA believes there is significant opportunity to overlap the design and planningphase for CO2 transport and storage with the engineering and construction phase for transportand storage, which is anticipated to take 2–3 years. Based on the potential to conduct many ofthe design, planning, permitting, engineering, and construction steps, the EPA thus believes that
affected EGUs will need approximately 5 years, from start to finish, to be ready to implement
CO2 transport and storage.
The EPA expects that implementation of natural gas co-firing projects for affected coalfired steam-generating EGUs, including any necessary construction of natural gas pipelines, canbe completed in approximately 3.5 years. As discussed in the GHG Mitigation Measures for
Steam Generating Units TSD, 616 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 ofaffected 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:

616

GHG Mitigation Measures for Steam Generating Units TSD, chapters 3.2.1.4, 3.2.2.3, and4.7.1.
500

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

planning and design; permitting and approval; and construction. It is reasonable to assume thatthe 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 phasecan vary. Based on a review of recent FERC data, the average time for pipeline projects similarin scope to the projects considered in this TSD is about 1.5 years and would likely not exceed 4
years. The EPA notes that these data may not reflect that pipeline projects may be completed
more expeditiously in the presence of a regulatory deadline. 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, which would beJune 2026. The proposed compliance date for affected steam generating units is January 1, 2030.
The EPA requests comment on whether using a period of 3.5 years after state plan submission isappropriate 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 ofstate plan development, i.e., before the state plan submission deadline. The EPA is also
requesting comment on potential compliance dates between 1.5 and 5.5 years after state plansubmission (i.e., January 1, 2028, to January 1, 2032), including on the feasibility of completing
all the steps to implement natural gas co-firing and CCS within a shorter or longer timeframe. To
the extent that commenters believe more or less time after state plan submission is more
appropriate than the proposed 3.5 years, the EPA requests that commenters provide information
supporting the provision of a different compliance date. Additionally, the proposed state plan
501
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 stateplan submission and compliance dates accordingly.
As discussed in section XI.C of this preamble, the EPA is proposing to subcategorize
affected existing, frequently used combustion turbines that are covered under these emission
guidelines into two subcategories: one subcategory for affected combustion turbine EGUs that
adopt the pathway with a standard of performance based on CCS, referred to as the “CCS
subcategory” and one subcategory for affected combustion turbine EGUs that adopt the pathway
with a standard of performance based on hydrogen co-firing, referred to as the “hydrogen cofired subcategory.” For affected combustion turbines in the CCS subcategory, the EPA is
proposing a compliance date of January 1, 2035, which is the soonest the Agency believes thesesources can comply with standards of performance based on installation and operation of CCS,
given the timeframes for planning and construction of carbon capture and CO2 transport andstorage systems along with other demands on the infrastructure and resources needed to
implement CCS throughout the power sector and the broader economy. For affected combustion
turbines in the hydrogen co-fired subcategory, the EPA is proposing a two-phase standard of
performance, with a proposed compliance date for the first phase of January 1, 2032, and for thesecond phase of January 1, 2038.
For combustion turbine EGUs in the CCS subcategory, the same timeframes andconsiderations discussed for the planning and construction of CCS for affected coal-fired steam
generating units apply. That is, the EPA expects that the owners or operators of affected
combustion turbines will be able to complete the design, planning, permitting, engineering, and502This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

construction steps for the carbon capture and transport and storage systems within 5 years. As
with affected coal-fired steam generating units, the EPA believes that states and owners or
operators can and would take several of the initial steps in the design and planning processes for
combustion turbine EGUs as part of state plan development, i.e., prior to the proposed state plansubmission deadline in approximately June 2026.
However, as noted in section XI.C of this preamble, the EPA is projecting approximately
12 GW of coal-fired generation will likely retrofit with CCS in order to meet the proposed
January 1, 2030, compliance date for affected long-term coal-fired steam generating units. Theseand other CCS projects that are likely to be occurring in response to the IRA may take up asignificant amount of the capacity to plan and build CCS between 2023 and 2030. The EPA
anticipates that additional pipeline capacity will be constructed ahead of January 1, 2030, for
CO2 transport as well as for natural gas pipeline laterals that may be needed for affected coalfired steam generating units that will co-fire with natural gas as a control strategy. Due to theseand other overlapping demands on the capacity to design, construct, and operate carbon systems
as well as pipeline systems, the EPA is proposing to find that a January 1, 2030, compliance date
for affected combustion turbine EGUs in the CCS subcategory, although feasible for anindividual unit, would not be the most reasonable deadline for all of the units that would need to
install CCS. Therefore, the EPA is proposing to provide a compliance date for affected
combustion turbine EGUs in the CCS subcategory that is 5 years after the compliance date forlong-term coal-fired steam generating units, or January 1, 2035. The EPA requests comment on
its proposed compliance deadline for combustion turbine EGUs in the CCS subcategory,including on whether an earlier or later compliance date would be more reasonable given thetime needed to analyze, design, and construct carbon capture and CO2 transport and storage
503
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

systems and the overlapping timeframes for installation of CCS on EGUs under the proposed
CAA section 111(b) standards of performance for new combustion turbines and on existing coalfired steam generating units under these proposed emission guidelines.
For affected combustion turbine EGUs in the hydrogen co-fired subcategory, the EPA is
proposing a compliance deadline for the first phase of January 1, 2032. As discussed in sections
VII.F.3.c.v and vi of this preamble, currently the vast majority of hydrogen is not low-GHG
hydrogen. Midstream infrastructure limitations and the adequacy and availability of hydrogenstorage facilities currently present obstacles and increase prices for delivered low-GHG
hydrogen. However, given the growth in the hydrogen sector and Federal funding for DOE’s
H2Hubs, which will explicitly explore and incentivize hydrogen distribution, the EPA believeshydrogen 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 2032. Legislative
actions including the IIJA and IRA, utility initiatives, and industrial sector production andinfrastructure projects indicate that sufficient low-GHG hydrogen and sufficient distribution
infrastructure can reasonably be expected to be available by this time. On this basis, the EPA is
proposing that compliance with the first phase of the standard, which is based on an affected
EGU co-firing 30 percent (by volume) low-GHG hydrogen, will commence on January 1, 2032.
The proposed compliance date of January 1, 2038, for the second phase of the standard of
performance for combustion turbine EGUs in the hydrogen co-fired subcategory, which is basedon a proposed BSER of 96 percent (by volume) co-firing low-GHG hydrogen, is also based on
an assessment of when sufficient quantities of such hydrogen will be available, as well as whenturbine vendors are anticipated to have the equipment necessary for higher percentages ofhydrogen co-firing available. As discussed in section VII.F.3 of this preamble, the EPA expects
504This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

that based on technology advances, growing demand for low-GHG hydrogen, and the hydrogenproduction tax credits available under IRC 45V(b)(2), there will be continued expansion of thehydrogen production and transmission network between 2032 and 2038. The EPA also notes
that, based on the current ages of the existing combustion turbine fleet, the number of units thatwould be expected to meet their standards of performance in 2038 by co-firing 96 percent
hydrogen (by volume) is likely to decline. Therefore, the EPA believes it is reasonable to expectthat there will be sufficient low-GHG hydrogen in 2038 to provide the quantities needed for both
new and affected existing combustion turbines in the hydrogen co-fired subcategory to meet theirapplicable standards of performance. The EPA requests comment on this assessment, as well as
on whether compliance dates other that January 1, 2032, and January 1, 2038, would be morereasonable for the first and second phases of the standards for affected units in the hydrogen cofired subcategory, and why.
C. 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 toestablish requirements for state plans that, in turn, must include standards of performance forexisting sources. Under CAA section 111(a)(1), a standard of performance is “a standard foremissions of air pollutants which reflects the degree of emission limitation achievable throughthe 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 bestsystem of emission reduction for a given category or subcategory of sources and to determine the505This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

degree of emission limitation achievable through application of the BSER to affected sources. 617
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 establishingrequirements 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 levelof emission performance that would result if each affected source was achieving its presumptive
standard of performance, after accounting for any application of RULOF. 618 That is, while states
have the discretion to establish the applicable standards of performance for affected sources intheir state plans, the structure and purpose of CAA section 111 require that those plans achieveequivalent 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 (40 CFR part 60, subpart Ba) would provide that states are permitted, in appropriate
circumstances, to adopt compliance measures that allow their sources to meet their standards of

617

See, e.g., West Virginia v. EPA, 142 S. Ct. 2587, 2607 (2022) (“In devising emissions limits
for power plants, EPA first ‘determines’ the ‘best system of emission reduction’ that—taking
into account cost, health, and other factors—it finds ‘has been adequately demonstrated.’ The
Agency then quantifies ‘the degree of emission limitation achievable’ if that best system wereapplied to the covered source.”) (internal citations omitted).
618
As explained in section XI.D.2 of this preamble, states may invoke RULOF to apply a lessstringent standard of performance to a particular affected EGU when the state demonstrates that
the EGU cannot reasonably apply the BSER to achieve the degree of emission limitation
determined by the EPA. In this case, the state plan may not necessarily achieve the same
stringency as each source achieving the EPA’s presumptive standards of performance because
affected EGUs for which RULOF has been invoked would have standards of performance lessstringent than the EPA’s presumptive standards.
506This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

performance in the aggregate. 619 As with the establishment of standards of performance for
affected sources, CAA section 111 requires that state plans that include such flexibilities forcomplying with standards of performance demonstrate equivalent stringency as would beachieved if each affected source was achieving its standard of performance.
The requirement that state plans achieve equivalent stringency to the EPA’s BSER anddegree of emission limitation 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 todangerous 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 havebeen reduced “enough.” Rather, CAA section 111 requires affected sources to reduce theiremissions to the level that the EPA has determined is achievable through application of the bestsystem of emission reduction, i.e., to achieve emission reductions consistent with the applicable
presumptive standard of performance. Consistent with the statutory purpose of requiring affectedsources to operate more cleanly, the EPA typically expresses presumptive standards ofperformance 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., bypermanently 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

619

87 FR 79176, 79207–08 (December 23, 2015).

507

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

that impacts its overall emissions, e.g., by changing its utilization; however, the source is stillrequired 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 thestatutory 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 theirstate plans, and to provide flexibilities for affected sources to use in complying with thosestandards. However, state plans must demonstrate that they ultimately provide for equivalentstringency as would be achieved if each affected source was achieving the applicable
presumptive standard of performance, after accounting for any application of RULOF.
D. Establishing Standards of Performance
CAA section 111(d)(1)(A) provides that “each State shall submit to the Administrator aplan 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 standardsof performance for each existing affected EGU 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
508
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 establishingpresumptively approvable standards of performance for affected existing 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 toaffected EGUs.
Additionally, CAA section 111(d)(1)(B) permits states to take into consideration aparticular 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 toan 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 detailabout how the EPA proposes to implement the RULOF provision in the context of thisrulemaking is provided in section XII.D.2 of this preamble.
States also have the authority to apply standards of performance to affected EGUs thatare more stringent than the EPA’s presumptively approvable standards of performance. 620

620

40 CFR 60.24a(f). The EPA has proposed to revise this provision to clarify that it has theobligation and authority to review and approve state plans that contain the more stringent
requirements. 87 FR 79176, 79204 (December 23, 2022).
509

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

1. Application of Presumptive Standards
This section of the preamble describes the EPA’s approach to providing presumptive
standards of performance for each of the subcategories of affected EGUs under these emission
guidelines, including establishing baseline emission performance. Under this proposal, eachsubcategory with a proposed BSER and degree of emission limitation would have acorresponding methodology for establishing presumptively approvable standards of performance(also referred to as “presumptive standards of performance” or “presumptive standards”).
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 foreach affected EGU.
States also have the authority to deviate from the methodology for presumptively
approvable standards, in order to apply a more stringent standard of performance throughincreasing the degree of emission limitation beyond what the EPA has determined to beachievable for units as a general matter (e.g., a state decides that an EGU in the medium-termcoal-fired subcategory should co-fire 50 percent natural gas instead of 40 percent). Deviations toincrease stringency do not trigger use of the RULOF mechanism, which requires states todemonstrate that an affected EGU cannot reasonably apply the BSER to achieve the degree ofemission limitation determination by the EPA. 621 The EPA proposes to presume that standards of621

87 FR 79176, 79199 (December 23, 2022).

510

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

performance that are more stringent than the EPA’s presumptive standards are “satisfactory” forthe purposes of CAA section 111(d).
a. Establishing Baseline Emission Performance for Presumptive Standards
For each subcategory, the proposed methodology to calculate a standard of performanceentails establishing a baseline of CO2 emissions and corresponding electricity generation for anaffected EGU and then applying the degree of emission limitation achievable through theapplication of the BSER (as established in section X.D and XI.C of this preamble). The
methodology for establishing baseline emission performance for an affected EGU is identical ineach 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” forexisting electric steam generating units. See 40 CFR 52.21(b)(48)(i). Eight quarters of 40 CFRpart 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
511
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

by evaluating the CO2 emissions and electricity generation data for each of its affected EGUs for2018 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 thedate 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 performancebaseline 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 theowners 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 andshutdown, 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 andtotal electric generation over an 8-quarter period also aligns with the reporting and compliancerequirements. 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 the512This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

total reported electric generation for an affected EGU during the compliance year, which isconsistent with the expression of the degree of emission limitation proposed for eachsubcategory in sections X.D.4, X.E.2, and XI.C. The EPA believes that using total mass CO2
emissions and total electric generation provides a simple and streamlined approach forcalculating 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 throughimplicit 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 isappropriate to use.
The EPA is soliciting comment on the proposed baseline-setting approach andspecifically 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 forbaseline 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 forestablishing presumptively approvable standards of performance will provide certainty for states,
as well as transparency and a streamlined process for state plan development. While thisapproach is specifically designed to be flexible enough to accommodate unit-specificcircumstances, 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 the513
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

instances in which a state may need to use an alternate baseline-setting methodology will belimited to anticipated changes in operation, i.e., circumstances in which historical emission
performance is not representative of future emission performance. The EPA is proposing thatstates 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.
b. Presumptive Standards for Steam Generating Units
As described in section X.C of this preamble, the EPA is proposing to first subcategorize
affected existing steam generating units 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. As explained in section X.C.3, the EPA is proposing that an affected coal-fired
steam generating unit’s operating horizon determines the applicable subcategory in three of thefour subcategories; in the case of the near-term subcategory, the operating horizon and load levelestablish applicability.
The EPA notes that, as explained in section X.C.3 of this preamble, where the owners or
operators of affected coal-fired steam-generating units have elected to commit to permanently
cease operation (and, in the case of near-term operating horizon units, to limit their capacity
factor) and have also elected to make any such commitments federally enforceable throughinclusion in a state plan, a state may rely on such commitments to subcategorize coal-fired steam
generating units under these emission guidelines. To be included in a state plan a commitment tocease operations or to limit capacity factor must be enforceable by the state, whether through514
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

state rule, agreed order, permit, or other legal instrument. 622 Upon EPA approval of the stateplan, that commitment will become federally enforceable.
For affected oil- and natural gas-fired steam generating units, subcategories are definedby load level and the type of fuel fired, as well as locality (i.e., continental and non-continentalU.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 threesubcategories for natural gas-fired steam generating units based on load level (base load,intermediate, and low).
i. 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. Affectedcoal-fired steam generating units that have either (1) Elected to commit to permanently cease
operations on January 1, 2040, or later, or (2) that have not elected to commit to permanently
cease operations as part of 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 inemission rate on a gross basis over an extended period of time. The EPA is proposing that wherestates 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

622

40 CFR 60.26a.

515

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

subcategory, the EPA is soliciting comment on a capture rate of 90 to 95 percent and a degree ofemission 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 (asdescribed above); and applying the level of stringency, based on the application of the BSER, tothat 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 (seesection X.D.4.a of this preamble) compared to the baseline level of emission performance. Using
the complement of 88.4 percent (i.e., 11.6 percent) and multiplying it by the baseline level ofemission 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 subcategorycomply with federally enforceable increments of progress, which are described in section
XII.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.
ii. 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.
516
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Affected coal-fired steam generating units that have elected to commit 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 an affected EGU in this subcategory,those established standards of performance would be presumptively approvable when included ina state plan submission.
Establishing a standard of performance for an affected EGU in this subcategory consistsof two steps: establishing a source-specific level of baseline emission performance (as describedearlier in this preamble); and applying the level of emission reduction stringency, based on theapplication of the BSER, to that level of baseline emission performance. Implementation ofnatural gas co-firing at a level of 40 percent of total annual heat input translates to a level ofstringency 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 thepresumptively 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, itwill 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 thatis reflected in the baseline operation, the EPA is proposing that states account for suchpreexisting co-firing in adjusting the degree of emission limitation. If, for example, an EGU co517
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

fires natural gas at a level of 10 percent of the total annual heat input during the applicable 8quarter baseline period, the corresponding degree of emission limitation would be adjusted to 12
percent (i.e., an additional 30 percent of natural gas by heat input) to reflect the preexisting levelof natural gas co-firing. This results in a standard of performance based on the degree ofemission limitation achieving an additional 30 percent co-firing beyond the 10 percent that isaccounted for in the baseline. The EPA believes this approach is a more straightforwardmathematical 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 thebaseline. 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 massemissions 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 cofiring 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.
518
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

However, to qualify for inclusion in the subcategory an affected coal-fired steam generating unit
must have elected to commit to permanently cease operations prior to January 1, 2040. If a state
decides to rely on such a commitment to place an affected EGU into the medium-term coal-fired
subcategory by making it an enforceable element of its state plan, the commitment to cease
operations will become federally enforceable upon EPA approval of the plan.
The EPA is proposing that affected coal-fired EGUs that elect to commit to dates topermanently cease operations for subcategory applicability, including EGUs in the medium-termcoal-fired subcategory, have corresponding federally enforceable milestones with which theymust comply. The EPA intends these milestones to assist affected EGUs in ensuring they arecompleting the necessary steps to comply with their state plan and commitments to dates topermanently cease operations. These milestones are described in detail in section XII.D.3.b of
this preamble. Affected EGUs in this subcategory would also be required to comply with thefederally enforceable increments of progress described in section XII.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.
iii. 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 coal-fired steam generating units that elect to commit to permanently cease operations
before January 1, 2032, have a proposed BSER of routine methods of operation andmaintenance. Therefore, the proposed presumptively approvable standard of performance is not
519
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

to exceed the baseline emission performance of the affected EGU (as described in section
XII.D.1.a of this preamble).
Unlike the proposed standards of performance for the long-term and medium-term coalfired steam generating units, establishing a standard of performance for an affected EGU in theimminent-term subcategory consists of just one step. The EPA is proposing that where states use
the methodology described in section XII.D.1.a of this preamble to establish the baseline level ofemission performance for an affected EGU, the emission rate described by that baseline would
constitute the presumptively approvable standard of performance. This standard of performancereflects that the proposed BSER for these affected EGUs is routine methods of operation andmaintenance and a degree of emission limitation equivalent to no increase in emission rate fromthe baseline level of emission performance. This also ensures that the affected EGU will notbackslide in its emission performance.
Although the EPA believes that the baseline performance level adequately accounts forvariability in annual emission rate, the EPA is also soliciting comment on a methodology for apresumptive standard above the baseline emission performance. For the imminent-term coalfired 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 thebaseline emission performance, or that is 0 to 10 percent above the baseline emission
performance.
Because the EPA is soliciting comment on a potential BSER for this subcategory basedon low levels of natural gas co-firing, as described in section X.D.3.b.ii, comment is also being
solicited on the presumptively approvable standards for that potential BSER. The BSER is basedon the maximum hourly heat input of natural gas fired in the unit (MMBtu/hr) relative to the520
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

maximum hourly heat input the unit is capable of (i.e., the nameplate capacity on an MMBtu/hrbasis). The EPA is soliciting comment on the baseline natural gas co-firing level being
determined from the 5 years of data preceding the publication of the final rule, or based onengineering limitations (i.e., extent of startup guns or size of pipeline to unit). That percent ofheat input results in percent reductions from the emission performance baseline equivalent to thepercent of heat input times 0.4. Adjustments relative to current co-firing levels may be accounted
for in a manner consistent with section XII.D.1.b.ii. Alternatively, the EPA is soliciting comment
on a degree of emission limitation on a fuel heat input basis. For a potential BSER of low levelsof natural gas co-firing, the EPA is therefore also soliciting comment on a presumptively
approvable standard defined on a heat input basis.
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 theaffected 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 haveelected to commit to permanently cease operations prior to January 1, 2032. If a state decides torely on such a commitment to place an affected EGU into the imminent-term coal-fired
subcategory by making it an enforceable element of its state plan, the commitment to cease
operations will become federally enforceable upon EPA approval of the plan.
The EPA is also proposing that affected coal-fired steam generating units that haveelected to commit to 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

521
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

affected EGUs in ensuring they are completing the necessary steps to comply with these dates intheir state plan. These milestones are described in detail in section XII.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.
iv. Near-term Coal-fired Steam Generating Units
Similar to the proposed approach for establishing presumptively approvable standards ofperformance 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 XII.D.1.a of this preamble). The near-term subcategory includes
affected coal-fired steam generating units that have elected to commit to permanently cease
operations after December 31, 2031, and before January 1, 2035, and that have elected to adopt
an annual capacity factor limitation of 20 percent.
The EPA is proposing that where states use the methodology described in section
XII.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 approvablestandard 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

522
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

the 5-year period of data) above the baseline emission performance, or that is 0 to 10 percent
above the baseline emission performance.
Because the EPA is soliciting comment on a potential BSER for this subcategory basedon low levels of natural gas co-firing, as described in section X.D.3.b.ii, comment is also being
solicited on the presumptively approvable standards for that potential BSER. The BSER is basedon the maximum hourly heat input of natural gas fired in the unit (MMBtu/hr) relative to the
maximum hourly heat input the unit is capable of (i.e., the nameplate capacity on an MMBtu/hrbasis). The EPA is soliciting comment on the baseline natural gas co-firing level being
determined from the 5 years of data preceding the publication of the final rule, or based onengineering limitations (i.e., extent of startup guns or size of pipeline to unit). That percent ofheat input results in percent reductions from the emission performance baseline equivalent to thepercent of heat input times 0.4. Adjustments relative to current co-firing levels may be accounted
for in a manner consistent with section XII.D.1.b.ii. Alternatively, the EPA is soliciting comment
on a degree of emission limitation on a fuel heat input basis. For a potential BSER of low levelsof natural gas co-firing, the EPA is therefore also soliciting comment on a presumptively
approvable standard defined on a heat input basis.
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 haveelected to commit to permanently cease operations after December 31, 2031, and before January
1, 2035, and must have elected to adopt an annual capacity factor limitation of 20 percent. If a
state decides to rely on such commitments to place an affected EGU into the near-term coal-fired
523
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

subcategory by making them enforceable elements of its state plan, the commitments to cease
operations and to limit its capacity factor will become federally enforceable upon EPA approvalof the plan.
The EPA is also proposing that affected coal-fired EGUs that have elected to commit todates to permanently cease operations for subcategory applicability, including EGUs in the nearterm 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 XII.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.
v. Natural Gas-fired Steam Generating Units and Continental Oil-fired Steam Generating Units
This section describes the EPA’s proposed methodology for presumptively approvablestandards 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 baseload continental oil-fired steam generating units. It does not address non-continental intermediateoil-fired and non-continental base load oil-fired steam generating units, which are described in
section XII.D.1.b.vi of this preamble. The proposed definitions of these subcategories are
discussed in section X.C.2 of this preamble. The proposed presumptive standards of performanceare based on degrees of emission limitation that units are currently achieving, consistent with the524This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 ofperformance 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. Thisis largely because the low variability in emissions data at intermediate and base load for theseunits 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 standard of performance.
However, for natural gas- or oil-fired steam generating units with low annual capacity
factors, annual emission rates can be high (greater than 2,500 lb CO2/MWh-gross) and can varyconsiderably 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 notproposing 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 uniform
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 oilfired 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/MWh525
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

gross for about 90 percent of the units. Therefore, the EPA is proposing the presumptive standardof performance of an annual calendar-year emission rate of 1,500 lb CO2/MWh-gross for theseunits.
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 ofunits. 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 operatewith intermediate or high utilization. Liquid-oil-fired steam generating units with 24-monthcapacity 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, subpartUUUUU). If oil-fired units operated at higher annual capacities, it is likely they would do sowith 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 fornatural gas- and oil-fired steam generating units. Specifically, the EPA is soliciting comment on
standards between (1) 1,400 and 1,600 lb CO2/MWh-gross for intermediate load natural gas-fired
units, (2) 1,250 and 1,400 lb CO2/MWh-gross for base load natural gas-fired units, (3) 1,400 and
526This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

2,000 lb CO2/MWh-gross for intermediate load oil-fired units, and (4) 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 ishigher because of the limited data available for oil-fired units that operate at those annual
capacity factors.
vi. 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 proposingthat where states use the methodology described in section XII.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 inannual 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 theintermediate and base load subcategories.

527
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

c. Presumptive Standards for Combustion Turbines
As described in section XI.C, the EPA is proposing to define affected existing
combustion turbines under these emission guidelines as units with a capacity greater than 300
MW and an annual capacity factor of greater than 50 percent. Within this set of units, the EPA is
proposing two subcategories based on the type of fuel used: existing combustion turbines that
adopt the pathway with a standard of performance based on CCS, referred to as the “CCS
subcategory” and existing combustion turbines that adopt the pathway with a standard of
performance based on hydrogen co-firing, referred to as the “hydrogen co-fired subcategory.”
States, in their state plan submissions, would be required to assign existing combustion turbine
EGUs with capacities greater than 300 MW and the ability to operate at an annual capacity factor
of greater than 50 percent to one subcategory or the other. 623 States would then be required toinclude in their plans the presumptive standard of performance corresponding to the appropriate
subcategory for each affected existing combustion turbine EGU. As discussed in section XII.D.2
of this preamble, states, in applying a standard of performance to a particular affected existing
combustion turbine EGU, also have discretion to consider that EGU’s remaining useful life andother factors.
However, the EPA anticipates that some existing combustion turbine EGUs that are
greater than 300 MW do not intend to operate at an annual capacity factor of greater than 50
percent starting in 2032 (the first proposed compliance date for affected existing combustion

623

As explained in section XI.D of this preamble, the EPA is soliciting comment on, inter alia,
whether to finalize both the CCS and hydrogen co-fired pathways for existing combustion
turbines or whether to finalize a BSER determination with a single pathway. If the EPA does not
finalize the proposed two-pathway approach, the state plan requirements for existing combustion
turbines in this section XII of the preamble will be updated accordingly for the final rule.
528
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

turbine EGUs under these emission guidelines). Such an EGU may elect to commit to an
enforceable annual capacity factor limitation of less than or equal to 50 percent. If a state elects
to include such an enforceable commitment in its state plan, the state would not be required tohave a standard of performance for that particular combustion turbine EGU in its plan.
Otherwise, each affected existing combustion turbine that is greater than 300 MW and that has
the ability to operate at an annual capacity factor of greater than 50 percent must have asubcategory designation and standard of performance in the state plan.
The EPA is proposing that states may structure the requirements for affected combustion
turbine EGUs in their state plans so that the applicable standard of performance must be met for
years in which the unit operates above the 50 percent annual capacity factor threshold. States andthe owners or operators of affected EGUs that have such contingent standards of performance
would be required to ensure that an affected EGU has complied with its standard of performancefor each calendar year in which it has operated at an annual capacity factor of greater than 50
percent. The EPA expects that if the owner or operator of an affected combustion turbine EGU
that has a standard of performance believes there is a chance the EGU will operate at an annual
capacity factor of greater than 50 percent in the upcoming compliance period, it will plan to meetthat standard. Given this practical reality, the EPA is taking comment on whether it should
require that once an affected existing combustion turbine EGU has exceeded the 50 percent
annual capacity factor threshold and triggered application of its standard of performance for agiven compliance period, that EGU must continue to meet its standard in subsequent complianceperiods.

529
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

i. Carbon Capture and Storage Existing Combustion Turbine Generating Units
This section describes the EPA’s proposed methodology for establishing presumptively
approvable standards of performance for existing combustion turbine EGUs that adopt thepathway with a standard of performance based on CCS. Affected EGUs that are assigned to thissubcategory have a proposed BSER of CCS with 90 percent capture and a proposed degree ofemission limitation of 90 percent capture of the mass of CO2 in the flue gas (i.e., the mass of CO2
after the turbine but before the capture equipment) over an extended period of time and an 89
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 ofperformance for an affected EGU in this subcategory, those established standards would bepresumptively approvable when included in a state plan submission.
Establishing a standard of performance for an affected combustion turbine EGU in thissubcategory 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 applicationof the BSER, to that level of baseline emission performance. Implementation of CCS with acapture rate of 90 precent translates to a level of stringency of an 89 percent reduction in CO2emission rate (see section XI.C of this preamble) compared to the baseline level of emission
performance. Using the complement of 89 percent (i.e., 11 percent) and multiplying it by thebaseline level of emission performance results in the presumptively approvable standard of
performance. For example, if a combustion turbine EGU in this subcategory has a baseline levelof emission performance of 1,000 lbs per MWh, it will have a presumptively approvablestandard of performance of 110 lbs per MWh (1,000 lbs per MWh multiplied by 0.11).

530
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

The EPA is also proposing that affected combustion turbines in this subcategory comply
with federally enforceable increments of progress, which are described in section XII.D.3.a of
this preamble.
The EPA solicits comments on this proposed methodology for calculating presumptively
approvable standards of performance for existing combustion turbines in the CCS subcategory.
ii. Hydrogen Co-Fired Existing Combustion Turbine Generating Units
This section describes the EPA’s proposed methodology for establishing presumptively
approvable standards of performance for existing combustion turbines that adopt the pathway
with a standard of performance based on hydrogen co-firing. Affected combustion turbine EGUs
in this subcategory have a proposed BSER of hydrogen co-firing with two phases of stringency.
In the first phase, affected EGUs in this subcategory co-fire hydrogen at a level of 30 percent by
volume with a proposed degree of emission limitation of 12 percent reduction in emission rate ona gross basis over an extended period of time. In the second phase, affected EGUs in thissubcategory co-fire hydrogen at a level of 96 percent by volume with a proposed degree ofemission limitation of 88.4 percent reduction in emission rate on a gross basis over an extended
period of time. As described in section XII.B, compliance with the first phase commences on
January 1, 2032, and compliance with the second phase commences on January 1, 2038. The
EPA is proposing that where states use the methodology described here to establish standards ofperformance for this subcategory, those established standards of performance would bepresumptively approvable when included in a state plan submission.
Establishing a standard of performance for an affected EGU in this subcategory consistsof three steps: first, establishing a source-specific level of baseline emission performance (asdescribed earlier in this preamble); and second, applying the level of emission reduction
531
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

stringency for the first phase, based on the application of the first phase BSER, to that level ofbaseline emission performance; and third, applying the level of emission reduction stringency forthe second phase, based on the application of the second phase BSER, to that level of baseline
emission performance.
Implementation of hydrogen co-firing at a level of 30 percent by volume translates to alevel of stringency of a 12 percent reduction in CO2 emissions (see section XI.C of thispreamble) compared to the baseline level of emission performance. Using the complement of 12
percent (i.e., 88 percent) and multiplying it by the baseline level of emission performance resultsin the presumptively approvable standard of performance for the affected EGU. For example, if a
combustion turbine EGU that co-fires 30 percent hydrogen (by volume) has a baseline level ofemission performance of 1,000 lbs per MWh, it will have a presumptively approvable standardof performance of 880 lbs per MWh (1,000 lbs per MWh multiplied by 0.88) for the first phase.
Implementation of hydrogen co-firing at a level of 96 percent by volume translates to alevel of stringency of an 88.4 percent reduction in CO2 emissions (see section XI.C of thispreamble) compared to the baseline level of emission performance. Using the complement of
88.4 percent (i.e., 11.6 percent) and multiplying it by the baseline level of emission performance
results in the presumptively approvable standard of performance for the affected EGU. For
example, if a combustion turbine EGU that co-fires 96 percent hydrogen (by volume) has abaseline level of emission performance of 1,000 lbs per MWh, it will have a presumptively
approvable standard of performance of 116 lbs per MWh (1,000 lbs per MWh multiplied by
0.116) for the second phase.
The EPA is proposing that affected combustion turbine EGUs in this subcategory thatmeet their standards of performance using hydrogen co-firing must co-fire with low-GHG
532
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

hydrogen. States must make this an enforceable part of their state plans, as described in further
detail in section XII.F.1.b.i.
The EPA is also proposing that affected combustion turbines in this subcategory comply
with federally enforceable increments of progress, which are described in section XII.D.3.a of
this preamble.
The EPA solicits comment on the proposed methodology for calculating presumptively
approvable standards of performance for existing combustion turbine EGUs in the hydrogen cofired subcategory.
2. Remaining Useful Life and Other Factors
Under CAA section 111(d), the EPA is required to promulgate regulations under whichstates 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) thatsuch standards reflect the degree of emission limitation achievable through the application of the
BSER, as determined by the EPA. 624 The EPA identifies this degree of emission limitation aspart of its emission guideline. 40 CFR 60.22a(b)(5). Thus, as described in section X.D of thispreamble, the EPA is providing proposed methodologies for states to follow in determining andapplying presumptively approvable standards of performance to affected EGUs in each of thesubcategories covered by these emission guidelines.

624

West Virginia v. EPA, 142 S. Ct. 2587, 2607 (2022) (“In devising emissions limits for power
plants, EPA first ‘determines’ the ‘best system of emission reduction’ that—taking into accountcost, health, and other factors—it finds ‘has been adequately demonstrated.’ The Agency thenquantifies ‘the degree of emission limitation achievable’ if that best system were applied to thecovered source.”) (internal citations omitted).
533

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

While standards of performance must generally reflect the degree of emission limitationachievable through application of the BSER as determined by the EPA, CAA section 111(d)(1)also requires that the EPA regulations permit the states, in applying a standard of performance toa 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 thatis 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. 625 Specifically, the EPA proposed torequire the state to demonstrate that a particular facility cannot reasonably achieve the degree ofemission limitation achievable through application of the BSER based on one or more of threedelineated 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 notundermine 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 satisfactoryplans that the EPA can ultimately approve. 626
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

625
626

87 FR 79176, 79196–79206 (December 23, 2022).
87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-2021-0527-0002.
534

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

in section XII.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 associatedwith 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 particularaffected 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 toconsider 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 ofperformance. And, finally, it discusses the EPA’s proposed interpretation of the Clean Air Act aslaid 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, andthat the EPA has the ability and authority to approve such standards of performance into stateplans.

535
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

a. 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 particularaffected 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 standardsof performance for particular sources is consistent across states. The proposed revisions would
also ensure that the use of RULOF does not undermine the overall presumptive level ofstringency and the emission reduction benefits of an emission guideline, or undermine and rendermeaningless the EPA’s BSER determination. 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 offacilities) 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 ofthree 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. 627

627

87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-2021-0527-0002(containing proposed revisions to RULOF provisions at 40 CFR 60.24a(e)–(n)).
536This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

A state wishing to invoke RULOF in order to apply a less stringent standard to aparticular 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 ofemission 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 ofapplying that system, the costs of a system of emission reduction, the non-air quality health andenvironmental impacts and energy requirements associated with a system of emission reduction,and the extent of emission reductions from a system. 628
For each subcategory, the EPA evaluated certain metrics related to each of these BSER
factors. For example, 629 in evaluating the costs associated with CCS and natural gas co-firing forexisting coal-fired steam generating units, the EPA considered both $/ton CO2 reduced andincreases in levelized costs expressed as dollars per MWh electricity generation. 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 as $/ton of CO2 reduced
and $/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 fundamentally different,

628

The EPA also considered impacts on the energy sector as part of its BSER determinations.
However, because this consideration does not apply at the level of a particular affected EGU, it
would not be appropriate basis for invoking RULOF.
629
The examples are only for illustrative purposes and should not be interpreted to represent thedifference that must exist to demonstrate a fundamental difference between the EPA’s BSER
determination and a particular affected EGU’s circumstances.
537
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

i.e., significantly higher, than 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 tohave 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 something unique to the source’s being on a remote island—something that
the EPA did not consider in evaluating the BSER—results in the affected EGU not being able toreasonably achieve the standard of performance, then it may be reasonable to invoke RULOF forthat source.
Under the EPA’s proposed approach, states would not be able to invoke RULOF basedon 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 implement the presumptively approvable standard of performance inaccordance with the precise metrics (e.g., at exactly the same $/ton CO2 reduced or exactly thesame distance from a pipeline connection) of the BSER determination but is able to do so withina reasonable margin. In such instances, it would not be reasonable for a state to apply a lessstringent standard of performance.

538
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Many of the factors the EPA considers in its BSER determination, and therefore many of
the factors states might consider in determining whether to invoke RULOF for any particularsource, are reflected in the cost consideration. As noted previously in this section, the EPA isproviding a range of cost evaluations for CCS and natural gas co-firing based on different
assumptions regarding amortization period and capacity factor. For example, the EPA is
proposing to determine that the cost of CCS for long-term coal-fired steam generating units isreasonable based on the following calculations: for a reference unit with a 12-year amortization
period and 50 percent capacity factor the cost is $14/ton CO2 reduced or $12/MWh, and that the
average cost for the fleet under the same assumptions is $8/ton CO2 or $7/MWh. For natural gas
co-firing for medium-term coal-fired steam generating units, the EPA is proposing to find thefollowing costs are reasonable: for a reference unit with a 50 percent capacity factor and an
amortization period ranging from 6 to 10 years, a cost of $53-$66/ton CO2 or $9-$12/MWh. The
average cost for the fleet under the same assumptions is $64-$78/ton CO2 or $11-$14/MWh.
Any costs associated with any BSER for affected EGUs that the EPA determines arereasonable under these emission guidelines cannot be a basis for invoking RULOF. Additionally,
costs that are not fundamentally different from costs that the EPA has determined are or could bereasonable for sources cannot be a basis for invoking RULOF. Thus, costs that are notfundamentally different from, e.g., $29/MWh (the cost for installation of wet-FGD on a 300 MW
coal-fired steam generating unit, used for cost comparison in section X.D.1.a.ii of this preamble
and detailed in section VII.F.3.b.iii(B)(5) of this preamble) are not a basis for invoking RULOF
under these emission guidelines. On the other hand, costs that constitute outliers, e.g., that are
greater than the 95th percentile of costs on a fleetwide basis (assuming a normal distribution) orthat are the same as costs the EPA has determined are unreasonable elsewhere under these539
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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, forrepresentative, 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 thatare 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 could be a difference based on physicalimpossibility or technical infeasibility. In making BSER determinations, the EPA must find thata 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 andcombustion turbine EGUs in the CCS subcategory, the EPA determined that CCS is adequately
demonstrated because its components can be and have been applied to the source category andbecause it is generally geographically available to affected EGUs. However, it may be possiblethat a particular affected EGU is physically unable to implement CCS due to, e.g., theimpossibility of constructing a pipeline or establishing other means 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

540
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

difference between the EPA’s BSER determination and the circumstances of this particularaffected EGU and the state may invoke RULOF.
The EPA has proposed under 40 CFR part 60, subpart Ba that states may invoke RULOF
if they can demonstrate that a source 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. 630 It thus follows that states would be able to invoke RULOF underthese emission guidelines 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 thesource category generally.
However, the EPA has also proposed in subpart Ba 631 that a state may not invoke
RULOF to provide a less stringent standard of performance for a particular source if that sourcecannot apply the BSER but can reasonably implement a different system of emission reduction toachieve the degree of emission limitation required by the EPA’s BSER determination. While astate may be able to demonstrate that the source cannot reasonably apply the BSER based on oneof 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 degreeof 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 coalfired EGUs, in particular, will also be informed by the structure of the EPA’s proposed

630

87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-2021-0527-0002(proposed revisions to RULOF provisions at 40 CFR 60.24a(e)).
631
87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-2021-0527-0002(proposed revisions to RULOF provisions at 40 CFR 60.24a(g)).
541This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 toachieve the presumptive level of stringency would result in unreasonable cost resulting fromplant age. 632 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 fundamentallyfrom the costs that the EPA found were reasonable in making its BSER determination.
As explained in section X of this preamble, these proposed emission guidelines include
BSER determinations and presumptive standards of performance for affected coal-fired EGUs infour subcategories: imminent-term, near-term, medium-term, and long-term. Owing to the basisof these subcategories, the EPA’s proposed BSER determinations for each of these subcategories
already consider costs amortized consistent with the operating horizons of sources within eachsubcategory. The EPA therefore does not anticipate that states would be likely to demonstrate theneed 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.

632

87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-2021-0527-0002(proposed revisions to RULOF provisions at 40 CFR 60.24a(e)(1)).
542This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Conversely, the proposed subcategories for existing combustion turbines do not consider
affected EGUs’ operating horizons. The useful life of a combined cycle unit is approximately 25
to 30 years. 633 More than 151 GW of combined cycle units came on-line in the 2000 to 2010
timeframe, 634 meaning that many of these units could potentially be at or nearing the end of theirremaining useful lives in the 2035 to 2040 timeframe. If an affected combustion turbine EGU has
decided to cease operations and elects to make that cessation enforceable, the period over which
controls would be amortized, depending on what that period of time is, may be short enough toinvoke RULOF based on unreasonable cost of control.
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 theapplicable 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 thedetermination of the best system of emission reduction in the emission guidelines” 635 that maketimely compliance impossible. However, given the relatively long lead times and compliancetimeframes proposed in these emission guidelines, the EPA anticipates that these circumstances
will be rare. 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

633

https://sargentlundy.com/wp-content/uploads/2017/05/Combined-Cycle-PowerPlantLifeAssessment.pdf.
634
U.S. Environmental Protection Agency. National Electric Energy Data System (NEEDS) v6.
October 2022. https://www.epa.gov/power-sector-modeling/national-electric-energy-datasystem-needs-v6.
635
87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-2021-0527-0002(proposed revisions to RULOF provisions at 40 CFR 60.24a(e)(3)).
543This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

from reliable and adequately documented sources and be applicable to and appropriate for theaffected facility. 636
Additionally, as discussed in section XII.D.1.a of this preamble, the EPA is proposing amethodology 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, both in sum and as individual, segregable pieces, to these emission guidelines. In
particular, the EPA requests comment on factual circumstances in which it may or may not beappropriate for states to invoke RULOF for affected EGUs, given the proposed BSER
determinations and presumptive standards of performance, 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 fordetermining when the costs of a control technology for a particular source are “fundamentallydifferent” from the Agency’s BSER determination and thus a basis for invoking RULOF. The

636

87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-2021-0527-0002(proposed revisions to RULOF provisions at 40 CFR 60.24a(j)).
544This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

EPA additionally seeks comment on any source category-specific considerations for invoking
RULOF for affected EGUs, including any additional or different requirements that might benecessary to ensure that use of RULOF does not undermine the presumptive stringency of theseemission guidelines.
b. Calculation of a Standard That Accounts for RULOF
Subpart Ba, both the presently applicable requirements and as the EPA has proposed torevise 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 revisions to 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 thesource and evaluating each system using the same factors and evaluation metrics that the EPA
considered in determining the BSER for the applicable subcategory. 637 As part of determining
source-specific BSER, the state would also have to determine the degree of emission limitationthat 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.638
Consistent with these proposed requirements in subpart Ba, the EPA is proposing thatstates invoking RULOF would be required to evaluate certain controls as appropriate forsubcategories of affected EGUs. The EPA believes these proposed requirements are necessary to637

To the extent that a state seeks to apply RULOF to a class of affected EGUs that the state candemonstrate are similarly situated in all meaningful ways, the EPA proposes to permit the state
to conduct an aggregate analysis of the BSER factors for the entire class of EGUs for which
RULOF has been invoked.
638
87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-2021-0527-0002(proposed revisions to RULOF provisions at 40 CFR 60.24a(f)).
545This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

ensure that states reasonably consider the controls that may qualify as the best system of
emission reduction. Additionally, the EPA is proposing to provide the order in which states mustevaluate controls. A list of controls, ordered from more to less stringent, can provide usefulstreamlining as states may reasonably choose to conduct a less in-depth evaluation of controls
further down the list if they determine a more stringent control is the best system of emission
reduction for a particular source. The EPA also believes that providing a list of controls forevaluation will provide states with clarity and certainty about what the Agency will find is asatisfactory source-specific BSER analysis pursuant to the RULOF mechanism. However, the
EPA is also requesting comment on whether to provide lists of controls to be evaluated in asource-specific BSER analysis as a presumptively approvable approach, as opposed torequirements. Regardless of how the EPA finalizes the approach to controls for source-specificanalyses, states would retain discretion to evaluate additional types of controls as part of asource-specific BSER determination for sources pursuant to RULOF.
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 thedegree 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 apotential BSER. The EPA is also proposing that states invoking RULOF for affected long-term
and medium-term 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 then evaluate lower levels of natural gas co-firing unless it has
demonstrated that natural gas co-firing at any level is physically impossible or technically546This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

infeasible at the source. Similarly, if a state invoking RULOF for an affected EGU in the longterm subcategory demonstrates that the EGU cannot co-fire with natural gas at 40 percent, the
EPA is proposing that the state must then evaluate lower levels of co-firing as potential BSERs
for the source, unless the state can demonstrate that it is physically impossible or technicallyinfeasible for the source to co-fire natural gas. States may also consider additional potential
source-specific BSERs for affected EGUs in either subcategory.
For states invoking RULOF for affected existing combustion turbine EGUs, the EPA is
similarly proposing a requirement to evaluate certain control strategies as part of a sourcespecific BSER analysis. As a preliminary step, for sources in either the CCS combustion turbine
subcategory or the hydrogen co-fired combustion turbine subcategory, the EPA is proposing thata state would first have to demonstrate why the affected EGU cannot reasonably participate in
the other subcategory and meet that other subcategory’s presumptive standard of performance. If
a unit can reasonably comply with the presumptive standard of performance for the alternate
source category, it must do so.
For combustion turbines in the CCS subcategory that cannot reasonably comply with thepresumptive standards of performance for either that subcategory or the hydrogen co-fired
subcategory, the EPA is proposing that, unless a state has demonstrated that it is physically
impossible or technically infeasible for a unit to implement CCS, the state must evaluate CCS
with lower rates of carbon capture as a potential BSER. If CCS with lower rates of capture is not
the BSER, the state would then be required to consider comprehensive turbine upgrades, andfinally smaller scale efficiency improvements. For hydrogen co-fired combustion turbines thatcannot reasonably comply with the presumptive standards of performance for either subcategory,a state would first analyze lower percentages of hydrogen co-firing, followed by comprehensive
547
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

turbine upgrades, and lastly smaller scale efficiency improvements. States would also be free toanalyze additional potential source-specific BSERs for affected combustion turbine EGUs ineither subcategory.
The EPA requests comment on the proposed requirement to consider certain control
technologies as part of source-specific BSER determinations, and specifically on whether the
Agency should require this approach as proposed or, in the alternative, provide it as apresumptively approvable approach to conducting a source-specific BSER analysis.
The EPA notes again that, under both the proposed subpart Ba and CAA section
111(d), 639 an affected EGU that cannot reasonably apply the EPA’s BSER but can achieve thedegree of emission limitation for the applicable subcategory through other reasonable systems ofemission reduction cannot be given a less stringent standard of performance. In this case, theaffected EGU’s standard of performance would still reflect the degree of emission limitationachievable 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. 640 Amongother requirements, the EPA in an emission guideline would have to either identify the outermost
date to cease operations for the relevant source category that qualifies for consideration ofremaining useful life or provide a methodology and considerations for states to use in639

As discussed earlier in this preamble, permitting a state to apply a less stringent standard to anaffected EGU that can achieve the degree of emission limitation the EPA determined is required
would be inconsistent with CAA section 111(d). See also 87 FR 79176 (December 23, 2022),
Docket ID No. EPA-HQ-OAR-2021-0527-0002 (proposed revisions to RULOF provisions at 40
CFR 60.24a(g)).
640
87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-2021-0527-0002(proposed revisions to RULOF provisions at 40 CFR 60.24a(h), (i)).
548This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

establishing such an outermost date. Proposed subpart Ba also provides that an affected sourcewith 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 tosupersede the application of subpart Ba for coal-fired steam generating units with respect to the
proposed requirements to establish outermost and imminent dates to cease operations forinvoking RULOF based on an affected EGU’s remaining useful life. As explained earlier in thissection of the preamble, the EPA has designed the subcategories for coal-fired affected EGUs
under these emission guidelines to accommodate sources’ self-identified operating horizons.
This approach to subcategorization obviates the need to establish an outermost date to cease
operations to guide 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. Although 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, states are not precluded from doing so based on unit-specific circumstances.￼￼
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 notproposing 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 thatstates will find it necessary to invoke RULOF for these sources.
549
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

The EPA is also proposing to supersede the requirement in subpart Ba to establish
imminent and outermost dates for the consideration of remaining useful life for affected
combustion turbine EGUs. While, as discussed above in this section of the preamble, it is likelythat some portion of the existing combustion turbine fleet will be reaching the end of its
remaining useful life in the 2035 to 2040 timeframe, the structure of the proposed subcategories,
the length of time between state plan submission and the compliance dates for the subcategories,
and the staggered compliance dates for the two subcategories make it difficult to set a widelyapplicable date or dates that represent an imminent cessation of operations. States would not be
precluded from demonstrating that an affected combustion turbine EGU’s remaining useful life
is so short that it qualifies for a business-as-usual standard of performance (i.e., that its remaining
useful life is so short that the cost of any control would be unreasonably high). Similarly, basedon the proposed BSERs for the subcategories and the staggered nature of the proposedcompliance dates for combustion turbine EGUs, the EPA does not believe it is helpful to set anoutermost date for the considering of remaining useful life for these units. The EPA requests
comment on its proposal to supersede the requirements in subpart Ba to set imminent andoutermost dates for the consideration of remaining useful life for affected combustion turbine
EGUs. If commenters believe such dates would be useful to guide states’ consideration ofremaining useful life for affected existing combustion turbines, the EPA further requests input onwhat those dates could be, and why.
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

550
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

EGU commits to permanently cease operations as an enforceable requirement. 641 The plan would
also have to include measures that provide for the implementation and enforcement of such acommitment. The EPA is not proposing to supersede this proposed requirement for the purposeof this emission guideline; states that include a RULOF standard based on an affected EGU’s
remaining useful life must make the source’s voluntary commitment to permanently cease
operations by a date certain 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 lessstringent standard, the state plan must include that operating condition as an enforceable
requirement. 642 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 whatthat 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 stringencyof these emission guidelines, the EPA is proposing to require that standards of performance

641

87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-2021-0527-0002(proposed revisions to RULOF provisions at 40 CFR 60.24a(h), (i)(3)).
642
87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-2021-0527-0002(proposed revisions to RULOF provisions at 40 CFR 60.24a(h)).
551This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

determined through this RULOF mechanism be in the same form of rate-based emission
limitations. 643
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 forsources 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 tothe proposed requirement that states evaluate certain control options for affected coal-fired steam
generating units in the long-term and medium-term subcategories and for affected combustion
turbine EGUs as part of their source-specific BSER determination, the proposal to not provide
outermost or imminent dates to cease operations for the consideration of remaining useful life,
and the proposal to require RULOF standards of performance to be in the form of lb CO2/MWhemission limitations.
c. Consideration of Impacted Communities
While the consideration of RULOF may warrant application of a less stringent standardof 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 toimpacts from those EGUs. Those communities could be put in the position of bearing the bruntof the greater health and environmental impacts resulting from an affected EGU implementing aless stringent standard of performance than would otherwise have been required pursuant to theemission guidelines. A lack of consideration of such potential outcomes would be antithetical tothe public health and welfare goals of CAA section 111(d).

643

87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-2021-0527-0002(proposed revisions to RULOF provisions at 40 CFR 60.24a(f)(3)).
552This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Therefore, the proposed subpart Ba revisions would require that states applying lessstringent standards of performance consider the potential pollution impacts and benefits ofcontrol 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 throughapplication of such BSERs. 644 The state will have identified these communities as pertinent
stakeholders in the process of meaningful engagement, which is discussed in section XII.F.1.b of
this preamble.
If the EPA finalizes the requirement under subpart Ba to consider the potential pollution
impacts and benefits of control to the communities most affected by and vulnerable to emissions
from a RULOF source communities as proposed, state plan submissions under these emission
guidelines would have to demonstrate that the state considered such impacts and benefits inapplying a less stringent standard of performance to such a source. The EPA expects that states’
meaningful engagement with pertinent stakeholders on the state plan development generally will
include engagement on any potential use of RULOF to apply less stringent standards ofperformance. The proposed requirement that states consider the potential pollution impacts andbenefits of control in the context of a source-specific BSER analysis for a particular source isintended to provide for states’ consideration of health and environmental effects on thecommunities that are most affected by and vulnerable to emissions from that particular source.
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 theidentified communities under each option. If the comparative analysis shows that emissions from644

87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-2021-0527-0002(proposed revisions to RULOF provisions at 40 CFR 60.24a(k)).
553This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

an affected EGU could be controlled at a higher cost but that such control benefits thecommunities 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 plan submission under these emission guidelines must clearly identify thecommunities most affected by and vulnerable to emissions from the designated facility. The EPA
is proposing that, in evaluating potential source-specific BSERs, a state must document any
health or environmental impacts and benefits of control options and describe how it consideredthose impacts on the identified communities. Pursuant to the proposed meaningful engagement
requirements discussed in section XII.F.1.b of this preamble, states’ plan submissions would also
be required to include a summary of the meaningful engagement the state conducted and asummary of stakeholder input received, including any engagement and input on RULOF sources
and the calculation of less-stringent standards of performance.
The EPA solicits comments on additional ways in which states might consider potential
pollution impacts and benefits of control to communities most affected by and vulnerable toemissions from affected EGUs when determining a less-stringent standard pursuant to RULOF.
In particular, the Agency is requesting comment on metrics or information concerning health andenvironmental impacts from affected EGUs that states can consider in source-specific RULOF
determinations. As discussed in section XII.F.1.b, the EPA is also requesting comment on tools
and methodologies for identifying communities that are most affected by and vulnerable toemissions from affected EGUs under these emission guidelines.

554
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

d. 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 stateplan 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, 645 states carry the burden of
making the demonstrations required under the RULOF mechanism and have the obligation tojustify 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
inadequacies in a state plan’s demonstration are 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 mustmeet all other applicable requirements of subpart Ba and these emission guidelines. 646
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 andappropriateness of the information on which the state relied. Both a demonstration that a
particular affected EGU meets the threshold requirements to invoke RULOF and thedetermination 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 to645

CAA section 111(d)(2), 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR2021-0527-0002 (proposed revisions to RULOF provisions at 40 CFR 60.24a(j)).
646
87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-2021-0527-0002(proposed revisions to RULOF provisions at 40 CFR 60.24a(l)).
555This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

use information that is applicable to and appropriate for the particular source at issue. 647 Thismeans that, when available, the state must use source- and site-specific information. This isconsistent 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 specificcircumstances.
In some instances, site-specific information may not be available. In such cases, it may bereasonable 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-sitespecific information must explain why that information is reasonable to rely on to determine aless 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. 648
The EPA solicits comment on the types of source-specific and other information thatstates 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 beappropriate for states to use in this context.
e. 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

647

87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-2021-0527-0002(proposed revisions to RULOF provisions at 40 CFR 60.24a(j)(1)).
648
87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-2021-0527-0002(proposed revisions to RULOF provisions at 40 CFR 60.24a(j)(2)).
556This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

proposed revisions to subpart Ba to clarify that states may consider RULOF to include more
stringent standards of performance in their state plans. 649 The allowance in CAA section
111(d)(1) that states may consider “other factors” does not limit states to considering only factorsthat may result in a less stringent standard of performance; other factors that states may wish toaccount 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 orstate 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 infact more stringent than the presumptively approvable standard of performance for the applicablesubcategory. 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 thestandard will achieve equivalent or better emission reductions. In this case, the EPA believes it isappropriate 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 andregulatory requirements, including that they are adequately demonstrated. 650 As for all standardsof performance, the state plan must include requirements that provide for the implementation and

649

87 FR 79176, 79204 (December 23, 2022), Docket ID No. EPA-HQ-OAR-2021-0527-0002(proposed revisions to RULOF provisions at 40 CFR 60.24a(m), (n)).
650
87 FR 79176, 79204 (December 23, 2022), Docket ID No. EPA-HQ-OAR-2021-0527-0002(proposed revisions to RULOF provisions at 40 CFR 60.24a(m)).
557This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 requirementsof 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.

558
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

3. Increments of Progress and Milestones for Affected EGUs that Have Elected to Commit toCease Operations
The EPA’s long-standing CAA section 111 implementing regulations at 40 CFR part 60,
subpart Ba 651 provide that state plans must include legally enforceable increments of progress toachieve compliance for each designated facility when the compliance schedule extends morethan a specified length of time from the state plan submission date. 652 The EPA’s December
2022 proposed revisions to subpart Ba would require increments of progress when thecompliance date is more than 16 months after the state plan submission deadline. 653 Under these
proposed emission guidelines, the state plan submission date would be 24 months (see section
XII.F.2 of this preamble) from promulgation of the emission guidelines, which the EPA iscurrently anticipating will be June 2026. The proposed compliance dates for affected EGUs
within the proposed subcategories all fall on or after January 1, 2030, which is more than 16
months after the state plan submission deadline. The EPA is therefore proposing to require thatstate plans include increments of progress as discussed in this section. For the purpose of theseemission guidelines, the EPA refers to pre-compliance date, federally enforceable requirements
associated with the planning, construction, and operation of natural gas or hydrogen 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 steam generating EGUs in the imminent-term, near-term, and medium-term
subcategories. These additional state plan requirements are intended to ensure that affected coalfired steam generating units can complete the steps necessary to qualify for a subcategory with aless stringent BSER and to provide the public assurance that those steps will be concluded in atimely manner.
559
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

a. Increments of Progress
The EPA is proposing to adopt emission guideline-specific implementation of the fivegeneric 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 thedesignated facility to the appropriate air pollution control agency; (2) Awarding of contracts foremission control systems or for process modifications, or issuance of orders for the purchase ofcomponent 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. To this end, the EPA is proposing that state plans must include specified
enforceable increments of progress as required elements for coal-fired EGUs that use natural gas
co-firing to meet the standard of performance for the medium-term existing coal-fired steam
generating subcategory and for natural gas-fired combustion turbine EGUs that use hydrogen cofiring to meet the standard of performance for hydrogen co-fired combustion turbine
subcategory. The EPA is additionally proposing that state plans must include enforceable
increments of progress for units that use CCS to meet the standard of performance for the longterm existing coal-fired steam generating subcategory or for the CCS combustion turbine
subcategory.
Some increments have been adjusted to more closely align with planning, engineering,and construction steps anticipated for designated facilities that will be complying with standardsof performance with natural gas or hydrogen co-firing or CCS, but they retain the basic structureand substance of the increments in the general implementing regulations. In addition, consistent
with 40 CFR 60.24a(d), the EPA is proposing similar additional increments of progress for the560
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

long-term and medium-term coal-fired subcategories as well as both combustion turbine
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 standardof performance. The EPA is also proposing an additional increment of progress related to theidentification of an appropriate sequestration site for the long-term coal-fired subcategory andthe CCS combustion turbine subcategory. Finally, the proposed emission guidelines include an
additional increment of progress that that applies solely to the hydrogen co-fired combustion
turbine subcategory related to securing sufficient hydrogen contract capacity to meet the standardof performance.
The EPA notes that affected EGUs do not necessarily have to implement the EPA’s
BSER technology to comply with their applicable standards of performance. For example,
affected EGUs in the medium- and long-term coal-fired steam generating unit subcategories may
meet their standards of performance using approaches other than natural gas co-firing and CCS,
respectively. Where the owners or operators of affected EGUs select compliance approaches thatdeviate from the BSER technology associated with a subcategory requiring increments ofprogress, the EPA proposes that the state plan would be required to specify increments ofprogress for the relevant affected EGUs that are consistent with the increments in 40 CFR
60.21a(h), as well as dates for achieving each increment.
The EPA is proposing that final compliance with the applicable standard of performance,
also defined as the final increment of progress at 40 CFR 60.21a(h)(5), must occur no later thanJanuary 1, 2030 for steam generating units in the medium-term and long-term subcategories, nolater than January 1, 2035 for combustion turbine EGUs in the CCS subcategory, and no later

561
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

than January 1, 2032 for combustion turbine EGUs in the hydrogen co-fired subcategory. 654 For
the remaining increments, the EPA is not proposing date-specific deadlines for achieving
increments of progress. Instead, the EPA proposes that states must assign calendar day deadlines
for each of the remaining increments for each affected EGU in their state plan submissions. The
first increment of progress listed at 40 CFR 60.21a(h)(1), submittal of a final control plan to the
air pollution control agency, must be assigned the earliest calendar date deadline among theincrements. The EPA believes that allowing states to schedule sources’ increments of progress
would provide them with flexibility to tailor compliance timelines to individual facilities, allow
simultaneous work toward separate increments, and still ensure full performance by thecompliance date. 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 ofprogress rather than leaving the timing for most increments to state discretion. The EPA alsoseeks comment on the specific deadlines or timeframes that the EPA could assign to eachincrement 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 andmaintenance, which does not require the installation of significant new emission controls or
operational changes. Because there is no need for the types of increments of progress specified in

654

The EPA is proposing that the second phase of the standard of performance for existinghydrogen co-fired combustion turbines, which corresponds to co-firing 96 percent by volume
low-GHG hydrogen, would start on January 1, 2038. However, the EPA is not proposing an
increment of progress associated with this second phase because the Agency anticipates therelevant planning, design, and construction steps will have occurred ahead of the January 1, 2032
compliance date.
562
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

40 CFR 60.21a(h) to ensure that affected EGUs in the imminent and near-term coal-fired and oiland 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 steam generating units falling within the medium-term subcategory andcombustion turbine EGUs within the hydrogen co-fired subcategory (i.e., units with proposed
BSERs of co-firing clean fuels), 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 or turbine modifications, orissuance of orders for the purchase of component parts to accomplish such modifications.
Affected EGUs can demonstrate compliance with this increment by submitting sufficientevidence that the appropriate contracts have been awarded. (3) Initiation of onsite construction or
installation of any boiler or turbine modifications necessary to enable natural gas co-firing at alevel of 40 percent on an annual average basis or hydrogen co-firing at 30 percent on an annual
average basis, as appropriate for the applicable subcategory. (4) Completion of onsite
construction of any boiler or turbine modifications necessary to enable natural gas co-firing at alevel of 40 percent on an annual average basis or hydrogen co-firing at 30 percent on an annual
average basis, as appropriate for the applicable subcategory. (5) Final compliance with the563This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

standard of performance by January 1, 2030 for coal-fired steam generating units and by January
1, 2032 for combustion turbine EGUs.
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 with proposed BSERs based on co-firing clean fuels (natural gas co-firing for mediumterm coal-fired steam generating EGUs and hydrogen co-firing for hydrogen co-fired combustion
turbine EGUs) to ensure timely completion of any pipeline infrastructure needed to transport
natural gas or hydrogen to designated facilities within each subcategory. Affected EGUs would
be required to demonstrate that all permitting actions related to pipeline construction havecommenced 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 thepermit sought and the authority to which each permit application was submitted, an attestationthat 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 atimeline to complete all pipeline permitting activities.
Affected EGUs within the hydrogen co-fired combustion turbine subcategory must meetan additional increment of progress to demonstrate they have secured access to hydrogen
supplies sufficient to meet their anticipated 2032 fuel needs. This increment can be met by acapacity contract for hydrogen at volumes in 2032 consistent with the information provided in
the final control plan and the pipeline specification included in the pipeline construction
increment of progress.

564
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

For coal-fired EGUs falling within the long-term subcategory and for combustion turbine
EGUs falling within the CCS subcategory (i.e., units with proposed BSERs of CCS), 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 theappropriate air pollution control agency. The final control plan must be consistent with thesubcategory 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 foremission control systems or for process modifications, or issuance of orders for the purchase ofcomponent parts to accomplish emission control or process modification. Affected EGUs candemonstrate compliance with this increment by submitting sufficient evidence that theappropriate contracts have been awarded. (3) Initiation of onsite construction or installation ofemission control equipment or process change required to achieve 90 percent CO2 capture on anannual basis. (4) Completion of onsite construction or installation of emission control equipment
or process change required to achieve 90 percent CO2 capture on an annual basis. (5) Final
compliance with the standard of performance by January 1, 2030 for coal-fired steam generating
units and by January 1, 2035 for combustion turbine EGUs.
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 coal-fired steam
generating unit and CCS combustion turbine subcategories. The first mirrors the proposed
approach for the co-firing subcategories to ensure timely completion of pipeline infrastructure
and the second is designed to ensure timely selection of an appropriate sequestration site. As thefirst additional increment, the EPA proposes that affected EGUs using CCS to comply with their565
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

standards of performance would be required to demonstrate that all permitting actions related topipeline construction have commenced by a date specified in the state plan. Evidence in supportof the demonstration must include pipeline planning and design documentation that informed thepermitting process, a complete list of pipeline-related permitting applications, including thenature of the permit sought and the authority to which each permit application was submitted, anattestation 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 atimeline to complete all pipeline permitting activities.
The second proposed additional increment of progress for affected EGUs using CCS tocomply with their standards of performance is formulated to ensure timely completion of site
selection for geologic sequestration of captured CO2 from the facility. Affected EGUs within thissubcategory must submit a report identifying the geographic location where CO2 will be injectedunderground, 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 ofprogress for coal-fired steam generating units falling within the medium-term subcategory, theseven increments of progress for units within the hydrogen co-fired combustion turbine
subcategory, and the seven increments of progress proposed for both subcategories that
anticipate CCS adoption. The EPA seeks comment on whether the increments contain an
appropriate level of specificity to establish clear, verifiable criteria to ensure that states andaffected EGUs are taking the steps necessary to reach full compliance. If commenters believe
they do not, the EPA requests comment on the appropriate level of specificity for each
566
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

increment. Additionally, as discussed in section XII.F.1.b.ii of this preamble, the EPA is
proposing a requirement that each state plan provide for the establishment of Carbon Pollution
Standards for EGUs 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 thoseincrements, the schedule required in the state plan for achieving them, and any documentationnecessary to demonstrate that they have been achieved to this website in a timely manner.
b. Milestones for Affected EGUs that Have Elected to Commit 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 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; where owners or operators of affected EGUs have elected tocommit to permanently cease operations by a date certain before January 1, 2040, and, where astate further elects to include such commitments as an enforceable element in a state plan, such
EGUs will fall into one of these three subcategories. Accordingly, affected EGUs in theimminent-term, near-term, and medium-term subcategories have BSERs that are specificallytailored to and dependent on their shorter operating horizons. The EPA is aware that there aremany 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 planrequirements, referred to as “milestones,” for EGUs in the imminent-term, near-term, andmedium-term subcategories.
567
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

The proposed milestone reporting requirements count backward from an affected EGU’s
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 an
Initial Milestone Report to the applicable state administering authority that includes thefollowing: (1) A summary of the process steps required for the affected EGU to permanently
cease operation by the date included in the state plan, including the approximate timing andduration 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 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 includedin the Milestone Report compare to the timelines of similar units within the state that havepermanently ceased operations within the 10 years prior to the date of promulgation of theseemission 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 toinvestors in which the plans for the EGU are mentioned and any integrated resource plan.
For each of the remaining years prior to the date to permanently cease operations that isused to determine the applicable subcategory, affected EGUs must submit an annual Milestone
Status Report that addresses the following: (1) Progress toward meeting all milestones andrelated metrics identified in the Milestone Report; and (2) supporting regulatory documents,
568
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

including correspondence and official filings with the relevant regional transmission
organization, balancing authority, public utility commission, or other applicable authority todemonstrate compliance with or progress toward all milestones.
The EPA is also proposing that affected EGUs with reporting milestones associated withcommitments 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 suchcessation is permanent, including any regulatory filings with applicable authorities ordecommissioning 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 commitments topermanently cease operations would be required to post their Initial Milestone Report, annual
Milestone Status Reports, and Final Milestone Status Report, including the schedule forachieving milestones and any documentation necessary to demonstrate that milestones have beenachieved, on the Carbon Pollution Standards for EGUs website, as described in section XII.F.1.b,within 30 business days of being filed.
The EPA recognizes that applicable regulatory authorities, retirement processes, andretirement approval criteria will vary across states and affected EGUs. The proposed milestonerequirements are intended to establish a general framework flexible enough to account forsignificant differences across jurisdictions while assuring timely planning toward the dates bywhich affected EGUs permanently cease operations. The EPA requests comment on this569
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

proposed approach, specifically whether any jurisdictions present unique state circumstances thatshould be considered when defining milestones and the required reporting elements.
4. 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, totalheat input, and total gross electricity output, including electricity generation and, whereapplicable, 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 inthe calendar quarter. The monitoring requirements of 40 CFR part 75 require most fossil fuelfired 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 technicallyreliable method of emission measurement for EGUs that burn solid fuels, as it provides ameasurement 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 canaccount for variability in the fuels and the combustion process. Reference methods have beendeveloped to ensure that all CEMS meet the same performance criteria, which helps to ensure
consistent, accurate data. Natural gas-fired combustion turbines have options under appendices D
and G of 40 CFR part 75 to use fuel flowmeters in lieu of a CO2 CEMS. The flue flowmeter data,
paired with fuel quality data, is used to determine CO2 mass emissions and heat input.

570
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 asthey have under existing programs, such as the Acid Rain Program (ARP) and the Regional
Greenhouse Gas Initiative (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. Similarly, the majorityof natural gas-fired combustion turbines that may be affected by this rule already use fuelflowmeters to monitor and report CO2 mass emissions and heat input under appendices D and G
of 40 CFR part 75. Relying on the same monitors that are certified and quality-assured inaccordance 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 flowrate.
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 andother 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 forcommercial applications or that capture and maintain custody of a CO2 stream in order tosequester 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
571
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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. 655,656,657
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 proposed GHGRP subpart VV. If the emitting EGU sends
the captured CO2 offsite, it must assure that the CO2 is managed at a facility subject to the
GHGRP requirements, and the facility injecting the CO2 underground must report under GHGRP
subpart RR or proposed GHGRP subpart VV. This proposal does not change any of therequirements 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 thetons of CO2 captured by the emitting EGU. The tons of CO2 sequestered by the geologic

655

87 FR 36920 (June 21, 2022).
International Standards Organization (ISO) standard designated as CSA Group (CSA) /American National Standards Institute (ANSI) ISO 27916:2019, Carbon Dioxide Capture,
Transportation and Geological Storage—Carbon Dioxide Storage Using Enhanced Oil Recovery(CO2-EOR) (referred to as “CSA/ANSI ISO 27916:2019”).
657
As described in 87 FR 36920 (June 21, 2022), both subpart RR and proposed subpart VV(CSA/ANSI ISO 27916:2019) require an assessment and monitoring of potential leakage
pathways; quantification of inputs, losses, and storage through a mass balance approach; anddocumentation of steps and approaches used to establish these quantities. Primary differences
relate to the terms in their respective mass balance equations, how each defines leakage, andwhen facilities may discontinue reporting.
572
656

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

sequestration site are not part of that calculation, though the EPA anticipates that the quantity of
CO2 sequestered will be substantially similar to the quantity captured. 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. The BSER is determined to be adequately
demonstrated based solely on geologic sequestration that is not associated with EOR. However,
EGUs also have the compliance option to send CO2 to EOR facilities that report under GHGRP
subpart RR or proposed 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. This will avoid duplicative monitoring, reporting, and verification requirements
between this proposal and the GHGRP, while also ensuring that the facility injecting andsequestering the CO2 (which may not necessarily be the EGU) maintains responsibility for theserequirements. 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
573
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

rate, c) to ensure accurate and complete accounting of CO2 mass emissions emitted to theatmosphere and captured for use or sequestration, at what locations should CO2 concentrationand 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 toaccurately 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 andensure 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 andreport 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 thestack (or duct). Under 40 CFR part 75, EGUs must complete regular performance tests on theflue gas flow monitor based on EPA Reference Method 2 or its allowable alternatives that areprovided 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
574
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

results from the use of EPA Reference Method 2 when the specific flow conditions (e.g., angularflow) are present in the stack. However, EGUs with stack gas flow monitors are not required touse 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 thestudy, 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.
E. Compliance Flexibilities
In developing these proposed emission guidelines, the EPA has heard from stakeholders
seeking flexibility in complying with standards of performance under these emission guidelines.
In particular, stakeholders have requested that the EPA allow states to include flexibilities suchas averaging and market-based mechanisms in their state plans, as has been permitted under prior
EPA rules. The EPA is proposing to allow states to incorporate averaging and emission trading
into their state plans, provided that states ensure that use of these compliance flexibilities will
result in a level of emission performance by the affected EGUs that is equivalent to each source
individually achieving its standard of performance. As discussed below, the EPA also recognizes
that the structure of the proposed subcategories and associated degrees of emission limitation, as
575This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

well as the unique characteristics of the existing sources in the relevant source categories, will
likely require that certain limitations or conditions be placed on the incorporation of averaging
and trading in order to ensure that such standards are at least as stringent as the EPA’s BSER.
This section discusses considerations related to such compliance flexibilities in the context of
this particular rule and set of regulated sources—existing steam generating units and existing
combustion turbine EGUs—and solicits comment on whether certain types of averaging andtrading maintain the stringency of the EPA’s BSER.
1. 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 theiremission 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 ofperformance 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

576This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

averaging, where appropriate for a particular emission guideline and consistent with the intended
environmental outcomes of the BSER. 658 See 87 FR 79208 (December 23, 2022).
Consistent with the return to this longstanding position, the EPA is proposing to allow
states to incorporate trading and averaging in their state plans under these emission guidelines.
States would not be required to allow for such compliance mechanisms in their state plans but
could provide for trading and averaging for existing steam generating units and/or existing
combustion turbines at their discretion. 659 As discussed in section XII.C of this preamble, stateplans must demonstrate that they achieve a level of emission performance by affected EGUs thatis consistent with the application of the BSER. The EPA is therefore proposing that, in order tofind that a state plan that includes trading or averaging is “satisfactory,” it must demonstrate thatit maintains the level of emission performance for the source category that would be achieved if
each affected EGU was individually achieving its presumptive standard of performance, after
allowing for any application of RULOF. In the case of averaging, discussed in section XII.E.3 of

658

The EPA has authorized trading or averaging as compliance methods in several emission
guidelines. See, e.g., 40 CFR 60.33b(d)(2) (emission guidelines for municipal waste combustors
permit state plans to establish trading programs for NOX emissions); 70 FR 28606, 28617 (May18, 2005) (Clean Air Mercury Rule authorized trading) (vacated on other grounds); 40 CFR
60.24(b)(1) (subpart B CAA section 111 implementing regulations promulgated in 2005 allow
states’ standards of performance to be based on an “allowance system”); 80 FR 64662, 64840(October 23, 2015) (CPP authorizing trading or averaging as a compliance strategy). In the
recent supplemental proposal to promulgate emission guidelines for the oil and natural gas
industry, the EPA has also proposed to allow states to permit sources to demonstrate compliancein the aggregate. 87 FR 74702, 74812 (December 6, 2022).
659
The EPA notes that these flexibilities, trading and averaging, would be used to comply withstandards of performance, rather than to establish standards of performance in the first instance.
In contrast to the RULOF mechanism, which, as described in section XI.D.2 of this preamble,
states may use to establish different standards of performance than those described by the EPA’s
BSER, trading or averaging may be used to demonstrate compliance with already establishedstandards of performance. That is, states incorporating trading or averaging would not need toundergo a RULOF demonstration for sources participating in trading or averaging programs.
577
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

this preamble, an equivalence demonstration would be relatively straightforward. For emission
trading programs, ensuring equivalent emission performance in the aggregate may be moredifficult.
Section XII.E.2 of this preamble discusses considerations related to the appropriatenessof trading and averaging for affected EGUs in certain circumstances, e.g., affected EGUs withproposed BSERs based on routine methods of operation and maintenance. Section XII.E.2 of thispreamble also discusses program design examples as well as potential design elements and takescomment on whether these or other designs or design elements could ensure that use of emission
trading or averaging does not undermine the stringency of the EPA’s BSER. However, theAgency is not proposing a presumptively approvable averaging or trading approach at this time.
The EPA also notes that 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 XII.F.1.b of this preamble, meaningful engagement provides an opportunity forcommunities most affected by and vulnerable to the impacts of a plan to provide input, including
input on any impacts resulting from the use of trading or averaging for compliance.
2. Emission Trading
The EPA is proposing to allow state plans to include emission trading programs as acompliance flexibility for affected existing EGUs under these emission guidelines and is taking
comment on whether certain types of trading programs could satisfy the requirement to maintainequivalence with source-specific application of standards of performance. This section discusses
considerations related to affected EGUs under these emission guidelines and how a state could
578This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

potentially incorporate a rate-based trading program or a mass-based trading program in a waythat preserves the stringency of the BSER.
a. 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 firstallowance 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 tosuccessively 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. 660 Annual progress reports demonstratethat EPA trading programs have been successful in mitigating the problems they were designed
to address, exhibiting significant emission reductions and extraordinarily high levels ofcompliance. 661 In addition, several states have implemented regional or intrastate CO2 emissions

660

The six current CSAPR trading programs are the CSAPR NOX Annual Trading Program,
CSAPR NOX Ozone Season Group 1 Trading Program, CSAPR SO2 Group 1 Trading Program,
CSAPR SO2 Group 2 Trading Program, CSAPR NOX Ozone Season Group 2 Trading Program,
and CSAPR NOX Ozone Season Group 3 Trading Program. The regulations for the six CSAPR
programs are set forth at subparts AAAAA, BBBBB, CCCCC, DDDDD, EEEEE, and GGGGG,
respectively, of 40 CFR part 97. The regulations for the Texas SO2 Trading Program are set forthat subpart FFFFF of 40 CFR part 97. The Acid Rain Program SO2 trading program is set forth inTitle IV of the Clean Air Act Amendments of 1990.
661
Environmental Protection Agency (2021). Power Sector Programs—Progress Report. EPA.
https://www3.epa.gov/airmarkets/progress/reports/index.html.
579This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 canallow 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 adiverse 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 typicallyaccompanied 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. 662
Emission trading may also provide important benefits. Having flexibility to prioritize themost cost effective emission reductions among affected EGUs may reduce the cost ofcompliance as well as provide flexibility for fleet management, while achieving the requisite
level of emission performance. In particular, emission trading may provide some short-term
operational flexibility.

662

LaCount, M. D., Haeuber, R. A., Macy, T. R., & Murray, B. A. (2021). Reducing Power
Sector Emissions under the 1990 Clean Air Act Amendments: A Retrospective on 30 Years ofProgram Development and Implementation. Atmospheric Environment (Oxford, England: 1994),
245, 1–10. https://doi.org/10.1016/j.atmosenv.2020.118012.
580
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

At the same time, there may be 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 while the proposed emission guidelines include both steam generating units andcombustion turbines, the fleet of affected steam generating units is expected to shrink under
BAU projections (see section IV.F of this preamble), and the number of existing combustion
turbines subject to these emission guidelines is limited (see section XI.C of this preamble) given
the subcategory applicability thresholds. As a result, there is unlikely to be as much diversity incost and emission performance among affected emission sources (resulting in less diversity inemission reduction opportunities and marginal abatement costs) as seen in prior emission trading
programs for the electric power sector.
The utility of trading under these emission guidelines may also be obviated somewhat by
the subcategories that the EPA has proposed to establish for existing coal-fired steam generating
units and existing gas combustion turbines. The specific subcategories proposed under theseemission guidelines for steam generating units are designed to provide for much of the same
operational flexibility as would be provided through trading; as a result, the EPA believes that it
would not be appropriate to allow affected EGUs in certain subcategories—imminent-term andnear-term coal-fired steam generating units and natural gas- and oil-fired steam generating
units—to comply with their standards of performance through trading. Similarly, the EPA
believes it would not be appropriate to allow affected EGUs with less-stringent, source-specificstandards based on RULOF to comply with those standards of performance through trading. As
discussed in section X.D.3 of this preamble, the proposed BSER determinations for theimminent- 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)
581
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

and, as a result, are based on routine methods of operation and maintenance. Natural gas- andoil-fired steam generating units also have proposed BSER determinations based on routine
methods of operation and maintenance. An emission trading program that includes affected
EGUs that have BSERs and resulting standards of performance based on limited expected
emission reduction potential—or, in the case of affected EGUs for which states have invoked
RULOF, less stringent standards of performance—may introduce the risk of undermining theintended stringency of the BSER for other facilities.
The EPA also believes that emission trading may be inappropriate for some subcategories
of affected EGUs based on other, subcategory-specific reasons. Affected EGUs 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 tosource behavior that may be non-responsive to the economic incentives of a trading program.
This consideration may be relevant for affected EGUs in the long-term coal-fired steam
generating unit subcategory and the CCS combustion turbine subcategory that comply with theirstandards of performance using CCS. Additionally, the utilization applicability criterion forexisting combustion turbines creates a barrier to emission trading under these emission
guidelines. Specifically, existing combustion turbines that are greater than 300 MW qualify asaffected EGUs and thus have applicable standards of performance only when they operate at anannual capacity factor of greater than 50 percent. When they operate at an annual capacity factorof 50 percent or less, they are not subject to standards of performance. The EPA believes that thefact that units may fall in or out of a trading program from year to year very likely precludes
their inclusion in any such program as a practical matter.

582
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

The EPA requests comment on these challenges and on whether, in light of these andother considerations, emission trading should be permitted for certain subcategories and not
permitted for others, and on whether emission trading should be limited to within certain
subcategories, and why. In the following sections, the EPA discusses potential rate-based andmass-based emission trading program approaches that could potentially be included in a stateplan and solicits comment on applied implementation issues in the context of these proposedemission guidelines and the considerations discussed in this subsection XII.E.2.a of thepreamble.
b. Rate-based Emission Trading
A rate-based trading program allows affected EGUs to trade compliance instruments thatare 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 demonstrate equivalentstringency as would be achieved if each affected EGU was achieving its standard of
performance.
In this example, affected EGUs that perform at a lower emission rate (lb CO2/MWh) thantheir 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 equivalentamount 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

583
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

pose a challenge 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/MWhemission 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, basedon 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 theirstandard 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 complianceinstruments when demonstrating compliance, such that their demonstrated CO2 emission rate isequivalent to their rate-based standard of performance. Transfer and use of these complianceinstruments 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
584This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

are automatically accounted for in the award of the compliance instrument. By default, only
operating affected EGUs could receive or participate in the trading of compliance instruments.
The EPA is seeking comment on whether rate-based emission trading might beappropriate under these emission guidelines, taking into consideration the discussion of theappropriateness of trading for certain subcategories in section XII.E.2.a of this preamble. In
particular, the EPA requests comment on whether and how a rate-based emission trading
program could be designed to ensure equivalent stringency as would be achieved if eachparticipating affected EGU was achieving its source-specific standard of performance, given the
structure of the proposed subcategories and their proposed BSERs. The EPA also requests
comment on any other methods of rate-based trading that would preserve the stringency of theBSER.
c. Mass-based Emission Trading
A mass-based trading program establishes a budget of allowable mass emissions for agroup 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 aspart of a state plan. The EPA requests comment on whether this or another method of massbased trading could ensure equivalent stringency as would be achieved if each participating
affected EGU was achieving its source-specific standard of performance.
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,
585
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 astate plan relatively straightforward. However, this familiarity comes with an awareness on thepart 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. Past experience shows that emission budgets haveoften 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 wasadopted and when compliance obligations begin. Projecting affected EGU fleet composition andutilization beyond the relative near term has become increasingly challenging, driven by factors
including changes in relative fuel prices and continued rapid improvement in the cost andperformance of wind and solar generation, along with new incentives for technology deployment
provided by the IIJA and the IRA. Critically, if affected EGUs reduce utilization or exit thesource category, the remaining affected EGUs face a reduced or eliminated obligation to improvetheir emission performance. In this case, the emission budget would be established at a levelsuch that the sources would not be collectively meeting the required level of emission
performance commensurate with each source achieving its rate-based standard of performance.
One program design states might employ to ensure that affected EGUs participating in a
mass-based trading program continue to meet the level of emission performance prescribed bycategory-wide, source-specific implementation of the rate-based standards of performance
includes regularly adjusting emission budgets to account for sources that cease operations orchange their utilization. One budget adjustment method that the EPA has developed is dynamic

586
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

budgeting, as applied in the Good Neighbor Plan 663, in which budgets are updated annuallybased on recent historical generation. States could apply a similar dynamic budgeting process tomass-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 theparticipating affected EGUs, as described in section XII.D of this preamble, multiplied by eachaffected EGU’s recent historical generation. The emission budget would be updated regularly 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 throughmass-based trading, though the EPA acknowledges that existing state or regional mass-based
trading programs may have developed other regular emission budget adjustment methods that
could potentially provide similar assurance and might provide a model that could be applied for
trading under these emission guidelines.
The EPA also acknowledges that other methods could be used to establish an emission
budget that, in conjunction with the aforementioned dynamic budget approach, could achieve atleast the requisite level of emission performance consistent with application of the BSER. States
could use a single rate at the level of the subcategory or source category that is, for example, as
stringent as the most controlled unit in the group (based on unit-specific standards ofperformance as defined in section XII.D.1) to establish the emission budget.
The EPA is seeking comment on whether mass-based emission trading might beappropriate under these emission guidelines, taking into consideration the discussion of theappropriateness of trading for certain subcategories in section XII.E.2.a of this preamble. In

663

The final Good Neighbor Plan was signed by the Administrator on March 15, 2023. At thistime, the final action has not yet been published in the Federal Register.
587

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

particular, the EPA requests comment on whether and how a mass-based emission trading
program could be designed to ensure equivalent stringency as each participating affected EGU
achieving its source-specific standard of performance, given the structure of the proposedsubcategories and their proposed BSERs. 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 onother approaches or features that could ensure that emission budgets reflect the stringency thatwould be achieved through unit-specific application of rate-based standards of performance.
d. General Emission Trading Program Implementation Elements
The EPA notes that states would need to establish procedures and systems necessary to
implement and enforce an emission trading program, whether it is rate-based or mass-based, if
they elect to incorporate emission trading into their state plans. This would include, but is not
limited to, establishing compliance timeframes and the mechanics for demonstrating complianceunder 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 toparticipating affected EGUs.
The EPA acknowledges that the proposed dates as of which standards of performance
would apply for sources covered by these emission guidelines differ by subcategory: January 1,
2030, for all steam generating units; January 1, 2032, for the hydrogen co-fired combustion
turbine subcategory; and January 1, 2035, for the CCS combustion turbine subcategory. If
588
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

trading is permitted for two or more of these sets of sources, this difference could potentiallypose an implementation challenge where a trading program includes these sources. To address
this issue, a program could, for example, begin in 2030 for steam generating units and bring in
combustion turbine EGUs later, or states could delay implementation of a trading program tocoincide with the later combustion turbine date. The Agency requests comment on potential
ways to address this implementation issue in the context of a state plan, and whether this issue
impacts the utility or feasibility of trading across subcategories.
The EPA is also requesting comment on whether and to what extent there would be adesire 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.
e. Banking of Compliance Instruments
The EPA requests comment on whether state plans should be allowed to provide forbanking 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 stringency ofthe 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 futurecontrol 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
589
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

addition to requesting comment on whether the EPA should permit allowance banking, 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.
f. Interstate Emission Trading
The EPA is requesting comment on whether, and under what circumstances orconditions, to allow interstate emission trading under these emission guidelines. Given theinterconnectedness 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 thesame form of trading and have identical trading program requirements. There are manyrequirements for program reciprocity and approvability that would need to be established in theemission guidelines, in addition to providing mechanisms for submission and EPA review ofstate plans that include interstate trading mechanisms. Given the increased level of program
complexity that would be necessary to accommodate interstate trading and the operational
flexibilities already provided by the structure of the proposed subcategories and their proposed
BSERs, the EPA requests comment on whether there is utility in providing for it under theseemission guidelines. In addition, the EPA requests comment on the information, guidance, andrequirements the EPA would need to provide for states to implement successful interstate
emission trading programs.
3. Rate-based Averaging
The EPA is proposing to allow state plans to include rate-based averaging as acompliance flexibility for affected EGUs under these emission guidelines. This section discusses
590This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

how states could potentially incorporate a rate-based averaging program in a way that preserves
the stringency of the EPA’s BSER as well as some considerations related to incorporating
averaging in state plans. The EPA is seeking comment on one potential method, described in thissection, as well as other methods that could maintain the required level of emission performanceequivalent to each source individually achieving its standard of performance.
Averaging allows multiple affected EGUs to jointly meet a rate-based standard of
performance. Affected EGUs participating in averaging could, for example, demonstratecompliance 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 participatein 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 withsource-specific standards of performance.
Averaging can provide potential benefits. First, it offers some flexibility for sources totarget cost effective reductions at any affected EGU. For example, owners or operators ofaffected 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-stackconfiguration). In such instances, unit-level compliance involves apportioning reported
emissions to individual affected EGUs that share a stack based on electricity generation or otherparameters.
However, the EPA notes that the subcategory approach in these emission guidelines
already provides significant operational flexibility for affected EGUs, potentially making the591
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

provision of further flexibility through averaging redundant or inappropriate, especially at theowner or operator level.
The EPA is seeking comment on the utility of rate-based averaging 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) or
to certain subcategories.
4. Relationship to Existing State Programs
The EPA recognizes that many states have adopted binding policies and programs (withboth a supply-side and demand-side focus) under their own authorities 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 morenarrowly 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 theirpotential to reduce power sector CO2 emissions through a range of strategies broader than those592This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

proposed here pursuant to CAA section 111(d). The EPA seeks comment on whether there areany elements of the proposed emission guidelines that might interfere with the implementation ofstate requirements that limit CO2 emissions from EGUs that may be subject to the proposedemission guidelines.
F. State Plan Components and Submission
This section describes the proposed requirements for the contents of state plans, theproposed timing of state plan submissions, and the EPA’s review of and action on state plansubmissions. This section also discusses issues related to the applicability of a Federal plan andtiming 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 plansubmissions under these particular emission guidelines, 664 those proposals are addressed
explicitly in section XII.F.1.b on specific state plan requirements and throughout this preamble.
Unless expressly amended or superseded in these proposed emission guidelines, the provisionsof subpart Ba would apply.
1. 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 CFRpart 60, subpart Ba. The EPA is also proposing additional plan components that are specific tostate plans submitted pursuant to these emission guidelines. For example, the EPA is proposing

664

40 CFR 60.20a(a)(1).

593

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

plan components that are necessary to implement and enforce the specific types of standards ofperformance for affected EGUs that would be adopted by a state and incorporated into its stateplan.
a. General Components
The CAA section 111 implementing regulations at 40 CFR part 60 subpart Ba provide
separate lists of administrative and technical criteria that must be met in order for a state plansubmission 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 (element 9 in the list
below). 665 If that criterion is finalized as proposed, the complete list of applicable administrativecompleteness criteria for state plan submissions would be: (1) A formal letter of submittal fromthe 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 theplan, 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, wheneverpossible, 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 the665

87 FR 79176, 79204 (December 23, 2022), Docket ID No. EPA-HQ-OAR-2021-0527-0002(proposed revisions at 40 CFR 60.27a(g)(2)).
594This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 wasgiven 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.
Pursuant to subpart Ba, the technical criteria required for all plans must include each of
the following: 666 (1) Description of the plan approach and geographic scope; (2) Identification ofeach designated facility (i.e., affected EGU); identification of standards of performance for eachaffected EGU; and monitoring, recordkeeping, and reporting requirements that will determine
compliance by each designated facility; (3) Identification of compliance schedules and/or
increments of progress; (4) Demonstration that the state plan submission is projected to achieve
emission performance under the applicable emission guidelines; (5) Documentation of state
recordkeeping and reporting requirements to determine the performance of the plan as a whole;and (6) Demonstration that each standard is quantifiable, permanent, verifiable, enforceable, andnon-duplicative.

666

40 CFR 60.27a(g)(3)).

595This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

b. Specific State Plan Requirements
To ensure that state plans submitted pursuant to these emission guidelines are consistent
with the requirements of subpart Ba, the EPA is proposing regulatory requirements that would
apply to all affected EGUs subject to a standard of performance under a state plan pursuant tothese proposed emission guidelines, as well as requirements that apply to affected EGUs within
specific subcategories. Standards of performance for affected EGUs included in a state plan must
be quantifiable, verifiable, permanent, enforceable, and non-duplicative. Additionally, per CAA
section 302(l), standards of performance must be continuous in nature. Additional proposed stateplan requirements include:

Identification of affected EGUs and the subcategory to which each affected EGU is
assigned;

Identification of standards of performance for each affected EGU in lb CO2/MWh-grossbasis, including provisions for implementation and enforcement of such standards;



Identification of enforceable increments of progress and milestones, as required for
affected EGUs within the applicable subcategory, included as enforceable elements of astate plan;

If relevant, identification of applicable enforceable requirements that are prerequisites forinclusion of an affected EGU in a specific subcategory, such as enforceable commitments
to cease operations by a specified date or to limit annual capacity factor, where a state
and the owner or operator of an affected EGU have chosen to rely on such commitments
in order for the affected EGU to be included in a specific subcategory, included as
enforceable elements of a state plan; and596
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.



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 anaffected EGU within a respective subcategory. These proposed methodologies are specified foreach of the subcategories of affected EGUs in section XII.D.1 of this preamble.
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 XII.C of this preamble, in order for the
EPA to find a state plan “satisfactory,” that plan must achieve the level of emission performancethat 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 toestablish the applicable standards of performance for affected sources in their state plans, thestructure and purpose of CAA section 111 require that those plans achieve an equivalent level ofemission performance as applying the EPA’s presumptive standards of performance to thosesources (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 the presumptively approvable standard of performance. Such requirements include ademonstration by the state of why an affected EGU for which the state invokes RULOF cannot
reasonably apply the BSER. The state would also be required to demonstrate where and how it
considered the potential pollution impacts and benefits of control to communities most affectedby and vulnerable to emissions from the designated facility. The EPA expects that states would
597
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

identify these communities, gather information about the potential pollution impacts and benefitsof control, and document how they have considered that information in setting source-specificstandards of performance for RULOF sources through their meaningful engagement processes.
In addition to consideration of impacts on and benefits to affected communities in thecontext of invoking RULOF for particular sources, the proposed revisions to the CAA section
111 subpart Ba implementing regulations include requirements for public engagement on overall
state plan development. These requirements are intended to ensure robust and meaningful public
involvement in the plan development process and to ensure that those who are most affected by
and vulnerable to the impacts of a plan will share in the benefits of the plan and are protectedfrom being adversely impacted. The 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.
The fundamental purpose of CAA section 111 is to reduce emissions from categories ofstationary 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 publichealth and welfare. Meaningful engagement is a corollary to the longstanding requirement for
public participation, including through public hearings, in the course of state plan development
under CAA section 111. 667 A robust and meaningful engagement process is critical to ensuringthat the entire public has an opportunity to participate in the state plan development process andthat states understand and consider the full range of impacts of a proposed plan.

667

40 CFR 60.23(c)-(g); 40 CFR 60.23a(c)-(h).

598This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 plandevelopment or plan revision process. Such engagement must not bedisproportionate in favor of certain stakeholders. It must include the developmentof 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. 668
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 ofthe plan or plan revision.” 669 The preamble to the proposed revisions to subpart Ba notes that
“increased vulnerability of communities may be attributable, among other reasons, to both anaccumulation of negative and lack of positive environmental, health, economic, or social
conditions within these populations or communities.” 670
In the context of these emission guidelines, the air pollutant of concern is greenhousegases 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 toserious and life-threatening environmental and human health impacts. Thus, one set of impacts
on communities that states should consider in identifying pertinent stakeholders is climatechange impacts, including increased incidence of drought and flooding, damage to crops and668

87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-2021-0527-0002(proposed revisions at 40 CFR 60.21a(k)).
669
87 FR 79176, 79191 (December 23, 2022), Docket ID No. EPA-HQ-OAR-2021-0527-0002(proposed revisions at 40 CFR 60.21a(l)).
670
87 FR 79176, 79191 (December 23, 2022).
599
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

disruption of associated food, fiber, and fuel production systems, increased incidence of pests,
increased incidence of heat-induced illness, and impacts on water availability and water quality.
These and other such climate change-related impacts can have a disproportionate impact oncommunities and populations depending on, inter alia, accumulation of negative and lack ofpositive 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 within the state that are most affected by and/or vulnerable to the impacts ofclimate 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 thispreamble, on climate impacts, to assist them in identifying their pertinent stakeholders).
Additionally, communities near affected EGUs may also be affected by a state plan or plan
revision due to impacts associated with implementation of that plan. For example, communities
located near affected EGUs may be impacted by construction and operation of infrastructure
required under a state plan. Activities related to the construction and operation of new naturalgas, CCS, and hydrogen pipelines may impact individuals and communities both locally and atlarger distances from affected EGUs but near any associated pipelines. Thus, communities nearaffected EGUs and communities near pipelines constructed pursuant to state plan requirements
should be considered pertinent stakeholders and included in meaningful engagement.
The EPA also acknowledges that employment at affected EGUs (including employment
in operation and maintenance as well as in construction for installation of pollution control
technology) is impacted by power sector trends on an ongoing basis, and states may choose to600
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

take energy communities into consideration as part of meaningful engagement. A variety offederal programs are available to support these communities. 671
In some cases, an affected EGU may be located near state or Tribal borders and impact
communities in neighboring states or Tribal lands. In such cases, the EPA believes it could bereasonable for a state to identify pertinent stakeholders in the neighboring state or Tribal land
and to work with the relevant air pollution control authority to conduct meaningful engagementthat addresses cross-border impacts. The EPA solicits comment on how meaningful engagement
should apply to pertinent stakeholders outside a state’s borders.
It is important for states to recognize and engage the communities most affected by
and/or vulnerable to the impacts of a state plan, particularly as these communities may not have
had a voice when the affected EGUs were originally constructed. Consistent with the longstanding requirements for public engagement in state plan development, states should design
meaningful engagement to ensure that all pertinent stakeholders are able to provide input on how
affected EGUs in their state comply with their state plan requirements pursuant to these emission
guidelines. Because these emission guidelines address air pollution that becomes well mixed and

671

An April 2023 report of the federal Interagency Working Group on Coal and Power Plant
Communities and Economic Revitalization (Energy Communities IWG) summarizes how the
Bipartisan Infrastructure Law, CHIPS and Science Act, and Inflation Reduction Act have greatly
increased the amount of federal funding relevant to meeting the needs of energy communities, aswell as how the Energy Communities IWG has launched an online Clearinghouse of broadly
available federal funding opportunities relevant for meeting the needs and interests of energy
communities, with information on how energy communities can access federal dollars and obtain
technical assistance to make sure these new funds can connect to local projects in theircommunities. Interagency Working Group on Coal and Power Plant Communities and Economic
Revitalization. “Revitalizing Energy Communities: Two-Year Report to the President” (April
2023). https://energycommunities.gov/wp-content/uploads/2023/04/IWG-Two-Year-Report-tothe-President.pdf.
601
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

is long-lived in the atmosphere, the EPA expects states will consider communities andpopulations within the state that are both most impacted by particular affected EGUs andassociated pipelines and that will be most affected by the overall stringency of state plans. (Notethat the EPA addresses consideration of impacts of particular sources in the context of RULOF
in section XII.D.2.c of this preamble.)
During the Agency’s pre-proposal outreach, some environmental justice organizations
and community representatives raised strongly held concerns about the potential health,environmental, and safety impacts of CCS. The EPA believes that any deployment of CCS canand should take place in a manner that is protective of public health, safety, and the environment,
and that includes early and meaningful engagement with affected communities and the public.
As stated in the Council on Environmental Quality’s (CEQ) February 2022 Carbon Capture,
Utilization, and Sequestration Guidance, “the successful widespread deployment of responsible
CCUS will require strong and effective permitting, efficient regulatory regimes, meaningful
public engagement early in the review and deployment process, and measures to safeguard
public health and the environment.” 672
As discussed in section V.C.3 of this preamble, the EPA is required to consider nonair
quality health and environmental impacts, along with other considerations, in determining the
BSER for both new and existing affected EGUs. In developing this proposed rulemaking, the
EPA heard and carefully considered concerns expressed by affected communities regarding thepossible impacts of CCS and hydrogen infrastructure in the context of selecting the proposed
BSER. After weighing any adverse nonair quality health and environmental impacts of CCS and

672

Carbon Capture, Utilization, and Sequestration Guidance, 87 FR 8808, 8809 (February 16,2022), https://www.govinfo.gov/content/pkg/FR-2022-02-16/pdf/2022-03205.pdf.
602

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

hydrogen co-firing along with the other BSER considerations, including the significant amountof emission reductions that can be achieved, and the reasonableness of the control costs, the EPA
decided to propose that CCS and hydrogen co-firing meet the qualifications for the BSER for
certain subcategories of sources. See, for example, section X.D.1.a.iii of this preamble.
The EPA recognizes, however, that facility- and community-specific circumstances,including the existence of cumulative impacts affecting a community’s resilience or where
infrastructure buildout would necessarily occur in an already vulnerable community, may also
exist. The meaningful engagement process is designed to identify and enable consideration ofthese and other facility- and community-specific circumstances. This includes consideration offacility- and community-specific concerns with emissions control systems, including CCS andhydrogen co-firing. States should design meaningful engagement to elicit input from pertinent
stakeholders on facility- and community-specific issues related to implementation of emissions
control systems generally, as well as on any considerations for particular systems.
If the revisions to subpart Ba are finalized as proposed, states would need to demonstratein 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, including information about the potential
pollution impacts and benefits of control. 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 belimited to notification through the Internet. Other channels may include notice throughnewspapers, libraries, schools, hospitals, travel centers, community centers, places of worship,
gas stations, convenience stores, casinos, smoke shops, Tribal Assistance for Needy Families
603
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

offices, Indian Health Services, clinics, and/or other community health and social services asappropriate. The state should also consider any geographic, linguistic, or other barriers toparticipation 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 thesubmission incomplete or to disapprove the plan. As discussed in section XII.F.2 of thispreamble, the EPA is proposing to provide 24 months from the date of publication of final
emission guidelines for state plan submission, which should allow states adequate time to
conduct meaningful engagement.
The EPA is requesting comment on what assistance states and pertinent stakeholders mayneed in conducting meaningful engagement with affected communities to ensure that there are
adequate opportunities for public input on decisions to implement emissions control technology(including but not limited to CCS or low-GHG hydrogen). The EPA is also requesting commenton any tools or methodologies that states may find helpful for identifying communities that are
most affected by and vulnerable to emissions from affected EGUs under these emission
guidelines. The EPA is also requesting comment on whether it would be useful for the Agency to
promulgate minimum approvability requirements for meaningful engagement that are specific tothese emission guidelines and, if so, what those requirements should be.
i. Specific State Plan Requirements for Existing Combustion Turbines Co-Firing Low-GHG
Hydrogen
As discussed in section XI.C of this preamble, the EPA is proposing that the BSER for
affected combustion turbine EGUs in the hydrogen co-fired subcategory is co-fired 30 percent
low-GHG hydrogen by volume starting January 1, 2032, and 96 percent low-GHG hydrogen by
604
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

volume starting January 1, 2038. Therefore, as discussed in section XII.D.1.c.ii of this preamble,
the EPA is proposing a rate-based presumptive standard of performance for the hydrogen cofired subcategory based on co-firing low-GHG hydrogen at these levels. However, CAA section
111 does not require that sources meet their applicable standards of performance byimplementing the BSER. Therefore, affected combustion turbine EGUs in the hydrogen co-fired
subcategory do not necessarily have to meet their standards of performance by co-firinghydrogen. However, should they choose to comply in this manner, the hydrogen that they co-fireto meet their standards of performance must be low-GHG hydrogen. Thus, the EPA is proposingthat state plans require that affected EGUs in the hydrogen co-fired subcategory that meet theirstandards of performance by co-firing hydrogen demonstrate that they are co-firing low-GHG
hydrogen. The EPA discusses its rationale for requiring low-GHG hydrogen to be used forcompliance and its proposed definition of low-GHG hydrogen in sections VII.F.3.c.vi and
VII.F.3.c.vii(F) of this preamble.
Section VII.K.3 of this preamble discusses the EPA’s proposal to closely follow
Department of Treasury protocols, which are currently under development, in determining how
affected EGUs demonstrate compliance with the requirement to use low-GHG hydrogen. In thecontext of the proposed CAA section 111(b) rule for new combustion turbines, 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 andinput, purchasing agreements, contracts, and attribute certificates. The EPA is also taking
comment, in the context of the CAA section 111(b) rule, on whether EGUs should be required tomake fully transparent their sources of low-GHG hydrogen and the corresponding quantities
605
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

procured, as well as on whether the EPA should require EGUs to demonstrate that their hydrogenis exclusively from facilities that produce only low-GHG hydrogen, as a means of reducing
burden and opportunities for double counting. The EPA proposed to mirror the requirements it
finalizes for verification of low-GHG hydrogen for new combustion turbine EGUs, as discussed
in section VII.K.3 of this preamble, in the state plan requirements for affected existing
combustion turbine EGUs in the hydrogen co-fired subcategory under these emission guidelines.
The EPA therefore requests comment on the proposed approaches for verifying that low-GHG
hydrogen is used for complying with an applicable standard of performance discussed in section
VII.K.3 of this preamble. Additionally, the EPA requests comment on any unique considerations
regarding the implementation of such verification requirements through state plans, including
whether any additional or different requirements may be necessary to ensure that affected
existing combustion turbine EGUs in the hydrogen co-firing subcategory that co-fire hydrogen tomeet their standards of performance co-fire with low-GHG hydrogen.
ii. 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 a state relies on thatcommitment for subcategory applicability (e.g., a state elects to rely on an affected coal-fired
steam-generating unit’s commitment to permanently cease operations by December 31, 2034, tomeet the applicability requirements for the near-term subcategory), must be in the form of an

606
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

emission limit of 0 lb CO2/MWh that applies on the relevant date. 673 Such an emission limit
would be included in a state regulation, permit, order, or other acceptable legal instrument andsubmitted to the EPA as part of a state plan. If approved, the affected EGU would have afederally enforceable emission limit of 0 lb CO2/MWh that would become effective as of thedate 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 andenforceability relative to the alternative, which is an enforceable commitment in a state plan tocease operation by a date certain.
Second, the EPA is proposing that state plans that cover affected coal-fired steam
generating units within any subcategory that is based on the date by which a source elects topermanently 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 applicablestate and federal requirements for permanently ceasing operation of the EGU, including removalfrom 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 require owners and operators ofaffected EGUs to establish publicly accessible websites, referred to here as a “Carbon Pollution
Standards for EGUs Website,” to which all reporting and recordkeeping information for eachaffected 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

673

As explained in section X of this preamble, an affected EGU’s federally enforceablecommitment to cease operations is not part of that EGU’s standard of performance but is rather aprerequisite condition for subcategory applicability.
607

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 a portion of theaffected EGUs may already be posting comparable reporting and recordkeeping information to
publicly available websites under the EPA’s April 2015 Coal Combustion Residuals Rule, 674
such that the burden of this website requirement for these units could be minimal.
In particular, the EPA is proposing that the owners or operators of affected EGUs would
be required to post to their websites their subcategory designations and compliance schedules,
including for increments of progress and milestones, leading up to full compliance with theapplicable standards of performance. Owners or operators would also be required to post to theirwebsites any information or documentation needed to demonstrate that an increment of progressor milestone has been achieved. Similarly, the EPA is proposing that emissions data and otherinformation needed to demonstrate compliance with a standard of performance would also be
required to be posted to the Carbon Pollution Standards for EGUs Website for an affected EGU
in a timely manner. The EPA is proposing that all information required to be made publicly
available on the Carbon Pollution Standards for EGUs Website be posted within 30 businessdays of the information becoming available to or reported by the owner or operator of an affected
EGU. Information would have to remain 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.

674

See https://www.epa.gov/coalash/list-publicly-accessible-internet-sites-hosting-compliancedata-and-information-required for a list of websites for facilities posting Coal Combustion Rulecompliance information.
608

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

The EPA proposes that owners or operators of affected EGUs that are also subject tosimilar website reporting requirements for the Coal Combustion Residuals Rule may use an
already established website to house the reporting and recordkeeping information necessary tosatisfy its Carbon Pollution Standards for EGUs 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.
To make it easier for the public to find the relevant Carbon Pollution Standards for EGUs
Websites, the EPA is also proposing that a state must establish a website that displays the links to
the websites for all affected EGUs in its state plan.
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 arequirement that the owner or operator of each affected 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 thereport, the owner or operator of the affected EGU would be required to explain the cause orcauses 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 thetimeframes in which the owner or operator intends to cure the deviation. The owner or operatorof the EGU must submit the report to the state regulatory agency and post the report to theaffected EGU’s Carbon Pollution Standards for EGUs 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
609
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

to ensure compliance while addressing genuine risks to electric system reliability. In theseemission guidelines, the EPA has included subcategories for coal-fired steam generating units
that take into account the operating horizons of these units and has provided relatively longplanning and compliance timeframes. The EPA’s proposed emission guidelines for existing
combustion turbines likewise provide extensive lead time to meet the proposed degrees ofemission limitation and apply only to a portion of the fleet that exceeds certain capacity andutilization thresholds. The Agency therefore does not anticipate that either the need for certain
coal-fired steam generating units and existing combustion turbines 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 believes it is appropriate to provide accommodations for potential
isolated instances in which unanticipated factors beyond an owner or operator’s control, andability to predict and plan for, could have an adverse, localized impact on electric reliability. Insuch instances, affected EGUs could find themselves in the position of either operating innoncompliance 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 inviolation of CAA requirements, seeking injunctive relief, civil penalties and, in certain
circumstances, other appropriate relief. The EPA also has the discretion to agree to negotiatedresolutions, including administrative compliance orders (“ACOs”) for achieving compliance with
CAA requirements, that include expeditious compliance schedules with enforceable compliancemilestones. The EPA does not generally speak to the intended scope of its enforcement efforts,
particularly in advance of a violation actually occurring. However, the EPA is explaining its
610
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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: 675•

The owner/operator of the affected EGU requesting an ACO has requested, in writing andin 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 theestablished reliability criteria for the relevant control area/balancing authority, 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 withwritten 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 theneed to continue operating for reliability purposes is due to factors beyond the control of

675This is a nonexclusive list of conditions. The EPA may choose to consider additional factors
when deciding whether to enter an ACO in any given situation.
611

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 andpotential noncompliance through a state plan revision.
If deemed appropriate to do so, the EPA would issue an ACO that includes a complianceschedule 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 torequest an ACO to address reliability risk and anticipated noncompliance in circumstances inwhich 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 or operator of
an affected EGU would have to submit to the EPA in order to be considered for an ACO.
2. 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. 676 For the purpose of theseparticular emission guidelines, the EPA is proposing to supersede that timeline and is proposing

676

87 FR 79182 (December 23, 2022), Docket ID No. EPA-HQ-OAR-2021-0527-0002(proposed revisions at 40 CFR 60.23a(a)).
612This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

a state plan submission deadline that is 24 months from the date of publication of the final
emission guidelines. Crucially, these proposed emission guidelines apply to a relatively large andcomplex source category—existing fossil fuel-fired steam generating units and existing fossil
fuel-fired combustion turbines. 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 tomany 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 additionallycomplicated 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 thosesources; 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.
Additionally, prior to an owner or operator providing a suggestion for a subcategory andstandard of performance for an affected EGU to a state, that owner or operator will likely need toanalyze options for complying with the applicable BSER for the subcategory. The EPA
anticipates that some owners or operators of affected coal-fired steam generating units andaffected combustion turbines will do feasibility and FEED studies for CCS prior to committing
to it as a control strategy in a state plan. As discussed in section XII.B of this preamble and in the613This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

GHG Mitigation Measures for Steam Generating Units TSD, FEED studies take approximately
12 months to complete, 677 after which additional time is necessary to allow the conclusions fromthat study to be integrated into a state’s planning process for certain affected EGUs. For othercoal-fired steam generating units, there may also be planning, design, and permitting exercisesthat will be necessary for utilities to undertake prior to committing to a subcategory based onnatural gas co-firing. While any boiler modifications required for affected EGUs that intend to
co-fire natural gas are relatively straightforward, the owners or operators of EGUs in themedium-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 todetermine feasibility and, in some cases, could involve FERC approval. Similar considerations
apply for affected combustion turbine EGUs in the hydrogen co-fired subcategory with regard to
any turbine upgrades that may be necessary to co-fire higher percentages of hydrogen and/or tothe construction of any pipeline laterals that are necessary to supply the EGU with low-GHG
hydrogen. Based on the approximately 12-month period that states and the owners or operatorsof affected EGUs will likely take to assess control strategies for these units, the EPA does notbelieve it is reasonable to require state plans to be submitted 15 months after promulgation ofthese emission guidelines.
In the proposed subpart Ba timelines for state plan submission, the EPA justified thegenerally 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

677

GHG Mitigation Measures for Steam Generating Units TSD, chapter 4.7.1.
614This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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
which compliance strategy (such as CCS or co-firing) will be appropriate at a given EGU.
Additionally, the EPA does not believe providing a longer timeline for the submission of stateplans in this particular instance would ultimately impact how quickly the affected EGUs cancomply with their standards of performance. As explained in section XII.B of this preamble andin the GHG Mitigation Measures for Steam Generating Units TSD, the EPA anticipates thatCCS 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 someowners/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 forplan revisions and delayed emission reductions. In contrast, providing 24 months for state plansubmission would mean that although plans would be due June 2026, owners or operators ofaffected EGUs would have had time to complete their feasibility and FEED studies and some
initial planning steps before then. The EPA anticipates that owners or operators would needapproximately 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 threemonths will adversely impact public health or welfare, especially when it is considered thatproviding more time for state plan development in this instance is more likely to ultimately resultin certainty and timely emission reductions. The EPA solicits comment on the 24-month stateplanning period. The EPA specifically requests comments from owners and operators of affected
615This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

EGUs regarding the steps, and amount of time needed for each step, that they would have toundertake to determine the applicable subcategories and to plan and implement the associatedcontrol 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 andthe 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.
The EPA is additionally requesting comment on a potential bifurcated approach to stateplan submissions for affected steam generating units and affected combustion turbine EGUs. In
contrast to the proposed compliance deadline for steam generating units, the EPA is proposing
compliance deadlines for combustion turbine EGUs in the CCS subcategory and combustion
turbine EGUs in the hydrogen co-fired subcategory of January 1, 2035, and January 1, 2032
(with a second phase commencing on January 1, 2038), respectively. Despite the longer period
between the anticipated promulgation of these emission guidelines and the proposed compliancedeadlines for affected combustion turbine EGUs, the EPA is proposing that state plansubmissions containing standards of performance and other applicable requirements for theseunits would be due 24 months after promulgation. Based on many of the same considerations
regarding power sector planning and coordination discussed above, the EPA believes that states;
owners and operators of affected EGUs; RTOs, ISOs, or other balancing authorities; and the
public may benefit from considering the control strategies for all affected EGUs under these
616
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

emission guidelines on the same timeline. Additionally, the EPA is cognizant of the need toachieve emission reductions and thus the public health and welfare benefits as soon asreasonably practicable.
However, the EPA also acknowledges that the compliance timeframes for combustion
turbine EGUs are likely to be longer than those for steam generating units under these emission
guidelines due to, inter alia, the need to phase installation of CCS across the power sector andthe continued ramp-up in production and transmission capacity for low-GHG hydrogen. The
EPA is therefore requesting comment on an approach in which states would submit two different
plans on different timelines: a state plan addressing affected steam-generating units due 24months after promulgation of these emission guidelines and a second state plan addressing
affected combustion turbine EGUs due 36 months after promulgation of these emission
guidelines. The EPA solicits comment on this staggered approach and on whether 36 months, ora longer or shorter period, could be an appropriate state plan submission deadline for combustion
turbine EGUs, and why. The EPA requests that commenters explain if and how a longer stateplan submission timeline for affected combustion turbine EGUs would be consistent withachieving the emission reductions under these emission guidelines as quickly as reasonably
practicable, as well as on the potential interactions between the state plan submission time frame
and the proposed compliance deadlines for combustion turbine EGUs. The EPA also solicits
comment from potentially impacted communities and other pertinent stakeholders on any
considerations related to providing a longer state plan submission timeframe for combustion
turbine EGUs under these emission guidelines.

617
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

3. State Plan Revisions
The EPA expects that the state plan submission deadline proposed under these emission
guidelines would give states, utilities and independent power producers, and stakeholders
sufficient time to determine in which subcategory each of the affected EGUs falls and toformulate and submit a state plan accordingly. However, the EPA also acknowledges that,
despite states’ best efforts to accurately reflect the plans of owners or operators with regard toaffected EGUs at the time of state plan submission, such plans may subsequently change. In
general, states have the authority and discretion to submit revised state plans to the EPA for
approval. 678 State plan revisions are generally subject to the same requirements as initial stateplan submissions 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 shouldplan accordingly to avoid noncompliance.
The EPA is proposing a state plan submission date that is 24 months after the publicationof final emission guidelines and is proposing that the first compliance date for a portion ofaffected EGUs would be on January 1, 2030. A state may choose to submit a plan revision prior
to compliance with its existing state plan requirements; however, the EPA reiterates that any
already approved federally enforceable requirements, including milestones, increments of678

40 CFR 60.23a(a)(2), 60.28a.

618

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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
for coal-fired steam generating affected EGUs or ahead of the separate compliance dates forachieving the CCS-based or hydrogen co-firing-based standards for existing combustion
turbines. 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 onthem and effectuate any changes to existing state plan requirements 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
XII.F.4 of this preamble.
Under the proposed emission guidelines for existing coal-fired steam generating units,states would place their affected coal-fired steam generating units into one of four subcategories
based on the time horizons over which those EGUs elect to operate. These subcategories are
static—affected EGUs would not be able move between subcategories absent a plan revision. 679
However, the EPA acknowledges that there may be instances in which a change in subcategory
will be necessary. For affected coal-fired steam generating EGUs that are switching into theimminent-term, near-term, or medium-term subcategories, the EPA proposes to require that thestate include in its state plan revision documentation of the affected EGU’s submission to the679

If the EPA finalizes an option for states to include dual paths for an affected coal-fired EGU
or EGUs in their state plans, those affected EGUs would be able to choose between two
subcategories prior to the final compliance date without the state’s needing to revise its plan.
619

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 ornotices 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 Carbon Pollution Standards for EGUs Website. These proposed requirements
are modeled on the proposed milestones for sources electing to commit to permanently cease
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 imminentterm, near-term, or medium-term subcategories would also be required to comply with theproposed enforceable milestones applicable to those subcategories.
Some changes between subcategories of affected coal-fired steam generating EGUs,
including from the long-term into the medium-term subcategory and from the imminent-term ornear-term into the medium-term or long-term subcategory, would entail new standards ofperformance reflecting a different add-on control strategy than initially anticipated. In order toavoid undermining the stringency of these proposed emission guidelines, the EPA expects
affected EGUs changing subcategories before the January 1, 2030, compliance deadline to makeevery reasonable effort to meet that compliance deadline. However, the EPA acknowledges that,
620
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

in some circumstances, it may not be possible to complete the necessary planning andconstruction 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 XII.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.” 680 In order to invoke RULOF to change a compliance deadline for anaffected 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 thisdemonstration 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.
Like subcategorization for affected coal-fired steam-generating units, states would place
their affected combustion turbine EGUs into one of the two subcategories in their state plans,along with the corresponding standard of performance. These subcategory designations are

680

87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-2021-0527-0002(proposed revisions to RULOF provisions at 40 CFR 60.24a(e)(3)).
621This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

static—affected EGUs would not be able to move between subcategories absent a plan revision.
The EPA expects that situations necessitating a change in subcategory for combustion turbine
EGUs will be far less likely than for coal-fired steam-generating units. However, should the needarise for an affected combustion turbine EGU to change subcategories in a state plan, the sameconsiderations discussed above for coal-fired steam generating units would apply. If a
combustion turbine EGU changes subcategories in a manner that entails a new standard of
performance that is based on a different control technology than initially anticipated, the EPA
expects the owner or operator of that EGU to make every reasonable effort to meet the originalcompliance deadline for the newly applicable subcategory. For situations in which this is
impossible, the EPA is proposing that states could use the RULOF mechanism as describedabove to provide a revised compliance deadline. As part of its RULOF demonstration, a state
would be required to provide evidence supporting the affected combustion turbine’s need toswitch subcategories, as well as a demonstration that the need to invoke RULOF and to provide a
different compliance deadline was not caused by the owner or operator’s self-createdimpossibility.
Documentation related to these demonstrations must also be posted to the Carbon
Pollution Standards for EGUs Website. For example, it would not be reasonable for a state thathas 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 reasonablesystems 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 additionallyproposing to consider whether an affected EGU has been complying with its applicable622
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 compliancedeadline first evaluate whether the affected EGU is able to comply with that standard by adifferent, 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 XII.D.2 of this preamble.
4. Dual-Path Standards of Performance for Affected EGUs
Under the structure of these emission guidelines as proposed, states would assign affectedcoal-fired steam generating units to subcategories in their state plans and an affected EGU would
not be able to change its applicable subcategory without a state plan revision. This is because,due to the nature of the BSERs for coal-fired steam generating units, an affected EGU thatswitches between subcategories may not be able to meet compliance obligations for a new anddifferent subcategory without considerable lag time and thus the switch would result innoncompliance and a loss of emission reductions. Similarly, states would be required to assign
their affected combustion turbine EGUs to either the CCS or hydrogen co-fired subcategory intheir state plans, at which point a unit could not switch between subcategories without a plan
623
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

revision. Therefore, as a general matter, states must assign each affected EGU to a subcategory
and have in place all the legal instruments necessary to implement the requirements for thatsubcategory by the time of state plan submission.
However, the EPA acknowledges that there may be circumstances in which the owner or
operator of a coal-fired steam generating unit has not yet finalized its future operating plans andwishes to retain the option to choose between two different subcategories ahead of the proposed
January 1, 2030, compliance date. Similarly, the owner or operator of a combustion turbine EGU
may wish to retain the ability to choose between the CCS and hydrogen co-fired subcategories,
particularly because the relatively long period between state plan submission and compliancemeans that a unit’s circumstances could change materially in that time. The EPA is therefore
soliciting comment on the following dual-path approach that may result in an additional
flexibility for owners or operators of affected coal-fired steam generating units and affected
combustion turbine 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 steam generating
units and combustion turbine 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 coal-fired steam generating unit that wants the option to be part of either the longterm or imminent-term subcategory, the state plan would include an enforceable 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 and624
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

maintenance. The affected EGU would be required to meet all compliance obligations for bothsubcategories, including increments of progress and/or milestones for commitments to cease
operations, leading up to the compliance date of January 1, 2030. The state and the owner or
operator of the 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 thecompliance date. For affected coal-fired steam generating units, the state would be required to
notify the EPA of the applicable standard by July 1, 2029. For affected combustion turbine
EGUs, the state would be required to notify the EPA of the applicable standard by the earliest
compliance date, or July 1, 2031. If the state has not notified the EPA by the required date (July
1, 2029, or July 1, 2031) of the final applicable subcategory for the affected EGU, the EPA is
proposing that a coal-fired steam generating unit would automatically be subject to therequirements of the subcategory that corresponds to the longer remaining life of the EGU, while
a combustion turbine EGU would automatically be subject to the requirements of the CCS
subcategory. Additionally, if the affected EGU misses an enforceable increment of progress,
milestone (as described in section XII.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 othersubcategory. If the EGU misses submissions for increments of progress and/or milestones forboth subcategories, the EGU will automatically be subject to the requirements of the subcategorythat corresponds to the longer remaining life of the EGU (for coal-fired steam generating units)or the CCS subcategory (for combustion turbine EGUs) and will additionally be found to be outof compliance for the increment of progress or milestone that it has missed.

625This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

The EPA is soliciting comment on this approach to provide flexibility to states andaffected coal-fired steam generating units and affected combustion turbine EGUs. In someinstances, owners or operators of affected EGUs may wish to have additional time to evaluate
future operating plans; this proposed dual-path approach should provide owners or operators
additional time to commit to a subcategory. However, with this additional time comes additionalburden 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 steam generating unit 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 cofiring 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 thelong-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 affectedcoal-fired steam generating units and affected combustion turbine EGUs would be able tocomply with applicable requirements in a timely manner. Additionally, the EPA solicits
comment on whether notification deadlines of July 1, 2029, for coal-fired steam generating units,
and July 1, 2031, for combustion turbine EGUs are the appropriate dates for a final decision
between two potential standards of performance and why.

626This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

5. 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 681 and a 12-monthtimeline for action on state plans. 682 The EPA is not proposing to supersede these timelines;
therefore, review of and action on state plan submissions will be governed by the requirements ofrevised 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 ofthat submission. If the EPA has failed to make a completeness determination for a state plansubmission 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 thecomponents of state plan submissions against the applicable requirements of subpart Ba andthese 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, partiallyapprove, partially disapprove, and conditionally approve a state plan submission. 683 Anycomponents of a state plan submission that the EPA approves become federally enforceable.

681

The timeframes and requirements for state plan submissions described in this section also
apply to state plan revisions. See generally 40 CFR 60.27a.
682
87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-2021-0527-0002(proposed revisions at 40 CFR 60.27a).
683
87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-2021-0527-0002(proposed revisions at 40 CFR 60.27a(b)).
627This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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.
6. 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 theseemission guidelines. The EPA’s obligation to promulgate a Federal plan is triggered in threesituations: 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 astate’s plan. 684 Where a state has failed to submit a plan by the submission deadline, theproposed revisions to subpart Ba would give the EPA 12 months from the state plan submission
due date to promulgate a Federal plan; otherwise, the 12-month period starts from the date thestate 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. 685 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.

684

87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-2021-0527-0002(proposed revisions at 40 CFR 60.27a(c)).
685
87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-2021-0527-0002(proposed revisions at 40 CFR 60.27a(d)).
628This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 complianceschedule than provided by these emission guidelines, in which case the EPA would follow thesame process and criteria in the regulations that apply to states’ provision of RULOF
standards. 686 Under the proposed revisions to subpart Ba, the EPA would also be required to
conduct meaningful engagement with pertinent stakeholders prior to promulgating a Federalplan. 687
As described in section XII.F.2 of this preamble, the EPA is proposing to allow states 24months for a state plan submission after the promulgation of the final emission guidelines.
Therefore, the EPA would be obligated to promulgate a Federal plan within 36 months of the
final emission guidelines for all states that fail to submit plans. Note that this will be the earliest
obligation for the EPA to promulgate Federal plans for states and that different triggers (e.g., adisapproved 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 CFRpart 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

686

40 CFR 60.27a(e)(2).
87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-2021-0527-0002(proposed revisions at 40 CFR 60.27a(f)).
629

687

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

when evaluating the TIP submission and will approve the TIP if appropriate. The EPA iscommitted 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 forareas 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 anduntil the EPA approves an applicable TIP applicable to those facilities.
XIII. Implications for Other EPA Programs
A. Implications for New Source Review (NSR) Program
CAA section 110(a)(2)(C) requires that a 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 modificationsof existing sources that emit “regulated NSR pollutants” at or above certain establishedthresholds. New sources and modifications that emit regulated NSR pollutants under theestablished 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 the630
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

source for each of its emitted pollutants at the time the permit is issued. Major NSR permits forsources 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. 688 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 otherrequirements, meet the Lowest Achievable Emissions Rate (LAER) pursuant to CAA sections
171(3) and 173(a)(2) for any pollutant subject to NNSR. For sources subject to minor NSR, the
CAA and EPA rules do not set forth prescriptive control technology requirements for minor NSR
programs so these permits can be less stringent than major NSR permits. Due to the pollutantspecific applicability of the NSR program, it is 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

688

For the PSD program, “regulated NSR pollutant” includes any pollutant for which a NAAQS
has been promulgated (“criteria pollutants”) and any other air pollutant that meets therequirements of 40 CFR 52.21(b)(50). Some of these non-criteria pollutants include fluorides,
sulfuric acid mist, hydrogen sulfide, total reduced sulfur, and reduced sulfur compounds.
631
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

regulations define it as a “major stationary source.” 689 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) 690, the source can be subject to major NSR requirements for any otherregulated 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 691, the EPA has notpromulgated a GHG SER but applies a BACT applicability threshold of 75,000 TPY CO2e. 692
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 changeor 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.” 693 As with newsources, the one exception to this applicability approach is GHG, which currently applies a

689

For PSD, the statute uses the term “major emitting facility” and defines it as a stationary
source that emits, or has a PTE, at least 100 tons per year (TPY) if the source is in one of 28
listed source categories, or at least 250 TPY if the source is not a listed source category. CAA
section 169(1). For NNSR, the emissions threshold for a major stationary source is 100 TPY, andlower thresholds apply for certain pollutants based on the severity of the nonattainment
classification.
690
As a result of the Supreme Court’s decision in UARG v. EPA, the D.C. Circuit issued anamended judgment in Coalition for Responsible Regulation, Inc. v. EPA, Nos. 09-1322, 10-073,
10-1092 and 10-1167 (D.C. Cir. April 10, 2015), which, among other things, vacated the PSD
and title V regulations under review in that case to the extent that they require a stationary source
to obtain a PSD or title V permit solely because the construction of the source, or a modification
at the source, emits or has the potential to emit GHGs at or above the applicable major NSR
thresholds.
691
Consistent with the 2009 Endangerment Findings, the PSD program treats GHG as a single
air pollutant defined as the aggregate group of six gases: CO2, N2O, CH4, HFCs, PFCs, and SF6.
40 CFR 52.21(b)(49)(i).
692
See Janet G. McCabe and Cynthia Giles, Next Steps and Preliminary Views on the
Application of Clean Air Act Permitting Programs to Greenhouse Gases Following the Supreme
Court's Decision in Utility Air Regulatory Group v. Environmental Protection Agency (July 24,2014), https://www.epa.gov/sites/default/files/2015-12/documents/20140724memo.pdf.
693
Per 40 CFR 52.21(b)(1)(i)(c), a minor source that undergoes a physical change that would
itself be considered major, is subject to major source requirements.
632
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

BACT applicability threshold in lieu of a SER and can only be subject to major NSR if anotherpollutant 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 haveboth 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 newemissions unit, or if it involves multiple types of emission units.694 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 eachpollutant that is subject to PSD at the major stationary source or at each emissions unit involvedin 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 eachavailable 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 of694

40 CFR 52.21(a)(2)(iv); 40 CFR 52.21(b)(2)(i); 40 CFR 52.21(b)(3).
633This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

performance under the NSPS. 695 Permitting authorities may determine BACT by applying the
EPA’s five-step “top down” approach. 696 The ultimate determination of BACT is made by thepermitting authority after a public notice and comment period of at least 30-days on the draft
permit and supporting information. 697
1. 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 theapplicability of the NSPS and commences construction after the date of the proposed NSPS in
the Federal Register. 698 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 modificationthat commences construction or reconstruction of a stationary combustion turbine EGU after thedate of publication of this proposed NSPS, the PSD permit should reflect a BACT determinationthat is at least as stringent as the promulgated NSPS for each of the source’s affected EGUs.

695

42 U.S.C. § 7479(3) (“In no event shall application of ‘best available control technology’
result in emissions of any pollutants which will exceed the emissions allowed by any applicablestandard established pursuant to [CAA Section 111 or 112].”).
696
U.S. EPA, NSR Workshop Manual (Draft October 1990),
https://www.epa.gov/sites/default/files/2015-07/documents/1990wman.pdf; U.S. EPA, PSD and
Title V Permitting Guidance for Greenhouse Gases (March 2011),
https://www.epa.gov/sites/default/files/2015-07/documents/ghgguid.pdf.
697
40 CFR 124.10.
698
U.S. EPA, PSD and Title V Permitting Guidance for Greenhouse Gases (March 2011), p. 25.
634
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 indeveloping the NSPS. As explained above, BACT is a case-by-case review that considers anumber 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.
2. 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 eachaffected 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 operationalchange. Under the NSR program, undertaking a physical or operational change may require thesource 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

635This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

prior to making the changes unless the permitting authority determines that the action is exempt
from permitting. 699
Thus, there may be 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 may occur is if an affected source experiences greater
unit availability and reliability as a result of implementing its BSER requirement (e.g., anefficiency 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
with 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 inutilization 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 ormore of its pollutants, the source may be required to obtain a major NSR permit for themodification.
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 thestandards of performance of the emission guidelines. One of these flexibilities is the ability forstates to establish the standards of performance in their plans in such a way so that their affected699

The EPA sought to exempt environmentally beneficially pollution control projects from NSR
requirements in a 2002 rule that codified longstanding EPA policy, but this rule was struck downin court. New York v. EPA, 413 F.3d 3, 40–42 (D.C. Cir. 2005) (New York I).
636

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

sources, in complying with those standards, in fact would not have emission increases thattrigger 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 asaffected sources comply with the standards of performance, their emissions would not increase in
a way that trigger major NSR requirements. For example, a state could, as part of its state plan,develop enforceable conditions for a source expected to trigger major NSR that would
effectively limit the unit’s ability to increase its emissions in amounts that would trigger major
NSR (effectively establishing a synthetic minor limitation). 700
B. 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

700

Certain stationary sources that emit or have the potential to emit a pollutant at a level that isequal to or greater than specified thresholds are subject to major source requirements. See, e.g.,
CAA sections 165(a)(1), 169(1), 501(2), 502(a). A synthetic minor limitation is a legally andpracticably enforceable restriction that has the effect of limiting emissions below the relevant
level and that a source voluntarily obtains to avoid major stationary source requirements, such as
the PSD or title V permitting programs. See, e.g., 40 CFR 52.21(b)(4), 51.166(b)(4), 70.2
(definition of “potential to emit”).
637

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

terminals). 701 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 applicablerequirements. Requirements resulting from these rules that are imposed on EGUs or otherpotentially 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 inaccordance with the schedule established in the title V regulations. For example, if the permit hasa remaining life of three years or more, a permit reopening to incorporate the newly applicablerequirement shall be completed no later than 18 months after promulgation of the applicablerequirement. If the permit has a remaining life of less than three years, the newly applicablerequirement 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 “notfederally enforceable” until the EPA has approved the state plan. The EPA solicits comment onwhether, and under what circumstances, states might use this mechanism.
XIV. 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 these701

In some circumstances, the EPA may delegate authority for part 71 permitting to anotherpermitting agency, such as a tribal agency or a state. The EPA has entered into delegationagreements for certain part 71 permitting activities with at least one tribal agency. There are
currently no states that do not have an approved part 70 program; thus, there is no need for the
EPA to delegate part 71 delegated authority to any state at this time.
638

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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) combustion turbine phase 1 and phase 2 standards and 111(d) steam generating
turbine proposals in combination. The second and third scenarios represent different stringenciesof 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 PerformanceStandards for Greenhouse Gas Emissions from New, Modified, and Reconstructed Fossil FuelFired 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 innature 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, theEPA believes that such illustrative analysis can provide important insights.
In the RIA, the EPA evaluates the potential impacts of the three illustrative scenarios
using the present value (PV) of costs, benefits, and net benefits, calculated for the years 2024 to
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 specificsnapshot 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
639This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

analyses of anticipated economic and energy impacts, environmental justice impacts, andemployment 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 ofthe variety of impact analysis just mentioned, please see the RIA, which is available in thedocket for this action. The EPA also seeks comment on all aspects of the analysis, including
modeling assumptions.
A. Air Quality Impacts
For the analysis of the proposed standards for new combustion turbines and for existing
steam generating EGUs, which do not include the impact of the proposed standards for existing
combustion turbines and the third phase of the proposed standards for new combustion turbines,
total cumulative power sector CO2 emissions between 2028 and 2042 are projected to be 617
million metric tons lower under the illustrative proposal scenario than under the baseline. Table 7
shows projected aggregate annual electricity sector emission changes for the illustrative proposal
scenario, relative to the baseline.
Table 7—Projected Electricity Sector Emission Impacts for the Illustrative Proposal
Scenario, Relative to the Baseline
CO2 (million Annual NOX
Ozone
Annual SO2
Direct PM2.5
metric tons)(thousandSeason NOX (thousand short (thousand short
short tons)(thousand
tons)
tons)
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
Note: Ozone season is the May through September period in this analysis.
The emissions changes in these tables do not account for changes in HAP that are likely to occur
as a result of this action.
640
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

For the analysis of the proposed standards for existing combustion turbines and for thethird phase of the proposed standards for new natural gas-fired EGUs, total cumulative power
sector CO2 emissions between 2028 and 2042 are estimated to be between 215-409 million
metric tons lower than under the illustrative proposal scenario.
Table 8—Estimated Electricity Sector Emission Impacts from Existing Gas Standard andThird Phase of low-GHG Hydrogen Co-firing standard for New Base Load Combustion Turbines
CO2 (million metric tons)
Low
High
2028
0
0
2030
0
0
2035
-20
-37
2040
-20
-39
B. Compliance Cost Impacts
The power industry’s compliance costs are represented in this analysis as the change inelectric power generation costs between the baseline and illustrative scenarios, including the costof monitoring, reporting, and recordkeeping. In simple terms, these costs are an estimate of theincreased power industry expenditures required to comply with the proposed actions.
The compliance assumptions—and, therefore, the projected compliance costs—set forthin 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 scopeand 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 tothe states in developing their state plans.
The impact of the IRA is to accelerate the ongoing shift towards lower emitting
technology. In particular, tax credits for low-emitting technology results in growing generation
share for renewable resources and the deployment of 11 GW of CCS retrofits on existing coal
641
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

fired EGUs, and 10 GW of CCS retrofits on existing combined cycle EGUs by 2035. New
combined cycle builds are 22 GW by 2030, and existing coal capacity continues to decline,
falling to 69 GW by 2030 and 35 GW by 2040. As a result, the compliance cost of the proposed
rules is lower than it would be absent the IRA.
We estimate the present value (PV) of the projected compliance costs for the analysis of
the proposed standards for new combustion turbines and for existing steam-generating EGUs,
which do not include the impact of the proposed standards for existing combustion turbines
EGUs and the third phase of the proposed standards for new combustion turbines over the 2024
to 2042 period, as well as estimate the equivalent annual value (EAV) of the flow of thecompliance costs over this period. The EAV represents a flow of constant annual values that, hadthey 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, isestimated to be about $14 billion, with an EAV of about $0.95 billion. At the 7-percent discountrate, the PV of the compliance costs is estimated to be about $10 billion, with an EAV of about$0.98 billion.
The EPA has developed a separate estimate of the projected compliance costs for the
proposed standards for existing combustion turbines and third phase of the proposed standards
for new natural gas-fired EGUs over the 2024 to 2042 period. The PV of these compliance costs,
discounted at the 3-percent rate, is estimated to be between about $5.7 to 10 billion, with an EAVof between about $0.4 to 0.7 billion. At the 7 percent discount rate, the PV of these compliancecosts is estimated to be between about $3.5 to 6.2 billion, with an EAV of about $ 0.34 to 0.6
billion.
642
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Sections 3 and 8 of the RIA present detailed discussions of the compliance costprojections for the proposed requirements, as well as projections of compliance costs for less andmore stringent regulatory options. For a detailed description of these compliance costprojections, please see sections 3 and 8 of the RIA. The EPA solicits comment on its costestimation generally.
C. Economic and Energy 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 9 presents a variety of energy market impact estimates for 2028, 2030, 2035, and2040 for the illustrative proposal scenario, relative to the baseline. These results pertain to theanalysis of the proposed standards for new combustion turbines and for existing steam
generation EGUs, and do not include the impact of the proposed standards for existing
combustion turbines and the third phase of the proposed standards for new combustion turbines.
Table 9—Summary of Certain Energy Market Impacts for the Illustrative Proposal
Scenario, Relative to the Baseline[Percent change]
2028
2030
2035
2040
(%)
(%)
(%)
(%)
Retail electricity prices
-1%
2%
0%
0%
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.
643
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

More broadly, changes in production in a directly regulated sector may have effects onother 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 forparticular 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 aregulation across all sectors in the economy.
In 2015, the EPA established a Science Advisory Board (SAB) panel to consider thetechnical merits and challenges of using economy-wide models to evaluate costs, benefits, andeconomic 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 morecomprehensive assessment of the effects of air regulations. 702 In response to the SAB’s
recommendations, the EPA developed a new CGE model called SAGE designed for use inregulatory analysis. A second SAB panel performed a peer review of SAGE, and the review
concluded in 2020. 703
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. As presented in the RIA,

702

U.S. EPA. 2017. SAB Advice on the Use of Economy-Wide Models in Evaluating the Social
Costs, Benefits, and Economic Impacts of Air Regulations. EPA-SAB-17-012.
703
U.S. EPA. 2020. Technical Review of EPA's Computable General Equilibrium Model,
SAGE. EPA-SAB-20-010.
644This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

annualized social costs estimated in SAGE are approximately 35 percent larger than the partial
equilibrium private compliance costs (less taxes and transfers) derived from IPM. This isconsistent with general expectations based on the empirical literature. 704 However, the social costestimate reflects the combined effect of the proposed rules’ requirements and interactions with
IRA subsidies for specific technologies that are expected to see increased use in response to the
proposed rules. We are not able to identify their relative roles at this time. The EPA solicits
comment on the SAGE analysis presented in the RIA appendix.
Environmental regulation may affect groups of workers differently, as changes inabatement and other compliance activities cause labor and other resources to shift. An
employment impact analysis describes the characteristics of groups of workers potentiallyaffected 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.
D. 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 theseprojected impacts. 705 These proposed rules are projected to reduce emissions of CO2, SO2, NOX,
and PM2.5 nationwide which we estimate will provide climate benefits and public health benefits.

704

See, for example, Marten, A. L., Garbaccio, R., and Wolverton, A. 2019. Exploring theGeneral Equilibrium Costs of Sector-Specific Environmental Regulations. Journal of the
Association of Environmental and Resource Economists, 6(6), 1065-1104.
705
These results pertain to the analysis of the proposed standards for new combustion turbine
EGUs and for existing steam-generating EGUs, and do not include the impact of the proposed
standards for existing combustion turbine EGUs and the third phase of the proposed standards
for new natural gas-fired EGUs.
645
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 tochanges 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 thevalue 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 theimportant 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 underestimatesof 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
646This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

2008, following a Ninth Circuit Court of Appeals remand of a rule for failing to monetize thebenefits 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 havedetermined 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 theissues and studies discussed therein, the EPA finds that these estimates, while likely anunderestimate, are the best currently available SC-GHG estimates. These SC-GHG estimates
were developed over many years using a transparent process, peer-reviewed methodologies, thebest 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, includingthat the models used to produce them do not include all of the important physical, ecological, andeconomic 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, theInteragency 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
647
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 foropportunities 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. If EPA’s
updated SC-GHG methodology is finalized before these rules are finalized, the EPA intends topresent monetized climate benefits using the updated SC-GHG estimates in the final RIA. 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 andSO2 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 PM2.5attributable health effects. These proposed rules are also expected to reduce ozone season NOXemissions 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 inmost locations reduces human exposure to ozone and the incidence of ozone-related healtheffects, though the degree to which ozone is reduced will depend in part on local concentrationlevels of VOCs. The RIA estimates 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 Estimating PM2.5- and Ozone-Attributable Health Benefits
648This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

TSD, 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 to 2042
period, discounted to 2024 in 2019 dollars, for the analysis of the proposed standards for new
natural gas-fired EGUs and for existing coal-fired EGUs, which do not include the impact of the
proposed standards for existing natural gas-fired EGUs and the third phase of the proposed
standards for new natural gas-fired EGUs. We monetize benefits of the proposed standards andevaluate 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 $68 billion, with an EAV of
about $4.8 billion discounted at 3 percent. Combining the projected monetized climate andhealth benefits yields a total PV estimate of about $98 billion and EAV estimate of $6.9 billion.
At a 7 percent discount rate, these proposed rules are expected to generate projected PVof monetized health benefits of about $44 billion, with an EAV of about $4.3 billion discounted
at 7 percent. The EPA notes that while OMB Circular A-4, as published in 2003, recommends
using 3 percent and 7 percent discount rates as "default" values, Circular A-4 also recognizes that“special ethical considerations arise when comparing benefits and costs across generations,” andCircular A-4 acknowledges that analyses may appropriately “discount future costs andconsumption benefits…at a lower rate than for intragenerational analysis.” Therefore, climate
benefits remain discounted at 3 percent in this benefits analysis. Thus, these proposed rules
649
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

would generate a PV of total monetized benefits of $74 billion, with an EAV of $6.4 billion
discounted at a 7 percent rate.
The projected PV of monetized climate benefits for the analysis of the impact of the
proposed standards for existing combustion turbines and the third phase of the proposed
standards for new natural gas-fired EGUs is between about $10 to 20 billion, with an EAV of
between about $0.7 to 1.4 billion using the SC-CO2 discounted at 3 percent.
The results presented in this section provide an incomplete overview of the effects of the
proposals. The monetized climate benefits estimates do not include important benefits that weare unable to fully monetize due to data and modeling limitations. 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.
E. 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, theAgency has analyzed the impacts of these proposed rules on communities with potential
environmental justice concerns and engaged with stakeholders representing these communities toseek input and feedback. The EPA evaluates, to the extent practicable, whether proposed GHG

650
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

reductions are accompanied by changes in other health-harming pollutants that may place further
burdens on these communities. 706
Executive Order 12898 is discussed in section XV.J of this preamble and analyticalresults are available in section 6 of the RIA.
1. Introduction
Executive Order 12898 directs the EPA to identify the populations of concern who aremost 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 thedevelopment, 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 adisproportionate burden of environmental harms and risks, including those resulting from thenegative environmental consequences of industrial, governmental, and commercial operations orprograms and policies”. 707 In recognizing that minority and low-income populations often bear
an unequal burden of environmental harms and risks, the EPA continues to consider ways ofprotecting them from adverse public health and environmental effects of air pollution.

706

These results pertain to the analysis of the proposed standards for new combustion turbine
EGUs and for existing steam-generating EGUs, and do not include the impact of the proposed
standards for existing combustion turbine EGUs and the third phase of the proposed standards
for new natural gas-fired EGUs.
707
Plan EJ 2014. Washington, DC: U.S. EPA, Office of Environmental Justice.
https://www.epa.gov/environmentaljustice/plan-ej-2014
651
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

2. Analytical Considerations
EJ concerns for each rulemaking are unique and should be considered on a case-by-casebasis, and the EPA’s EJ Technical Guidance states that “[t]he analysis of potential EJ concerns
for regulatory actions should address three questions:
1. Are there potential EJ concerns associated with environmental stressors affected by theregulatory action for population groups of concern in the baseline?
2. Are there potential EJ concerns associated with environmental stressors affected by theregulatory action for population groups of concern for the regulatory option(s) underconsideration?
3. 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 exposuresand impacts. For the rules, the EPA quantitatively evaluates the proximity of existing affectedfacilities to potentially vulnerable and/or overburdened populations for consideration of local
pollutants impacted by these rules but not modeled here (RIA section 6.4), as well as 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 was performed to answer separate questions
and is associated with unique limitations and uncertainties.

652
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Baseline demographic proximity analyses provide information as to whether there may
be potential EJ concerns associated with environmental stressors emitted from sources affectedby 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 tothe 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 populationof potentially affected units greater than 25 MW indicated that the demographic percentages ofthe 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 anotherfacility is significantly above the national average, and all three facilities were well above thenational 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 Technical653
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Guidance document more directly than the proximity analyses, as they evaluate a form of theenvironmental stressor primarily affected by the regulatory actions (RIA section 6.5). Baselineozone 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, andAmerican 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 groupsof 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 toremain after implementation of the regulatory action or alternatives under consideration. This isdue 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 orexacerbate PM2.5 exposures disparities across populations of EJ concern analyzed. Regardingozone exposures, while most policy options and future years analyzed will not likely mitigate orexacerbate 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 the654This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

small magnitude of the ozone concentration changes (question 3). Importantly, the actions
described in these proposals are expected to lower PM2.5 and ozone in many areas, and thus
mitigate some pre-existing health risks of air pollution across all populations evaluated.
3. Outreach and Engagement
In outreach with potentially vulnerable communities, residents have voiced two primaryconcerns. First, there is the concern that their communities have experienced historicallydisproportionate burdens from the environmental impacts of energy production, and second, thatas the sector evolves to use new technologies such as CCS and hydrogen, they may continue toface disproportionate burdens.
With regard to CCS, the EPA is proposing that CCS is a component of the BSER for new
base load stationary combustion turbine EGUs, existing coal-fired steam generating units that
intend to operate after 2040, and large and frequently operated existing stationary combustion
turbine EGUs. The EPA recognizes and has given careful consideration to the various concernsthat potentially vulnerable communities have raised with regard to the use of CCS in determiningthat CCS is BSER for these sources. In the following section, the EPA discusses various
measures undertaken in this rulemaking and elsewhere to address community concerns on thismatter.
One concern the EPA has heard from stakeholders 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 toadditional harmful pollution. There are several important factors the EPA considered in
evaluating the emission impact of an upgraded EGU when determining BSER for these units that
intend to operate in the long term. First, CCS is the most effective add-on pollution control
655This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

available for mitigation of GHG emissions from affected sources. Second, most CCS
technologies work much more effectively when the EGU is emitting the lowest levels of SO2
possible; therefore it is likely that as part of a CCS installation, companies will improve their
EGUs’ SO2 control. Third, a CCS retrofit may trigger requirements under the major NSR
program because of the potential for an emissions increase of one or more pollutants due to theadditional energy production by the EGU to power the CO2 capture system. If the source isundergoing major NSR permitting, the permitting authority would provide an opportunity for the
public to comment on the draft permit, which is another avenue for affected residents to submit
input regarding additional controls that may be needed to meet best available control technology
requirements for non-GHG pollutants such as NOX. 708
Communities have also expressed concerns about CO2 pipeline safety and geologic
sequestration. As discussed in section VII.F.3.b.iii of the preamble, supercritical CO2 pipeline
safety is regulated by PHMSA. These regulations protect against environmental release duringtransport and PHMSA has announced steps to further strengthen its safety oversight ofsupercritical CO2 pipelines, including initiating a new rulemaking to update standards forsupercritical CO2 pipelines and solicited research proposals to strengthen CO2 pipeline safety. 709
Geologic sequestration of CO2 is regulated by the EPA through the UIC Program under the Safe
Drinking Water Act, and through the GHGRP under the Clean Air Act. UIC Class VI regulations
include strong protections for communities to prevent contamination of underground sources of708

The EPA discusses the interactions between CCS and non-GHG pollutants for existing coalfired steam generating units in section X.D.1.a.iii(B) of this preamble.
709
PHMSA, “PHMSA Announces New Safety Measures to Protect Americans From Carbon
Dioxide Pipeline Failures After Satartia, MS Leak.” 2022.
https://www.phmsa.dot.gov/news/phmsa-announces-new-safety-measures-protect-americanscarbon-dioxide-pipeline-failures.
656This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

drinking water. These regulatory protections include a variety of measures, including proper sitecharacterization and strict construction, operating, and monitoring requirements to ensure welland formation integrity, proper plugging of wells, and long-term project management and postinjection site care to ensure leakage prevention. 710 GHGRP requirements complement and build
on UIC regulations through air-side monitoring and reporting requirements that provide the EPA
and communities with a transparent means of evaluating the effectiveness of geologic
sequestration. These programs work in combination to provide security and transparency.
The final concern the EPA has heard from stakeholders is about a lack of opportunity for
impacted communities to voice opinions about projects like this that affect them. Recognizing
the important stake that local residents have in decisions regarding EGUs in their communities,
the EPA expects that states will address facility-specific concerns about how to responsibly
deploy CCS and any other potential control strategies in the course of meaningful engagement
under the proposed emission guidelines for existing steam generating units and existing
combustion turbines, as discussed in section XII.F.1.b of the preamble. State plans should
specifically ensure that community members have an opportunity to share their input if they
reside near a fossil fuel-fired steam generating unit that plans to install CCS to meet therequirements of these proposed rules regarding how to responsibly deploy this technology.
With regard to the decision to construct a new combustion turbine, most of the safeguards
outlined above for CCS retrofits apply. While meaningful engagement applies under emission
guidelines to existing sources, there exists an opportunity for community engagement for new

710

See generally Administrator Michael S. Regan, Underground Injection Control Class VI
Letter to Governors (December 9, 2022), https://www.epa.gov/system/files/documents/202212/AD.Regan_.GOVS_.Sig_.Class%20VI.12-9-22.pdf.
657
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

sources as part of the major NSR permitting process, in the event that the source triggers major
NSR requirements. While new combustion turbines that co-fire with hydrogen may trigger major
NSR, there are cases in which they are less likely to trigger major NSR, such as: (1) If the new
combustion turbine is proposed at an existing facility and the facility is able to reduce its
emissions more than the emissions increase from the combustion turbine (e.g., if the combustion
turbine replaces an existing coal-fired EGU and the facility has emission reduction credits fromthe shutdown unit), or (2) if the emissions from the new combustion turbine are low enough to
not trigger major NSR.
The EPA further notes that hydrogen production presents a unique set of potential issues
for vulnerable communities. During the February 27th National Tribal Energy Roundtable
Webinar, one of the primary concerns articulated was the potential for fossil-derived hydrogen toessentially extend the life of petrochemical industries already creating localized pollution
loading. Since hydrogen is non-toxic, and it does not produce carbon dioxide when burned, theinclusion of hydrogen in combustion turbine operations will lower overall health risks comparedwith hydrocarbons. Perceived community risks with hydrogen related to storage andtransportation include its combustibility and propensity to leak due to extremely low molecularweight. Despite concerns about hydrogen, its low molecular weight ensures that it dissipates anddisperses quickly when released outdoors, reducing unintended combustion risks compared withother fuels. 711 Adequate ventilation and leak detection are available to ensure safety and areimportant elements in the design of hydrogen systems. Concerns around hydrogen leaks can be
mitigated with hydrogen monitoring systems combined with adequate ventilation and leak711

Department of Energy, Safe Use of Hydrogen https://www.energy.gov/eere/fuelcells/safe-usehydrogen.
658
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

detection equipment, including special flame detectors. 712 Further, building and operational
codes and standards developed specifically for hydrogen’s properties can minimize risks aroundhydrogen usage in a community. 713
New combustion turbine models designed to combust hydrogen, and those potentiallybeing retrofit to combust hydrogen, may be co-located with electrolyzers that produce thehydrogen the facility will use. In such instances, water scarcity could be exacerbated in someareas by the freshwater demands of electrolytic hydrogen production, which could pose aparticular challenge for vulnerable communities. As such, electrolyzer siting will need to takewater availability into account. Examples for sustainable siting for electrolyzers are emerging inEurope, which has begun to employ Sustainable Value Methodology designed to be sensitive towater access and availability and includes, “decision-making support, combining economic,
environmental and social criteria”. 714 We also expect advances in electrolytic technology overtime to reduce water demand, including the potential to enabling sea-water usage inelectrolyzers. 715
F. Grid Reliability Considerations
The requirements for sources and states set forth in these proposed actions weredeveloped cognizant of concerns about an electric grid under transition, and related reliability

712

Ibid.
Department of Energy, Safety Codes and Standards
https://www.energy.gov/eere/fuelcells/safety-codes-and-standards-basics.
714
Journal of Cleaner Production, Volume 315, 15 September 2021, 128124, “Water Availability
and Water Usage Solutions for Electrolysis in Hydrogen Production” Simoes, Sophia et. al.
https://www.sciencedirect.com/science/article/pii/S0959652621023428.
715
Sun, F., Qin, J., Wang, Z. et al. Energy-saving hydrogen production by chlorine-free hybrid
seawater splitting coupling hydrazine degradation. Nat Commun 12, 4182 (2021).
https://doi.org/10.1038/s41467-021-24529-3.
659
713

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

considerations. As previously stated, a variety of important influences have led to notablechanges in the generation mix and expectations of how the power sector will evolve. These
trends have generally put existing high-emitting generators under greater economic pressure andwill 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 thecountry 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 andsupply of electricity. A wide range of stakeholders including power generators, grid operatorsand 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 otherstakeholders 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 reductionsin 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
660
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

gas-fired combustion turbines that allow for the stringency of standards of performance to varyby capacity factor; subcategories for existing steam EGUs that are based on operating horizons
and fuel reflecting the request of industry stakeholders; compliance deadlines for both new andexisting EGUs that provide ample lead time to plan; and proposed state plan flexibilities. In
addition, this preamble discusses EPA’s intention to exercise its enforcement discretion where
needed to address any potential instances in which individual EGUs may need to temporarily
operate for reliability reasons, and to set forth clear and transparent expectations foradministrative compliance orders to ensure that compliance with these proposed rules can beachieved without impairing the ability of power companies and grid operators to maintainreliability. As such, these proposed rules provide the flexibility needed to avoid reliability
concerns while still securing the pollution reductions consistent with section 111 of the CAA.
To support these proposed actions, the EPA has conducted an analysis of resource
adequacy based upon power sector modeling and projections of the standards on existing steam
generating units, and the first two phases of the standards on new combustion turbines, as well as
the results of the spreadsheet-based analysis of the standards on existing combustion turbines andthe third phase of the standards on new combustion turbines, that can be found in the RIA. Any
potential impact of these proposed actions is dependent upon a myriad of decisions andcompliance 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 tomaintain electric reliability. While not explicitly modeled using IPM, the proposed emission
guidelines for existing natural gas-fired EGUs are estimated to have very little incremental
impact on resource adequacy. The guidelines would affect a subset of the total natural gas fleet,and units that install CCS are still able to maintain capacity accreditation values (after accounting
661
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

for capacity de-rates). Moreover, units that operate below 50 percent capacity factor annually(and are not subject to the CCS requirement) would still be able to operate at higher levels during
times of greater demand, thereby maintaining their capacity accreditation values.
The results presented in the Resource Adequacy Analysis TSD, which is available in thedocket, show that the projected impacts of the proposed rules on power system operations, underconditions preserving resource adequacy, are modest and manageable. For the specific scenarios
analyzed in the RIA, the implementation of the proposed rules can be achieved while
maintaining resource adequacy even as shifts in existing and new capacity occur. Retirements areoffset by additions, along with reserve transfers where/when needed, which demonstrates that
ample compliance pathways exist for sources while preserving resource adequacy.
The EPA routinely consults with the DOE and FERC on electric reliability and intends tocontinue to do so as it develops and implements a final rule. This ongoing engagement will bestrengthened with routine and comprehensive communication between the agencies under the
DOE-EPA Joint Memorandum of Understanding on Interagency Communication andConsultation on Electric Reliability signed on March 8, 2023. 716 The memorandum will provide
greater interagency engagement on electric reliability issues at a time of significant dynamism inthe power sector, allowing the EPA 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 ofreliable 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,

716

Joint Memorandum of Understanding on Interagency Communication and Consultation on
Electric Reliability (March 8, 2023). https://www.epa.gov/power-sector/electric-reliability-mou.
662

This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

share information, and consult on policy and program decisions to assure the continued
reliability of the bulk power system.
In addition, the EPA observes that power companies, grid operators, and state public
utility commissions have well-established procedures in place to preserve electric reliability inresponse 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 theextended 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 aparticular 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 thaninvesting it in new emissions controls at the unit. Such a retirement decision will require theunit’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 reliabilityof 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. These proposed actions
do not interfere with these already available provisions, but rather provides a long-term pathway

663
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

for sources to develop and implement a proper plan to reduce emissions while maintaining
adequate supplies of electricity.
XV. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and Executive Order 13563:
Improving Regulation and Regulatory Review
These actions were submitted to the Office of Management and Budget (OMB) for
review under Section 3(f)(1) of Executive Order 12866. Any changes made in response torecommendations received as part of Executive Order 12866 review have been documented in
the docket. The EPA prepared an analysis of the potential costs and benefits associated withthese 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 10 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. This analysis covers the impacts of the
proposed standards for new combustion turbines and for existing steam generating EGUs, anddoes not include the impact of the proposed standards for existing combustion turbines and thethird phase of the proposed standards for new combustion turbines. The estimated monetized net
benefits are the projected monetized benefits minus the projected monetized costs of the
proposed rules.

664
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

The projected climate benefits in table 8 are based on estimates of the social cost ofcarbon (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 toconsider the costs and benefits of its actions. Accordingly, in addition to the projected climate
benefits of the proposals from anticipated reductions in CO2 emissions, the projected monetized
health benefits include those related to public health associated with projected reductions in fineparticulate matter (PM2.5) and ozone concentrations. The projected health benefits are associatedwith 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 anticipatesthat taking non-monetized effects into account would show the proposals to have a greater net
benefit than this table reflects.
Table 10—Projected Monetized Benefits, Compliance Costs, and Net Benefits of the
Proposed Rules, 2024 through 2042 717[Billions 2019$, Discounted to 2024]a
3% Discount Rate
7% Discount Rate
Climate Benefitsc$30$30
Present ValuedHealth Benefits
$68
$44
717

This analysis pertains to the proposed standards for new combustion turbines and for existing
steam generating EGUs and does not include the impact of the proposed standards for existing
combustion turbines and the third phase of the proposed standards for new combustion turbines.
665
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

Compliance Costs

$14

$10

Net Benefitse
$85
$64
c
Climate Benefits
$2.1
$2.1
d
Health Benefits
$4.8
$4.3
EquivalentbAnnualized Value
Compliance Costs
$0.95
$0.98
Net Benefitse
$5.9
$5.4
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 from2024 to 2042.
c
Climate benefits are based on changes (reductions) in CO2 emissions. Climate benefits in thistable are based on estimates of the SC-CO2 at a 3 percent discount rate and are discounted usinga 3 percent discount rate to obtain the PV and EAV estimates in the table. The EPA does nothave a single central SC-CO2 point estimate. We emphasize the importance and value ofconsidering the benefits calculated using all four SC-CO2 estimates (model average at 2.5
percent, 3 percent, and 5 percent discount rates; 95th percentile at 3 percent discount rate). As
discussed in section 4 of the RIA, consideration of climate benefits calculated using discountrates below 3 percent, including 2 percent and lower, is also warranted when discounting
intergenerational impacts.
d
The EPA notes that while OMB Circular A-4, as published in 2003, recommends using 3
percent and 7 percent discount rates as "default" values, Circular A-4 also recognizes that“special ethical considerations arise when comparing benefits and costs across generations,” andCircular A-4 acknowledges that analyses may appropriately “discount future costs andconsumption benefits…at a lower rate than for intragenerational analysis.” Therefore, climate
benefits remain discounted at 3 percent in this benefits analysis.
e
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 withseveral point estimates and are presented at real discount rates of 3 and 7 percent.
f
Several categories of benefits remain unmonetized and are thus not reflected in the table. Nonmonetized benefits include important climate, health, welfare, and water quality benefits and aredescribed in RIA Table 4-6.
As shown in table 10, 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 a666This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

projected PV of monetized health benefits of about $68 billion, with an EAV of about $4.8
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 compliancecosts yields a net benefit PV estimate of about $85 billion and EAV of about $5.9 billion at a 3
percent discount rate.
At a 7 percent discount rate, the proposed rules are expected to generate projected PV ofmonetized health benefits of about $44 billion, with an EAV of about $4.3 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 $74 billion, with an EAV of about $6.4
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 $64 billion and an
EAV of about $5.4 billion discounted at 7 percent.
The EPA has developed a separate analysis of the proposed standards for existing
combustion turbines and third phase of the proposed standards for new natural gas-fired EGUs
over the 2024 to 2042 period. This analysis includes estimated compliance costs and climate
benefits, and is located in Section 8 of the RIA. The PV of the compliance costs, discounted atthe 3-percent rate, is estimated to be between about $5.7 to 10 billion, with an EAV of between
about $0.40 to 0.70 billion. At the 7 percent discount rate, the PV of the compliance costs is
estimated to be between about $ 3.5 to 6.2 billion, with an EAV of about $ 0.34 to 0.60 billion.
The PV of the climate benefits, discounted at the 3-percent rate, is estimated to be between about$10 to 20 billion, with an EAV of between about $0.70 to 1.4 billion.
667
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

As discussed in section XIV of this preamble, the monetized benefits estimates provide
an incomplete overview of the beneficial impacts of the proposals. In particular, the monetizedclimate benefits are incomplete and an underestimate as explained in section 4.2 of 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 have greater benefits than the estimates in the preamble and
RIA reflect. Simultaneously, the estimates of compliance costs used in the net benefits analysis
may provide an incomplete characterization of the true costs of the rule. The balance of
unquantified benefits and costs is ambiguous but is unlikely to change the result that the benefitsof the proposals exceed the costs by billions of dollars annually.
We also note that the RIA follows the EPA’s historic practice of using a technology-richpartial equilibrium model of the electricity and related fuel sectors to estimate the incremental
costs of producing electricity under the requirements of proposed and final major EPA power
sector rules. In Appendix B of the RIA for these actions, the EPA has also included an economywide analysis that considers additional facets of the economic response to the proposed rules,
including the full resource requirements of the expected compliance pathways, some of which
are paid for through subsidies in the partial equilibrium analysis. The social cost estimates in theeconomy-wide analysis and discussed in Appendix B of the RIA are still far below the projected
benefits of the proposed rules.

668
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

B. Paperwork Reduction Act (PRA)
1. 40 CFR Part 60, Subpart TTTTThis action does not impose any new information collection burden under the PRA. OMB
has previously approved the information collection activities contained in the existing
regulations and has assigned OMB control number 2060-0685.
2. 40 CFR Part 60, Subpart TTTTa
The information collection activities in this proposed rule have been submitted forapproval 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
2771.01. You can find a copy of the ICR in the docket for this rule, and it is briefly summarized
here.
Respondents/affected entities: Owners and operators of fossil-fuel fired EGUs.
Respondent’s obligation to respond: Mandatory.
Estimated number of respondents: 2.
Frequency of response: Annual.
Total estimated burden: 110 hours (per year). Burden is defined at 5 CFR 1320.3(b).
Total estimated cost: $14,000 (per year), includes $0 annualized capital or operation &maintenance costs.
An agency may not conduct or sponsor, and a person is not required to respond to, acollection 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 theprovided burden estimates and any suggested methods for minimizing respondent burden to the669
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

EPA using the docket identified at the beginning of this rule. The EPA will respond to any ICRrelated 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 atwww.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].
3. 40 CFR Part 60, Subpart UUUUb
The information collection activities in this proposed rule have been submitted forapproval 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
2770.01. 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 fuelfired steam generating units. The information collection requirements are based on therecordkeeping and reporting burden associated with developing, implementing, and enforcing aplan 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 aclaim of confidentiality is made is safeguarded according to Agency policies set forth in 40 CFRpart 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 104,000 hours at a total annual labor cost of
670
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

$13.1 million. The annual burden for the Federal government associated with the state collectionof information (averaged over the first 3 years following promulgation) is estimated to be 27,347
hours at a total annual labor cost of $1.8 million. Burden is defined at 5 CFR 1320.3(b).
Respondents/affected entities: States with one or more designated facilities covered undersubpart UUUUb.
Respondent’s obligation to respond: Mandatory.
Estimated number of respondents: 50.
Frequency of response: Once.
Total estimated burden: 104,000 hours (per year). Burden is defined at 5 CFR 1320.3(b).
Total estimated cost: $13,163,689, 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, acollection 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 theprovided 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 ICRrelated 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 atwww.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].
671
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

4. 40 CFR Part 60, Subpart UUUUaThis proposed rule does not impose an information collection burden under the PRA.
C. 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 subdivisions, 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 todetermining if the NSPS would have a significant economic impact on a substantial number ofsmall 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 themeeting. 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 notproceed with convening the SBAR panel.

672This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 whenstates 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.
D. 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 benefitcost analysis, which is in section XIV of this preamble and in the RIA.

673
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 forstates 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
XII.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 initiatedconsultation 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 ofState 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
674
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 PublicPower Association, Large Public Power Council, National Rural Electric Cooperative
Association, and National Association of Regulatory Utility Commissioners to participate in themeeting. The purpose of the consultation was to provide general background on theserulemakings, 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 letterswere submitted to the pre-proposal non-rulemaking docket. See Docket ID No. EPA-HQ-OAR2022-0723-0013, EPA-HQ-OAR-2022-0723-0016, EPA-HQ-OAR-2022-0723-0017, EPA-HQOAR-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.
E. 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 therelationship between the national government and the states, or on the distribution of power andresponsibilities among the various levels of government.
The EPA has concluded that the proposed emission guidelines may have federalism
implications, because they 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.
Any potential federalism implications arise from the provisions of CAA section
111(d)(1), which direct the EPA to “prescribe regulations . . . under which each State shallsubmit to the [EPA] a [state] plan…” establishing standards of performance for sources in the675This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

state. As discussed in the Supporting Statement found in the docket for this rulemaking, thedevelopment 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 withstate legislatures as appropriate, and develop a plan submittal.
Although the direct compliance costs may not be substantial, the EPA nonetheless elected
to consult with representatives of state and local governments in the process of developing theseactions 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 invitedthe 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 ofState 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 andlocal governments. Subsequent to the September 22, 2022, meeting, the EPA received letters
676This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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, EPAHQ-OAR-2022-0723-0017, EPA-HQ-OAR-2022-0723-0020, and EPA-HQ-OAR-2022-07230021. For a summary of the Federalism consultation see the memorandum in the docket titledFederalism Pre-Proposal Consultation Summary. A detailed Federalism Summary Impact
Statement (FSIS) describing the most pressing issues raised in pre-proposal and post-proposalcomments 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 onthese proposed actions from state and local officials.
F. Executive Order 13175: Consultation and Coordination with Indian Tribal Governments
These actions do not have tribal implications, as specified in Executive Order 13175. The
proposed NSPS would impose requirements on owners and operators of new or reconstructedstationary 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.

677
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 withtribes. The EPA specifically solicits additional comment on these proposed rules from tribal
officials.
G. Executive Order 13045: Protection of Children from Environmental Health Risks and Safety
Risks Populations and Low-Income Populations
Executive Order 13045 (62 FR 19885, April 23, 1997) directs federal agencies to include
an evaluation of the health and safety effects of the planned regulation on children in federal
health and safety standards and explain why the regulation is preferable to potentially effective
and reasonably feasible alternatives. This action is not subject to Executive Order 13045 because
the EPA does not believe the environmental health risks or safety risks addressed by this action
present a disproportionate risk to children. The EPA evaluated the health benefits of the CO2,
ozone and PM2.5 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 CO2related 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 thatnationally, 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 alternativesof these rulemakings.

678This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

H. Executive Order 13211: Actions Concerning Regulations that Significantly Affect Energy
Supply, Distribution, or Use
These actions, which are significant regulatory actions under Executive Order 12866, arelikely 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. This analysis pertains to
the proposed standards for new combustion turbines and for existing steam generating EGUs,
and does not include the impact of the proposed standards for existing combustion turbines andthe third phase of the proposed standards for new combustion turbines. 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 sections 5.1 and 8.3.3 of
the RIA, which is in the public docket.
I. National Technology Transfer and Advancement Act (NTTAA) and 1 CFR Part 51
These proposed actions involve technical standards. Therefore, the EPA conductedsearches for the New Source Performance Standards for Greenhouse Gas Emissions from New,
Modified, and Reconstructed Fossil Fuel-Fired Electric Generating Units; Emission Guidelinesfor Greenhouse Gas Emissions from Existing Fossil Fuel-Fired Electric Generating Units; andRepeal of the Affordable Clean Energy Rule through the Enhanced National Standards Systems
Network (NSSN) Database managed by the American National Standards Institute (ANSI).
Searches were conducted for EPA Method 19 of 40 CFR part 60, appendix A. No applicable
voluntary consensus standards were identified for EPA Method 19. For additional information,please see the March 23, 2023, memorandum titled, Voluntary Consensus Standard Results for
679This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

New Source Performance Standards for Greenhouse Gas Emissions from New, Modified, andReconstructed Fossil Fuel-Fired Electric Generating Units; Emission Guidelines forGreenhouse Gas Emissions from Existing Fossil Fuel-Fired Electric Generating Units; andRepeal of the Affordable Clean Energy Rule.
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 suchstandards should be used in these regulations.
J. Executive Order 12898: Federal Actions to Address Environmental Justice in Minority
Populations and Low-Income Populations
Executive Order 12898 (59 FR 7629; February 16, 1994) directs federal agencies, to thegreatest 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 humanhealth or environmental conditions that exist prior to this action result in disproportionate andadverse 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 havethe 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 this680
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.

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 populationsof 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 ofcolor, low-income populations, Indigenous peoples, and/or other potential populations ofconcern 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 associatedwith this action are likely to result in a change in disproportionate and adverse effects on peopleof color, low-income populations and/or Indigenous peoples. However, the EPA believes that the
projected total cumulative power sector reduction of 617 million metric tons 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 uniquelyvulnerable to climate change health impacts in the U.S. See sections VII, X, and XIV of thispreamble for further information regarding GHG controls and emission reductions.

Michael S. Regan,
Administrator.

681
This document is a prepublication version, signed by EPA Administrator, Michael S. Regan on 5/8/2023. We havetaken steps to ensure the accuracy of this version, but it is not the official version.