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Rule2026-19071

Partial Repeal of the Carbon Pollution Standards for Fossil Fuel-Fired Electric Generating Units

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Published

September 17, 2026

Effective

November 16, 2026

Issuing agencies

Environmental Protection Agency

Abstract

In this final rule, the U.S. Environmental Protection Agency (EPA) is repealing most provisions of the 2024 Carbon Pollution Standards for greenhouse gas (GHG) emissions from fossil fuel-fired electric generating units (EGUs) based on a reevaluation of the best system of emission reduction for the relevant subcategories. Specifically, the EPA is repealing the emission guidelines for existing fossil fuel-fired steam generating units, the carbon capture and sequestration/storage (CCS)-based standards for coal-fired steam generating units undertaking a large modification, and the CCS-based standards for new base load stationary combustion turbines (i.e., Phase 2 standards). In a separate action published concurrently with this final rule, the EPA is issuing a supplemental proposal soliciting comment on additional reasons to rescind all GHG emission requirements for fossil fuel-fired EGUs to effectuate the best reading of Clean Air Act (CAA) section 111 and ensure consistency with applicable principles of administrative law beyond those reasons on which the EPA solicited comment in the June 2025 notice of proposed rulemaking.

Full Text

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[Federal Register Volume 91, Number 179 (Thursday, September 17, 2026)]
[Rules and Regulations]
[Pages 58954-59000]
From the Federal Register Online via the Government Publishing Office [<a href="http://www.gpo.gov">www.gpo.gov</a>]
[FR Doc No: 2026-19071]

[[Page 58953]]

Vol. 91

Thursday,

No. 179

September 17, 2026

Part II

Environmental Protection Agency

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40 CFR Part 60

Partial Repeal of the Carbon Pollution Standards for Fossil Fuel-Fired
Electric Generating Units; Final Rule

Federal Register / Vol. 91 , No. 179 / Thursday, September 17, 2026 /
Rules and Regulations

[[Page 58954]]

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60

[EPA-HQ-OAR-2025-0124; FRL-12674-02-OAR]
RIN 2060-AW55

Partial Repeal of the Carbon Pollution Standards for Fossil Fuel-
Fired Electric Generating Units

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

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SUMMARY: In this final rule, the U.S. Environmental Protection Agency
(EPA) is repealing most provisions of the 2024 Carbon Pollution
Standards for greenhouse gas (GHG) emissions from fossil fuel-fired
electric generating units (EGUs) based on a reevaluation of the best
system of emission reduction for the relevant subcategories.
Specifically, the EPA is repealing the emission guidelines for existing
fossil fuel-fired steam generating units, the carbon capture and
sequestration/storage (CCS)-based standards for coal-fired steam
generating units undertaking a large modification, and the CCS-based
standards for new base load stationary combustion turbines (i.e., Phase
2 standards). In a separate action published concurrently with this
final rule, the EPA is issuing a supplemental proposal soliciting
comment on additional reasons to rescind all GHG emission requirements
for fossil fuel-fired EGUs to effectuate the best reading of Clean Air
Act (CAA) section 111 and ensure consistency with applicable principles
of administrative law beyond those reasons on which the EPA solicited
comment in the June 2025 notice of proposed rulemaking.

DATES: This final rule is effective on November 16, 2026. The approval
of the Director of the Federal Register (FR) for incorporation by
reference (IBR) of certain material listed in this rule expires as of
November 16, 2026.

ADDRESSES: The EPA established a docket for this rulemaking under
Docket ID No. EPA-HQ-OAR-2025-0124. All documents in the docket are
listed on the <a href="https://www.regulations.gov">https://www.regulations.gov</a> website. Although listed,
some information is not publicly available, e.g., Confidential Business
Information (CBI) or other information whose disclosure statute
restricts. The EPA does not place certain other material, such as
copyrighted material, on the internet; this material is publicly
available only as portable document format (PDF) versions on the EPA
computers in the docket office reading room. The public cannot download
certain databases and physical items from the docket but may request
these items by contacting the docket office at (202) 566-1744. The
docket office has 10 business days to respond to these requests. With
the exception of such material, publicly available docket materials are
available electronically at <a href="https://www.regulations.gov">https://www.regulations.gov</a>.

FOR FURTHER INFORMATION CONTACT: For information about this final rule,
contact U.S. EPA, Attn: Dr. Gregory Honda, Mail Drop: Industrial
Processing and Power Division, 109 T.W. Alexander Drive, P.O. Box
12055, Research Triangle Park, North Carolina 27711; telephone number:
(919) 541-2034; and email address: <a href="/cdn-cgi/l/email-protection#80e8efeee4e1aee7f2e5e7eff2f9c0e5f0e1aee7eff6">[email&#160;protected]</a>.

SUPPLEMENTARY INFORMATION:
Preamble acronyms and abbreviations. Throughout this notice the use
of ``we,'' ``us,'' or ``our'' refers to the EPA. The EPA uses multiple
acronyms and terms in this preamble. While this list may not be
exhaustive, to ease the reading of this preamble and for reference
purposes, the EPA defines the following terms and acronyms here:

ACE Affordable Clean Energy [rule]
AI artificial intelligence
BSER best system of emission reduction
Btu British thermal units
Btu/kWh British thermal units per kilowatt-hour
CAA Clean Air Act
CAAA Clean Air Act Amendments
CCS carbon capture and sequestration/storage
CCUS carbon capture, utilization, and storage
CFR Code of Federal Regulations
CO<INF>2</INF> carbon dioxide
CPS Carbon Pollution Standards
CPP Clean Power Plan
CRA Congressional Review Act
DOE Department of Energy
EAV equivalent annualized value
EGU electric generating unit
EIA Energy Information Administration
E.O. Executive Order
EOR enhanced oil recovery
EPA Environmental Protection Agency
EPAct05 Energy Policy Act of 2005
FEED Front-End Engineering Design
FR Federal Register
GHG greenhouse gas
GW gigawatt
ICR information collection request
IGCC integrated gasification combined cycle
IRC Internal Revenue Code
lb pound
MMBtu million British thermal units
MMBtu/h million British thermal units per hour
MW megawatt
MWh megawatt-hour
MWe megawatt-equivalent
NAAQS National Ambient Air Quality Standards
NAICS North American Industry Classification System
NERC North American Electric Reliability Corporation
NETL National Energy Technology Laboratory
NGCC natural gas combined cycle
NPRM notice of proposed rulemaking
NSPS new source performance standards
NTTAA National Technology Transfer and Advancement Act
OBBBA One Big Beautiful Bill Act of 2025
OMB Office of Management and Budget
PRA Paperwork Reduction Act
PV Present Value
RFA Regulatory Flexibility Act
RIA regulatory impact analysis
SO<INF>2</INF> sulfur dioxide
UIC Underground Injection Control
UMRA Unfunded Mandates Reform Act
U.S.C. United States Code

Table of Contents

I. Executive Summary
A. Cost Savings
II. General Information
A. Where To Get a Copy of This Document and Other Related
Information
B. Action Applicability
C. Statutory Authority
1. Regulation of Emissions From New Sources
2. Regulation of Emissions From Existing Sources
3. Key Elements of Determining a Standard of Performance
D. Severability
E. Reliance Interests
III. Background
A. EPA Regulation of GHG Emissions Under CAA Section 111
B. Carbon Pollution Standards
C. Changes in Trends in Fossil Fuel-Fired EGUs
D. June 2025 NPRM
IV. Repeal of Sections of the Carbon Pollution Standards
A. Repeal of the Emission Guidelines for Existing Fossil Fuel-
Fired Steam Generating Units
1. CCS-Based Requirements for Long-Term Existing Coal-Fired
Steam Generating Units
2. Natural Gas Co-Firing-Based Requirements for Existing Medium-
Term Coal-Fired Steam Generating Units
3. Requirements for Existing Natural Gas- and Oil-Fired Steam
Generating Units
4. Conclusion
B. Repeal of the CCS-Based Requirements for Coal-Fired Steam
Generating Units Undertaking a Large Modification
C. Partial Repeal of the 2024 Standards for New Combustion
Turbine EGUs
1. Phase 2 CCS-Based Requirements for New Base Load Combustion
Turbines
2. Summary of Substantial Comments on the 2024 Efficiency-Based
Requirements for New Intermediate and Base Load Combustion Turbines
3. Conclusion
D. Consideration of Alternatives
V. Statutory and E.O. Reviews
A. E.O. 12866: Regulatory Planning and Review and E.O. 13563:
Improving Regulation and Regulatory Review

[[Page 58955]]

B. E.O. 14192: Unleashing Prosperity Through Deregulation
C. Paperwork Reduction Act (PRA)
1. 40 CFR Part 60, Subpart TTTT
2. 40 CFR Part 60, Subpart TTTTa
3. 40 CFR Part 60, Subpart UUUUb
D. Regulatory Flexibility Act (RFA)
E. Unfunded Mandates Reform Act (UMRA)
F. E.O. 13132: Federalism
G. E.O. 13175: Consultation and Coordination With Indian Tribal
Governments
H. E.O. 13045: Protection of Children From Environmental Health
Risks and Safety Risks
I. E.O. 13211: Actions Concerning Regulations That Significantly
Affect Energy Supply, Distribution, or Use
J. National Technology Transfer and Advancement Act (NTTAA) and
1 CFR Part 51
K. Congressional Review Act (CRA)

I. Executive Summary

In this final rule, the EPA is finalizing the repeal of most of the
GHG standards promulgated in the 2024 Carbon Pollution Standards
(``2024 CPS'') for fossil fuel-fired power plants.\1\ Specifically, the
EPA is finalizing the repeal of the emission guidelines for existing
fossil fuel-fired steam generating units, the CCS-based standards for
coal-fired steam generating units undertaking a large modification, and
the 2024 CCS-based standards for new base load stationary combustion
turbines.
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\1\ 89 FR 39798 (May 9, 2024).
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With this final action, the EPA addresses much of the regulatory
uncertainty brought by the Agency's novel attempts to regulate GHG
emissions from fossil fuel-fired power plants under CAA section 111.
The EPA attempted to restrict GHG emissions from power plants for the
first time in 2015, when the Agency issued both new source performance
standards (NSPS) for new power plants (``2015 NSPS'') \2\ and emission
guidelines for existing power plants (the Clean Power Plan (``2015
CPP'')).\3\
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\2\ 80 FR 64510 (October 23, 2015).
\3\ 80 FR 64662 (October 23, 2015).
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In West Virginia v. EPA, the U.S. Supreme Court struck down \4\
these efforts in large part, ruling that CAA section 111 does not
authorize the EPA to adopt a regulatory scheme that ``cap[s] carbon
dioxide emissions at a level that will force a nationwide transition
away from the use of coal to generate electricity.'' \5\ Rather than
change course, however, the EPA in 2024 promulgated a new rule that
embraced the goals of the 2015 NSPS and 2015 CPP by expanding
restrictions on certain new sources and regulating existing sources in
a similar manner.
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\4\ The Supreme Court stayed the 2015 CPP after the U.S. Court
of Appeals for the D.C. Circuit declined to do so prior to merits
briefing. West Virginia v. EPA, 577 U.S. 1126 (2016).
\5\ 597 U.S. 697, 735 (2022).
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The EPA's most recent effort to regulate GHG emissions from the
power sector, the 2024 CPS, includes standards of performance for new
and reconstructed fossil fuel-fired combustion turbines and for certain
modified fossil fuel-fired steam generating power plants, as well as
rules directing States to set standards of performance for existing
fossil fuel-fired steam generating power plants. During the rulemaking
and subsequent litigation over the 2024 CPS, numerous States, regulated
entities, and other stakeholders warned that these requirements are
based on technologies that have not been adequately demonstrated, are
unachievable, threaten to impose massive costs on the power sector, and
do not adequately ensure the national interest in affordable, reliable
electricity.
On January 20, 2025, President Trump issued Executive Order (E.O.)
14154, ``Unleashing American Energy,'' which directs Federal agencies,
including the EPA, to review existing regulations ``to identify those
agency actions that impose an undue burden on the identification,
development, or use of domestic energy resources--with particular
attention to oil, natural gas, coal, hydropower, biofuels, critical
mineral, and nuclear energy resources.'' \6\ The E.O. further affirms
that it is ``the policy of the United States to ensure that all
regulatory requirements related to energy are grounded in clearly
applicable law.'' \7\ During the course of this review, the EPA has
identified GHG emissions standards for power plants as one such action,
including the 2024 CPS requirements that are the subject of this final
rule.\8\
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\6\ 90 FR 8353 (January 20, 2025).
\7\ Id.
\8\ References to ``GHG standards'' here and elsewhere include
NSPS promulgated under CAA section 111(b) and emission guidelines
for existing sources promulgated under CAA section 111(d). See 42
U.S.C. 7411(b), (d).
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On February 19, 2025, President Trump issued E.O. 14219, ``Ensuring
Lawful Governance and Implementing the President's `Department of
Government Efficiency' Deregulatory Initiative,'' which directs Federal
agencies, including the EPA, to identify and consider taking action to
repeal ``regulations that are based on anything other than the best
reading of the underlying statutory authority or prohibition'' and
``regulations that implicate matters of social, political, or economic
significance that are not authorized by clear statutory authority.''
\9\ The EPA identified GHG emissions standards for power plants during
the course of this review, including the 2024 CPS requirements that are
the subject of this final rule.
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\9\ 90 FR 10583 (February 25, 2025).
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On April 8, 2025, President Trump issued E.O. 14261,
``Reinvigorating America's Beautiful Clean Coal Industry and Amending
Executive Order 14241,'' which determined that ``coal is essential to
our national and economic security'' and established ``a national
priority to support the domestic coal industry by removing Federal
regulatory barriers that undermine coal production.'' \10\ E.O. 14261
specifically found that ``coal resources will be critical to meeting
the rise in electricity demand due to the resurgence of domestic
manufacturing and the construction of artificial intelligence data
processing centers'' and to increasing ``energy supply,'' lowering
``electricity costs,'' stabilizing the power grid, creating ``high
paying jobs,'' supporting ``burgeoning industries,'' and assisting
allies abroad.\11\ Accordingly, E.O. 14261 directed the EPA, among
other Federal agencies, to ``identify any guidance, regulations,
programs, and policies within their respective executive department or
agency that seek to transition the Nation away from coal production and
electricity generation'' and ``consider revising or rescinding Federal
actions identified in subsection (a) of this section consistent with
applicable law.'' \12\ The EPA identified GHG emissions standards for
power plants during the course of this review as well, including the
2024 CPS requirements that are the subject of this final rule and are
estimated to result in mass closures of coal-fired power plants.
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\10\ 90 FR 15517 (April 14, 2025).
\11\ Id.
\12\ Id.
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The EPA reviewed the GHG emissions standards for the power sector,
as directed by E.O. 14154, E.O. 14219, and E.O. 14261, and has
substantial concerns about the legal and technical underpinnings of the
Agency's efforts to regulate GHG emissions from fossil fuel-fired power
plants. Based on a reassessment of the legal and technical conclusions
in the 2015 NSPS and 2024 CPS, the EPA issued a notice of proposed
rulemaking in June 2025 (``June 2025 NPRM'') that included both a
primary proposal and an alternative proposal. The primary proposal
would have repealed all GHG emissions

[[Page 58956]]

standards for new and existing sources in the fossil fuel-fired EGU
source category.\13\ Specifically, the EPA proposed to determine that
CAA section 111 requires the Agency to make a finding that GHG
emissions from fossil fuel-fired power plants ``cause[ ], or contribute
significantly'' to ``air pollution which may reasonably be anticipated
to endanger public health or welfare'' (which we shorthand as
``dangerous air pollution'') as a predicate to regulating GHG emissions
from those plants. The EPA further proposed to find that GHG emissions
from fossil fuel-fired power plants do not contribute significantly to
dangerous air pollution. The EPA is not acting on those proposed
determinations at this time and is instead concurrently issuing a
supplemental proposal soliciting additional public comment on the
underlying question raised in the primary basis of the June 2025 NPRM:
Whether the EPA lacks statutory authority to regulate GHG emissions
from fossil fuel-fired power plants under CAA section 111. Whereas the
primary proposal in the June 2025 NPRM sought public comment on whether
fossil fuel-fired EGUs ``contribute significantly'' to air pollution,
the supplemental notice seeks public comment on the distinct question
whether global climate change concerns satisfy the threshold
requirement in CAA section 111(b)(1)(A) that fossil fuel-fired power
plant emissions contribute significantly to ``air pollution which may
reasonably be anticipated to endanger public health or welfare.''
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\13\ 90 FR 25752 (June 17, 2025).
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The EPA's alternative proposal was based on the Agency's
reexamination of the best system of emission reduction (BSER)
determinations and associated requirements for fossil fuel-fired power
plants in the 2024 CPS, which it undertook to ensure that all
regulatory requirements are grounded in applicable law. Under CAA
section 111(a)(1), the EPA determines the BSER which, taking into
account cost and any nonair quality and environmental impacts and
energy requirements, has been adequately demonstrated. Based on the
review of the BSER and associated requirement, the EPA proposed, in the
alternative, to repeal parts of the 2024 CPS including the emission
guidelines and other CCS-based requirements. As discussed below, the
EPA is finalizing the alternative proposal repealing parts of the 2024
CPS and revising the associated BSER determinations as follows.
The EPA is finalizing the repeal of the emission guidelines for
existing fossil fuel-fired steam generating units in their entirety.
Specifically, the EPA is finalizing the determination that 90 percent
CCS is not the BSER for existing long-term coal-fired steam generating
units because 90 percent CCS has not been adequately demonstrated, the
costs of 90 percent CCS are not reasonable, and the associated degree
of emission limitation is not achievable. In a change from the 2024
CPS, the EPA concludes that previous projects that failed to achieve 90
percent CCS were not a sufficient basis to conclude the technology has
been adequately demonstrated. Additionally, the carbon dioxide
(CO<INF>2</INF>) capture, pipeline, and sequestration infrastructure
necessary to implement 90 percent CCS for the fleet of existing coal-
fired steam generating units does not currently exist and would need to
be broadly deployed. Because it is significantly unlikely that the
necessary infrastructure for CCS can be deployed by the January 1, 2032
compliance date, the EPA is finalizing the determination that the
degree of emission limitation in the 2024 CPS for long-term coal-fired
steam generating units is not achievable.
The EPA is finalizing the determination that 40 percent natural gas
co-firing is not the BSER for existing medium-term coal-fired steam
generating units because 40 percent natural gas co-firing constitutes
impermissible generation shifting under West Virginia and because the
Agency erred in the 2024 CPS by construing West Virginia too narrowly
in this respect. Additionally, a thorough consideration of the ``energy
requirements'' BSER factor in CAA section 111(a)(1) shows that natural
gas co-firing in a steam generating unit is an inefficient use of
natural gas. Moreover, because it is unlikely that the necessary
pipeline infrastructure can be deployed by the January 1, 2030
compliance date, the EPA is finalizing the determination that the
degree of emission limitation is not achievable. Based on these
conclusions, the EPA is repealing the requirements in the emission
guidelines related to existing long-term and medium-term coal-fired
steam generating units.
The EPA is also repealing the requirements in the emission
guidelines related to natural gas- and oil-fired steam generating
units. The EPA believes that requiring States to develop, submit, and
implement plans solely for natural gas- and oil-fired steam generating
units would be an inefficient use of State resources, as these sources
comprise a relatively small part of the source category and the
requirements under the 2024 emission guidelines for these sources would
result in few or no emission reductions.
Furthermore, because the EPA is finalizing that 90 percent CCS has
not been adequately demonstrated, the costs are not reasonable, and the
degree of emission limitation is not achievable, the EPA is finalizing
the repeal of the CCS-based requirements for coal-fired steam
generating units undertaking a large modification.
The EPA is also finalizing that 90 percent CCS has not been
adequately demonstrated and that the costs are not reasonable for new
base load stationary combustion turbines. Furthermore, because it is
unlikely that the infrastructure necessary for CCS can be deployed by
the January 1, 2032 compliance date, the EPA has determined that the
phase 2 standards of performance in the 2024 CPS for new base load
combustion turbines are not achievable. The contrary determinations in
the 2024 CPS appear to be in error for many of the same reasons that
apply to existing coal-fired steam generating units. Consequently, the
EPA is finalizing repeal of the phase 2 CCS-based requirements for new
base load stationary combustion turbines.
The EPA solicited comment in general on the other GHG requirements
for fossil fuel-fired EGUs and received comments suggesting that the
2024 efficiency-based standards (i.e., the phase 1 standards) for new
stationary combustion turbines are not achievable. However, the EPA is
not revising or repealing those requirements in this final rule. The
EPA acknowledges commenters' meritorious concerns regarding the 2024
efficiency-based standards for new stationary combustion turbines.
While the EPA is not repealing or otherwise revising the 2024
efficiency-based standards in this final action, the Agency notes that
it is concurrently issuing a supplemental proposal that, if finalized,
would repeal all GHG standards for the fossil fuel-fired EGU source
category under CAA section 111, including the 2024 efficiency-based
standards in question. That action, if finalized as proposed, would
resolve commenters' concerns.

A. Cost Savings

Over the 2026 to 2047 period, the present value (PV) of the
estimated compliance cost savings for the power sector in 2024 dollars,
discounted to 2025, is $160 billion using a three percent discount rate
and $95 billion using a seven percent discount rate. Over this same
period, the PV of the estimated real resource cost savings, which is
the full avoided expenditure on physical and labor inputs used in the

[[Page 58957]]

power sector for compliance, is $280 billion using a three percent
discount rate and $180 billion using a seven percent discount rate
discounted to 2025.\14\ The cost savings do not account for benefits
such as ensuring electric grid reliability and other secondary and
tertiary benefits that cannot be monetized.
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\14\ The real resource cost savings account for the costs that
society avoids paying as an outcome of the CPS requirements the EPA
is repealing in this final rule. See Regulatory Impact Analysis for
the Final Partial Repeal of the Carbon Pollution Standards for
Fossil Fuel-Fired Electric Generating Units, available in the docket
for this rulemaking (Document ID No. EPA-HQ-OAR-2025-0124).
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II. General Information

A. Where To Get a Copy of This Document and Other Related Information

In addition to the docket, an electronic copy of this final action
will be on the internet. Following signature by the Administrator, the
EPA will post a copy of this final action at <a href="https://www.epa.gov/stationary-sources-air-pollution/greenhouse-gas-standards-and-guidelines-fossil-fuel-fired-power">https://www.epa.gov/stationary-sources-air-pollution/greenhouse-gas-standards-and-guidelines-fossil-fuel-fired-power</a>. Following publication in the
Federal Register (FR), the EPA will post the FR version at this same
website.

B. Action Applicability

Fossil fuel-fired electric utility steam generating units and
stationary combustion turbine EGUs that provide electricity to the
electric grid (a utility power distribution system) comprise the source
category that is subject to this action. The 2022 North American
Industry Classification System (NAICS) code for the source category is
221112. The EPA does not intend this identification to be exhaustive
but rather to provide a guide for readers regarding the entities that
this final action is likely to affect.
The final repeal of 40 Code of Federal Regulations (CFR) part 60,
subpart UUUUb, is applicable to States that, under the existing
regulations, must develop and submit state plans pursuant to CAA
section 111(d). The final repeal of 90 percent CCS-based requirements
of 40 CFR part 60, subpart TTTTa, is applicable to affected facilities
that began construction, reconstruction, or modification after May 23,
2023. This final action also affects Federal, State, local, and Tribal
government entities that own and/or operate EGUs subject to 40 CFR part
60, subpart TTTTa, as affected facilities are no longer subject to
requirements based on 90 percent CCS.

C. Statutory Authority

CAA section 111 authorizes the EPA to list and regulate a category
of stationary sources if the Administrator, ``in his judgment,'' finds
that the source category ``causes, or contributes significantly to, air
pollution which may reasonably be anticipated to endanger public health
or welfare.'' \15\ The listing of a source category triggers the EPA's
authority to promulgate ``standards of performance'' for new sources
and, under limited circumstances, to prescribe regulations under which
States submit plans that establish standards of performance for
existing sources.\16\ CAA section 111, along with agencies' authority
to reconsider prior regulations, provides the statutory authority for
this final action.\17\
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\15\ 42 U.S.C. 7411(b)(1)(A).
\16\ 42 U.S.C. 7411(b), (d).
\17\ See FDA v. Wages & White Lion Invs., LLC, 604 U.S. 542, 568
(2025); FCC v. Fox TV Stations, Inc., 556 U.S. 502, 517-18 (2009);
Motor Vehicle Mfrs. Ass'n v. State Farm Mut. Auto. Ins. Co., 463
U.S. 29, 41-42 (1983); see also Clean Air Council v. Pruitt, 862
F.3d 1, 8 (D.C. Cir. 2017) (``Agencies obviously have broad
discretion to reconsider a regulation at any time.'')
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1. Regulation of Emissions From New Sources
CAA section 111(b)(1)(A) authorizes the Administrator to publish,
and from time-to-time revise, a list of categories of stationary
sources that the Administrator, ``in his judgment,'' finds ``causes, or
contributes significantly to, air pollution which may reasonably be
anticipated to endanger public health or welfare.'' Once the EPA lists
a source category under CAA section 111(b)(1)(A), the EPA must, under
CAA section 111(b)(1)(B), establish ``standards of performance'' for
``new sources'' in the source category. These standards are referred to
as new source performance standards, or NSPS. The NSPS are national
requirements that apply directly to new sources within the relevant
source category.
CAA section 111(a)(2) defines a ``new source'' as ``any stationary
source, the construction or modification of which is commenced after
the publication of regulations (or, if earlier, proposed regulations)
prescribing a standard of performance under this section, which will be
applicable to such source.'' CAA section 111(a)(4) defines
``modification'' as ``any physical change in, or change in the method
of operation of, a stationary source which increases the amount of any
air pollutant emitted by such source or which results in the emission
of any air pollutant not previously emitted.'' While this provision
treats modified sources as new sources, the EPA's regulations also
treat a source that undergoes ``reconstruction,'' by substantially
replacing its components, as a new source.\18\
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\18\ 40 CFR 60.15.
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CAA section 111(a)(1) defines ``standard of performance'' as ``a
standard for emissions of air pollutants'' that must be promulgated or
revised in a specified manner. When the EPA establishes or revises a
performance standard, CAA section 111(a)(1) provides that such a
standard must ``reflect[ ] the degree of emission limitation achievable
through the application of the best system of emission reduction which
(taking into account the cost of achieving such reduction and any
nonair quality health and environmental impact and energy requirements)
the Administrator determines has been adequately demonstrated.'' Thus,
the term ``standard of performance,'' as used in CAA section 111, makes
clear that the EPA must determine both the ``best system of emission
reduction . . . adequately demonstrated'' for emissions of the relevant
air pollutants by regulated sources in the source category and the
``degree of emission limitation achievable through the application of
the [BSER].'' \19\ As explained elsewhere in this preamble, to
determine the BSER, the EPA first identifies the ``system[s] of
emission reduction'' that are ``adequately demonstrated'' and then
determines the ``best'' of those adequately demonstrated systems,
``taking into account'' factors including ``cost,'' ``nonair quality
health and environmental impact,'' and ``energy requirements.'' The EPA
has discretion in determining the BSER, and has historically followed a
``technology-based approach'' that focuses on ``measures that improve
the pollution performance of individual sources,'' such as ``add-on
controls.'' \20\ (If no system of emission reduction can be deemed
adequately demonstrated in light of the EPA's consideration of these
factors, then it may be the case that EPA cannot identify BSER).
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\19\ West Virginia, 597 U.S. at 709.
\20\ See id. at 727 (quoting the 2015 CPP).
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After determining the BSER, the EPA derives the ``degree of
emission limitation achievable'' through ``application'' of the BSER. A
standard of performance is ``achievable'' if a technology can
reasonably be projected to be available to an individual source at the
time it is constructed so as to allow it to meet the standard.\21\ The
EPA must then, under CAA section

[[Page 58958]]

111(b)(1)(B), promulgate ``standard[s] for emissions''--the NSPS--that
reflect that level of stringency. The EPA may determine that different
sets of sources have different characteristics relevant for determining
the BSER for emissions of the relevant air pollutants and may
subcategorize sources accordingly pursuant to CAA section
111(b)(2).\22\
---------------------------------------------------------------------------

\21\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 391
(D.C. Cir. 1973).
\22\ 42 U.S.C. 7411(b)(2).
---------------------------------------------------------------------------

2. Regulation of Emissions From Existing Sources
The EPA has generally used CAA section 111 to establish standards
for emissions of air pollutants from new sources within a category. In
the rare instances where new stationary source standards concern air
pollutant emissions that are not regulated under the National Ambient
Air Quality Standards (NAAQS) program pursuant to CAA sections 108-110
or under the National Emission Standards for Hazardous Air Pollutants
(NESHAP) program pursuant to CAA section 112, the statute provides a
separate authority for addressing emissions of such air pollutants from
existing sources in the source category.\23\ In these limited
circumstances, the promulgation of standards for new stationary sources
triggers the EPA's authority to promulgate regulations for emissions of
that pollutant from existing sources within the same category under CAA
section 111(d).\24\
---------------------------------------------------------------------------

\23\ 42 U.S.C. 7411(d)(1)(A)(i)-(ii).
\24\ See West Virginia, 597 U.S. at 710 (``Section 111(d) thus
`operates as a gap-filler,' empowering EPA to regulate harmful
emissions not already controlled under the Agency's other
authorities. . . . Reflecting the ancillary nature of Section
111(d), EPA has used it only a handful of times since the enactment
of the statute in 1970.'').
---------------------------------------------------------------------------

In contrast to the national regime for new sources under CAA
section 111(b), CAA section 111(d) establishes a framework of
``cooperative federalism for the regulation of existing sources.'' \25\
CAA section 111(a)(6) defines an ``existing source'' as ``any
stationary source other than a new source.'' CAA section 111(d)(1)
provides that when air pollutants covered by an NSPS for a source
category are not already encompassed within the NAAQS program or NESHAP
program, the EPA ``shall prescribe regulations which shall establish a
procedure similar to that provided by'' CAA section 110 ``under which
each State shall submit to the Administrator'' a plan for addressing
emissions of such air pollutants by existing sources within such source
category.\26\ Reference to CAA section 110 incorporates the statute's
provision for State submission and EPA review of state implementation
plans (SIPs) that provide for the implementation, maintenance, and
enforcement of the NAAQS for the areas within such State.\27\ In a
comparable manner, State plans required by the regulations authorized
in CAA section 111(d) must ``establis[h] standards of performance for
any existing stationary source'' for the air pollutant at issue and
``provid[e] for the implementation and enforcement of such standards of
performance.''
---------------------------------------------------------------------------

\25\ Am. Lung Ass'n v. EPA, 985 F.3d 914, 931 (D.C. Cir. 2021),
rev'd in part sub nom. West Virginia, 597 U.S. 697.
\26\ 42 U.S.C. 7411(d)(1). CAA section 111(a)(6) defines an
``existing source'' as ``any stationary source other than a new
source.'' 42 U.S.C. 7411(a)(6).
\27\ 42 U.S.C. 7410.
---------------------------------------------------------------------------

In the relatively few instances in which the EPA applies CAA
section 111(d), the Agency generally promulgates regulations, termed
``emission guidelines,'' that identify the BSER and the degree of
emission limitation achievable through the application of the BSER.
These regulations then require States to establish standards of
performance for emissions of the air pollutant at issue by covered
sources that reflect that level of stringency.\28\ States need not
compel regulated sources to adopt the particular components of the BSER
itself. Rather, States have discretion in designing the policies and
rules their sources will use to achieve the degree of emission
limitation required by the emission guidelines. The statute also
requires the EPA's regulations to permit a State ``in applying a
standard of performance to any particular source'' to ``take into
consideration, among other factors, the remaining useful life of the
existing source to which such standard applies.'' \29\ Once the EPA
approves a State's plan, its provisions become federally enforceable
against the source in the same manner as the provisions of an approved
SIP under the CAA.\30\ If a State elects not to submit a plan or
submits a plan that the EPA does not find ``satisfactory,'' the CAA
authorizes the Agency to promulgate a plan that establishes Federal
standards of performance for the State's existing sources.\31\
---------------------------------------------------------------------------

\28\ As discussed below, CAA section 111(d)(1)(B) provides that,
in certain circumstances, States may apply standards of performance
that are less stringent than the degree of emission limitation that
the EPA determines in the emission guidelines. See 42 U.S.C.
7411(d)(1)(B).
\29\ 42 U.S.C. 7411(d)(1).
\30\ 42 U.S.C. 7411(d)(2)(B).
\31\ 42 U.S.C. 7411(d)(2)(A).
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3. Key Elements of Determining a Standard of Performance
Congress first defined the term ``standard of performance'' when
enacting CAA section 111 in the 1970 CAA, amended the definition in the
1977 CAA Amendments, and amended the definition again in the 1990 CAA
Amendments to largely restore the definition as in the 1970 CAA. The
D.C. Circuit has reviewed CAA section 111 rulemakings on numerous
occasions since the early 1970s and developed a body of case law that
interprets the term.\32\
---------------------------------------------------------------------------

\32\ Am. Lung Ass'n, 985 F.3d at 914; Delaware v. EPA, No. 13-
1093 (D.C. Cir. May 1, 2015); Portland Cement Ass'n v. EPA, 665 F.3d
177 (D.C. Cir. 2011); Lignite Energy Council v. EPA, 198 F.3d 930
(D.C. Cir. 1999); Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir.
1981); Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427 (D.C. Cir.
1973); Portland Cement Ass'n, 486 F.2d at 375.
---------------------------------------------------------------------------

Whether promulgated by the EPA under CAA section 111(b) or
established by the States under CAA section 111(d) in response to
emission guidelines promulgated by the Agency, the basis for standards
of performance is the ``degree of emission limitation'' that is
``achievable'' by sources in the source category by application of the
``best system of emission reduction'' that the EPA determines is
``adequately demonstrated.'' As explained in this section, systems are
not ``adequately demonstrated'' if they are ``purely theoretical or
experimental.'' \33\ The D.C. Circuit has stated that in determining
the ``best'' adequately demonstrated system for the pollutants at
issue, the EPA must also take into account ``the amount of air
pollution'' reduced.\34\ The D.C. Circuit has also stated that the EPA
may weigh the various factors identified in the statute and case law to
determine the ``best'' system and has emphasized that the EPA has
significant discretion in weighing the factors.\35\
---------------------------------------------------------------------------

\33\ Essex Chem. Corp., 486 F.2d at 433-34.
\34\ Sierra Club, 657 F.2d at 326; see id. at 347 (stating that
the EPA must take ``technological innovation'' into account).
\35\ Lignite Energy Council, 198 F.3d at 933 (``Because section
111 does not set forth the weight that should be assigned to each of
these factors, we have granted the agency a great degree of
discretion in balancing them.'').
---------------------------------------------------------------------------

After determining the BSER, the EPA sets an achievable emission
limit based on application of the BSER.\36\ For a CAA section 111(b)
rule, the EPA determines the standard of performance that reflects that
achievable emission limit. For a CAA section 111(d) rule, the States
establish the standards of performance that reflect the degree of
emission limitation that the EPA has included in

[[Page 58959]]

an emission guideline. In applying these standards to existing sources,
States are permitted to consider a source's remaining useful life and
other factors.\37\
---------------------------------------------------------------------------

\36\ See, e.g., 77 FR 49490, 49494 (August 16, 2012) (describing
the three-step analysis in setting a standard of performance).
\37\ 42 U.S.C. 7411(d)(1).
---------------------------------------------------------------------------

In identifying ``system[s] of emission reduction,'' the EPA
historically has followed a ``technology-based approach'' that focuses
on ``measures that improve the pollution performance of individual
sources,'' such as ``add-on controls.'' \38\ In the 2015 CPP, the EPA
significantly departed from its historical approach to standard setting
under CAA section 111(b) by setting a BSER in which the ``system'' of
emission reduction involved shifting electricity generation from one
type of fuel to another. In West Virginia, the U.S. Supreme Court
applied the major questions doctrine to hold that neither the term
``system'' nor any other provision of the CAA provided the requisite
clear authorization to support the 2015 CPP's BSER, which the Court
described as ``carbon emissions caps based on a generation shifting
approach'' \39\ that capped GHG ``emissions at a level that will force
a nationwide transition away from the use of coal to generate
electricity[.]'' \40\ The Court explained that the EPA's BSER
``forc[es] a shift throughout the power grid from one type of energy
source to another,'' which constituted ``unprecedented power over
American industry'' and was different in kind from the type of
``system'' of emission reduction envisioned by CAA section 111(d).\41\
---------------------------------------------------------------------------

\38\ See West Virginia, 597 U.S. at 727 (quoting 80 FR 64662,
64784 (October 23, 2015)).
\39\ Id. at 732.
\40\ Id. at 734.
\41\ Id. at 728 (citation omitted).
---------------------------------------------------------------------------

To qualify as the BSER, the system of emission reduction must be
``adequately demonstrated'' as ``the Administrator determines.'' \42\
The plain text of CAA section 111(a)(1), and in particular the terms
``adequately'' and ``the Administrator determines,'' confers upon the
EPA the discretion to identify the appropriate system, including making
scientific and technological determinations and considering a broad
range of policy considerations.\43\ However, the terms ``adequately''
and ``demonstrated,'' as well as applicable case law, make clear that
the EPA may not determine that a ``purely theoretical or experimental''
system is ``adequately demonstrated.'' \44\ Moreover, applicable case
law and the text and structure of CAA section 111, including the
requirement that the resulting emission limitation be ``achievable''
and the eight-year review requirement in CAA section 111(b)(1)(B),
place an outer bound on the EPA's discretion to project technological
development into the future.
---------------------------------------------------------------------------

\42\ 42 U.S.C. 7411(a)(1).
\43\ Nat'l Asphalt Pavement Ass'n v. Train, 539 F.2d 775, 786
(D.C. Cir. 1976); Essex Chem. Corp., 486 F.2d at 434.
\44\ Essex Chem. Corp., 486 F.2d at 433-34; see Portland Cement
Ass'n, 486 F.2d at 391-92 (the EPA may not base an ``adequately
demonstrated'' determination on a `` `crystal ball' inquiry'')
(citation omitted).
---------------------------------------------------------------------------

In addition, CAA section 111(a)(1) requires the EPA to account for
``the cost of achieving [the emission] reduction'' in determining the
adequately demonstrated BSER. Although the CAA does not describe how
the EPA should account for costs to affected sources, the D.C. Circuit
has formulated the cost standard in various ways, including by stating
on the upper bound that the EPA may not adopt a standard the cost of
which would be ``excessive'' or ``unreasonable.'' \45\ The EPA has
discretion in considering cost under CAA section 111(a), both in
determining the appropriate level of costs and in balancing costs with
other BSER factors.\46\ The D.C. Circuit has repeatedly upheld the
EPA's consideration of cost in reviewing standards of performance.\47\
---------------------------------------------------------------------------

\45\ Sierra Club, 657 F.2d at 343; see 79 FR 1430, 1464 (January
8, 2014); Lignite Energy Council, 198 F.3d at 933 (costs may not be
``exorbitant''); Portland Cement Ass'n v. Train, 513 F.2d 506, 508
(D.C. Cir. 1975) (costs may not be ``greater than the industry could
bear and survive'').
\46\ Sierra Club, 657 F.2d at 343.
\47\ See Essex Chem. Corp., 486 F.2d at 440; Portland Cement
Ass'n, 486 F.2d at 387-88; Sierra Club, 657 F.2d at 313.
---------------------------------------------------------------------------

Under CAA section 111(a)(1), the EPA must take into account ``any
nonair quality health and environmental impact and energy
requirements'' in determining the BSER. Nonair 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.\48\ Energy requirements may
include the impact, if any, of the air pollution controls on the
source's own energy needs.\49\ In addition, based on the D.C. Circuit's
interpretations of CAA section 111, energy requirements may also
include the impact, if any, of the air pollution controls on the energy
supply for a particular area or nationwide.\50\ Furthermore, the EPA
has considered under this statutory factor whether possible controls
would create risks to the reliability of the national electricity
system.\51\
---------------------------------------------------------------------------

\48\ Portland Cement Ass'n, 486 F.2d at 387-88.
\49\ For details on the modeled energy requirements associated
with CCS, please see section 6.4 of the RIA for this final rule.
\50\ See Sierra Club, 657 F.2d at 327-28 (quoting 44 FR 33580,
33583-84 (June 11, 1979)); 79 FR 1430, 1465 (January 8, 2014)
(citing Sierra Club, 657 F.2d at 351).
\51\ See, e.g., 89 FR 39886 (May 9, 2024).
---------------------------------------------------------------------------

The D.C. Circuit has also held that the term ``best'' authorizes
the EPA to consider factors that further the purpose of the statute in
addition to the ones enumerated in CAA section 111(a)(1). In
particular, consistent with the plain language and the purpose of CAA
section 111(a)(1), which requires the EPA to determine the ``best
system of emission reduction'' (emphasis added), the D.C. Circuit has
previously held that the Agency must consider the quantity of emissions
at issue.\52\ The EPA has broad discretion in determining which
adequately demonstrated system of emission reduction is the ``best.''
In Sierra Club, the D.C. Circuit explained that ``section 111(a)
explicitly instructs the EPA to balance multiple concerns when
promulgating a NSPS'' and emphasized that ``[t]he text gives the EPA
broad discretion to weigh different factors in setting the standard,''
including the amount of emission reductions, the cost of the controls,
and the nonair quality environmental impacts and energy
requirements.\53\
---------------------------------------------------------------------------

\52\ Sierra Club, 657 F.2d at 326. The D.C. Circuit has also
held that Congress intended for CAA section 111 to create incentives
for new technology, and therefore that the EPA is to consider
technological innovation as one of the factors in determining the
``best system of emission reduction.'' See id. at 346-47.
\53\ Sierra Club, 657 F.2d at 319, 321; see also New York v.
Reilly, 969 F.2d 1147, 1150 (D.C. Cir. 1992).
---------------------------------------------------------------------------

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 so as to allow the source to meet the
standard.\54\ The courts have established this approach for
achievability in cases concerning CAA section 111(b) NSPS. A generally
comparable approach applies to CAA section 111(d), although the BSER
may differ in some cases between new and existing sources due to, for
example, higher costs and feasibility of retrofit.\55\ For existing
sources, CAA section 111(d)(1) requires the EPA to establish
regulations for State plans that, in turn, must include ``standards of
performance.'' As the Supreme Court has recognized, the EPA generally
carries out this provision by promulgating emission guidelines that
determine the BSER for a source category and then identify the degree
of

[[Page 58960]]

emission limitation achievable by application of the BSER.\56\
---------------------------------------------------------------------------

\54\ See Portland Cement Ass'n, 486 F.2d at 391.
\55\ See, e.g., 40 FR 53340 (November 17, 1975).
\56\ See West Virginia, 597 U.S. at 710; 40 CFR 60.21(e),
60.21a(e) (definition of ``emission guideline'' includes provision
of the degree of emission limitation achievable through the
application of the BSER as determined by the Administrator).
---------------------------------------------------------------------------

D. Severability

In this final rule, the EPA is repealing (1) the emission
guidelines for existing fossil fuel-fired steam generating EGUs in 40
CFR part 60, subpart UUUUb; (2) the 90 percent CCS-based standards of
performance for coal-fired steam generating units undertaking a large
modification in 40 CFR part 60, subpart TTTT; and (3) the 90 percent
CCS-based standards of performance for new base load stationary
combustion turbines in 40 CFR part 60, subpart TTTTa. Although the
record evidence supporting each of these separate actions may overlap,
particularly pertaining to 90 percent CCS, the repeal of each is
supported by its own, standalone rationale and is severable from the
others. That is, the repeal of the emission guidelines for existing
sources in subpart UUUUb does not impact the 90 percent CCS-based
standards of performance for coal-fired steam generating units
undertaking a large modification and new base load stationary
combustion turbines, as these rules apply to different sets of sources.
Similarly, the repeal of the 90 percent CCS-based standards of
performance either for modified sources or for new sources does not
impact either of the two other rules. Again, while the records
supporting each of these separate actions may overlap, application of
the record evidence to each of the separate sets of regulated sources
may yield different outcomes. If a court were to invalidate one or more
of those actions, the EPA would still be able to implement the repeal
of the remaining action or actions.
Additionally, within the group of existing fossil fuel-fired steam
generating units (the sources regulated by 40 CFR subpart 60 subpart
UUUUb), each of the following actions is severable: repeal of the BSER
determination and associated requirements for the subcategory of long-
term coal-fired steam generating EGUs, repeal of the BSER determination
and associated requirements for the subcategory of medium-term coal-
fired steam generating EGUs, and repeal of the requirements for the
subcategory of oil- and natural gas-fired steam generating EGUs. That
is, the repeal of the requirements for each separate subcategory of
existing fossil fuel-fired steam generating units is based on an
independent rationale and is severable from the repeal of the
requirements for each other subcategory of existing units. If a court
were to invalidate the EPA's action with regard to one or more
subcategories of existing units, the Agency would still be able to
implement the repeal of the requirements for the remaining
subcategories or subcategory. This is because the requirements for each
subcategory are self-contained in the regulations and, due to the
design of the emission guidelines in subpart UUUUb, it would have been
relatively difficult for sources to shift between subcategories. Thus,
the repeal of the requirements for each subcategory of existing fossil
fuel-fired steam generating units is severable.

E. Reliance Interests

The EPA requested comment on reliance interests on the 2015 NSPS
and the 2024 CPS in the June 2025 NPRM that commenters believed the
Agency should consider in formulating a final action.\57\ Potentially
significant and legitimate reliance interests may arise, for example,
when regulated parties or other stakeholders expend resources to comply
with existing standards, including by pricing compliance into costs for
consumers. Significant and legitimate reliance interests may also arise
when stakeholders reasonably factored the existence of standards into
concrete plans that cannot be readily modified. Under relevant case
law, these and other reliance interests may be a relevant consideration
to weigh against competing rationales when deciding whether to change
the Agency's position.\58\ However, the EPA notes that general
interests in retaining the at-issue 2024 CPS requirements for the sake
of regulating GHG emissions from fossil fuel-fired power plants do not
justify such retention in the absence of statutory authority and a
reasoned basis for particular control requirements. To the extent the
EPA is repealing aspects of the 2024 CPS based on applicable statutory
requirements, the unlawful nature of those aspects necessitates repeal;
the change-in-position doctrine does not expand an agency's statutory
authority for the purpose of addressing reliance interests. Where
possible and appropriate, the Agency considered whether any asserted
reliance interests are significant and legitimate and, if so, whether
different or additional regulatory actions could address such concerns,
consistent with the requirements of the statute.\59\
---------------------------------------------------------------------------

\57\ 90 FR 25752, 25777 (June 17, 2025).
\58\ See, e.g., DHS v. Regents of Univ. of Cal., 591 U.S. 1, 30
(2020).
\59\ The Agency also notes that because this final rule
addresses certain requirements of the 2024 CPS only, we are not
addressing any potential reliance interests on the 2015 NSPS at this
time.
---------------------------------------------------------------------------

The EPA carefully reviewed public comments to assess whether any
aspects of this final action should be adjusted to account for reliance
interests. The Agency received no comments on reliance interests
arising from the 2024 CPS from regulated entities. To our knowledge, no
expenditures on projects involving fossil fuel-fired power plants have
been made exclusively in response to the 2024 CPS requirements that the
EPA is repealing. The EPA notes that under the compliance dates and
assumed project schedules for the two control strategies that served as
the basis for requirements in the 2024 CPS concerning coal-fired power
plants--90 percent CCS and 40 percent natural gas co-firing--affected
sources would not yet have incurred significant expenditures. The
compliance dates for these requirements, as well as the alternative
compliance option of ceasing operations, were not scheduled to begin
until 2032. Although, as discussed elsewhere in this preamble, the
requirements involved a long implementation timeline and many fossil
fuel-fired EGUs are subject to long planning horizons, much of the
required buildout was anticipated to be on the part of third parties
(pipeline infrastructure and injection wells, for example), and this
rulemaking occurred far enough in advance to forestall the vast
majority of sunk costs that would otherwise have been incurred. Based
on information available to the Agency, such costs would have begun to
accrue in earnest around the time of this final rule, making the action
both timely and supporting reliance on the cost- and achievability-
based rationales discussed herein.
Similarly, the EPA did not receive any comments from States on any
resource expenditures they may have made to develop State plans in
response to the emission guidelines for existing sources under 40 CFR
part 60, subpart UUUUb. The EPA has not received any State plan
submissions to date, and such plans were subject to extension
opportunities and review that may have involved different timelines and
further efforts in any event. Nor has the EPA promulgated a Federal
plan in the absence of approved State plans, meaning air agencies have
not expended resources participating in such a rulemaking or assisting
regulated sources with compliance.

[[Page 58961]]

The EPA received one comment asserting State-related reliance
interests, summarized below. However, upon careful examination, the EPA
determined that this comment asserted general interests that are not
properly understood as significant and serious reliance on the 2024 CPS
that would warrant a different or additional regulatory outcome as to
the 2024 CPS requirements at issue in this rulemaking. Therefore, the
Agency is not aware of any substantial reliance interests that would
have informed its decision making for purposes of this final action.
Comment: One commenter asserted that State and local air agencies
are relying on potential non-GHG emission reduction co-benefits from
the 2024 CPS to reach NAAQS attainment for criteria pollutants. The
commenter asserted that State and local agencies have invested
significant staff hours and funds in planning, outreach, modeling, and
rule development to implement SIPs for NAAQS attainment. The commenter
stated that the proposed repeal potentially required States to develop
planning scenarios with and without the 2024 CPS. The commenter stated
that State and local agencies must develop new attainment strategies
and incur additional expenditures.
EPA Response: The EPA disagrees that State and local air agencies
have reasonably relied on the at-issue 2024 CPS requirements to the
extent that the impact of repeal on planning activities would amount to
serious and irreversible harms. While the EPA acknowledges there may be
overlaps between NAAQS attainment planning and the GHG control
strategies that States would have had to develop under the 2024 CPS,
these programs are governed by separate statutory provisions and
address different pollutants on different timelines and under different
regulatory paradigms. That is, while GHG control strategies States may
have been developing pursuant to the 2024 CPS may have had co-benefits
in terms of reductions of criteria air pollutants, we disagree that
such co-benefits engender serious reliance interests relevant to this
rulemaking because they do not justify retaining a GHG regulatory
program that is not consistent with the relevant statutory
requirements. This final action does not impact any of the EPA's
criteria pollutant standards of performance for power plants regulated
under and listed in various pre-2015 source categories pursuant to CAA
section 111, which are more directly relevant to NAAQS attainment.
Moreover, the absence of comments raising resource expenditures
related to State and local air agency implementation of the 2024 CPS
emission guidelines suggests that air agencies have not, in fact,
expended significant resources developing GHG control strategies
because of the 2024 CPS. NAAQS attainment efforts are ongoing, and the
projected criteria emission co-benefits in the 2024 CPS for the at-
issue requirements are small in absolute terms. That is not surprising
given the relatively long time horizon involved in developing such
submissions and the short period of time that elapsed between
finalization of the 2024 CPS and the announcement of reconsideration.
To the extent the commenter asserts that State and local air agencies
worked to develop options with and without the 2024 CPS, the Agency
notes that such considerations are expected when analyzing the many
options available to States in exercising their considerable discretion
in developing strategies to attain and maintain the NAAQS and that
requirements, particularly at the proposal stage, are necessarily
subject to change.
While it is reasonable for States to consider the different control
strategies they will be applying to their sources in a coordinated
manner, the 2024 CPS requirements at issue could not have engendered
serious reliance interests under the circumstances sufficient to
warrant different or additional regulatory actions in this rulemaking.
The Agency finalized the CPS in May 2024 and announced its intention to
reconsider the rule in March 2025.\60\ At the same time, NAAQS
attainment planning has been ongoing, in many cases, for decades. It is
therefore not likely that States could have relied on the existence of
and obligations under the 2024 CPS for NAAQS attainment planning
purposes. And, in all likelihood, State and local air agencies would
necessarily have to take into consideration other developments in the
electric power sector due to changes in, e.g., electricity demand, such
that they would be considering the adequacy of their NAAQS attainment
planning even absent the repeal of the 2024 CPS requirements being
finalized in this action. Moreover, it is a normal course of action for
State and local air agencies to re-evaluate their planning in response
to changes in Federal air regulations.
---------------------------------------------------------------------------

\60\ ``Trump EPA Announces Reconsideration of Biden-Harris Rule,
`Clean Power Plan 2.0,' '' That Prioritized Shutting Down Power
Plants While Raising Costs on American Families'' (March 12, 2025).
Available at: <a href="https://www.epa.gov/newsreleases/trump-epa-announces-reconsideration-biden-harris-rule-clean-power-plan-20-prioritized">https://www.epa.gov/newsreleases/trump-epa-announces-reconsideration-biden-harris-rule-clean-power-plan-20-prioritized</a>.
---------------------------------------------------------------------------

Considering these factors, the EPA believes that the commenter's
concerns do not constitute a serious reliance interest warranting a
different outcome. Such co-benefit considerations would not be an
adequate basis to retain the at-issue 2024 CPS requirements, which must
be justified under and consistent with statutory requirements with
respect to the subject of the regulations (i.e., GHG emissions). The
2024 CPS regulates GHG emissions in the form of CO<INF>2</INF> for the
fossil fuel-fired EGU source category and the Agency did not, in the
2024 CPS, analyze or promulgate the at-issue requirements as multi-
pollutant standards.

III. Background

A. EPA Regulation of GHG Emissions Under CAA Section 111

This section discusses the EPA's efforts to regulate GHG emissions
under CAA section 111 since 2015, including the regulation of fossil
fuel-fired EGUs, associated case law that is relevant to this action,
and the EPA's asserted legal basis for regulating GHG emissions under
CAA section 111.
The EPA has regulated air pollutants from power plants under CAA
section 111 since 1971, when the Agency listed ``fossil fuel-fired
steam generators of more than 250 million British thermal units per
hour (MMBtu/h) heat input'' as a source category under CAA section
111(b)(1)(A) \61\ and subsequently promulgated NSPS for certain air
pollutants.\62\ In 1977, the EPA listed fossil fuel-fired ``stationary
gas turbines'' in a category under CAA section 111(b)(1)(A) \63\ and
subsequently promulgated NSPS for certain air pollutants.\64\ However,
the EPA did not invoke CAA section 111 to regulate GHG emissions from
power plants until 2015, when the Agency promulgated the 2015 NSPS,
which addressed GHG emissions as measured by the equivalent of
CO<INF>2</INF> emissions, from new fossil fuel-fired EGUs under CAA
section 111(b); \65\ and the 2015 CPP, which set emission guidelines
directing States to regulate GHG emissions as measured by the
equivalent of CO<INF>2</INF> emissions from existing EGUs under CAA
section 111(d).\66\
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\61\ 36 FR 5931 (March 31, 1971).
\62\ See, e.g., 36 FR 24876 (December 23, 1971); 40 CFR 60,
subpart Da.
\63\ See 42 FR 53657 (October 3, 1977).
\64\ See, e.g., 44 FR 62792 (September 10, 1979); 40 CFR 60,
subpart KKKK.
\65\ 80 FR 64510 (October 23, 2015).
\66\ 80 FR 64662 (October 23, 2015).

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[[Page 58962]]

In the 2015 NSPS, the EPA laid out a novel legal basis for
regulating GHG emissions based on global climate change concerns under
CAA section 111. Additionally, in that rule, the EPA asserted that the
Agency was not required to make a finding of significant contribution
under CAA section 111 before regulating GHG emissions. The EPA
explained that CAA section 111(b)(1)(A) requires the Administrator to
list any source category that ``causes, or contributes significantly
to, air pollution which may reasonably be anticipated to endanger
public health or welfare.'' The EPA posited that, unlike other CAA
provisions, CAA section 111(b)(1)(A) does not require the EPA to make
endangerment and significant contribution findings for individual
pollutants. Rather, the EPA asserted that once such findings are made
for any pollutant emitted by a source category, the Agency has
discretion to regulate all pollutants emitted by the source category
subject only to rational basis constraints.\67\
---------------------------------------------------------------------------

\67\ 80 FR 64510, 64529-30 (October 23, 2015).
---------------------------------------------------------------------------

Using this framework, the EPA created a new source category (i.e.,
all fossil fuel-fired EGUs) consisting of the type of power plants
previously listed in the 1970s under separate source categories.
Specifically, the EPA took the step of ``combining the steam generator
and combustion turbine categories into a single category of fossil
fuel-fired electricity generating units for purposes of promulgating
standards of performance for GHG emissions.'' \68\ The EPA explained
that ``[c]ombining the two categories is reasonable because they both
provide the same product: Electricity services,'' and that combining
the source categories in the 2015 NSPS was consistent with the Agency's
decision to combine the categories ``in the CAA section 111(d) rule for
existing sources that accompanies [the 2015 NSPS],'' i.e., in the 2015
CPP.\69\ The Agency maintained, however, that it was not listing a new
source category and therefore was not required to make any endangerment
or significant contribution finding for the fossil fuel-fired EGU
source category to promulgate NSPS.
---------------------------------------------------------------------------

\68\ See id. at 64531.
\69\ Id.
---------------------------------------------------------------------------

The EPA determined that it had a rational basis for concluding that
emissions of CO<INF>2</INF> from fossil fuel-fired power plants merit
regulation under CAA section 111. In reaching that conclusion, the
Agency stated that it had determined in the 2009 Endangerment Finding
that GHG emissions may reasonably be anticipated to endanger public
health or welfare and that more recent information confirmed this
determination. The EPA explained that the approach it was taking with
regard to endangerment and GHG emissions from the fossil fuel-fired EGU
source category was ``substantially similar to that reflected in the
2009 Endangerment Finding and the 2010 denial of petitions to
reconsider.'' \70\ The EPA added that ``the high level of GHG emissions
from fossil fuel-fired EGUs makes clear that it is rational for the EPA
to regulate GHG emissions from this sector.'' \71\
---------------------------------------------------------------------------

\70\ Id. at 64531; see 75 FR 49556 (August 13, 2010) (denying
petitions for reconsideration of the 2009 Endangerment Finding).
\71\ 80 FR 64510, 64530 (October 23, 2015).
---------------------------------------------------------------------------

The EPA explained the legal basis for its interpretation of CAA
section 111(b)(1)(A) as follows: The Agency noted that the EPA had
listed fossil fuel-fired steam generators as a source category in 1971
and combustion turbines as a source category in 1979, in each case on
the basis of the sources' emissions of non-GHG air pollutants, and the
EPA acknowledged that the Agency had not considered GHG emissions at
the time of those listings. Even so, in the 2015 NSPS, the EPA stated
that the Agency interpreted CAA section 111 to provide that after the
EPA listed a source category once, the CAA authorized the Agency to
promulgate NSPS for any air pollutant from a source listed in that
source category, so long as the EPA had a rational basis for doing
so.\72\
---------------------------------------------------------------------------

\72\ Id. at 64529-31.
---------------------------------------------------------------------------

The EPA received comments on the 2015 NSPS stating that CAA section
111 did not authorize regulation of GHGs from fossil fuel-fired EGUs
until the Agency first makes a finding that emission of GHGs from these
power plants contributes significantly to air pollution which may
reasonably be anticipated to endanger public health or welfare. The EPA
disagreed with those comments. The EPA took the position that CAA
section 111(b)(1)(A), 111(b)(1)(B), and 111(a)(1), read together,
authorize the Agency to regulate an air pollutant from a listed source
category, subject to the standards of rationality under CAA section
307(d)(9)(A), and do not require the EPA to make an additional
determination, as a predicate for regulation, that the air pollutant
contributes significantly to dangerous air pollution.\73\
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\73\ Promulgation of NSPS under CAA section 111(b)(1)(B) is
subject to the requirements of CAA section 307(d), under CAA section
307(d)(1)(C). See 42 U.S.C. 7607(d)(1)(C).
---------------------------------------------------------------------------

Notwithstanding the EPA's position in the 2015 NSPS that CAA
section 111 does not require a pollutant-specific significant
contribution finding for GHG emissions, the Agency purported to make,
in the alternative, separate endangerment and significant contribution
findings pursuant to CAA section 111(b)(1)(A) for GHG emissions from
fossil fuel-fired EGUs. In doing so, the EPA asserted that the
information and conclusions in the preamble to the 2015 NSPS provided a
sufficient basis for such findings.\74\ That is, the EPA took the
position that regardless whether the Agency needed only a rational
basis to regulate CO<INF>2</INF> emissions from fossil fuel-fired EGUs
or was instead required to make new endangerment and significant
contribution findings, we had made the requisite determinations based
on the 2009 Endangerment Finding and the additional information
presented in the preamble to the 2015 NSPS.
---------------------------------------------------------------------------

\74\ 80 FR 64510, 64530-31 (October 23, 2015).
---------------------------------------------------------------------------

The 2015 NSPS promulgated standards of performance to limit
emissions of GHGs, manifested as CO<INF>2</INF>, from newly
constructed, modified, and reconstructed fossil fuel-fired electric
utility steam generating units (i.e., utility boilers and integrated
gasification combined cycle (IGCC) combustion turbines) and newly
constructed and reconstructed stationary combustion turbines. These
final standards are codified in 40 CFR part 60, subpart TTTT. In
promulgating the 2015 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 2015 NSPS also included standards of performance for steam
generating units that undergo a ``reconstruction'' as well as units
that implement ``large modifications'' (i.e., modifications resulting
in an increase in hourly CO<INF>2</INF> emissions of more than 10
percent). The 2015 NSPS did not establish standards of performance for
steam generating units that undertake ``small modifications'' (i.e.,
modifications resulting in an increase in hourly CO<INF>2</INF>
emissions of less than or equal to 10 percent), due to the limited
information available to inform the analysis of a BSER and
corresponding standard of performance.
The 2015 NSPS also finalized standards of performance for newly
constructed and reconstructed natural gas-fired stationary combustion
turbines that operate at base load and non-base load, based on
efficient natural gas

[[Page 58963]]

combined cycle (NGCC) technology or the use of lower-emitting fuels
(referred to as clean fuels in the 2015 NSPS) as the BSER. The EPA did
not promulgate final standards of performance for modified stationary
combustion turbines under CAA section 111(d) due to lack of
information.
Petitioners challenged the 2015 NSPS in the D.C. Circuit, and the
case has been held in abeyance over the years since in light of the
EPA's subsequent rulemakings.
In the 2015 CPP--promulgated at the same time as the 2015 NSPS--the
EPA interpreted CAA section 111(d) to require the Agency to regulate
GHG emissions from existing sources in the newly combined source
category because we had promulgated the 2015 NSPS for GHG emissions
from new sources in that source category under CAA section 111(b).\75\
The Agency noted that GHGs, and CO<INF>2</INF> in particular, are not
separately regulated under the NAAQS program under CAA sections 107-110
or the NESHAP program under CAA section 112. The EPA determined that
the BSER for existing fossil fuel-fired EGUs consisted primarily of
generation shifting measures, as described in section II.C of this
preamble.\76\ The Supreme Court stayed the 2015 CPP pending review in
February 2016,\77\ and the D.C. Circuit held the litigation in abeyance
and ultimately dismissed the challenges to the 2015 CPP in light of
subsequent developments.\78\
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\75\ 80 FR 64662, 64702 (October 23, 2015).
\76\ Id. at 64728-29.
\77\ West Virginia v. EPA, 577 U.S. 1126 (2016).
\78\ Am. Lung Ass'n, 985 F.3d at 937.
---------------------------------------------------------------------------

In 2018, following a change in administration, the EPA proposed to
revise the NSPS for new, modified, and reconstructed fossil fuel-fired
steam generating units and IGCC units (2018 NSPS Proposal).\79\ The EPA
proposed to revise the NSPS for newly constructed units based on a
revised BSER of a highly efficient EGU without partial CCS. The EPA
also proposed to revise the NSPS for modified and reconstructed units.
The EPA never finalized the 2018 NSPS Proposal, and the Agency
rescinded the proposal as part of the 2024 CPS.
---------------------------------------------------------------------------

\79\ 83 FR 65424 (December 20, 2018).
---------------------------------------------------------------------------

In 2019, the EPA repealed the 2015 CPP and replaced that rulemaking
with the Affordable Clean Energy (ACE) Rule.\80\ In the ACE Rule, the
Agency determined that the statutory ``text and reasonable inferences
from it'' indicate that the best ``system'' of emission reduction as
defined in CAA section 111(a)(1) ``is limited to measures that can be
applied to and at the level of the individual source,'' meaning the
BSER must be control measures for reducing emissions at individual
sources.\81\ The Agency concluded that generation shifting is not such
a control measure.\82\ In addition, the EPA further concluded that the
2015 CPP was a ``major rule'' subject to the major questions doctrine
and therefore must be supported by ``a clear statement from Congress.''
Because the statutory phrase ``best system of emission reduction'' does
not clearly speak to generation shifting, the Agency reasoned that CAA
section 111 should not be read to encompass generation-shifting
measures.\83\ To replace the 2015 CPP, the EPA promulgated as part of
the ACE Rule a new set of emission guidelines for existing coal-fired
steam-generating EGUs.\84\ In these new emission guidelines, the EPA
determined the BSER for existing coal-fired EGUs to be heat rate
improvements alone. Specifically, the EPA listed various technologies
that could improve heat rate and identified the ``degree of emission
limitation achievable'' by providing ranges of expected emission
reductions associated with each of the technologies.\85\ The EPA also
explained that we were not determining CCS as the BSER in part because
of unreasonable expense and was not determining natural gas co-firing
as the BSER because co-firing was an inefficient use of natural
gas.\86\
---------------------------------------------------------------------------

\80\ 84 FR 32520 (July 8, 2019).
\81\ See id. at 32523-24.
\82\ See id. at 32546.
\83\ See id. at 32529.
\84\ See id. at 32532.
\85\ Id. at 32535-38.
\86\ Id. at 32545.
---------------------------------------------------------------------------

In 2021, a divided panel of the D.C. Circuit vacated the ACE Rule,
including the repeal of the 2015 CPP.\87\ The panel majority held,
among other things, that CAA section 111 did not limit the EPA, in
determining the BSER, to measures applied at and to an individual
source and that CAA section 111 authorized the Agency to determine
generation shifting is the BSER. The panel majority also rejected in
the argument that generation-shifting implicated ``the so-called `major
questions' doctrine'' based on its interpretation of the Supreme
Court's decisions in Massachusetts and AEP.\88\ As a result, the D.C.
Circuit vacated both the repeal of the 2015 CPP and the ACE Rule.\89\
The court did not address most other challenges to the ACE Rule,
including the arguments concerning the heat rate improvement BSER.
---------------------------------------------------------------------------

\87\ Am. Lung Ass'n, 985 F.3d at 914.
\88\ Id. at 959.
\89\ Id. at 995. In a partial dissent, Judge Walker argued that
the 2015 CPP (and aspects retained in the 2019 ACE Rule) violated
the major questions doctrine because CAA section 111 does not
include a clear statement of authority to regulate GHG emissions
from power plants. Id. at 995-1003.
---------------------------------------------------------------------------

Several petitioners argued that the ACE Rule was invalid on the
grounds that the EPA had predicated regulation of GHG emissions from
existing EGUs on the new source GHG emissions standards in the 2015
NSPS. In addition, petitioners argued that those standards were flawed
because CAA section 111 required them to be predicated on a pollutant-
specific significant contribution finding with identified standards or
criteria for determining significance. The D.C. Circuit held that it
did not need to decide whether CAA section 111 requires a pollutant-
specific significant contribution finding for GHG emissions from EGUs
as a predicate for CAA section 111 regulation because the EPA had made
such a finding in the alternative. The court rejected the petitioners'
argument that the significant contribution finding was flawed due to
lack of identified criteria for significance and explained that the
magnitude of GHG emissions from EGUs supported the significance finding
without identified criteria for significance.\90\
---------------------------------------------------------------------------

\90\ Id. at 974-77.
---------------------------------------------------------------------------

In 2022, the U.S. Supreme Court in West Virginia reversed the D.C.
Circuit's decision to vacate the ACE Rule's embedded repeal of the 2015
CPP.\91\ As noted in section II.C of this preamble, the Supreme Court
concluded that the 2015 CPP's BSER of ``generation shifting''
implicated the major questions doctrine and exceeded the EPA's
statutory authority because CAA section 111 does not clearly authorize
the Agency to regulate GHG emissions in a manner that forces a
nationwide transition away from using coal to generate electricity.\92\
---------------------------------------------------------------------------

\91\ West Virginia, 597 U.S. 697.
\92\ Id. at 734-35.
---------------------------------------------------------------------------

Following the U.S. Supreme Court's decision in West Virginia, the
EPA informed the D.C. Circuit that the Agency intended to replace the
ACE Rule.\93\ On October 27, 2022, the D.C. Circuit took the necessary
steps to, among other things, respond to the Supreme Court's decision
by ensuring that the 2015 CPP remained repealed and stay further
proceedings with respect to the challenges to the ACE Rule given the
EPA's plans to replace that rule.\94\
---------------------------------------------------------------------------

\93\ Am. Lung Ass'n v. EPA, D.C. Cir. No. 19-1140, Motion to
Govern, Doc. #196782 (October 3, 2022).
\94\ Am. Lung Ass'n v. EPA, D.C. Cir. No. 19-1140, Order, Doc.
#1970895 (October 27, 2022).

---------------------------------------------------------------------------

[[Page 58964]]

B. Carbon Pollution Standards

On May 9, 2024, the EPA promulgated the CPS, which consisted of
several separate actions.\95\ The first action was the repeal of the
ACE Rule. The EPA explained, among other things, that the suite of heat
rate improvements that was identified in the ACE Rule as the BSER is
not an appropriate BSER for existing coal-fired EGUs.\96\
---------------------------------------------------------------------------

\95\ 89 FR 39798 (May 9, 2024).
\96\ In the CPS, the EPA also withdrew the separate proposed
revisions to the New Source Review (NSR) regulations that were
included the ACE Rule proposal. See 83 FR 44746, 44773-83 (August
31, 2018).
---------------------------------------------------------------------------

In addition, the 2024 CPS included emission guidelines for GHG
emissions from existing fossil fuel-fired steam generating units, which
include the separate subcategories of coal-fired units, oil-fired
units, and gas-fired units.\97\ For long-term coal-fired units, the EPA
finalized 90 percent CCS as the BSER, with a presumptive standard of an
88.4 percent reduction in annual emission rate and a compliance
deadline of January 1, 2032. The EPA asserted that 90 percent CCS is an
adequately demonstrated technology that achieves significant emissions
reduction and that costs are reasonable, considering the supposedly
declining costs of the technology and the Internal Revenue Code (IRC)
section 45Q tax credit available for a certain number of years to
generating sources that use CCS technology. In recognition of the
significant capital expenditures involved in deploying CCS and
previously announced retirement dates for several coal-fired steam
generating units, the EPA finalized a separate subcategory for existing
coal-fired units that demonstrate that they plan to permanently cease
operation before January 1, 2039. For this subcategory, the BSER is co-
firing with natural gas at a level of 40 percent of the unit's annual
heat input, the presumptive standard is a 16 percent reduction in
annual emission rate, and the compliance deadline is January 1, 2030.
In addition, the EPA exempted existing coal-fired units that
demonstrate that they plan to permanently cease operation prior to
January 1, 2032. The EPA determined that these controls were cost-
effective primarily by reference to two metrics used in prior
rulemakings. The first metric determines the annualized cost in dollars
for each ton, or other quantity, of the regulated air pollutant removed
through the system of emission reduction. The second metric, which the
EPA particularly relied on in rules for the electric power sector,
determines the annualized cost of controls relative to the electricity
generated by the EGU in dollars per megawatt-hour ($/MWh) of
generation.\98\
---------------------------------------------------------------------------

\97\ Although the EPA also proposed emission guidelines for GHG
emissions from existing fossil fuel-fired combustion turbines in the
proposed CPS, the Agency did not finalize those emission guidelines.
\98\ 89 FR 39798, 39882 (May 9, 2024).
---------------------------------------------------------------------------

For existing natural gas- and oil-fired steam generating units, the
EPA further subcategorized them into base load (units with annual
capacity factors greater than or equal to 45 percent), intermediate
load (units with annual capacity factors greater than or equal to eight
percent and less than 45 percent), and low load (units with annual
capacity factors less than eight percent) subcategories. The EPA
finalized routine methods of operation and maintenance as the BSER for
base load and intermediate load units, with presumptive standards for
base load units of 1,400 pounds (lb) CO<INF>2</INF>/MWh-gross, and for
intermediate load units of 1,600 lb CO<INF>2</INF>/MWh-gross.\99\ For
low load units, the EPA finalized a uniform fuels BSER and a
presumptive input-based standard of 170 lb CO<INF>2</INF>/MMBtu for
oil-fired sources and a presumptive standard of 130 lb CO<INF>2</INF>/
MMBtu for natural gas-fired sources.
---------------------------------------------------------------------------

\99\ ``Gross'' refers to the electricity generated by the EGU,
as opposed to ``net,'' which is equivalent to the electricity
delivered to the grid and accounts for the loss due to the
electricity used by auxiliary equipment at the facility.
---------------------------------------------------------------------------

The 2024 CPS also included standards of performance for new and
reconstructed combustion turbines organized into three subcategories:
base load, intermediate load, and low load. For base load turbines, the
standard consisted of two components in two phases. The first component
is based on a BSER of highly efficient generation (which was determined
based on the emission rates achieved by the best performing units), and
the EPA required compliance with this first component upon the
effective date of the 2024 CPS. The second component is based on a BSER
of 90 percent CCS, and the EPA required compliance with this second
component on January 1, 2032. For intermediate load turbines, the EPA
determined that highly efficient simple-cycle generation is the BSER.
For low load combustion turbines, the EPA determined that the use of
lower-emitting fuels is the BSER.
In addition, the EPA revised the standards of performance for coal-
fired steam generating units that undertake a large modification (i.e.,
a modification that increases the hourly emission rate of the source by
more than 10 percent) to be based on the BSER of 90 percent CCS.
Finally, the EPA withdrew the 2018 NSPS Proposal for GHG emissions from
coal-fired EGUs.\100\
---------------------------------------------------------------------------

\100\ 83 FR 65424 (December 20, 2018).
---------------------------------------------------------------------------

Following promulgation of the 2024 CPS, many States and industry
groups filed petitions for review in the D.C. Circuit, and many
subsequently filed motions to stay the rule. The D.C. Circuit denied
the stay motions on July 19, 2024,\101\ and the Supreme Court denied
these motions on October 16, 2024.\102\ Justice Thomas would have
granted a stay, and Justice Kavanaugh, joined by Justice Gorsuch, wrote
that ``the applicants have shown a strong likelihood of success on the
merits as to at least some of their challenges to the [EPA's] rule.''
\103\ The parties briefed the merits, and the D.C. Circuit held oral
argument on December 6, 2024. Following a change in administration, the
D.C. Circuit agreed to hold the case in abeyance pending further
actions by the Agency.
---------------------------------------------------------------------------

\101\ West Virginia v. EPA, D.C. Cir. No. 24-1120, Order, Doc.
#2065493 (July 19, 2024).
\102\ West Virginia v. EPA, 145 S. Ct. 2 (2024).
\103\ Id.
---------------------------------------------------------------------------

C. Changes in Trends in Fossil Fuel-Fired EGUs

In the 2024 CPS, the historical data that supported the analysis
that the EPA conducted and relied on to assess the rule's projected
impacts showed only incremental increases in electricity demand: a 13
percent increase between 2000 and 2022, with demand remaining
relatively flat from 2007 to 2022. At the same time, the share of coal-
fired electricity decreased in both relative and absolute terms,
declining 58 percent and going from delivering 52 percent of total net
generation in 2000 to 19 percent in 2022. Natural gas-fired net
generation increased by 181 percent over this period, delivering 39
percent of net generation in 2022. The combination of wind and solar
net generation grew 172 percent over this period, delivering 15 percent
of total net generation in 2022. Natural gas surpassed the total net
generation from coal on an absolute basis in 2016, and renewables
surpassed the total net generation from coal on an absolute basis in
2022.\104\ The information that the EPA analyzed for purposes of the
2024 CPS indicated that the sector trend of moving away from coal-fired
generation was likely to continue, the

[[Page 58965]]

share of electricity generation from natural gas-fired sources would
likely decline, and the share of generation from non-emitting
technologies would likely continue to increase. In the 2024 CPS, the
EPA anticipated that the recent trend of retirements of coal-fired
capacity (at an average annual rate of 10 gigawatt (GW) from 2015 to
2023) would continue due to the economics of coal-fired generation. At
the time of the 2024 CPS final rule, more than half of the coal-fired
steam generating units in operation had announced that they would
retire or convert to natural gas by 2039.\105\
---------------------------------------------------------------------------

\104\ Power Sector Trends Technical Support Document for the New
Source Performance Standards for Greenhouse Gas Emissions from New,
Modified, and Reconstructed Fossil Fuel-Fired Electric Generating
Units; Emission Guidelines for Greenhouse Gas Emissions from
Existing Fossil Fuel-Fired Electric Generating Units; and Repeal of
the Affordable Clean Energy Rule at 5-6, Document ID No. EPA-HQ-OAR-
2023-0072-8920.
\105\ 89 FR 39798, 39816-18 (May 9, 2024).
---------------------------------------------------------------------------

In contrast, updated information and analysis of power sector
trends indicates a significantly different landscape moving forward. As
noted in the June 2025 NPRM, the EPA believes that coal-fired steam
generating unit capacity and generation will continue to comprise a
substantial portion of the nation's electricity supply due to
increasing electricity demand.\106\ Several key factors play major
roles in reshaping projections of electricity markets over the coming
decades. Demand growth across the U.S. is significantly higher than
prior estimates. According to the 2024 North American Electric
Reliability Corporation (NERC) Long Term Reliability Assessment, peak
demand remained static nationwide over the ten-year period from 2013
through 2022.\107\ In 2022, NERC projected a 0.65 percent compound
annual growth rate for summer peak demand based on the ten-year period
of 2022 through 2031.\108\ In contrast, in late 2024, NERC projected a
1.67 percent compound annual growth rate for summer peak demand based
on the ten-year period of 2025 through 2034.\109\ Increasing amounts of
large commercial and industrial loads, particularly those related to
data center demand for artificial intelligence (AI) applications, are
primarily driving this nearly 2.6-fold increase in projected growth
rates. Sub-nationally, these impacts are even more striking. The
Electric Reliability Council of Texas' (ERCOT) 2025 long-term load
forecast projects summer peak demand rising at an 8.9 percent annual
growth rate based on the six-year period of 2025 to 2031.\110\ The 2025
long-term load forecast for PJM, a regional transmission organization
serving large parts of the eastern US, projects a 3.1 percent annual
growth rate in summer peak demand based on the ten-year period of 2025
to 2035.\111\ NERC concludes that critical reliability challenges face
the sector when considering the need to meet this higher level of
demand, manage ongoing thermal retirements, and develop additional
transmission and support resources.\112\ A recent Department of Energy
(DOE) report, which examines reliability implications of ongoing
thermal retirements in the face of projected increases in electricity
demand, echoes these findings and further states that the risk of power
outages may increase by a hundred fold in some instances if firm
resources continue to retire in the face of projected load growth.\113\
---------------------------------------------------------------------------

\106\ See 90 FR 25752, 25772, 25774 (June 17, 2025).
\107\ NERC 2023 Long-Term Reliability Assessment (December
2024). Available at: <a href="https://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/NERC_Long%20Term%20Reliability%20Assessment_2024.pdf">https://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/NERC_Long%20Term%20Reliability%20Assessment_2024.pdf</a>.
\108\ NERC 2021 Long-Term Reliability Assessment (December
2022). Available at: <a href="https://www.nerc.com/our-work/assessments/past-reliability-assessments">https://www.nerc.com/our-work/assessments/past-reliability-assessments</a>.
\109\ NERC 2023 Long-Term Reliability Assessment (December
2024). Available at: <a href="https://www.nerc.com/our-work/assessments/past-reliability-assessments">https://www.nerc.com/our-work/assessments/past-reliability-assessments</a>.
\110\ ERCOT. 2025 System Planning Long-term Hourly Peak Demand
and Energy Forecast. Available at: <a href="https://www.ercot.com/files/docs/2025/04/08/2025_LTLF_Report.docx">https://www.ercot.com/files/docs/2025/04/08/2025_LTLF_Report.docx</a>.
\111\ PJM. 2025 Long-Term Load Forecast Report. Available at:
<a href="https://www.pjm.com/-/media/DotCom/library/reports-notices/load-forecast/2025-load-report.pdf">https://www.pjm.com/-/media/DotCom/library/reports-notices/load-forecast/2025-load-report.pdf</a>.
\112\ NERC 2023 Long-Term Reliability Assessment (December
2024). Available at: <a href="https://www.nerc.com/our-work/assessments/past-reliability-assessments">https://www.nerc.com/our-work/assessments/past-reliability-assessments</a>.
\113\ U.S. Department of Energy, Resource Adequacy Report
Evaluating the Reliability and Security of the United States
Electric Grid (2025). Available at: <a href="https://www.energy.gov/sites/default/files/2025-07/DOE%20Final%20EO%20Report%20%28FINAL%20JULY%207%29.pdf">https://www.energy.gov/sites/default/files/2025-07/DOE%20Final%20EO%20Report%20%28FINAL%20JULY%207%29.pdf</a>.
---------------------------------------------------------------------------

The passage of the One Big Beautiful Bill Act of 2025 (OBBBA) will
also have important impacts on the power sector. The phaseout of tax
subsidies to wind and solar resources will likely reduce incremental
builds of these technologies, particularly after 2028. This, in turn,
will further increase the need for retaining existing thermal resources
(including coal-fired steam generating units) and building new thermal
(including new combustion turbines) resources to help meet increasing
electricity demand. Considering these changes, the EPA expects the
OBBBA to produce a net effect of reducing factors that boosted the
economic competitiveness of wind and solar resources and improving the
economic competitiveness of thermal generation (including coal and
natural gas-fired generation).
Moreover, higher levels of electricity demand result in greater
demand for around-the-clock power, which results in a higher
utilization of coal- and gas-fired resources in the EPA's current
analysis than in the EPA's 2024 analysis underpinning the 2024
CPS.\114\ The trends the EPA has incorporated into the updated analysis
result in projections that show total electricity generation will
increase by approximately 15 percent by 2030 and 25 percent by
2035,\115\ significantly higher than projections in the 2024 analysis
for the 2024 CPS.\116\
---------------------------------------------------------------------------

\114\ See memorandum entitled Trends Relating to Fossil Fuel-
fired Electric Generating Units in the docket for this rulemaking
(Docket ID No. EPA-HQ-OAR-2025-0124).
\115\ Id.
\116\ U.S. EPA. Regulatory Impact Analysis for the New Source
Performance Standards for Greenhouse Gas Emissions from New,
Modified, and Reconstructed Fossil Fuel-Fired Electric Generating
Units; Emission Guidelines for Greenhouse Gas Emissions from
Existing Fossil Fuel-Fired Electric Generating Units; and Repeal of
the Affordable Clean Energy Rule (May 2024). Document ID No. EPA-HQ-
OAR-2023-0072-8913.
---------------------------------------------------------------------------

This recent change in demand for around-the-clock power already is
effecting changes in the current market, as shown by a number of coal-
fired steam generating units that are delaying or canceling their
scheduled retirements due to increased electricity demand.\117\ Using
the latest available data from the Energy Information Administration
(EIA), in 2024, the U.S. power sector had approximately 174 GW of coal-
fired EGUs that collectively consumed approximately 7.0 quadrillion
British thermal units (Btus) of energy. According to data reported by
the owners and operators of coal-fired capacity, the EIA expects 146 GW
of this capacity to remain in service through 2032. In addition, the
EIA now expects 24.5 GW of combined cycle additions and 11.5 GW of
combustion turbine additions over the next five years,\118\
demonstrating a sharp increase from the August 2023 EIA data underlying
the analysis of the 2024 CPS, which cited roughly 9.6 GW of combined
cycle and 1.9 GW of combustion turbine additions planned for
construction between 2025 and 2030.\119\
---------------------------------------------------------------------------

\117\ Power. U.S. Coal Plants Get Reprieve as Market and
Policies Change. Available at: <a href="https://www.powermag.com/u-s-coal-plants-get-reprieve-as-market-and-policies-change">https://www.powermag.com/u-s-coal-plants-get-reprieve-as-market-and-policies-change</a>.
\118\ U.S. Energy Information Administration. EIA Power Monthly
(October 2025). Available at: <a href="https://www.eia.gov/electricity/data/eia860m/xls/october_generator2025.xlsx">https://www.eia.gov/electricity/data/eia860m/xls/october_generator2025.xlsx</a>.
\119\ U.S. Energy Information Administration. EIA Power Monthly
(August 2023). Available at: <a href="https://www.eia.gov/electricity/data/eia860m/xls/august_generator2023.xlsx">https://www.eia.gov/electricity/data/eia860m/xls/august_generator2023.xlsx</a>.
---------------------------------------------------------------------------

The EPA's updated projections reflect these changes.\120\ As a
specific example, at the end of 2024, 174 GW of coal-fired EGUs were
active in the power sector

[[Page 58966]]

nationwide.\121\ In the 2024 CPS, the EPA projected that, in the
baseline absent requirements, approximately 40 GW of existing coal
capacity would still be active by 2040.\122\ However, the EPA has
revisited the 2024 baseline in light of the information above. The EPA
now projects that, absent the requirements of the 2024 CPS,
approximately 100 GW of coal capacity would be active in 2040,\123\
more than twice the capacity EPA previously projected. Similarly, in
the 2024 CPS, the EPA projected approximately 26 GW of incremental NGCC
capacity additions by 2035.\124\ The EPA now projects, absent the
requirements of the 2024 CPS, approximately 155 GW of new NGCC capacity
by 2035. Based on the EPA's updated projections, informed by the recent
and consequential changes in the electricity market, a much larger
number of EGUs would be subject to the requirements of the 2024 CPS
than previously estimated for the purposes of that rulemaking.
---------------------------------------------------------------------------

\120\ See memorandum entitled Trends Relating to Fossil Fuel-
fired Electric Generating Units in the docket for this rulemaking
(Docket ID No. EPA-HQ-OAR-2025-0124).
\121\ U.S. Energy Information Administration. EIA Power Monthly
(December 2024). Available at: <a href="https://www.eia.gov/electricity/monthly/archive/december2024.pdf">https://www.eia.gov/electricity/monthly/archive/december2024.pdf</a>.
\122\ U.S. EPA. RIA for 2024 CPS. Document ID No. EPA-HQ-OAR-
2023-0072-8913. Table 3-14.
\123\ See memorandum entitled Trends Relating to Fossil Fuel-
fired Electric Generating Units in the docket for this rulemaking
(Docket ID No. EPA-HQ-OAR-2025-0124).
\124\ U.S. EPA. RIA for 2024 CPS. Document ID No. EPA-HQ-OAR-
2023-0072-8913. Table 3-14.
---------------------------------------------------------------------------

D. June 2025 NPRM

In June 2025, the EPA issued a NPRM that included two proposals: a
primary proposal and an alternative proposal. The primary proposal
would have repealed all GHG regulations for fossil fuel-fired EGUs
under CAA section 111 on the basis that the source category does not
significantly contribute to dangerous GHG air pollution. Specifically,
the EPA proposed to conclude that CAA section 111 is best read to
require, or at least authorize the EPA to require, the Administrator's
determination that an air pollutant emitted by a source category
causes, or contributes significantly to, air pollution which may
reasonably be anticipated to endanger public health or welfare as a
predicate to establishing emission standards for that pollutant. The
EPA further proposed to determine, in a change from the 2015 NSPS and
the 2024 CPS, that GHG emissions from fossil fuel-fired power plants do
not contribute significantly to dangerous air pollution as required for
the promulgation of new and existing source standards. The EPA proposed
to find that the contribution of this source category is not
significant because GHG emissions from those sources are a small and
decreasing part of global emissions, cost-effective control measures
are not reasonably available, and this Administration's priority is to
protect the environment, public health, and welfare through energy
dominance and independence secured through the use of fossil fuels to
generate power. On the basis of the proposed finding that GHG emissions
from fossil fuel-fired power plants do not contribute significantly to
dangerous air pollution, the EPA proposed to repeal all GHG emissions
standards for the power sector under CAA section 111, specifically the
2015 NSPS (codified in 40 CFR part 60, subpart TTTT) and the 2024 CPS
(codified in 40 CFR part 60, subparts TTTTa and UUUUb).
In the alternative, based largely on a review of the BSER
determinations in the 2024 CPS, the EPA proposed to repeal the emission
guidelines for existing steam generating units in 40 CFR part 60,
subpart UUUUb, the CCS-based requirements for coal-fired steam
generating units undergoing a large modification in 40 CFR part 60,
subpart TTTTa, and the CCS-based phase 2 requirements for new base load
combustion turbines in 40 CFR part 60, subpart TTTTa. The EPA also
solicited comment, in general, on the other standards (e.g., phase 1
standards for new combustion turbines).

IV. Repeal of Sections of the Carbon Pollution Standards

The EPA is finalizing the repeal of the emission guidelines in the
2024 CPS for existing fossil fuel-fired steam generating units in 40
CFR part 60, subpart UUUUb. The EPA also is finalizing the repeal of
the requirements for coal-fired steam generating units undertaking a
large modification in 40 CFR part 60, subpart TTTTa and the phase 2
CCS-based requirements for new base load combustion turbine EGUs in 40
CFR part 60, subpart TTTTa. As discussed in more detail in this section
of the preamble, the EPA is finalizing those repeals on the bases that
(1) 90 percent CCS is not the BSER for existing long-term coal-fired
steam generating units and the degree of emission limitation in the
2024 CPS is not achievable, (2) 40 percent natural gas co-firing is not
the BSER for medium-term coal-fired steam generating units and the
degree of emission limitation is not achievable, (3) it would be
imprudent to require States to submit plans for oil- and natural gas-
fired steam generating units, and (4) 90 percent CCS is not the BSER
for new base load combustion turbines and the associated standards of
performance are not achievable.
The EPA acknowledges the uncertainty created by the 2024 CPS,
particularly given the consequential changes to projected trends in
electricity demand and generation.\125\ To provide near-term relief to
affected sources from the regulatory burdens of the 2024 CPS that are
the cause of this uncertainty, the EPA is finalizing, based largely on
the unreasonableness of the BSER determinations in the 2024 CPS, the
repeal of the emission guidelines for existing steam generating units,
the CCS-based requirements for coal-fired steam generating units
undergoing a large modification, and the CCS-based phase 2 requirements
for new base load combustion turbines.
---------------------------------------------------------------------------

\125\ See, e.g., Comments of the Power Generators Air Coalition
on EPA's Proposed Repeal of Greenhouse Gas Emissions Standards for
Fossil-Fuel Fired Electric Generating Units at 6, Document ID No.
EPA-HQ-OAR-2025-0125-0610; Comments from the Edison Electric
Institutes on the Proposed Rule Repeal of Greenhouse Gas Emissions
Standards for Fossil Fuel-Fired Electric Generating Units at 6-12,
Document ID No. EPA-HQ-OAR-2025-0125-0897.
---------------------------------------------------------------------------

Specifically, the EPA is finalizing the determination that 90
percent CCS is not the BSER for existing long-term coal-fired steam
generating units because it has not been adequately demonstrated and
because the costs are not reasonable. Furthermore, because it is
unlikely the infrastructure for CCS can be deployed by the January 1,
2032 compliance date, the EPA is finalizing the determination that the
degree of emission limitation in the 2024 CPS for long-term coal-fired
steam generating units is not achievable. The EPA is also finalizing
the determination that 40 percent natural gas co-firing is not the BSER
for existing medium-term coal-fired steam generating units for several
reasons. First, 40 percent natural gas co-firing cannot be BSER because
40 percent natural gas co-firing is a type of generation-shifting and
is precluded by the Supreme Court's decision in West Virginia.
Additionally, 40 percent natural gas co-firing cannot be BSER because
consideration of the energy requirements shows that 40 percent natural
gas co-firing has adverse consequences for the energy system. Moreover,
because it is unlikely the infrastructure for 40 percent co-firing can
practicably be deployed by the January 1, 2030 compliance date, the EPA
is finalizing the determination that the degree of emission limitation
in the 2024 CPS for medium-term coal-fired steam generating units is
not achievable. Therefore, the EPA is repealing the BSER
determinations, presumptive standards of performance, and all

[[Page 58967]]

related requirements in the emission guidelines for existing long-term
and medium-term coal-fired steam generating units.
Additionally, the EPA is repealing the requirements for existing
natural gas- and oil-fired steam generating units because it would be
an inefficient use of State resources to develop, submit, and implement
state plans solely for natural gas- and oil-fired steam generating
units, which comprise a relatively small part of the source category
and would contribute few or no emission reductions under the existing
emission guidelines. That is, it would not be reasonable for the EPA to
require States to prepare plans for existing natural gas- and oil-fired
steam generating units given that the Agency is repealing the
requirements for existing coal-fired steam generating units.
The EPA is thus repealing the substantive requirements and, on that
basis, is repealing 40 CFR part 60, subpart UUUUb--the emission
guidelines for existing fossil fuel-fired steam generating units--in
its entirety.
Because the EPA is determining that 90 percent CCS is not the BSER
for existing long-term coal-fired steam generating units, the EPA is
also repealing the CCS-based requirements for coal-fired steam
generating units undertaking a large modification. The EPA is also
determining that 90 percent CCS is not the BSER for new base load
combustion turbine EGUs because it has not been adequately demonstrated
and the costs are not reasonable. Furthermore, because it is unlikely
that the infrastructure necessary for CCS can be deployed by the
January 1, 2032 compliance date, the EPA is determining that the phase
2 standards of performance in the 2024 CPS for new base load combustion
turbines are not achievable. Consequently, the EPA is repealing the
phase 2 CCS-based requirements for new base load combustion turbine
EGUs.
Although the EPA discusses each relevant repeal and the associated
bases below, several observations about the 2024 CPS reinforce the
fundamental issues with that prior action--and the 2015 CPP that
preceded it--and support the Agency's decision to proceed with these
repeals, including the repeal of standards predicated on 90 percent
CCS.
First, the 2024 CPS reflected an overly restrained reading of the
Supreme Court's assessment of the 2015 CPP in West Virginia. The EPA
initially viewed that decision as barring only standards that expressly
require generation shifting.\126\ Upon further consideration, the EPA
now accepts that decision as holding that the Agency may not impose
standards with the objective or result of generation shifting at the
scale the Court found to raise a major question reserved for Congress.
Information reviewed since promulgation of the 2024 CPS demonstrates
that standards predicated on achieving 90 percent CCS cross that
threshold. Regulated sources in the relevant subcategories (i.e., coal
plants) were given the choice between complying with the standards by
2032 or ceasing operations by 2032. Because, for the reasons discussed
throughout this preamble, emission limitation requirements based on 90
percent CCS are not achievable, the 2024 CPS effectively requires coal
plants to shut down by 2032--a form of generation shifting. Under these
circumstances, retaining these aspects of the 2024 CPS would be
improper.
---------------------------------------------------------------------------

\126\ See, e.g., US working on power plant standards for energy
transition: US EPA head, July 29, 2023, available at <a href="https://www.world-energy.org/article/34841.html">https://www.world-energy.org/article/34841.html</a> (``We are working on a
proposed power plant standard in the United States that helps us to
transition from heavily fossil fuel resources to clean resources. .
. .'').
---------------------------------------------------------------------------

Second, the 2024 CPS reflected an overbroad reading of CAA section
111 that did not recognize or account for limits on the EPA's ability
to identify a BSER requiring the deployment of new infrastructure over
a long time horizon. In promulgating the 2024 CPS, the EPA projected--
based on, as discussed below, optimistic assumptions--that complex
carbon capture, transmission, and injection infrastructure that did not
yet exist could be deployed nationwide within seven years, and did not
view the inherent uncertainties and long time horizon as a barrier to
adopting, or reason not to adopt, 90 percent CCS as the BSER. Upon
further consideration, the Agency concludes that the inherent
difficulties in accurately projecting such large-scale deployments
counsel against selecting BSERs predicated on large-scale national
infrastructure buildouts years into the future, particularly given the
statute's eight-year cycle for reviewing the effectiveness of
promulgated standards.
Third, and relatedly, the 2024 CPS reflected an overbroad reading
of CAA section 111 that did not recognize or account for the scale of
the infrastructure required for compliance, including the difference
between systems that sources can apply to meet the standards that apply
to them and systems that require significant investment and performance
by third parties. Owners and operators of power plants subject to 90
percent CCS-based requirements are dependent on third parties to
develop and operate virtually all the components of CCS. Transport and
storage, in particular, differ from the types of equipment the Agency
has historically selected as BSER. All relevant third parties would
need to timely complete their components of the infrastructure across
large geographic areas for the owners and operators to be able to
implement the CCS requirements by the compliance date, and thereafter,
owners and operators must rely on the continued cooperation and
operation of these third parties. Upon further consideration, the EPA
concludes that the scale of the necessary infrastructure, including the
necessary involvement of third parties nationwide, is different in kind
from control measures historically considered under CAA section 111 and
counsels against selecting 90 percent CCS as BSER.
The remainder of this section details the rationale for the repeal
of the emission guidelines for existing fossil fuel-fired steam
generating units, the CCS-based requirements for coal-fired steam
generating units undertaking a large modification, and the 2024 CCS-
based requirements for new combustion turbine EGUs. The EPA carefully
considered the comments received on the June 2025 NPRM in the
development of this final rulemaking and the supporting rationale. The
EPA discusses some of the overarching comments received on the June
2025 NPRM and provides responses in this section of the preamble.\127\
---------------------------------------------------------------------------

\127\ Responses to substantial comments on specific issues are
addressed in the relevant sections of this preamble. Responses to
additional comments are in the RTC, available in the docket for this
rulemaking (Docket ID No. EPA-HQ-OAR-2025-0124).
---------------------------------------------------------------------------

Comments: The EPA received extensive comments on both the primary
and alternative proposals of the June 2025 NPRM. Among the group of
commenters generally in favor of the proposals, some supported
finalizing the primary proposal, some supported finalizing the
alternative proposal, and others supported finalizing both proposals.
Among the commenters in favor of finalizing both proposals, some
recommended finalizing the alternative proposal first, followed by the
primary proposal, while others urged the EPA to finalize both proposals
simultaneously. Other commenters opposed both proposals.
EPA Response: Based on consideration of those comments and other
factors, in this final rule, the EPA is finalizing only the alternative
proposal in the June 2025 NPRM--that is, the proposal to repeal the
emission guidelines for existing steam generating

[[Page 58968]]

units and the CCS-based requirements for new base load combustion
turbine EGUs and coal-fired steam generating units undertaking a large
modification. This final action is based on a record-focused
reevaluation of the BSER determinations for the relevant subcategories.
As previously explained, the EPA is taking this final action to provide
near-term relief from regulatory requirements it now finds are unlawful
or otherwise unreasonable. The EPA is not, in this rulemaking,
finalizing the primary proposal in the June 2025 NPRM to repeal all GHG
regulations for fossil fuel-fired EGUs under CAA section 111 on the
basis that the source category does not significantly contribute to
qualifying air pollution. The EPA is instead issuing a supplemental
proposal soliciting additional public comment on the underlying
question raised in the primary basis of the June 2025 NPRM: Whether the
EPA lacks statutory authority to regulate GHG emissions from fossil
fuel-fired power plants under CAA section 111 under the applicable
statutory standard for such regulation. The primary proposal in the
June 2025 NPRM sought public comment on whether fossil fuel-fired EGUs
``contribute significantly'' to air pollution, and the supplemental
notice seeks public comment on the distinct question whether global
climate change concerns satisfy the threshold requirement in CAA
section 111(b)(1)(A) that the source category emissions contribute
significantly to ``air pollution which may reasonably be anticipated to
endanger public health or welfare.'' We will evaluate both proposed
approaches and rationales in taking final action, as both issues--
contribution and endangerment--were the subject of significant
interpretive and policy changes in the 2009 Endangerment Finding and
the 2015 NSPS (as retained by the 2024 CPS) that extended the Agency's
novel approach to power plant stationary sources. The EPA therefore is
responding in this final rule only to comments on the alternative
proposal that the Agency is finalizing--the proposal to repeal 40 CFR
part 60, subpart UUUUb and certain components of 40 CFR part 60,
subpart TTTTa. The EPA is not responding at this time to comments that
relate solely to the June 2025 primary proposal.
Comments: Some commenters opposed to the proposal to repeal the
emission guidelines and other CCS-related requirements asserted that
such repeal would be unlawful because the EPA must consider
alternatives to the BSER determinations and requirements at issue and/
or immediately promulgate different requirements based on alternative
BSERs. Commenters asserted that the CAA requires the EPA to set
standards of performance under CAA section 111(b) for GHG emissions
from fossil fuel-fired power plants because they are listed as a source
category under CAA section 111 and that the Agency has previously
determined that such emissions contribute significantly to GHG air
pollution that endangers public health and welfare. Additionally, these
commenters asserted that CAA section 111(d) requires the EPA to
promulgate emission guidelines for existing sources that would be
subject to the standards under CAA section 111(b) if the sources were
new sources. Commenters asserted that the repeal of the 2024 CPS's
emission guidelines and standards of performance at issue in this
rulemaking would leave these legal mandates unfilled and that repealing
these requirements without considering and/or promulgating alternative
requirements based on alternative BSERs would be arbitrary and
capricious.
EPA Response: The EPA disagrees with these comments. The EPA
carefully considered alternatives to repeal of the emission guidelines
and standards of performance (e.g., whether to revise the BSER
determinations or compliance schedules for the affected sources and
whether to promulgate different standards immediately) and is
determining that it is not necessary to do so at this time. The EPA
remains concerned that it lacks the requisite statutory authority to
regulate GHG emissions from power plants in the first instance under
the applicable statutory standard for regulation. Indeed, other
commenters urged that the EPA must resolve this predicate question
before promulgating additional or different standards. Accordingly, the
EPA is exercising its discretion to proceed through multiple steps that
will address the totality of the problem before it in an orderly
fashion.
In a concurrently issued supplemental proposal, the EPA is
proposing to find that the Agency lacks the requisite legal basis to
regulate GHG emissions from fossil fuel-fired power plants under CAA
section 111. These proposed bases are in addition to those presented in
the primary proposal in the June 2025 NPRM and will be considered
together with the bases previously presented in taking final action. If
finalized as proposed, this subsequent action would abrogate any legal
requirement and authority to replace the BSER determinations and
associated requirements that the EPA is repealing in this final rule.
Such action would render it inappropriate and unnecessary to promulgate
any alternative BSER determinations, standards of performance, or
compliance schedules. Conversely, if the EPA determines that it has the
requisite statutory authority, the Agency would conduct additional
analyses and propose any necessary and appropriate additional
requirements for the fossil fuel-fired EGU source category at that
time, having confirmed its statutory basis for doing so.
As a general matter, ``[n]othing prohibits federal agencies from
moving in an incremental manner.'' \128\ The EPA notes that CAA section
111 contemplates that the Agency need not immediately promulgate
standards upon listing a source category and that review of regulations
for a previously listed source category occurs on an eight-year cycle.
Moreover, CAA section 111(b)(1)(B) does not require the Agency to
regulate all types of emissions simultaneously, and CAA section 111(d)
does not provide a deadline for promulgating emission guidelines. Even
with respect to source categories for which no regulations exist,
Congress previously provided a prioritization scheme in CAA section
111(f) under which the EPA was required to promulgate such regulations
over the course of a six-year period. The EPA has consistently taken
the position that it need not, in any particular CAA section 111
rulemaking, address all potential issues relevant to the at-issue
source category. This final action does not repeal all requirements
applicable to the fossil-fuel fired EGU source category, and as noted
elsewhere in this preamble, nothing in this final action disturbs
criteria pollutant emission standards applicable to power plants
regulated under pre-2015 listings.
---------------------------------------------------------------------------

\128\ Fox Television Stations, 556 U.S. at 522; see, e.g., Pub.
Safety Spectrum All. v. FCC, No. 24-1363, slip op. 20 (D.C. Cir.
July 21, 2026) (it was reasonable for the FCC to defer making
relevant decisions to a subsequent action).
---------------------------------------------------------------------------

Thus, the EPA need not analyze and promulgate alternative BSERs and
associated requirements to address serious issues identified with
certain existing standards. In this context, this final rule simply
represents a permissible first step in a multi-step process.\129\ As
noted above, the EPA is

[[Page 58969]]

taking this first step to provide near-term relief from 2024 CPS
requirements that it is now determining to be unlawful or otherwise
unreasonable and which, absent further action, would imminently begin
forcing the expenditure of significant resources. Promulgation of
alternative BSERs or compliance schedules at this time would require
completing multiple additional steps, including resolving questions
regarding the Agency's statutory authority and analyzing competing
alternative BSERs and requirements, all of which would delay resolution
of the distinct issues addressed in this rulemaking and defeat the
purpose of resolving these distinct issues before regulated sources are
put to the choice between expending significant resources to comply, or
planning to close, before the current 2032 compliance deadline (or
other upcoming compliance deadlines, as applicable).
---------------------------------------------------------------------------

\129\ See Grand Canyon Air Tour Coal. v. FAA, 154 F.3d 455, 471
(D.C. Cir. 1998) (``ordinarily, agencies have wide latitude to
attack a regulatory problem in phases and . . . a phased attack
often has substantial benefits''); Las Vegas v. Lujan, 891 F.2d 927,
935 (D.C. Cir. 1989) (upholding agency action that was a first step
toward a ``complete solution,'' stating that ``agencies have great
discretion to treat a problem partially''); Nat'l Ass'n of
Broadcasters v. FCC, 740 F.2d 1190, 1210 (D.C. Cir. 1984) (it is
reasonable for an agency to ``defer resolution of issues raised in a
rulemaking even when those issues are `related' to the main ones
being considered''; the inquiry into when agencies may defer
resolution of issues raised in a rulemaking to a subsequent action
is ``a pragmatic one'').
---------------------------------------------------------------------------

The EPA does not believe its repeal of certain 2024 CPS standards
and requirements runs afoul of case law such as Regents of the
University of California and State Farm. These cases stand for the
proposition that when an agency ``rescinds a prior policy its reasoned
analysis must consider the `alternative[s]' that are `within the ambit
of the existing [policy].'' \130\ In concluding that the CAA and
general principles of administrative law do not require the EPA to
analyze and promulgate alternative, replacement BSER determinations or
requirements immediately and as part of this discrete repeal, the
Agency again emphasizes that this action is the first step in what is
intended to be a multi-step rulemaking process. If the second step of
this process is finalized as proposed, the ``existing policy'' will be
mooted based on the lack of legal basis for that policy in the first
instance. The EPA is thus not promulgating new standards for existing
coal-fired steam generating units or for new base load combustion
turbines in this final rule, and, accordingly, need not develop
alternative BSER determinations to support such new and additional
standards.
---------------------------------------------------------------------------

\130\ Regents, 591 U.S. at 30 (quoting State Farm, 463 U.S. at
51).
---------------------------------------------------------------------------

In analyzing this aspect of the problem, the EPA reviewed the
alternatives it considered prior to selecting the BSER and standards
finalized in the 2024 CPS to examine the scope and nature of possible
regulatory alternatives. The Agency believes that its prior
consideration and rejection of other potential BSERs in the 2024 CPS
rulemaking demonstrates that further analyzing additional alternative
BSERs and requirements would be unnecessary under the circumstances
here. In the 2024 CPS, the EPA considered and rejected a range of
potential alternatives to the BSERs ultimately selected. For long-term
coal-fired steam generating units now subject to standards based on 90
percent CCS, the EPA considered partial CCS at lower capture rates,
natural gas co-firing, and heat rate improvements.\131\ The EPA
rejected partial CCS ``because it achieves substantially fewer unit-
level reductions at greater cost, and because CCS at 90 percent is
achievable.'' \132\ The Agency also noted that ``the IRC section 45Q
tax credit may not be available to defray the costs of partial CCS and
the emission reductions would be limited.'' \133\ As explained in
section IV.A.1 of this preamble, the EPA now rejects the conclusion
that 90 percent CCS is adequately demonstrated and achievable and
further finds that the IRC section 45Q tax credit should not be
accounted for when evaluating the reasonableness of the costs of the
BSER. The EPA therefore believes the costs of partial CCS would be
significantly higher than anticipated in the 2024 CPS and therefore
remains an inappropriate alternative. With regard to natural gas co-
firing as an alternative to 90 percent CCS, as discussed in section
IV.A.2 of this preamble, the EPA is determining in this final rule that
this control strategy amounts to impermissible generation shifting,
thereby disqualifying it from being the BSER. And the EPA explained in
the 2024 CPS that it was not finalizing heat rate improvements as the
BSER ``because of the limited reductions and potential rebound
effect.'' \134\ Similarly, for medium-term coal-fired EGUs, the 2024
CPS considered CCS and heat rate improvements as potential BSERs and
rejected each.\135\ Thus, based on the EPA's earlier assessments and
the further analysis conducted for purposes of this final rule,
potential alternatives to 90 percent CCS for long-term coal-fired units
and 40 percent natural gas co-firing for medium-term coal-fired units
are not obvious and suffer from their own shortcomings. As noted above,
fully analyzing and working through these issues is a distinct task
that warrants a distinct process that would be most appropriate to
undertake after, and pending the results of, the Agency's consideration
of the scope of its statutory authority.
---------------------------------------------------------------------------

\131\ 89 FR 39798, 39846 (May 9, 2024).
\132\ Id.
\133\ Id.
\134\ Id.
\135\ Id. at 39895-96.
---------------------------------------------------------------------------

For new base load combustion turbines, the 2024 CPS included
consideration of potential alternative BSERs including lower-emitting
fuels, high efficiency generation, and hydrogen co-firing.\136\ In the
2024 CPS, the EPA explained that lower-emitting fuels are not the BSER
for new base load combustion turbines because they would achieve few
emission reductions.\137\ And the EPA further explained that, ``[i]n
light of public comments and additional analysis, uncertainties
regarding projected costs prevent the EPA from determining that low-GHG
hydrogen is a component of the BSER at this time.'' \138\ This previous
evaluation of potential alternative BSERs in the 2024 CPS corroborates
the EPA's conclusion in this rulemaking that it is not necessary for
the Agency to consider alternatives to repeal of the 90 percent CCS,
phase 2 BSER for new base load combustion turbines.
---------------------------------------------------------------------------

\136\ Id. at 39924.
\137\ Id.
\138\ Id. at 39939.
---------------------------------------------------------------------------

Comments: Some commenters asserted that the EPA's proposed repeal
of the 2024 CPS failed to consider the disbenefits of that proposal,
namely, forgone emissions reductions. One commenter noted that the
standards the Agency was proposing to repeal would reduce
CO<INF>2</INF> emissions by 1.38 billion metric tons over roughly two
decades. The commenter further stated that the standards the EPA was
proposing to repeal would also secure reductions of tens of thousands
of tons of particulate matter, sulfur dioxide, and nitrogen oxide
emissions. Commenters argued that the Agency had failed to consider the
public health benefits of the 2024 CPS and the corresponding
disbenefits of repealing certain requirements of that rule, and that
this purported oversight rendered the proposed repeal inconsistent with
the Administrative Procedure Act and the CAA.
EPA Response: The EPA disagrees with these comments. The Agency
acknowledges that CO<INF>2</INF> emission reductions are a relevant
consideration in making BSER determinations under a regulatory
framework that addresses GHG emissions from the affected sources. The
EPA also recognizes that this action to repeal requirements of the 2024
CPS forgoes the CO<INF>2</INF> emission reductions that were projected
to be

[[Page 58970]]

achieved under the 2024 CPS. However, the EPA emphasizes that the
repeal of the 2024 CPS requirements is based on the Agency's technical
determinations that 90 percent CCS and 40 percent natural gas co-firing
do not satisfy certain threshold legal criteria to be eligible to be
the BSER. For 90 percent natural gas co-firing, the EPA is determining,
among other things, that CO<INF>2</INF> capture at this rate is not
adequately demonstrated; the Agency is also determining that 40 percent
natural gas co-firing is impermissible generation shifting. Because
each of these determinations disqualifies the emissions control
strategy from further consideration, the amount of CO<INF>2</INF>
emission reductions available through implementation of these
strategies cannot compel a different outcome. Further, as discussed in
the relevant subsections of this preamble, many of the selected control
strategies underlying the at-issue 2024 CPS requirements are
infeasible, and the EPA has significantly revised its projections and
analysis in the 2024 CPS with respect to the timeline for
implementation. These issues mean that the emissions reductions
projected in the 2024 CPS were not likely to come to fruition in any
event absent outcomes inconsistent with the CAA (i.e., forced plant
closures because compliance by the applicable deadline is not
possible).
Separately, the EPA is also determining that the cost of 90 percent
CCS is unreasonable and that the energy impacts associated with 40
percent co-firing are unreasonable. The amount of CO<INF>2</INF>
emission reductions is relevant to the balancing of the BSER factors,
which also include cost and nonair quality health and environmental
impacts and energy requirements. As explained in this section of the
preamble, the EPA has considered the available emission reductions
associated with 90 percent CCS and 40 percent natural gas co-firing and
is finding that, on balance, these emission control strategies are
unreasonable. Furthermore, as explained in section IV.3 of this
preamble, the EPA is repealing the requirements for oil and natural
gas-fired steam generating units in part because the BSERs for these
units in the 2024 CPS would not have achieved appreciable
CO<INF>2</INF> emission reductions. The EPA has thus considered the
foregone CO<INF>2</INF> emission reductions and determined that its
action is reasonable notwithstanding.
While the EPA acknowledges that the 2024 CPS would have also
resulted in reductions of co-pollutants including particulate matter,
sulfur dioxide, and nitrogen oxides, reductions of these pollutants in
the 2024 CPS, or foregone emission reductions of these pollutants in
this action, did not factor into the Agency's BSER determinations for
the regulated pollutant--CO<INF>2</INF>--emitted from the regulated
sources. And even if the EPA were to consider these incidental
reductions of co-pollutants, the Agency would determine that the costs
and energy impacts of the controls should be weighted more heavily than
those forgone reductions.
The EPA's consideration of foregone emission reductions together
with costs in relation to projections in the 2024 CPS is consistent
with the Supreme Court's statement in Michigan v. EPA, 576 U.S. 743
(2015), that ``reasonable regulation ordinarily requires paying
attention to the advantages and the disadvantages of agency
decisions.'' \139\ That is, the EPA has considered the reductions that
the 2024 CPS would have achieved in CO<INF>2</INF> emissions, as well
as the reductions in the other pollutants emitted by power plants,
including particulate matter, sulfur dioxide, and nitrogen oxides. The
EPA has also considered the health impacts of reducing emissions of
these pollutants. Those emissions reductions and health impacts are
noted in section V.A of this preamble. However, the EPA believes that
any benefits from them are outweighed by the costs of the 2024 CPS,
including the costs to the industry (and, in many instances, to the
ratepayers who will absorb those costs through higher electricity
bills) of complying with the requirements, as also noted in section V.A
of this preamble, as well as the adverse energy impacts of using
natural gas for co-firing, as noted in section IV.A.2.a of this
preamble. In the EPA's view, this relative weighting is confirmed by
the uncertainty of actually achieving the benefits attributed to the
2024 CPS, in light of the record and legal deficiencies in the 2024
CPS's determination of CCS and co-firing as BSER, as noted in sections
IV.A.1 and IV.A.2 of this preamble. Accordingly, the EPA believes that
today's action to repeal the 2024 CPS is reasonable and consistent with
the Michigan statement cited above concerning reasonable regulation.
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\139\ Michigan, 576 U.S. at 753 (emphasis in original).
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A. Repeal of the Emission Guidelines for Existing Fossil Fuel-Fired
Steam Generating Units

This section details the rationale for the repeal of the emission
guidelines for existing fossil fuel-fired steam generating units.
1. CCS-Based Requirements for Long-Term Existing Coal-Fired Steam
Generating Units
In the 2024 CPS, the EPA determined the BSER for long-term coal-
fired steam generating units to be 90 percent CCS. The EPA premised
that BSER specifically on 90 percent CO<INF>2</INF> capture using an
amine solvent-based system, CO<INF>2</INF> transport through a
pipeline, and geologic sequestration of the CO<INF>2</INF> in a saline
reservoir. In the 2024 CPS, the EPA argued that 90 percent CCS,
including the 90 percent CO<INF>2</INF> capture component, was
adequately demonstrated. The EPA further argued that 90 percent CCS
satisfied the other criteria for BSER, including that costs were
reasonable based on counting the IRC section 45Q as a reduction in the
cost to the affected source of 90 percent CCS. Based on application of
the 90 percent CCS BSER to the affected sources, the EPA established a
degree of emission limitation and argued this was achievable by the
compliance date of January 1, 2032, considering the time necessary to
deploy capture equipment, transport, and sequestration.
The EPA proposed to repeal the requirements for long-term coal-
fired steam generating units based largely on a reassessment of the
record for the 2024 CPS. Specifically, the EPA proposed that 90 percent
CO<INF>2</INF> capture, and therefore 90 percent CCS as a whole, have
not been adequately demonstrated. The EPA further proposed that the
average unit-level costs of 90 percent CCS were unreasonable. In the
June 2025 NPRM, the EPA evaluated the average unit level costs assuming
a lower capacity factor of the host EGU and operation beyond the 12-
year period of availability of the IRC section 45Q tax credit. The
reduced amount of CO<INF>2</INF> that would be captured and eligible
for the IRC section 45Q tax credit resulted in higher costs than in the
2024 CPS. The EPA further proposed that the IRC section 45Q should not
be counted as a reduction in the costs of 90 percent CCS. Finally, the
EPA proposed that the degree of emission limitation in the 2024 CPS is
not achievable because it is unlikely that the infrastructure
(including the capture system, pipelines, and sequestration) for CCS
can be deployed by the January 1, 2032 compliance date.
The EPA has reassessed the record underlying the 2024 CPS. The EPA
is finalizing the determination that CCS with 90 percent capture is not
the BSER for long-term existing coal-fired steam generating units
because 90 percent CO<INF>2</INF> capture and, therefore, 90 percent
CCS have not been adequately demonstrated

[[Page 58971]]

and the costs are unreasonable. Additionally, the capture, pipeline,
and sequestration infrastructure necessary for 90 percent CCS for the
fleet of existing coal-fired steam generating units does not currently
exist and would need to be broadly deployed. It is unlikely the
infrastructure necessary for CCS can be deployed by the January 1, 2032
compliance date, and the EPA is therefore finalizing the determination
that the degree of emission limitation in the 2024 CPS for long-term
coal-fired steam generating units is not achievable. Consequently, for
the reasons explained in the June 2025 NPRM \140\ and discussed below,
the EPA is finalizing the repeal of the requirements in the emission
guidelines pertaining to long-term existing coal-fired steam generating
units.
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\140\ 90 FR 25752, 25769-73 (June 17, 2025).
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a. Adequately Demonstrated
CCS with 90 percent capture involves the capture of 90 percent of
the CO<INF>2</INF> emissions from the EGU, compression and transport of
the captured CO<INF>2</INF> via pipeline, and sequestration in geologic
storage. Due to the relatively low concentration of CO<INF>2</INF> in
the flue gas, an amine solvent-based capture system is better suited
for application to the post-combustion flue gas of fossil fuel-fired
EGUs than other CO<INF>2</INF> removal technologies (e.g., pressure-
swing adsorption). CO<INF>2</INF> removal occurs by reactive absorption
of the CO<INF>2</INF> from the flue gas into the amine solution in an
absorption column. The amine reacts with CO<INF>2</INF> but will also
react with impurities in the flue gas, including sulfur dioxide
(SO<INF>2</INF>). Particulate matter (PM) will also affect the capture
system. Adequate removal of SO<INF>2</INF> and PM prior to the
CO<INF>2</INF> capture system is therefore necessary. After
pretreatment of the flue gas with conventional SO<INF>2</INF> and PM
controls, the flue gas goes through a quencher to cool the flue gas and
remove further impurities before the CO<INF>2</INF> absorption column.
After absorption, the CO<INF>2</INF>-rich amine solution passes to the
solvent regeneration column, while the treated gas passes through a
water and/or acid wash column to limit emission of amines or other
byproducts. In the solvent regeneration column, the solution is heated
(using steam) to release the absorbed CO<INF>2</INF>. The released
CO<INF>2</INF> is then compressed and transported to a sequestration
site. In an integrated CO<INF>2</INF> capture system, steam and
electricity for the capture process are provided by the host-EGU; this
avoids the need to capture additional emissions from any auxiliary
boilers or cogeneration units.
In the 2024 CPS, the CO<INF>2</INF> capture component of the 90
percent CCS BSER was premised on an integrated amine solvent-based
CO<INF>2</INF> capture system with 90 percent removal of CO<INF>2</INF>
from the post-combustion flue gas of the host EGU. The EPA previously
argued that such a system was adequately demonstrated.
The EPA has reevaluated the record and is determining in this final
rulemaking that, critically, 90 percent capture of the CO<INF>2</INF>
from flue gas of an EGU has not been adequately demonstrated. As a
result, 90 percent CCS has not been adequately demonstrated and cannot
be the BSER for long-term coal-fired steam generating units. The EPA is
basing this conclusion primarily on a revised evaluation of the record
in the 2024 CPS, as detailed in this section of the preamble.\141\ The
EPA is additionally considering several developments since the EPA
promulgated the 2024 CPS (e.g., changes in the plans of certain CCS
projects).
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\141\ See Nat'l Ass'n of Home Builders v. EPA, 682 F.3d 1032,
1038 (D.C. Cir. 2012) (``EPA did not rely on new facts, but rather
on a reevaluation of which policy would be better in light of the
facts . . . . Fox makes clear that this kind of reevaluation is well
within an agency's discretion.'' (citing 556 U.S. at 514-15)).
---------------------------------------------------------------------------

In the 2024 CPS, the emission guidelines required States to
establish plans that would require long-term existing coal-fired steam
generating units to achieve an annual standard of performance based on
capturing 90 percent of the unit's total CO<INF>2</INF> emissions.
However, the record for 90 percent capture as adequately demonstrated
did not include an example of a commercial scale coal-fired steam
generating unit that was already capturing 90 percent of its annual
CO<INF>2</INF> emissions. Instead, the EPA attempted to argue that 90
percent capture has been adequately demonstrated based on other
evidence for the technology at that time. Specifically, the EPA relied
primarily on evidence that consisted of the operation of the
CO<INF>2</INF> capture system at Boundary Dam Unit 3, fixes applied at
Boundary Dam Unit 3, and testing on new solvents from different
vendors.\142\ Consequently, the EPA extrapolated from that combination
of primary evidence to determine that 90 percent capture would perform
as anticipated for the affected sources. On that basis, the EPA
concluded that 90 percent capture was adequately demonstrated for
existing coal-fired steam generating units.
---------------------------------------------------------------------------

\142\ The EPA also included other, secondary observations (e.g.,
projects in development) that would be insufficient on their own to
conclude 90 percent capture is adequately demonstrated.
---------------------------------------------------------------------------

The only datapoint for commercial scale post-combustion CCS on a
fossil fuel-fired EGU, with integrated steam and power, is Boundary Dam
Unit 3. However, between 2014 and 2022, the capture system at Boundary
Dam achieved a total capture efficiency of not more than 63 percent
over the course of a calendar year.143 144 This total annual
capture efficiency is substantially below the 90 percent capture level
specified by the BSER. While the EPA had acknowledged the challenges
and underperformance of the capture system at Boundary Dam in the 2024
CPS, the Agency asserted that fixes were available or could be made to
address those issues. However, many of those fixes were already made,
and performance remained below the design capture efficiency.\145\ The
EPA also previously argued that new solvents were available that could
capture CO<INF>2</INF> at higher rates to address these gaps.\146\
However, in the 2024 CPS, the EPA failed to reasonably account for
potential underperformance of capture systems using new solvents, and
the experience at Boundary Dam shows it would be reasonable to
anticipate that such capture systems would similarly underperform.\147\
Furthermore, the EPA also failed to account for any decrease in
operating-availability of capture, even though the annual operating-
availability of the capture system at Boundary Dam has been less than
100 percent.\148\ In combination, a capture system would achieve much
less than 90 percent total capture efficiency. On review, the EPA's

[[Page 58972]]

prior extrapolation fails to support CCS with 90 percent capture as
adequately demonstrated. The EPA's other tangential arguments in the
2024 CPS similarly fail to show that 90 percent capture has been
adequately demonstrated (including projects in development, as
discussed in section IV.A.1.a.iv of this final rule preamble).
Considering these factors, the EPA is finalizing the determination that
CCS with 90 percent capture and, consequently, 90 percent CCS are not
adequately demonstrated for existing coal-fired steam generating units.
The following subsections provide further explanation.
---------------------------------------------------------------------------

\143\ Here, total capture efficiency is equivalent to the mass
of CO<INF>2</INF> captured relative to (i.e., divided by) the mass
of CO<INF>2</INF> that the EGU would otherwise emit (including the
mass of CO<INF>2</INF> produced in the combustion chamber of the EGU
plus the mass of CO<INF>2</INF> produced by any auxiliary equipment
that supports the capture process) over a given period (e.g.,
annual).
\144\ Jacobs, B., et al. Reducing the CO<INF>2</INF> Emission
Intensity of Boundary Dam Unit 3 Through Optimization of Operating
Parameters of the Power Plant and Carbon Capture Facilities.
Proceedings of the 16th International Conference on Greenhouse Gas
Control Technologies (2022). Available at: <a href="https://dx.doi.org/10.2139/ssrn.4286430">https://dx.doi.org/10.2139/ssrn.4286430</a>.
\145\ The most recently reported total capture efficiency when
operating was 83 percent on an instantaneous basis. Accounting for
periods when the capture system is offline, the total annual capture
efficiency would be lower.
\146\ 95 percent total capture on an instantaneous basis, not
accounting for uncertainty in real-world operation or availability.
\147\ As the only commercial scale and long-term application of
CO<INF>2</INF> capture on a fossil fuel-fired EGU, Boundary Dam's
underperformance is a reasonable quantification of potential
underperformance.
\148\ Between 2015-2022, the availability of the capture system
relative to the EGU was, at best, 94 percent.
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i. Extrapolation From Boundary Dam Unit 3
In the 2024 CPS, the EPA based the determination that 90 percent
CO<INF>2</INF> capture was adequately demonstrated on the record for
amine-solvent CO<INF>2</INF> capture.\149\ Thus, the EPA relied heavily
on the operation of carbon capture at the commercial scale 110 megawatt
(MW) coal-fired Boundary Dam Unit 3 (Saskatchewan, Canada) to
demonstrate 90 percent capture. Boundary Dam has operated CCS since
2014. The unit uses Shell's amine-based CANSOLV[supreg] solvent
technology to capture CO<INF>2</INF> from the post-combustion flue gas
of the coal-fired boiler.\150\ Captured CO<INF>2</INF> is then
compressed, transported by pipeline, and used for enhanced oil recovery
(EOR) or stored in a saline aquifer at the Aquistore site.\151\ While
Boundary Dam Unit 3 achieved 89.7 percent capture over a 3-day test
early in its operation, longer-term capture levels have been
lower.\152\ Between 2015 and 2022, Boundary Dam achieved a total
capture efficiency of not more than 63 percent in a calendar year.\153\
This total long term capture efficiency is substantially below the 90
percent capture efficiency of the BSER.
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\149\ 89 FR 39798, 39848 (May 9, 2024).
\150\ Giannaris, S., et al. SaskPower's Boundary Dam Unit 3
Carbon Capture Facility--The Journey to Achieving Reliability.
Proceedings of the 15th International Conference on Greenhouse Gas
Control Technologies (2021). Available at: <a href="http://dx.doi.org/10.2139/ssrn.3820191">http://dx.doi.org/10.2139/ssrn.3820191</a>.
\151\ Aquistore. Available at: <a href="https://ptrc.ca/aquistore">https://ptrc.ca/aquistore</a>.
\152\ SaskPower Annual Report (2015-16). Available at: <a href="https://www.saskpower.com/-/media/saskpower/about-us/reports/past-reports/report-annualreport-2015-16.pdf">https://www.saskpower.com/-/media/saskpower/about-us/reports/past-reports/report-annualreport-2015-16.pdf</a>.
\153\ Jacobs, B., et al. Reducing the CO<INF>2</INF> Emission
Intensity of Boundary Dam Unit 3 Through Optimization of Operating
Parameters of the Power Plant and Carbon Capture Facilities.
Proceedings of the 16th International Conference on Greenhouse Gas
Control Technologies. (2022). Available at: <a href="https://dx.doi.org/10.2139/ssrn.4286430">https://dx.doi.org/10.2139/ssrn.4286430</a>.
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This lower total capture efficiency is due to, among other things,
the capture system at Boundary Dam Unit 3 typically processing less
than all of the flue gas, in part to ``maintain long-term reliable
operation.'' \154\ Prior to 2023, the CO<INF>2</INF> capture system at
Boundary Dam Unit 3, when operating, processed up to approximately 75
percent of the flue gas with 90 percent CO<INF>2</INF> capture from the
processed flue gas.\155\ The EPA argued in the 2024 CPS that such
capture from the majority of the flue gas supported the determination
of 90 percent capture from all of the flue gas as adequately
demonstrated; however, this ignores that the total capture efficiency
was substantially less than the 90 percent design capture efficiency.
---------------------------------------------------------------------------

\154\ SaskPower. ``Docket ID No. EPA-HQ-OAR-2023-0072: SaskPower
Correction of Reference to Boundary Dam Unit 3 Emissions Performance
in Proposed Rule'' (August 4, 2023). Document ID No. EPA-HQ-OAR-
2023-0072-0687.
\155\ Jacobs, B., et al. Reducing the CO<INF>2</INF> Emission
Intensity of Boundary Dam Unit 3 Through Optimization of Operating
Parameters of the Power Plant and Carbon Capture Facilities.
Proceedings of the 16th International Conference on Greenhouse Gas
Control Technologies. (2022). Available at: <a href="https://dx.doi.org/10.2139/ssrn.4286430">https://dx.doi.org/10.2139/ssrn.4286430</a>.
---------------------------------------------------------------------------

Additionally, Boundary Dam Unit 3 has experienced various technical
challenges that have reduced its performance.\156\ These include
fouling of the CO<INF>2</INF> absorber due to PM (fly ash), buildup of
scale on heat exchangers, biological fouling in the wash-water section
of the CO<INF>2</INF> absorber, foaming of the amine solvent in the
CO<INF>2</INF> absorber, and damage to the CO<INF>2</INF> compressor.
Fouling in the CO<INF>2</INF> absorber affects the throughput of the
process by increasing the pressure drop (i.e., difference in pressure
between the bottom and top of the absorber) such that it cannot be
overcome by the draft fans (i.e., more energy is required to move the
same volume of flue gas than the fans are designed to provide).
Boundary Dam Unit 3 has implemented improvements to its particulate
controls (electrostatic precipitator) and added more spray-wash systems
to mitigate fouling due to fly ash. Caustic shocking of the wash-water
section can reduce the buildup of biological material. Buildup of scale
on heat exchangers reduces throughput by increasing pressure drop,
while the layer of scale reduces the rate of heat transfer. To address
this issue, redundant heat exchangers with isolations were installed in
2017 to allow for removal of scale without shutting down the
CO<INF>2</INF> capture system. Finally, damage to the CO<INF>2</INF>
compressor caused by a loose bolt, and issues with a leaking
intercooler in the compressor, forced the CO<INF>2</INF> capture system
to be offline for several months in 2021 and the start of 2022. While
the compressor was repaired, the unit lacks a redundant compressor in
the event of a similar outage. Importantly, despite these attempts to
improve operation, the unit continues to underperform. Furthermore,
outages to address these issues have contributed to a lower total
capture efficiency.
---------------------------------------------------------------------------

\156\ Jacobs, B., et al. Reducing the CO<INF>2</INF> Emission
Intensity of Boundary Dam Unit 3 Through Optimization of Operating
Parameters of the Power Plant and Carbon Capture Facilities.
Proceedings of the 16th International Conference on Greenhouse Gas
Control Technologies. (2022). Available at: <a href="https://dx.doi.org/10.2139/ssrn.4286430">https://dx.doi.org/10.2139/ssrn.4286430</a>.
---------------------------------------------------------------------------

Comments: Some commenters agreed that Boundary Dam Unit 3 does not
support 90 percent capture as adequately demonstrated. Commenters noted
the low total capture efficiency achieved by the unit over time and the
challenges faced by the unit. Other commenters argued Boundary Dam Unit
3 does support 90 percent capture as adequately demonstrated because of
the capture rate from the processed flue gas and the fixes to the unit.
EPA Response: In approximately 2024, SaskPower made additional
improvements at Boundary Dam Unit 3 to increase throughputs, and
SaskPower noted that the capture system was processing a greater
portion of the flue gas (up to 95 percent of the flue gas, with 87
percent capture from the processed flue gas, resulting in 83 percent
total capture when operating).\157\ SaskPower has not reported whether
Boundary Dam Unit 3 has maintained that performance in the long
term.\158\ Notably, at those higher throughputs, the capture efficiency
from the processed flue gas is lower. Moreover, even with those
improvements, Boundary Dam continues to operate with capture
efficiencies below design specification. Therefore, the fixes applied
at Boundary Dam Unit 3 do not support 90 percent capture as adequately
demonstrated.
---------------------------------------------------------------------------

\157\ U.S. EPA, ``Meeting with SaskPower to Discuss CCS at
Boundary Dam Unit 3'' (January 18, 2024). Document ID No. EPA-HQ-
OAR-2023-0072-8906.
\158\ Status updates from Boundary Dam from the second quarter
of 2022 onward report average daily capture rates on a metric tons
per day basis, capture system availability, and emissions intensity.
Capture efficiency is not reported. See SaskPower. BD3 Status
Update: Q4 2024. Available at: <a href="https://saskpower.com/about-us/our-company/blog/2025/bd3-status-update-q4-2024">https://saskpower.com/about-us/our-company/blog/2025/bd3-status-update-q4-2024</a>.
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Additionally, the operating-availability of the capture system at
Boundary Dam Unit 3 has been less than 100 percent.\159\ Between 2015
and 2022, annual operating-availability of the capture plant relative
to the EGU varied

[[Page 58973]]

between 58 and 94 percent.\160\ In 2023, the average quarterly
operating-availability of the capture plant was approximately 85
percent.\161\ Operating-availability remained at this level in
2024.\162\ Lower operating-availabilities further contribute to lower
total capture efficiencies.
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\159\ Here, operating-availability is the percent of time that
the capture system is operating relative to the time that the EGU is
operating.
\160\ Jacobs, B., et al. Reducing the CO<INF>2</INF> Emission
Intensity of Boundary Dam Unit 3 Through Optimization of Operating
Parameters of the Power Plant and Carbon Capture Facilities.
Proceedings of the 16th International Conference on Greenhouse Gas
Control Technologies. (2022). Available at: <a href="https://dx.doi.org/10.2139/ssrn.4286430">https://dx.doi.org/10.2139/ssrn.4286430</a>.
\161\ SaskPower. BD3 Status Update: Q4 2023. Available at:
<a href="https://www.saskpower.com/about-us/our-company/blog/2024/bd3-status-update-q4-2023">https://www.saskpower.com/about-us/our-company/blog/2024/bd3-status-update-q4-2023</a>.
\162\ SaskPower. BD3 Status Update: Q4 2024. Available at:
<a href="https://saskpower.com/about-us/our-company/blog/2025/bd3-status-update-q4-2024">https://saskpower.com/about-us/our-company/blog/2025/bd3-status-update-q4-2024</a>.
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The total capture efficiency at Boundary Dam Unit 3 has been less
than 90 percent because the capture system has not processed all the
flue gas. Also, the capture efficiency is still less than 90 percent
when the capture system is operating even after applying fixes.
Additionally, the operating-availability of the capture system is less
than 100 percent. Considering this, the EPA concludes that the
experience at Boundary Dam Unit 3 does not support 90 percent CCS as
adequately demonstrated. Furthermore, the capacity of Boundary Dam Unit
3 is less than the capacity of the average U.S. coal-fired steam
generating unit of approximately 430 MW. Because CCS at Boundary Dam
Unit 3 underperformed at 110 MW, the EPA concludes that 90 percent
capture would similarly underperform at any units greater than 25 MW,
including larger units.
In the 2024 CPS, the EPA argued that new solvents achieving 95
percent capture efficiency were evidence that 90 percent capture was
adequately demonstrated. However, the EPA failed to reasonably account
for the performance that could be achieved in practice. The only
datapoint for commercial scale post-combustion CCS on a fossil fuel-
fired EGU, with integrated steam and power, is Boundary Dam Unit 3. As
noted in the June 2025 NPRM, it would be reasonable to anticipate that
a capture system using a new solvent would underperform to a similar
degree as Boundary Dam.\163\ A capture system using a new solvent, even
in a process designed to achieve 95 percent capture on an instantaneous
basis, would achieve just 66 percent total capture efficiency and still
fail to achieve 90 percent capture if the capture system using a new
solvent performed proportionately to Boundary Dam's best annual
performance.\164\ Even under more optimistic circumstances, assuming
Boundary Dam's best annual operating-availability and that a new
solvent capture system performs proportionally to Boundary Dam's recent
performance, the resulting total annual capture efficiency would be
only 82 percent.\165\ In combination, a capture system would achieve
much less than 90 percent total capture efficiency. On review, the
EPA's prior extrapolation fails to support CCS with 90 percent capture
as adequately demonstrated. Considering these factors, the EPA is
finalizing the determination that CCS with 90 percent capture is not
adequately demonstrated for existing coal-fired steam generating units.
---------------------------------------------------------------------------

\163\ 90 FR 25752, 25769 (June 17, 2025).
\164\ 95 percent design capture x (63 percent total annual
capture/90 percent design capture) = 66 percent total annual capture
efficiency. Between 2015 and 2022, Boundary Dam Unit 3 achieved a
total annual capture efficiency of not more than 63 percent. See
Jacobs, B., et al. Reducing the CO<INF>2</INF> Emission Intensity of
Boundary Dam Unit 3 Through Optimization of Operating Parameters of
the Power Plant and Carbon Capture Facilities. Proceedings of the
16th International Conference on Greenhouse Gas Control
Technologies. (2022). Available at: <a href="https://dx.doi.org/10.2139/ssrn.4286430">https://dx.doi.org/10.2139/ssrn.4286430</a>.
\165\ 94 percent availability x 95 percent design capture x (83
percent total capture/90 percent design capture) = 82 percent total
annual capture efficiency.
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ii. CO<INF>2</INF> Capture at Other Coal-Fired Steam Generating Units
In the 2024 CPS, to support the determination of 90 percent capture
as adequately demonstrated, the EPA cited other applications of CCS at
coal-fired steam generating units. These included CO<INF>2</INF>
capture at the Argus Cogeneration Plant (Trona, California), at AES's
Warrior Run (Cumberland, Maryland) and Shady Point (Panama, Oklahoma)
plants, and at Plant Barry's (Mobile, Alabama) 25 MWe (megawatt-
equivalent) project.\166\ These projects were not of an equivalent size
to commercial scale or, in the case of the Argus Cogeneration Plant,
captured far less than 90 percent of CO<INF>2</INF>. These earlier
examples would have informed the design of the capture system at
Boundary Dam Unit 3. However, the lessons learned from such projects
failed to limit the underperformance of the CO<INF>2</INF> capture
system at Boundary Dam. Consequently, they do not mitigate the
anticipated underperformance in the extrapolation of 90 percent CCS and
cannot support 90 percent capture as adequately demonstrated.
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\166\ Dooley, J.J., et al. ``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. (2009). Available at: <a href="https://doi.org/10.2172/967229">https://doi.org/10.2172/967229</a>.
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In the 2024 CPS, the EPA also cited the Petra Nova project at W.A.
Parish Unit 8 (Thompsons, Texas). The Petra Nova project began
operation in 2017, and the owner put the facility into reserve shutdown
(i.e., idled) in May 2020, citing the poor economics of utilizing
captured CO<INF>2</INF> for EOR at that time. On September 13, 2023,
the carbon capture facility at Petra Nova restarted.\167\ A final
report from the National Energy Technology Laboratory (NETL) details
the challenges that the project faced over an initial 3-year period,
including leaks from heat exchangers, build-up of slurry and solids on
the flue gas blower, and build-up of scale on various components.\168\
Petra Nova captured on average 92.4 percent of the CO<INF>2</INF> from
the 240 MWe flue gas processed over a 3-year period while operating.
However, that does not account for emissions during outages of the
CO<INF>2</INF> capture system. Maintenance to address outages directly
attributable to the CO<INF>2</INF> capture facility was approximately
10 percent of the year on average over that timeframe. Accounting for
those outages alone would, approximately, result in a total capture
efficiency of 83.2 percent. Furthermore, Petra Nova processes a 240 MWe
portion of the flue gas from the 610 MW W.A. Parish Unit 8. At full
load, that would equate to a capture efficiency of approximately 36
percent of the emissions from the coal-fired steam generating
unit.\169\ With 10 percent outages, this would be reduced further to
32.4 percent. Additionally, the 90 percent CCS BSER in the 2024 CPS was
premised on the CO<INF>2</INF> capture plant using integrated steam and
electricity from the host EGU. However, Petra Nova uses an auxiliary
natural gas-fired combustion turbine cogeneration unit to provide steam
and electricity to the CO<INF>2</INF> capture process, and the system
does not capture the CO<INF>2</INF> emissions from the auxiliary
cogeneration unit. This design is inconsistent with the premise of the
CCS BSER in the 2024 CPS. A system consistent with the premise of the
BSER uses integrated steam and power and would need to meet the
electricity and steam load requirements of the capture process.
Furthermore, accounting for

[[Page 58974]]

emissions from the auxiliary cogeneration unit would lower the capture
efficiency at Petra Nova further. In the 2024 CPS, by ignoring the
emissions from the auxiliary cogeneration unit, the EPA failed to
reasonably extrapolate the results at Petra Nova to a system using
integrated steam and power. Considering these factors, the experience
at Petra Nova does not support 90 percent capture as adequately
demonstrated.
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\167\ JX Nippon Oil & Gas Exploration Corporation. Restart of
the large-scale Petra Nova Carbon Capture Facility in the U.S.
(September 2023). Available at: <a href="https://www.eneos-xplora.com/english/newsrelease/upload_files/20230913EN.pdf">https://www.eneos-xplora.com/english/newsrelease/upload_files/20230913EN.pdf</a>.
\168\ W.A. Parish Post-Combustion CO<INF>2</INF> Capture and
Sequestration Demonstration Project, Final Scientific/Technical
Report (March 2020). Available at: <a href="https://www.osti.gov/servlets/purl/1608572">https://www.osti.gov/servlets/purl/1608572</a>.
\169\ 90 percent x 240 MWe / 610 MW = 36 percent.
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Comments: Some commenters cited additional examples of
CO<INF>2</INF> capture on coal-fired steam generating units in China.
Commenters cited the 150,000 metric tons of CO<INF>2</INF> per year
Jinjie demonstration project. Commenters also cited the 500,000 metric
tons of CO<INF>2</INF> per year Taizhou CCS project, which began
operation in June 2023 and captures less than 12.5 percent of the 1,000
MW EGU's total CO<INF>2</INF> emissions. Commenters also referenced the
1.5 million metric tons of CO<INF>2</INF> per year Longdong CCS project
at the coal-fired Zhengning Power Plant. Captured CO<INF>2</INF> will
be stored in geologic storage and used for EOR. The 270 MWe project has
a design capture efficiency of 95 percent from a portion of the flue
gas from a 1,000 MW coal-fired EGU.\170\
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\170\ State of the Art: CCS Technologies 2025. Global CCS
Institute (2025). Available at: <a href="https://www.globalccsinstitute.com/wp-content/uploads/2025/08/State-of-the-Art-CCS-Technologies-2025-Global-CCS-Institute.pdf">https://www.globalccsinstitute.com/wp-content/uploads/2025/08/State-of-the-Art-CCS-Technologies-2025-Global-CCS-Institute.pdf</a>. 27 percent of the flue gas is treated.
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EPA Response: The Jinjie demonstration project began operation in
June 2021 and processes less than five percent of the flue gas from one
of the units at the coal-fired power plant.\171\ By January 2025, the
Taizhou CCS project had captured just 300,000 metric tons of
CO<INF>2</INF>, far below its design basis. While a report states that
this project achieves a capture rate of 90.86 percent, detailed data
(e.g., operating-availability, amount of flue gas processed) is
limited.\172\ According to a press release, the Longdon CCS project
completed a 72-hour test on September 25, 2025, but the press release
did not contain detailed performance information.\173\ Beyond that
press release, no reports on the project are available. Because of the
limited data available, the EPA has concluded that these projects do
not support 90 percent capture as adequately demonstrated.
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\171\ Bongers, N. China's impressive strides towards CCUS. Low
Emission Technology Australia. (2025). Available at: <a href="https://letaustralia.com.au/wp-content/uploads/Executative-Summary-Chinas-Impressive-Strides-Towards-Carbon-Capture-Utilisation-and-Storage-CCUS.pdf">https://letaustralia.com.au/wp-content/uploads/Executative-Summary-Chinas-Impressive-Strides-Towards-Carbon-Capture-Utilisation-and-Storage-CCUS.pdf</a>.
\172\ Gong, H., et al. Taizhou 500kt per year post-combustion
carbon capture demonstration project. Clean Energy, 9 (4). (2025).
Available at: <a href="https://doi.org/10.1093/ce/zkaf011">https://doi.org/10.1093/ce/zkaf011</a>.
\173\ China Launches World's Largest Coal-fired Carbon Capture
Project (September 29, 2025). Available at: <a href="http://en.sasac.gov">en.sasac.gov</a>.cn/2025/09/
29/c_19886.htm.
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iii. Variations in Performance of CO<INF>2</INF> Capture
The determinations in the 2024 CPS assumed that the CO<INF>2</INF>
capture system is available every hour the EGU is operational and
performs at its design capture efficiency (or better) during each of
those hours. The EPA finds that the Agency did not adequately account
for variations in performance of CO<INF>2</INF> capture that would
result in a lower capture efficiency. This further supports the
conclusion that 90 percent CO<INF>2</INF> capture is not adequately
demonstrated for existing coal-fired steam generating units.
In the 2024 CPS, the EPA did not account for periodic decreases in
the performance of the CO<INF>2</INF> capture system due to solvent
degradation and fouling of components between maintenance cycles.
Boundary Dam Unit 3 experienced challenges with respect to solvent
foaming, biological fouling, scaling, and fouling from fly-
ash.174, 175 While units could take actions to address those
issues, performance and capture efficiency would necessarily decrease
in between treatments or maintenance (e.g., fouling would steadily
accumulate after cleaning). On average, the capture efficiency would
therefore be less than optimal. SaskPower indicated that even after
applying such fixes, Boundary Dam Unit 3 achieved, at best, a total
capture efficiency of 83 percent when the capture system was
operating.\176\
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\174\ Giannaris, S., et al. SaskPower's Boundary Dam Unit 3
Carbon Capture Facility--The Journey to Achieving Reliability.
Proceedings of the 15th International Conference on Greenhouse Gas
Control Technologies. (2021). Available at: <a href="http://dx.doi.org/10.2139/ssrn.3820191">http://dx.doi.org/10.2139/ssrn.3820191</a>.
\175\ Pradoo, P., et al. Improving the Operating Availability of
the Boundary Dam Unit 3 Carbon Capture Facility. Proceedings of the
16th International Conference on Greenhouse Gas Control
Technologies. (2022). Available at: <a href="http://dx.doi.org/10.2139/ssrn.4286503">http://dx.doi.org/10.2139/ssrn.4286503</a>.
\176\ U.S. EPA, ``Meeting with SaskPower to Discuss CCS at
Boundary Dam Unit 3'' (January 18, 2024). Document ID No. EPA-HQ-
OAR-2023-0072-8906.
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Furthermore, the EPA did not adequately account for periods of
startup on the operation of the capture system.\177\ After absorption,
thermal energy (heat) in the form of steam is required to release the
CO<INF>2</INF> from the CO<INF>2</INF>-rich solvent and electricity is
required to power the compressor to compress the CO<INF>2</INF> for
transport via pipeline. However, prior to substantial production of
steam and electricity, major components of the capture process may be
offline. Even assuming the capture system could consistently capture 90
percent CO<INF>2</INF> when operating, any CO<INF>2</INF> emitted prior
to operation of the capture equipment would necessarily result in an
average capture efficiency of less than 90 percent.
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\177\ 89 FR 39798, 39854, 39929 (May 9, 2024).
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To consistently achieve 90 percent capture on average, the source
would have to overperform during certain hours. The EPA cited results
from Boundary Dam that suggested higher capture efficiencies were
achieved at lower throughputs.\178\ However, in its justification of
the BSER, the EPA relied on an assumption that sources would operate at
high capacity throughout the course of the year. If that were the case,
the hypothetical higher capture efficiencies a system could potentially
achieve at lower throughputs would not occur in practice. To otherwise
achieve an annual average capture efficiency of 90 percent, higher
instantaneous capture efficiencies likely would need to be achievable.
In the 2024 CPS, the EPA cited vendor statements of pilot tests for
different commercial amine solvents where operators observed higher
capture efficiencies under specific conditions.\179\ However, the
experience at Boundary Dam shows that it would be reasonable to
anticipate that the total capture efficiency a system achieves in
practice would be less than design specifications.
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\178\ Jacobs, B., et al. Reducing the CO<INF>2</INF> Emission
Intensity of Boundary Dam Unit 3 Through Optimization of Operating
Parameters of the Power Plant and Carbon Capture Facilities.
Proceedings of the 16th International Conference on Greenhouse Gas
Control Technologies. (2022). Available at: <a href="https://dx.doi.org/10.2139/ssrn.4286430">https://dx.doi.org/10.2139/ssrn.4286430</a>.
\179\ 89 FR 39798, 39852 (May 9, 2024).
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iv. Planned Projects
In the 2024 CPS, the EPA also previously cited planned projects and
front-end engineering and design (FEED) studies.180, 181
However, the planned projects are neither operational nor provide
measured data. While the equipment for those planned projects may have
been designed for 90 or even 95 percent CO<INF>2</INF> capture, simply
designing a project for a certain percentage capture does not ensure
that the project will achieve that percentage capture in practice.
Boundary Dam Unit 3 did not achieve its design percentage capture, as
detailed in section IV.A.1.a.i of this preamble. Therefore, because
those hypothetical projects have not yet produced any data, they do not
mitigate

[[Page 58975]]

the potential underperformance of CO<INF>2</INF> capture, and,
therefore, are not sufficient to show that 90 percent CO<INF>2</INF>
capture is adequately demonstrated.\182\ Moreover, none of the projects
(for post-combustion CO<INF>2</INF> capture from fossil fuel-fired
EGUs) with feasibility or FEED studies previously cited by the EPA have
moved forward to construction.
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\180\ 89 FR 39798, 39851 (May 9, 2024).
\181\ See Chapter 4.4 and Table 13 of Greenhouse Gas Mitigation
Measures for Steam Generating Units. Document ID No. EPA-HQ-OAR-
2023-0072-9095.
\182\ This includes projects for CCS on coal-fired steam
generating units in West Virginia and Alaska that were recently
selected for funding by DOE. See Project Selections for Broad Agency
Announcement DE-FOA-0003605, Restoring Reliability: Coal
Recommissioning and Modernization (Topic 1). Available at: <a href="https://www.energy.gov/hgeo/project-selections-broad-agency-announcement-de-foa-0003605-restoring-reliability-coal-0">https://www.energy.gov/hgeo/project-selections-broad-agency-announcement-de-foa-0003605-restoring-reliability-coal-0</a>.
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There are no post-combustion CCS applications on fossil fuel-fired
EGUs that have begun operation since the finalization of the 2024 CPS
that are sufficient to support 90 percent capture as adequately
demonstrated. Rather, some of the planned projects cited in the 2024
CPS either have been abandoned or have faced other challenges. Project
Diamond Vault was a planned project to capture up to 95 percent of
CO<INF>2</INF> emissions from the 600 MW Madison Unit 3 at Brame Energy
Center in Lena, Louisiana.\183\ The FEED study and current plans for
carbon capture were abandoned in late 2024.\184\ Project Tundra is a
carbon capture project in North Dakota at the Milton R. Young Station
lignite coal-fired power plant that planned for the capture plant to
treat the flue gas from the 455 MW Unit 2 and some additional flue gas
from the 250 MW Unit 1 (an equivalent capacity of 530 MW in
total).\185\ TC Energy, a primary sponsor of Project Tundra, has since
withdrawn from the project, although the project may continue to move
forward depending on various factors.\186\ The timeframes for several
other CCS projects on coal-fired EGUs are unclear.\187\
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\183\ Project Diamond Vault Overview. Document ID No. EPA-HQ-
OAR-2025-0124-0027.
\184\ Cleco Corporate Holdings, LLC SEC Form 10Q, at 51 (August
18, 2024). Available at: <a href="https://www.sec.gov/Archives/edgar/data/18672/000108981924000026/cnl-20240630.htm">https://www.sec.gov/Archives/edgar/data/18672/000108981924000026/cnl-20240630.htm</a>.
\185\ ``An Overview of Minnkota's Carbon Capture Initiative--
Project Tundra,'' 2023 LEC Annual Meeting (October 5, 2023).
\186\ Power Engineering. Key partner withdraws from large-scale
CO<INF>2</INF> capture project. Available at: <a href="https://www.power-eng.com/environmental-emissions/carbon-capture-storage/key-partner-withdraws-from-large-scale-co2-capture-project/">https://www.power-eng.com/environmental-emissions/carbon-capture-storage/key-partner-withdraws-from-large-scale-co2-capture-project/</a>.
\187\ D. Gearino, A Carbon Capture Project Faces a New Delay in
a Year of Slow Progress for Coal Power Plants Looking for Retrofits,
Inside Climate News (December 10, 2024). Available at: <a href="https://insideclimatenews.org/news/10122024/north-dakota-coal-plant-carbon-capture-project-faces-new-delay/">https://insideclimatenews.org/news/10122024/north-dakota-coal-plant-carbon-capture-project-faces-new-delay/</a>.
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b. Cost
The EPA has re-evaluated the costs and associated assumptions of 90
percent CCS on existing long-term coal-fired steam generating units and
is finalizing the determination that the costs are not reasonable based
on the rationale detailed in this section of the preamble.
i. Capacity Factor, Effective Capture Efficiency, and Other Assumptions
In the 2024 CPS, costs for CCS on existing coal-fired steam
generating units were determined assuming a best-case scenario.
Specifically, the cost assessment assumed sources operated at high
annual capacity factors (80 percent) and that the CO<INF>2</INF>
capture equipment was available and performing optimally every hour the
EGU was operating. However, in 2023, coal-fired EGUs had an average
capacity factor of 42 percent.\188\ Lower capacity factors typically
result in less revenue from electricity generation. Moreover, as
detailed in the preceding section of this preamble, even with a design
capture efficiency of 90 percent, the actual total capture efficiency
over the course of the year is lower, and under some circumstances
significantly lower. Consequently, less CO<INF>2</INF> captured (due to
lower actual capture efficiency, lower EGU capacity factor, or both)
results in higher costs due to reduced revenue from the IRC section 45Q
tax credit.\189\
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\188\ U.S. Energy Information Administration. Electric Power
Annual. Available at: <a href="https://www.eia.gov/electricity/annual/">https://www.eia.gov/electricity/annual/</a>.
\189\ These tax credits are currently available for a twelve-
year period for facilities that commence construction before January
1, 2033, and can be used to offset tax liability. 26 U.S.C. 45Q
(2025).
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Furthermore, rather than directly considering the costs for any
operation after the expiration of availability of the IRC section 45Q
tax credit for existing coal-fired steam generating units in the 2024
CPS, the EPA committed to review the requirements of the emission
guidelines pertaining to existing coal-fired steam generating units by
January 1, 2041, and posited that other mechanisms for potential
valuation of EGUs operating with 90 percent CCS could arise in the
future.\190\ However, those assumptions are no longer reasonable
because the EPA believes that coal-fired steam generating units are now
more likely to operate longer than they will be able to claim the tax
credit. As noted in the June 2025 NPRM, the EPA believes that coal-
fired steam generating unit capacity and generation will continue to
comprise a substantial portion of the nation's electricity supply.\191\
A number of coal-fired steam generating units are delaying or canceling
their scheduled retirements in light of increasing electricity demand,
among other factors.\192\ The EPA's projections further show a
substantial capacity of coal-fired steam generating units operating in
the long term.\193\ Based on a lower capacity factor and operation
beyond 12 years, the EPA proposed that, even if the IRC section 45Q tax
credit is accounted for as a reduction, the costs are unreasonable and
solicited comment on the assumptions in evaluation of the
reasonableness of the cost of the BSER.
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\190\ 89 FR 39798, 39902 (May 9, 2024).
\191\ See 90 FR 25752, 25772, 25774 (June 17, 2025).
\192\ D. Proctor, U.S. Coal Plants Get Reprieve as Market and
Policies Change, Power (February 6, 2025). Available at: <a href="https://www.powermag.com/u-s-coal-plants-get-reprieve-as-market-and-policies-change/">https://www.powermag.com/u-s-coal-plants-get-reprieve-as-market-and-policies-change/</a>.
\193\ See memorandum entitled Trends Relating to Fossil Fuel-
fired Electric Generating Units in the docket for this rulemaking
(Docket ID No. EPA-HQ-OAR-2025-0124).
---------------------------------------------------------------------------

Comments: Some commenters agreed with the EPA's capacity factor
assumptions in the June 2025 NPRM for evaluating the cost of CCS as
BSER. Other commenters stated that the 80 percent capacity factor
assumed for cost calculations in the 2024 CPS was reasonable and argued
that the availability of the IRC section 45Q tax credit would
incentivize higher capacity factors. Commenters also argued that the
EPA's June 2025 NPRM was internally inconsistent, noting that elsewhere
the June 2025 NPRM stated that ``coal-fired steam generating unit
capacity and generation will continue to comprise a substantial portion
of the nation's electricity supply.'' \194\ Some commenters disagreed
with the EPA's analysis based on a capture system underperforming
(i.e., designed for 90 percent capture, but achieving 75 percent total
capture efficiency in practice). Commenters argued that the 75 percent
total capture efficiency was unjustified.
---------------------------------------------------------------------------

\194\ 90 FR 25774 (June 17, 2025).
---------------------------------------------------------------------------

EPA Response: As detailed in section IV.A.1.a of this preamble, it
is reasonable to anticipate that a capture system designed to achieve a
given capture efficiency would underperform. While CCS may achieve
emission reductions, evidence shows the CO<INF>2</INF> capture system
underperforms. The capture system at Boundary Dam Unit 3 was designed
to achieve 90 percent capture but achieved, at best, 63 percent total
capture efficiency on an annual basis between 2015 and 2022. Under a
set of assumptions that reflect the underperformance of CCS, lower
capacity factors, and the limited

[[Page 58976]]

availability of the IRC section 45Q tax credit,\195\ the costs are
substantially higher ($62/MWh, $124/ton of CO<INF>2</INF> reduced) than
those determined in the 2024 CPS and more than three times higher on a
$/MWh basis than the costs the EPA has previously determined to be
reasonable ($18.50/MWh).\196\ Even assuming a higher capacity factor
that reflects the average capacity factor of coal-fired steam
generating units of approximately 70 percent in the updated baseline
projection,\197\ costs remain high ($50/ton, $25/MWh).\198\ Such high
costs, particularly on a $/MWh basis, are not reasonable, even
considering the potential CO<INF>2</INF> emission reductions, and do
not support 90 percent CCS as BSER.
---------------------------------------------------------------------------

\195\ These costs include the costs of capital equipment, etc.,
consistent with 90 percent design capture rate, 63 percent actual
capture rate, a fixed 40 percent capacity factor, and 15-year
booklife (12 years of 45Q availability, three years without). Costs
are expressed in 2019$. See memorandum entitled Updated Evaluation
of Best System of Emission Reduction Costs of Carbon Capture and
Sequestration/Storage at Existing Coal-Fired Electric Generating
Units in the docket for this rulemaking.
\196\ Costs are expressed in 2019$. In a variety of rulemakings,
the EPA has required coal-fired EGUs to install and operate flue gas
desulfurization (FGD, or wet scrubbers) to reduce their
SO<INF>2</INF> emissions. The annualized cost of installing these
controls on a representative 700 to 300 MW coal-fired steam
generating unit are $14.80 to $18.50/MWh. Hence control costs that
are generally consistent with these values should be considered
reasonable. See 89 FR 39798, 39882 (May 9, 2024).
\197\ See memorandum entitled Trends Relating to Fossil Fuel-
fired Electric Generating Units in the docket for this rulemaking
(Docket ID No. EPA-HQ-OAR-2025-0124).
\198\ These costs include the costs of capital equipment, etc.,
consistent with 90 percent design capture rate, 63 percent actual
capture rate, a fixed 70 percent capacity factor, and 15-year
booklife (12 years of 45Q availability, three years without). Costs
are expressed in 2019$. See memorandum entitled Updated Evaluation
of Best System of Emission Reduction Costs of Carbon Capture and
Sequestration/Storage at Existing Coal-Fired Electric Generating
Units in the docket for this rulemaking.
---------------------------------------------------------------------------

ii. The IRC Section 45Q Tax Credit
The costs for 90 percent CCS are even higher if the IRC section 45Q
tax credit is not accounted for as a reduction ($77/MWh and $155/
ton).\199\ In the 2024 CPS, the costs of 90 percent CCS for existing
coal-fired steam generating units accounted for the IRC 45Q tax credit
by reducing the direct costs to the source for every ton of
CO<INF>2</INF> reduced. The 2024 CPS assessed costs over a period
consistent with the 12-year availability of the IRC section 45Q tax
credit. The 2024 CPS justified that position on grounds that CAA
section 111(a)(1) requires the EPA, in determining the BSER, to account
for ``the cost of achieving such [emissions] reduction,'' and asserted
that this provision refers to the cost to the source rather than the
societal cost. The Inflation Reduction Act (IRA) extended and expanded
the IRC section 45Q tax credit and included CAA section 135(a)(6),
requiring the EPA to promulgate regulations under the CAA's authorities
to ensure reductions in GHG emissions. In the 2024 CPS, the EPA further
stated that the IRA included legislative history stating that Congress
intended to authorize the Agency to promulgate regulations under CAA
section 111 to reduce GHGs from fossil fuel-fired power plants,
including regulations based on CCS that assumed lower cost due to the
45Q tax credit.\200\ In its proposed repeal of the 2024 CPS, the EPA
reevaluated this position and proposed that reducing control costs by
the amount of the tax credit is an incorrect accounting for the costs
of control, and solicited comment on this position.\201\
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\199\ These costs include the costs of capital equipment, etc.,
consistent with 90 percent design capture rate, 63 percent actual
capture rate, a fixed 70 percent capacity factor, and 15-year
booklife (no reduction in cost from 45Q). Costs are expressed in
2019$. See memorandum entitled Updated Evaluation of Best System of
Emission Reduction Costs of Carbon Capture and Sequestration/Storage
at Existing Coal-Fired Electric Generating Units in the docket for
this rulemaking.
\200\ 89 FR 39798, 39881 (May 9, 2024).
\201\ 90 FR 25752, 25772 (June 17, 2025).
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(A) Comments and Responses
Comments: Some commenters opposed the June 2025 NPRM and stated
that the EPA must account for the IRC section 45Q tax credit as a
reduction when evaluating the costs of 90 percent CCS. Commenters
argued that the EPA has long understood the ``cost'' in CAA section
111(a)(1) to refer to whether the cost to the regulated source would be
too great to implement the technology.\202\ Some commenters argued that
counting the IRC section 45Q tax credit as a reduction in costs in the
evaluation of reasonableness of the costs is the best reading of CAA
section 111(a)(1), which directs EPA to ``tak[e] into account the cost
of achieving such reduction,'' when determining the BSER, not costs
generally. Commenters stated the phrase ``such reduction'' refers to
the emission reduction ``achieve[ed] through the application of the
best system of emission reduction.'' Because sources are the entities
that apply the best system, the phrase ``cost of achieving such
reduction'' is best read as focusing on costs borne by those sources,
rather than broader economic impacts. Commenters argued the EPA has
followed this approach since the beginning of the regulatory
program.\203\
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\202\ Commenters cited Portland Cement Ass'n, 513 F.2d at 508
(``The industry has not shown inability to adjust itself in a
healthy economic fashion to . . . the standards prescribed.'').
\203\ Commenters cited Portland Cement Ass'n, 486 F.2d at 388,
observing that the ruling explained that the ``cost'' analysis is
focused on equipment and operating costs and rejected an argument
that a broader cost-benefit analysis evaluating impacts was required
because that would ``conflict with the specific time constraints
imposed on the administrator.''
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Other commenters agreed with the June 2025 NPRM and stated that the
EPA should not consider the IRC section 45Q tax credit as a reduction
when evaluating the cost of CCS as a potential BSER. One commenter
stated that the statute requires consideration of total costs and cited
the Supreme Court's decision in Michigan.\204\ Commenters claimed that
the decision held that the EPA must consider all costs, including
system and indirect costs, when evaluating the reasonableness of a
standard. Some commenters argued that tax credits do not reduce the
cost of 90 percent CCS but simply shift those costs to taxpayers. A few
commenters further stated that CAA section 111(a)(1) includes
consideration of societal costs beyond those to a source's owner or
operator. One commenter argued that the inclusion of ``cost'' in the
parenthetical of CAA section 111(a)(1), along with other factors that
account for societal disbenefits, suggests that the best reading of CAA
section 111(a)(1) is that the EPA should not focus solely on the cost
to the source when evaluating the BSER and, therefore, should not
account for the IRC section 45Q tax credit as reducing costs.
---------------------------------------------------------------------------

\204\ Commenters cited 576 U.S. at 752-53.
---------------------------------------------------------------------------

EPA Response: The EPA agrees with the commenters who stated that
the 2024 CPS erred in excluding the value of the IRC section 45Q tax
credit from the cost of CCS by counting the tax credit as a reduction
in the cost of CCS. CAA section 111(a)(1) provides that the EPA must
determine ``the best system of emission reduction . . . (taking into
account the cost of achieving such reduction and any nonair quality
health and environmental impact and energy requirements).'' This
provision does not, by its terms, limit the costs to those incurred
directly by the source. Under Loper Bright Enterprises v. Raimondo, 603
U.S. 369 (2024), the best interpretation of this provision is that the
costs include the full costs of the controls (i.e., without reduction
by the amount of the IRC section 45Q tax credit). Under the
justification in the 2024 CPS for considering the IRC section 45Q tax
credit, if a cost was passed on to the public through a large tax
credit or other similar subsidy

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